DNO ASA — Annual Report 2019

Mar 18, 2020

Content

Highlights 3 Key figures 4 Board of Directors 5 Board of Directors' report 7 Introduction 7 Operations review 8 Business development 9 Financial performance 9 Corporate governance 10 Enterprise risk management 12 HSSE performance 13 Organization and personnel 13 Parent company 16 Main events since yearend 16 Responsibility statement 17 Consolidated accounts 20 Parent company accounts 71 Auditor's report 85 Alternative performance measures 90 Glossary and definitions 93

Highlights

DNO¹ recorded 2019 revenues of USD 971 million, the highest in the Company's 48-year history, on the back of North Sea acquisitions and a record drilling campaign across its portfolio driving a 28 percent increase in Company Working Interest (CWI) production. Net profit during 2019 stood at USD 74 million and the Company exited the year with a cash balance of USD 486 million.

DNO more than doubled its operational spend during 2019 to over USD 600 million to deliver the largest annual drilling program in its history with 36 wells drilled or spud. Gross operated production in 2019 averaged 127,000 barrels of oil equivalent per day (boepd) including 104,800 boepd on a CWI basis, up from 117,600 boepd and 81,700 boepd, respectively, during 2018.

In the Kurdistan region of Iraq (Kurdistan), gross production from the two fields in the DNOoperated Tawke license climbed to 123,900 barrels of oil per day (bopd) in 2019, up from 113,100 bopd in 2018. In the DNO-operated Baeshiqa license containing two large structures with multiple target reservoirs, the Company reported a discovery in November 2019 with additional exploration and appraisal operations ongoing.

In the North Sea, the Company added CWI production of 17,400 boepd in 2019, through the acquisition of Faroe Petroleum plc (Faroe) and assets swap with Equinor Energy AS.

At yearend 2019, DNO held 106 licenses across its portfolio, nearly a fourfold increase from 28 licenses at yearend 2018. In Kurdistan, DNO continues to produce what are among the lowest cost oil barrels in the global oil and gas industry in terms of finding, development and lifting costs. With the addition of the North Sea licenses, the Company is now placed among the top three Europeanlisted independent oil and gas companies in terms of production and reserves (2P CWI reserves of 345 MMboe at yearend 2019).

¹ DNO ASA and the companies in which it directly or indirectly owns investments are separate and distinct entities. But in this publication, the collective expressions "DNO", "Company" and "Group" may be used for convenience where reference is made in general to those companies. Likewise, the words "we", "us", "or" and "ourselves" may be used in some places to refer to the companies of the DNO Group in general. These expressions are also used where no useful purpose is served by identifying any particular company or companies.

Key figures

Key financials (USD million)	2019	2018
Revenues	971.4	829.3
Gross profit	430.0	478.7
Profit/-loss from operating activities	75.6	376.8
Net profit/-loss	73.5	354.3
EBITDA	549.4	638.8
EBITDAX	695.8	703.5
Netback	606.3	489.1
Acquisition and development costs	407.9	138.0
Exploration expenses	146.4	64.7
Production and reserves	2019	2018
Gross operated production (boepd)	126,985	117,607
CWI production (boepd)	104,767	81,712
CWI 2P reserves (MMboe)	344.8	376.1
Key performance indicators	2019	2018
Lifting costs (USD/boe)	5.4	3.0
Netback (USD/boe)	16.3	16.4

The CWI production in 2019 includes production from the assets added through the swap agreement with Equinor Energy AS, effective from 1 January 2019; see Note 25 for details.

For more information about key figures, see the section on alternative performance measures.

Board of Directors

Bijan Mossavar-Rahmani Executive Chairman

Bijan Mossavar-Rahmani is an experienced oil and gas executive and has served as the Company's Executive Chairman of the Board of Directors since 2011.

Mr. Mossavar-Rahmani serves concurrently as Executive Chairman of Oslo-listed RAK Petroleum plc, the Company's largest shareholder. He is a Trustee of the New York Metropolitan Museum of Art where he chairs the audit committee and a member of Harvard University's Global Advisory Council. He has published more than ten books on global energy markets and was decorated Commandeur de l'Ordre National de la Côte d'Ivoire for services to the energy sector of that country. Mr. Mossavar-Rahmani is a graduate of Princeton (AB) and Harvard Universities (MPA). He is a member of the nomination and remuneration committees.

Lars Arne Takla Deputy Chairman

Lars Arne Takla has extensive experience from various managerial, executive and board positions in the international oil and gas industry.

Mr. Takla has held various managerial positions with ConocoPhillips, including Managing Director and President of the Scandinavian Division. He was Executive Chairman of the Norwegian Energy Company ASA between 2005 and 2011. Mr. Takla was appointed Commander of the Royal Norwegian Order of St. Olav for his strong contribution to the Norwegian petroleum industry. He holds a Master of Science degree in chemical engineering from the Norwegian University of Science and Technology. He was elected to the Company's Board of Directors in 2012 and is a member of the HSSE committee.

Elin Karfjell

Director

Elin Karfjell is Chief Financial Officer of Statsbygg and has held various management positions across a broad range of industries.

Ms. Karfjell has been Managing Partner of Atelika AS and has served as Chief Executive Officer of Fabi Group, Director of Finance and Administration at Atea AS and partner of Ernst & Young AS and Arthur Andersen. Other board directorships include Aker Philadelphia Shipyard, North Energy ASA and Contesto AS. Ms. Karfjell is a state authorized public accountant. She has a Bachelor of Science in Accounting from Oslo and Akershus University College of Applied Sciences and a Higher Auditing degree from the Norwegian School of Economics and Business Administration. Ms. Karfjell was elected to the Company's Board of Directors in 2015 and is a member of the audit committee.

Gunnar Hirsti Director

Gunnar Hirsti has extensive experience from various managerial, executive and board positions in the oil and gas industry as well as the information technology industry in Norway.

Mr. Hirsti was Chief Executive Officer of DSND Subsea ASA (now Subsea 7 S.A.) for a period of six years. He also served as Executive Chairman of the Board of Blom ASA for eight years. Mr. Hirsti holds a degree in drilling engineering from Tønsberg Maritime Høyskole in Norway. He was elected to the Company's Board of Directors in 2007 and is a member of the audit and remuneration committees.

Shelley Watson

Director

Shelley Watson began her career as a reservoir surveillance and facilities engineer with Esso Australia in its offshore Bass Strait operation.

Ms. Watson has held management positions with Novus Petroleum, Indago Petroleum and RAK Petroleum PCL where she served as General Manager until 2014. She was appointed as Chief Operating Officer of RAK Petroleum plc in February 2017 and Chief Financial Officer in May 2017. Ms. Watson holds a First Class Honours degree in chemical engineering and a Bachelor of Commerce degree from the University of Melbourne. She has served on the Company's Board of Directors since 2010 and is a member of the audit committee.

Board of Directors' report

Introduction

2019 full-year results highlights

• Gross operated production in 2019 of 126,985 boepd, up from 117,607 boepd in 2018;
• Gross production at the Tawke license in Kurdistan, containing the Tawke and Peshkabir fields averaged 123,940 bopd;
• CWI production of 104,767² , up from 81,712 boepd in 2018;
• Revenues of USD 971 million in 2019, up from USD 829 million in 2018;
• Kurdistan revenues totaled USD 717 million and North Sea revenues totaled USD 254 million;
• Operating profit of USD 76 million in 2019, down from USD 377 million in 2018;
• Operational spend of USD 606 million, up from USD 262 million in 2018 (net of exploration tax refund);
• Yearend cash balance of USD 486 million, down from USD 729 million at yearend 2018; and
• CWI 2P reserves of 345 million barrels of oil equivalent (MMboe), compared to 376 MMboe at yearend 2018.

For a detailed financial review, see section on financial performance.

Our vision and strategic priorities

DNO's vision is to be a leading independent exploration and production (E&P) company with a focus on the Middle East and the North Sea, with the aim of delivering attractive returns to shareholders by finding and producing oil and gas at low cost and at an acceptable level of risk. DNO's strategic priorities to deliver sustainable growth in a responsible manner are:

• Increasing production through the development of our existing reserves base;
• Creating reserves and contingent resource growth through focused exploration and appraisal drilling;
• Maintaining operational control, financial flexibility and the efficient allocation of capital in line with DNO's full-cycle business model to deliver growth at a low unit cost;
• Encouraging an entrepreneurial culture and attracting the best talent in the industry;
• Pursuing materially accretive acquisitions;
• Recognizing our corporate commitments and managing risks to the business; and
• Being a safety leader in our areas of operation.

Production strength and capacity

DNO reported gross operated production in 2019 of 126,985 boepd, up from 117,607 boepd in 2018. DNO's CWI production stood at 104,767 boepd in 2019, up from 81,712 boepd in 2018.

With CWI 2P reserves totaling 345 MMboe across its portfolio, DNO has the asset base to sustain long-term production growth.

Organic reserves and resource growth

Done in a structured manner, successful exploration can be one of the most cost-efficient methods of delivering significant

reserves growth and associated value creation. At DNO, we focus our efforts on areas where we have in-depth knowledge of the subsurface, playing to our technical and operational strengths as a fractured carbonate specialist. We also benchmark each prospect so that capital deployed to exploration is only allocated to those opportunities that meet our technical, financial and strategic requirements. Looking ahead, we will continue to actively pursue opportunities in high potential basins across the Middle East and the North Sea, with the goal of transforming resources into reserves at a low unit cost.

Operational control and financial flexibility

We operate a significant number of our oil and gas assets and have the necessary operational and financial management processes in place to efficiently deliver our work programs. To maintain the financial strength and flexibility to fund growth opportunities, we will look to internally generated funds and, when necessary, capital market transactions to strengthen the Company's balance sheet.

During 2019, DNO had an average lifting cost of USD 5.4 per boe.

Encouraging an entrepreneurial culture

DNO's growth and success revolve around the quality and commitment of our people. We are an entrepreneurial company with a flat organizational structure which means we can make decisions quickly and execute flexibly. Our employment practices and policies help our staff realize their full potential. We are committed to developing local talent in each of our operating areas.

Mergers and acquisitions

In addition to organic growth, we continuously evaluate new assets and take an opportunistic approach to potential acquisitions.

Corporate governance and managing risk

One of our priorities is to ensure that DNO is a responsible and transparent enterprise. We are committed to the highest standards of corporate governance and business conduct. Recognizing that the success of an oil and gas company is directly linked to how well risks are managed, we seek to improve our systems designed to identify and manage risks effectively. We are also committed to the health, safety and security of our employees, contractors and the communities in which we operate, as well as to responsible environmental practices. Please refer to the Corporate Social Responsibility Highlights 2019 and Country-by-Country Report 2019 for more information on activities in the areas in which we operate. Both reports are available on the Company's website.

² Includes production from the assets added through the swap agreement with Equinor Energy AS effective from 1 January 2019, see Note 25 for details.

Operations review

Annual Statement of Reserves and Resources

The Company's Annual Statement of Reserves and Resources (ASRR) has been prepared in accordance with the Oslo Stock Exchange listing and disclosure requirements Circular No. 1/2013. International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license in the Kurdistan region of Iraq (Kurdistan) containing the Tawke and Peshkabir fields. International petroleum consultants Gaffney, Cline & Associates (GCA) carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). DNO internally assessed the remaining licenses.

At yearend 2019, DNO's CWI 1P reserves stood at 205.6 MMboe, compared to 239.7 million barrels of oil (MMbbls) at yearend 2018, after adjusting for production during the year and technical revisions, offset partly by reserves added through the acquisition of Faroe Petroleum plc in 2019. On a 2P reserves basis, DNO's CWI reserves stood at 344.8 MMboe, compared to 376.1 MMboe at yearend 2018. On a 3P reserves basis, DNO's CWI reserves were 539.9 MMboe, compared to 538.9 MMbbls at yearend 2018. DNO's CWI 2C resources were 187.8 MMboe, compared to 76.8 MMboe at yearend 2018.

DNO's 2019 CWI production increased to 38.2 MMboe (of which 31.9 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in the UK), compared to 29.9 MMboe in 2018 (of which 29.1 MMbbls in Kurdistan and the balance in Oman).

DNO's yearend 2019 Reserve Life Index (R/P) stood at 5.4 years on a 1P reserves basis, 9.0 years on a 2P reserves basis and 14.1 years on a 3P reserves basis.

The ASRR report for 2019 is available on the Company's website.

Kurdistan

Tawke license

Gross production at the Tawke license, containing the Tawke and Peshkabir fields, averaged 123,940 bopd during 2019.

DNO delivered an active drilling campaign in 2019 at the Tawke and Peshkabir fields, where 18 wells were spud. Tawke field production averaged 68,749 bopd with the wells drilled in 2019 contributing 13 percent at yearend. Peshkabir field production averaged 55,191 bopd with the wells drilled in 2019 contributing 40 percent at yearend.

Engineering and construction work on the Peshkabir-to-Tawke gas injection project advanced during 2019. When commissioned in spring 2020, this project is expected to increase oil recovery rates and unlock additional volumes at the Tawke field while eliminating flaring at the Peshkabir field. The Peshkabir-to-Tawke gas injection project marks the first Enhanced Oil Recovery (EOR) project in Kurdistan.

DNO holds a 75 percent operated interest in the Tawke and Peshkabir fields with partner Genel Energy plc (25 percent).

Erbil license

At the Benanan field, a workover operation to suspend the Hawler-1A well was completed in the fourth quarter of 2019. DNO holds a 40 percent operated interest in the Erbil license with partner Gas Plus Erbil (40 percent) and the Kurdistan Regional Government (KRG) (20 percent).

The Company notified the KRG in early 2020 of its plan to relinquish operatorship and participation in the Erbil license, effective 21 May 2020.

Baeshiqa license

The Baeshiqa license contains two large structures with multiple independent stacked target reservoirs, including in the Cretaceous, Jurassic and Triassic formations.

In February 2019, DNO spud the Baeshiqa-2 exploration well to test the Jurassic and Triassic reservoirs at the Baeshiqa structure. In November 2019, the Company reported a discovery after flowing variable rates of light oil and sour gas to surface from the upper part of the Triassic Kurra Chine B reservoir. Following workover and acid stimulation in early 2020, testing operations have resumed.

The Baeshiqa-1 exploration well, spud in October 2018 and targeting the shallow Cretaceous reservoirs, was drilled to a depth of 1,511 meters and has been suspended pending completion of testing of the adjacent Baeshiqa-2 well.

Site construction is ongoing for a third exploration well (Zartik-1) to be spud in spring 2020 targeting the Jurassic and Triassic formations on the second structure.

DNO holds a 32 percent operated interest in the Baeshiqa license with partners ExxonMobil (32 percent), Turkish Energy Company (16 percent) and the KRG (20 percent).

RESERVES

On a CWI basis at yearend 2019, 1P reserves in DNO's Kurdistan portfolio totaled 156.9 MMbbls (239.7 MMbbls at yearend 2018), 2P reserves totaled 274.7 MMbbls (376.1 MMbbls at yearend 2018) and 3P reserves totaled 437.9 MMbbls (538.9 MMbbls at yearend 2018). The CWI 2C resources were 33.5 MMbbls, compared to 55.8 MMbbls at yearend 2018.

At the Tawke license, yearend 2019 gross 1P reserves stood at 227.6 MMbbls (156.9 MMbbls on a CWI basis), compared to 348.0 MMbbls (239.7 MMbbls on a CWI basis) at yearend 2018. At yearend 2019 gross 2P reserves stood at 400.0 MMbbls (274.7 MMbbls on a CWI basis), compared to 501.9 MMbbls (344.3 MMbbls on a CWI basis) at yearend 2018. At yearend 2019 gross 3P reserves stood at 640.7 MMbbls (437.9 MMbbls on a CWI basis), compared to 696.8 MMbbls (476.6 MMbbls on a CWI basis) at yearend 2018.

Reserves and contingent resources at the Erbil license were written down to zero at yearend 2019 given DNO's plans to relinquish the license.

No reserves or 2C resources were recorded for the Baeshiqa license at yearend 2019, pending conclusion of ongoing testing activities in the license.

North Sea

DNO has diversified production with the addition of nine fields in Norway and four fields in the UK. During 2019, CWI production averaged 16,478 boepd in Norway and 891 boepd in the UK.

In 2019, 17 North Sea wells were spud, including 10 exploration and appraisal wells and six production and injection wells in Norway and one exploration well in the UK.

At yearend 2019, DNO held interests in 102 licenses across its North Sea portfolio, of which 23 were operatorships. DNO held interests in 87 licenses in Norway (22 operatorships), 12 licenses in the UK (one operatorship), two licenses in the Netherlands and one in Ireland.

The Company announced in January 2020 that its whollyowned subsidiary DNO Norge AS had been awarded participation in 10 additional exploration licenses in Norway, of which two are operatorships, under Norway's Awards in Predefined Areas (APA) 2019 licensing round.

RESERVES

On a CWI basis at yearend 2019, 1P reserves in DNO's Norway licenses totaled 47.5 MMboe, 2P reserves totaled 68.3 MMboe and 3P reserves totaled 99.5 MMboe. No reserves were recorded in Norway at yearend 2018. The CWI 2C resources were 138.9 MMboe at yearend 2019, up from 7.6 MMboe at yearend 2018.

On a CWI basis at yearend 2019, 1P reserves in DNO's UK licenses totaled 1.2 MMboe, 2P reserves totaled 1.8 MMboe and 3P reserves totaled 2.6 MMboe. No reserves were recorded in the UK at yearend 2018. The CWI 2C resources were 10.5 MMboe at yearend 2019, compared to 8.5 MMbbls at yearend 2018.

Yemen

Operations in Yemen (Block 47) are currently under force majeure and suspended.

Business development

In 2017, DNO re-entered the North Sea by acquiring Origo Exploration Holding AS (Origo), which was subsequently renamed DNO Norge AS. DNO's portfolio has since expanded through a combination of licensing rounds, license swaps and acquisitions.

Notably, in early 2019 DNO completed the USD 780 million acquisition of Faroe Petroleum plc (Faroe), a London-listed oil and gas company with a primary focus on exploration, development and production in Norway and the UK.

The acquisition of Faroe transformed DNO into a more diversified company with a strong, second leg. Through the transaction, DNO picked up attractive exploration, production and development projects and an experienced North Sea oil and gas team.

An assets swap agreement with Equinor Energy AS (Equinor Assets Swap) was completed on 30 April 2019 following approval by Norwegian authorities. The transaction had an effective date of 1 January 2019. As part of the transaction, DNO's interests in the non-producing Njord and Hyme redevelopment and Bauge development assets were exchanged, on a cashless basis, for interests in four Equinorheld producing assets (the Alve, Marulk, Ringhorne East and Vilje fields).

DNO continues to develop a pipeline of new business opportunities with a focus on its focus in the Middle East and the North Sea. It is actively pursuing growth across the E&P lifecycle, including exploration, development and production, both organically as well as through opportunistic acquisitions.

Financial performance

Revenues, operating profit and cash

Total revenues in 2019 stood at USD 971.4 million, up from USD 829.3 million in 2018. The 2019 revenues were driven by the addition of the new North Sea assets and increased Kurdistan production but partially offset by a one-off increase in 2018 revenues from an accounting change in Kurdistan revenue recognition. Kurdistan revenues stood at USD 717.1 million (USD 811.3 million in 2018), North Sea revenues at USD 253.5 million and Oman revenues at USD 0.8 million (USD 18.0 million 2018). Effective 1 October 2018, Kurdistan revenue recognition changed from a cash basis to an accrual basis, resulting in the one-off booking of an additional USD 182.8 million in 2018 revenues.

The Group reported an operating profit of USD 75.6 million in 2019, down from USD 376.8 million during 2018. The operating profit in 2019 was impacted by higher expensed exploration and impairments relative to 2018. In addition, the operating profit in 2018 reflected the one-off increase from the accounting change in Kurdistan revenue recognition described above.

The Group ended the year with USD 485.7 million in cash and an additional USD 144.5 million in market value of treasury shares and financial investments, compared to USD 729.1 million and USD 281.3 million at yearend 2018, respectively.

Total cash flow from operating activities for the year was USD 385.3 million, compared to USD 472.0 million in 2018. The decrease in cash flow from operating activities compared to 2018 was primarily due to two delayed Kurdistan export payments totaling USD 107.1 million which were received in the beginning of 2020. The difference between the cash from operating activities and the operating profit mainly concerns depreciation, depletion and amortization (DD&A) and impairments.

Cost of goods sold

In 2019, the total cost of goods sold was USD 541.4 million, compared to USD 350.6 million in 2018. The 2019 cost of goods sold increased primarily due to the addition of the new North Sea assets and increased Kurdistan activities, partly offset by lower DD&A due to a change in reserves basis used in the calculation of DD&A for Kurdistan assets.

Lifting costs in 2019 totaled USD 199.1 million, compared to USD 90.4 million in 2018. Lifting costs per barrel in Kurdistan stood at USD 3.3 in 2019 (USD 2.8 per barrel in 2018). Lifting costs per boe in the North Sea stood at USD 17.7 in 2019. DNO did not have any production in the North Sea in 2018.

DD&A costs increased to USD 311.8 million in 2019 from USD 260.1 million a year earlier.

Impairment charges

The Group's total impairment charges stood at USD 162.0 million in 2019, compared to USD 1.9 million in 2018. The 2019 impairments were mainly related to the impairment of technical goodwill for the North Sea assets.

Exploration costs expensed

Total expensed exploration costs increased to USD 146.4 million in 2019, from USD 64.7 million in 2018. The increase in expensed exploration costs was driven primarily by higher exploration activity in the North Sea.

Acquisition and development costs

Total acquisition and development costs stood at USD 407.9 million in 2019, compared to USD 138.0 million in 2018. The 2019 acquisition and development costs increased primarily due to the addition of the new North Sea assets and higher investments in the Tawke and Baeshiqa licenses.

Assets, liabilities and equity

At yearend 2019, total assets stood at USD 3,271.9 million, compared to USD 2,004.3 million at yearend 2018. The increase in total assets was due to the recognition of acquired assets through the Faroe transaction. Total property, plant and equipment (PP&E), intangible assets and goodwill increased from USD 791.0 million at yearend 2018 to USD 2,030.0 million at yearend 2019.

Total liabilities increased from USD 786.5 million at yearend 2018 to USD 2,110.5 million at yearend 2019 primarily due to the recognition of assumed liabilities from the Faroe transaction and issuance of new bond loans. The equity ratio stood at 35.5 percent at yearend 2019 (60.8 percent at yearend 2018).

Going concern

The Company's Board of Directors finds that the assumptions for future and continued operations have not changed. Consequently, these financial statements are based on the going concern assumption in accordance with sections 3–3a of the Norwegian Accounting Act.

Corporate governance

DNO's corporate governance policy is based on the recommendations of the Norwegian Code of Practice for Corporate Governance.

The Articles of Association and the Norwegian Public Limited Liability Companies Act form the corporate legal framework for DNO's business activities. In addition, DNO is subject to, and complies with, the requirements of Norwegian securities legislation.

The Group regularly reports on its strategy and the status of its business activities through annual reports, half-year and fullyear results and other market presentations and releases.

Equity and dividends

SHAREHOLDERS' EQUITY

It is DNO's policy to maintain a strong credit profile and robust capital ratios. We therefore monitor capital on the basis of our equity ratio, with a policy that this ratio should be 30 percent or higher. As of 31 December 2019, this ratio was 35.5 percent. The Board of Directors considers this figure to be satisfactory given the Group's business objectives, strategy and risk profile.

DIVIDEND POLICY

The Board of Directors assesses on an annual basis whether dividend payments should be proposed for approval at the Annual General Meeting (AGM). Assessment is based on planned capital expenditure, cash flow projections and DNO's objective of maintaining a strong credit profile and robust capital ratios.

In August 2018, the Company announced plans for its first dividend distribution to shareholders in 13 years. In September 2018, the Company held an Extraordinary General Meeting (EGM) at which 99.9 percent of the votes cast approved the

resolution to distribute a dividend of NOK 0.20 per share to all shareholders holding shares as of 13 September 2018. By the same margin, shareholders also authorized the Board of Directors to approve an additional dividend payment of NOK 0.20 per share in the first half of 2019. In February 2019, the Company's Board of Directors approved a dividend payment of NOK 0.20 per share to be made on or about 27 March 2019 to all shareholders of record as of 18 March 2019. At the 2019 AGM, 99.9 percent of the votes cast approved the resolution to authorize the Board of Directors to approve a dividend distribution of NOK 0.20 per share in the second half of 2019 and a distribution of dividend of NOK 0.20 per share in the first half of 2020. In October 2019, the Company's Board of Directors approved a dividend payment of NOK 0.20 per share which was made on 4 November 2019 to all shareholders of record as of 28 October 2019.

AUTHORIZATIONS TO THE BOARD OF DIRECTORS

At the 2019 AGM, the Board of Directors was given the authority to buy treasury shares with a total nominal value of up to NOK 27,095,354. The maximum amount to be paid per share is NOK 100 and the minimum amount is NOK 1. Purchases of treasury shares are made on the Oslo Stock Exchange. The authorization is valid until the AGM in 2020, but not beyond 30 June 2020. As of 31 December 2019, DNO held 93,700,000 treasury shares.

The Board of Directors was further given the authority to increase the Company's share capital by up to NOK 40,643,031 which corresponds to 162,572,124 new shares. The authorization is valid until the AGM in 2020, but not beyond 30 June 2020.

Equal treatment of shareholders and transactions with close associates

The Company has one class of shares and each share represents one vote at the AGM. We are committed to treating all shareholders equally.

All transactions between the Company and related parties shall be on arm's length terms. Members of the Board of Directors and executive management are required to notify the board if they have any direct or indirect material interest in any transaction entered into by the Company.

For more information about related party transactions, see Note 21 in the consolidated accounts.

Freely negotiable shares

The Company's shares are listed on the Oslo Stock Exchange and are freely negotiable.

General meetings

The AGM, held by the end of June each year, is the highest authority of the Company. The minutes of the meetings are available on the Company's website.

AGMs are convened by written notice to all shareholders with a known address and published on the Company's website together with all appendices, including the recommendations of the nomination committee. The notice is sent and published no later than 21 days prior to the date of the meeting. Any person who is a shareholder at the time of the AGM can attend and vote, provided that they have been registered as a shareholder no later than the fifth working day before the meeting.

Shareholders unable to attend a general meeting may vote through a proxy.

In accordance with the Norwegian Public Limited Liability Companies Act, the auditor of DNO, or a shareholder representing at least five percent of the share capital, may request an extraordinary general meeting to deal with specific matters. The Board of Directors must ensure that the meeting is held within one month after the request has been submitted.

Board of Directors' composition and independence

The Company's Articles of Association require that the Board of Directors consists of three to seven members. All members, including the Executive Chairman, are elected by the AGM for a period of two years.

As of 31 December 2019, the Board of Directors consisted of five members, all of whom have relevant and broad experience. Three members are independent of the Company's main shareholders. There are two women on the board. The majority of the members are independent of the Company's executive management and material business contacts.

The members' shareholdings are specified in the notes to the consolidated accounts.

The Board of Directors' work

The role of the Board of Directors is to supervise the Company's executive management and strategic development in accordance with the long-term interests of its shareholders and other stakeholders.

The Board of Directors is subject to a set of procedural rules that, among other things, defines its responsibilities and the matters to be discussed at board level. The Board of Directors also regularly establishes work directives for the Managing Director.

The Board of Directors' committees

AUDIT COMMITTEE

The audit committee consists of three members: Mr. Gunnar Hirsti (chair), Ms. Shelley Watson and Ms. Elin Karfjell. Its mandate includes ensuring the quality and accuracy of the Company's financial reporting. The committee is also responsible for monitoring internal control and risk evaluation systems.

HSSE COMMITTEE

The HSSE committee is chaired by Mr. Lars Arne Takla. Its mandate is to review the Company's management of operational risks and HSSE performance.

REMUNERATION COMMITTEE

The remuneration committee consists of two members: Mr. Bijan Mossavar-Rahmani and Mr. Gunnar Hirsti. Its mandate is to consider matters relating to the compensation of executive management.

NOMINATION COMMITTEE

The Company's nomination committee consists of Mr. Bijan Mossavar-Rahmani and two external members, Ms. Anita Marie Hjerkinn Aarnæs and Mr. Kåre Tjønneland. Its mandate is to propose candidates for the Board of Directors and its various committees to the AGM. It also proposes the level of remuneration for the Board of Directors.

REMUNERATION OF DIRECTORS

The remuneration of the Board of Directors and its committees is decided by the AGM based on a recommendation from the nomination committee. Fees reflect the Board of Directors' responsibility, competence, workload and the complexity of the business and are determined separately for the Executive Chairman, the Deputy Chairman and other members. Additional fees are applied on a uniform basis for each director's participation in the committees.

Further information about the Board of Directors' remuneration is presented in the parent company accounts (see Note 3).

Remuneration of executive management

The remuneration of the Company's executive management, including the Managing Director, is subject to the evaluation and recommendation of the remuneration committee. The remuneration of the Company's Managing Director is evaluated annually and approved by the Board of Directors.

The remuneration of executive management is presented in the parent company financial statements (see Note 3).

The guidelines for remuneration of executive management are presented at the AGM in accordance with the provisions of the Norwegian Public Limited Liability Companies Act.

Responsibility for risk management and internal control

Risk management is integral to all of the Group's activities. Each member of executive management is responsible for continuously monitoring and managing risk within the relevant business areas. Every material decision is preceded by an evaluation of applicable business risks.

Reports on the Group's risk exposure and reviews of its risk management are regularly undertaken and presented to the executive management and the Board of Directors. The Company has an internal audit function that undertakes annual audits of the main business units and a compliance function whose role includes ensuring regulatory requirements and internal policies are followed.

Information and communication

Our policy is to provide material information to all shareholders in a timely manner.

DNO's consolidated financial statements are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) and additional disclosure requirements in the Norwegian Accounting Act. Interim reports and other relevant information are published on DNO's website and through the Oslo Stock Exchange.

We also publish an annual financial calendar setting out key dates and events, such as regular market presentations. The DNO investor relations' policy encourages open communication with capital markets and shareholders. In addition to scheduled half-year and full-year presentations, we also regularly hold presentations for investors and analysts.

Takeover

The Board of Directors has a responsibility to ensure that, in the event of a takeover bid, business activities are not disrupted unnecessarily. The Board of Directors also has a responsibility to ensure that shareholders have sufficient information and time to assess any such bid. Should a takeover situation arise, the Board of Directors would undertake an evaluation of the proposed bid terms and provide a recommendation to the shareholders as to whether or not to accept the proposal. The recommendation statement would clearly state whether the Board of Directors' evaluation is unanimous and the reasons for any dissent.

Auditor

DNO's external auditor is elected at the AGM, which also approves the auditor's fees for the parent company. The auditor annually presents an audit plan to the audit committee and participates in audit committee meetings to review the Group's internal control and risk management systems. The auditor also participates in board meetings when considered appropriate, with and without executive management present.

Information about the auditor's fees, including a breakdown of audit related fees and fees for other services, is included in the notes to the financial statements in accordance with the Norwegian Accounting Act.

DNO's external auditor is Ernst & Young AS.

Enterprise risk management

The objective of DNO's risk management is to identify potential exposures that may impact the Group and to manage identified risks within strict guidelines while pursuing our business objectives. We review our risk profile on a quarterly basis, incorporating industry-recognized risk identification and quantification processes. The Board of Directors and its committees also regularly monitor the Group's risk management systems and internal controls.

Financial risk

Risks related to oil and gas prices, interest rates and currency exchange rates, liquidity risk, concentration risk and credit risk constitute financial risks for the Group. In order to minimize any potentially adverse effects from such risks, financial risk is managed by the Group finance function under policies approved by the Board of Directors. For more information about how we manage financial risk, see Note 9 in the consolidated accounts.

Entitlement risk

DNO has interests in three licenses in Kurdistan through Production Sharing Contracts (PSCs) and has based its entitlement calculations on the terms of these PSCs. Although DNO has good title to its licenses, including the right to explore for and produce oil and gas from these licenses, the Federal Government of Iraq (FGI) has in the past challenged the validity of certain PSCs signed by the KRG.

Historically, as a result of disagreements between the FGI and the KRG, economic conditions in Kurdistan and limited available export channels, DNO has faced constraints in fully monetizing the oil it produces in Kurdistan. There is no guarantee that oil and gas can be exported in sufficient quantities or at prices required to sustain its operations and investment plans or that the Group will promptly receive its full entitlement payments for the oil and gas it delivers for export. Export sales have not always followed the PSC terms and there has been uncertainty related to both timing of revenue and receipt of payments.

Operational risk

DNO is exposed to operational risks across its portfolio. Operational risk applies to all stages of upstream operations, including exploration, development and production. Failure to manage operations efficiently can manifest itself in project delays, cost overruns, higher-than-estimated operating costs and lower-than-expected oil and gas production and/or reserves. Exploration activities are capital intensive and involve a high degree of geological risk. Sustained exploration failure can affect the future growth and upside potential of DNO.

Our ability to effectively manage and deliver value from our exploration, development and production activities is dependent on the quality of our staff and contractors. Inefficiency or interruption to our supply chain or the unwillingness of service contractors to engage in our areas of operation may also negatively affect operations.

The outbreak of the coronavirus (COVID-19) and the significant decline in oil prices in the first quarter of 2020 will have adverse effects on the Group's operations and financial results this year, but the extent and duration of these conditions over the longer term remain largely uncertain and dependent on future developments that cannot be accurately predicted at this time. Future oil price assumptions are key estimates in DNO's financial statements and a change in these assumptions may impact the recoverable amount of the Group's oil and gas assets, reserve and resource estimates, operational spend level and distribution of future dividends. Continuing low oil prices may also reduce the Group's revenues and increase the credit risk related to the Group's trade receivables.

DNO is closely monitoring the impact of the COVID-19 pandemic, including on border closures, travel restrictions and interruptions to supply chains and third-party services, among others, and will implement measures required to minimize the adverse impact on our staff, operations, liquidity and financial results.

Environmental risk

Oil and gas exploration and production, by its nature, involves exposure to potentially hazardous materials. The loss of containment of hydrocarbons or other dangerous substances could represent material risks. Through our operational controls, environmental impact assessments, asset integrity protocols and management systems related to health, safety and the environment, we aim to mitigate hazards with a potentially adverse impact on people, the environment, our assets, our profitability and our reputation.

Security risk

Although we operate in regions with security risks, we continuously work to manage these risks through clearly defined security protocols and practices. Nevertheless, we are often dependent on the quality of the security and protection provided by authorities in our host countries.

Compliance risk

DNO has a policy of zero tolerance for corruption, bribery and other illegal or inappropriate business conduct. Violations of compliance laws and contractual obligations can result in fines and a deterioration in the Group's ability to effectively execute its business plans. DNO adheres to a strict and comprehensive conflict of interest policy, trade sanctions and other policies focused around the Group's Code of Conduct to ensure regulatory and company expectations are met. A whistleblowing procedure is also in place.

Political risk

Our portfolio is located in some countries where political, social and economic instability may adversely impact our business. For example, the political and security situation in Yemen continued to deteriorate in 2019. In Kurdistan, we continue to closely monitor security conditions although our operations to date have seen minimal impact from regional developments.

Stakeholder risk

In order to operate effectively, it is necessary for the Company to maintain productive and proactive relationships with our stakeholders, host governments, business partners and the communities in which we operate. Failure to do so can result in difficulties in progressing initiatives as well as delays to ongoing operations.

HSSE performance

Our HSSE standards, procedures and protocols are based on the following principles:

• Avoid harm to all personnel involved in, or affected by, our operations;
• Minimize and where possible eliminate the impact of our operations on the environment;
• Comply with all applicable legal and regulatory requirements; and
• Achieve continuous improvement in HSSE performance.

During 2019:

• Only four Serious Vehicle Accidents took place despite distances driven of over four million kilometres. There were no recordable injuries as a result of these accidents;
• Total greenhouse gas emissions, including from operations in Kurdistan and the North Sea and from all DNO's offices and travel, stood at 639,200 tonnes of CO2 equivalent, up from 417,000 tonnes in 2018. The increase was largely due to flaring at the Peshkabir field which will be substantially reduced in 2020 through a USD 100 million project to capture Peshkabir gas and reinject it instead into the Tawke field for enhanced oil recovery;
• Spills/leaks stood at 30 in 2019, compared to five in 2018. The total volume spilled in 2019 was 65 barrels of oil compared to 35 barrels in 2018, all of which was removed and remediated at controlled sites; and
• Security incidents stood at one, down from four in 2018.

We continue to actively maintain the integrity of our facilities through structured maintenance programs and a focus on safety critical equipment and robust assurance of design.

There were zero Lost Time Injuries during the year, compared to two in 2018. Our Total Recordable Injury Frequency during 2019 was 0.9, compared to 1.0 in 2018.

We continue to work with our employees and third-party contractors on programs to improve safety performance with a focus in 2019 on safety leadership.

Sickness absence in 2019 was 2.0 percent, compared to 1.4 percent in 2018.

Organization and personnel

At yearend 2019, DNO had a workforce of 1,318 employees, of which 11 percent were women. A total of 76 individuals were based at the Company's headquarters in Oslo and 1,242 were engaged across our international operations, including in business unit offices in Stavanger, Dubai and London. Our workforce is characterized by strong cultural, religious and national diversity, with some 48 nationalities represented in Team DNO.

We strive to foster and maintain a culture built on trust, respect, teamwork, communication and commitment in a work environment free of discrimination.

Executive remuneration policy

The Board of Directors presents guidelines to the AGM regarding salary and other remuneration for the Managing Director and other executive management for the coming financial year in accordance with provisions of the Norwegian Public Limited Liability Companies Act, section 6-16 and section 5-6 third paragraph.

Remuneration policy for 2019

Any remuneration, bonuses or other incentive schemes must reflect the duties and responsibilities of the employees and add long-term value for shareholders.

Fixed remuneration

The Board of Directors has not set any upper or lower limit for the fixed salary of executive management for the coming year beyond the main principles set out above.

Variable remuneration

In addition to fixed salary, variable remuneration can be used to recruit, retain and reward employees. For executive management, such remuneration can include cash bonuses and share-based compensation. Annual bonuses, when awarded, are based on corporate results and/or individual performance. Other types of variable remuneration include newspaper, mobile phone and broadband communication subscriptions paid in accordance with established rates.

Pensions

DNO has a defined contribution scheme which meets the Norwegian legal requirements for mandatory occupational pensions.

Share-based incentive scheme

In addition to or in lieu of share-based compensation, the Board of Directors may implement a share-tracking incentive scheme utilising synthetic shares. The purpose of all such programs will be to: (i) align the interests of executive management and other employees with those of shareholders' interests, and (ii) reward value creation. The Board of Directors can decide whether to set allocation criteria, conditions or thresholds for the scheme.

Severance agreements

Severance payment agreements may be entered into selectively.

Binding sections

Remuneration as it relates to share-based incentive schemes is subject to a separate vote by the AGM and is binding once approved. Other sections of the remuneration policy are nonbinding guidelines for the Board of Directors and are therefore only subject to a consultative vote at the AGM.

Executive management

BJØRN DALE Managing Director

Mr. Dale joined DNO in 2011. Mr. Dale holds a Master of Law degree from the University of Oslo and an Executive MBA from the Stockholm School of Economics.

CHRIS SPENCER

Deputy Managing Director

Mr. Spencer joined DNO in 2017. Mr. Spencer previously served as CEO of Rocksource ASA and in various roles at Royal Dutch Shell and BP. Mr. Spencer is a Chartered Engineer with the Institution of Chemical Engineers in the United Kingdom.

HAAKON SANDBORG Chief Financial Officer

Mr. Sandborg joined DNO in 2001. In addition to his oil and gas experience, he has a background in banking, including positions at DNB Bank. Mr. Sandborg holds a Master of Business Administration from the Norwegian School of Business Administration.

UTE QUINN

Group General Counsel and Corporate Secretary

Ms. Quinn joined DNO in 2017. Ms. Quinn previously served as General Counsel of Sakhalin Energy and in various legal executive roles at Royal Dutch Shell and Hess Corporation. She holds a Bachelor of Arts from Vassar College and a law degree from Temple University School of Law.

NICHOLAS WHITELEY

Group Exploration and Subsurface Director

Dr. Whiteley joined DNO in 2015. Dr. Whiteley previously served as General Manager of Exploration of Cairn India. He started his career at BP and has a Master of Science degree in Earth Sciences from the University of Cambridge and a PhD from the University of Oxford.

ØRJAN GJERDE

Group Commercial Director

Mr. Gjerde joined DNO in 2017. Mr Gjerde previously served as CFO of Noreco and in management roles at various oil services companies. Mr. Gjerde is a state authorized public accountant and obtained his Master level degree in Accounting and Auditing from the Norwegian School of Economics.

TOM ALLAN

General Manager, Kurdistan Region of Iraq

Mr. Allan joined DNO in 2019. Mr. Allan previously served as COO of Oilserv and in various operational and managerial roles at Schlumberger. Mr. Allan holds a Bachelor of Science degree in Engineering from the Royal Military College of Canada.

RUNE MARTINSEN General Manager, DNO North Sea

Mr. Martinsen joined DNO in 2019. Mr. Martinsen previously served as Managing Director of Spirit Energy in Norway and the UK and in various leadership roles in Noreco and BP. Mr. Martinsen holds a Master of Science degree in Reservoir Engineering from University of Stavanger.

GEIR ARNE SKAU Human Resources Director

Mr. Skau joined DNO in 2019. Mr. Skau previously served in the Norwegian Armed Forces and in various human resources leadership roles at TechnipFMC. Mr. Skau was educated at the Norwegian Military Academy.

AERNOUT VAN DER GAAG Deputy Chief Financial Officer

Mr. Van der Gaag joined DNO in 2017. Mr. Van der Gaag previously served in various finance and business services roles at Talisman Energy and Royal Dutch Shell. Mr. Van der Gaag holds a Master of Business Economics from the University of Groningen.

TONJE PARELI GORMLEY General Counsel - Middle East

from the London Metropolitan University.

Ms. Gormley joined DNO in 2018 upon secondment as a partner from the law firm Arntzen de Besche and has since permanently joined DNO. Ms. Gormley holds a Master level degree in law from the University of Oslo and a diploma in law

Parent company

The parent company, DNO ASA, reported a net loss of USD 18.1 million in 2019, compared to a net profit of USD 428.2 million in 2018. Total assets as of 31 December 2019 were USD 1,473.4 million, up from USD 1,243.2 million at yearend 2018. Long-term intercompany receivables were USD 28.4 million as of 31 December 2019, compared to USD 56.1 million at yearend 2018. Long-term intercompany liabilities were USD 55.2 million as of 31 December 2019, up from USD 19.6 million at yearend 2018. The Company's cash balance at yearend 2019 was USD 389.0 million, down from USD 638.2 million at yearend 2018. Total shareholder equity at yearend 2019 was USD 477.1 million, down from USD 600.0 million in 2018.

The equity ratio was 32.4 percent (48.3 percent at yearend 2018). The Board of Directors will recommend that the shareholders approve the transfer of the net loss of USD 18.1 million from retained earnings at the forthcoming AGM.

Main events since yearend

On 14 January 2020, the Company announced that its whollyowned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which two are operatorships, under Norway's Awards in Predefined Areas (APA) 2019 licensing round. Of the 10 new licenses, five are in the North Sea, two in the Norwegian Sea and three in the Barents Sea.

On 28 February 2020, the Company announced that shareholders overwhelmingly approved the resolution to cancel all 108,381,415 own shares held by the Company at an Extraordinary General Meeting. The cancelled shares represented 10 percent of the Company's outstanding shares.

Responsibility statement

DNO ASA's consolidated financial statements for the period 1 January to 31 December 2019 have been prepared and presented in accordance with IFRS as adopted by the EU and additional disclosure requirements in the Norwegian Accounting Act. The separate financial statements for DNO ASA for the period 1 January to 31 December 2019 have been prepared in accordance with the Norwegian Accounting Act and Norwegian accounting standards. We confirm to the best of our knowledge that the consolidated and separate financial statements for the period 1 January to 31 December 2019 have been prepared in accordance with applicable accounting standards and give a fair view of the assets, liabilities, financial position and results for the period viewed in their entirety, and that the Board of Directors' report includes a fair review of any significant events that arose during the period and their effect on the financial statements, any significant related parties' transactions and a description of the significant risks and uncertainties to which the Group and the parent company are exposed.

Oslo, 17 March 2020

Bijan Mossavar-Rahmani Lars Arne Takla Shelley Watson Executive Chairman Deputy Chairman Director

Elin Karfjell Gunnar Hirsti Bjørn Dale Director Director Managing Director

Consolidated accounts

Consolidated statements of comprehensive income 20 Consolidated statements of financial position 21 Consolidated cash flow statement 22 Consolidated statements of changes in equity 23

Note disclosures

Note 1	Summary of IFRS accounting principles	24
Note 2	Segment information	35
Note 3	Revenues	37
Note 4	Cost of goods sold/Inventory	37
Note 5	Administrative/Other operating expenses	38
Note 6	Exploration expenses	40
Note 7	Financial income and financial expenses	40
Note 8	Income taxes	41
Note 9	Financial instruments	43
Note 10	Property, plant and equipment/Intangible assets	48
Note 11	Financial investments	53
Note 12	Trade and receivables	53
Note 13	Cash and cash equivalents	54
Note 14	Equity	54
Note 15	Interest-bearing liabilities	56
Note 16	Provisions for other liabilities and charges/Lease liabilities	57
Note 17	Commitments and contingencies	59
Note 18	Trade and other payables	60
Note 19	Earnings per share	60
Note 20	Group companies	61
Note 21	Related party disclosure	61
Note 22	Significant events after the reporting date	62
Note 23	Company Working Interest and net entitlement reserves (unaudited)	63
Note 24	Oil and gas license portfolio	65
Note 25	Business combinations	68

Parent company accounts

Income statement		71
Balance sheet		71
Cash flow statement		73
Note disclosures		74

Auditor's report 85

Annual Report and Accounts 2019 DNO 19

Board of Directors' report

Consolidated statements of comprehensive income

	1 January - 31 December
USD million	Note
		2019	2018
Revenues	2, 3	971.4	829.3
Cost of goods sold	4	-541.4	-350.6
Gross profit		430.0	478.7
Other income		-0.5	4.8
Administrative expenses	5	-26.1	-36.7
Other operating expenses	5	-19.3	-3.4
Impairment oil and gas assets	10	-162.0	-1.9
Exploration expenses	6	-146.4	-64.7
Profit/-loss from operating activities		75.6	376.8
Financial income	7	9.6	10.0
Financial expenses	7	-133.1	-64.3
Profit/-loss before income tax		-47.8	322.5
Tax income/-expense	8	121.3	31.8
Net profit/-loss		73.5	354.3
Other comprehensive income
Currency translation differences		-27.0	1.4
Items that may be reclassified to profit or loss in later periods		-27.0	1.4
Net fair value changes from financial instruments	11	25.8	12.1
Items that are not reclassified to profit or loss in later periods		25.8	12.1
Total other comprehensive income, net of tax		-1.2	13.5
Total comprehensive income, net of tax		72.3	367.7
Net profit/-loss attributable to:
Equity holders of the parent		73.5	354.3
Non-controlling interests		-	-
Total comprehensive income attributable to:
Equity holders of the parent		72.3	367.7
Non-controlling interests		-	-
Earnings per share, basic (USD per share)	19	0.07	0.34
Earnings per share, diluted (USD per share)	19	0.07	0.34
Weighted average number of shares outstanding (excluding treasury shares) (millions)		1,036.37	1,048.81

Consolidated statements of financial position

	Years ended 31 December
USD million Note
	2019	2018
ASSETS
Non-current assets
Goodwill 10	333.9	-
Deferred tax assets 8	63.7	7.0
Other intangible assets 10	346.6	32.8
Property, plant and equipment 10	1,349.5	758.1
Financial investments 11	21.0	230.8
Total non-current assets	2,114.7	1,028.8
Current assets
Inventories 4	28.2	8.3
Trade and other receivables 12	478.5	209.8
Tax receivables 8	164.8	28.3
Cash and cash equivalents 13	485.7	729.1
Total current assets	1,157.2	975.5
TOTAL ASSETS	3,271.9	2,004.3
EQUITY AND LIABILITIES
Equity
Share capital 14	33.3	35.0
Other reserves 14	181.0	239.6
Retained earnings	947.0	943.2
Total equity	1,161.3	1,217.8
Non-current liabilities
Deferred tax liabilities 8	217.6	-
Interest-bearing liabilities 15	836.0	575.7
Lease liabilities 16	11.1	-
Provisions for other liabilities and charges 16	422.8	68.1
Total non-current liabilities	1,487.5	643.8
Current liabilities
Trade and other payables 18	288.9	116.4
Income taxes payable 8	0.2	0.5
Current interest-bearing liabilities 15	225.6	18.4
Current lease liabilities 16	3.3	-
Provisions for other liabilities and charges 16	105.1	7.4
Total current liabilities	623.0	142.7
Total liabilities	2,110.5	786.5
TOTAL EQUITY AND LIABILITIES	3,271.9	2,004.3

Oslo, 17 March 2020

Bijan Mossavar-Rahmani Lars Arne Takla Shelley Watson Executive Chairman Deputy Chairman Director

Elin Karfjell Gunnar Hirsti Bjørn Dale

Director Director Managing Director

Consolidated cash flow statement

	1 January - 31 December
USD million	Note
		2019	2018
Operating activities
Profit/-loss before income tax		-47.8	322.5
Adjustments to add/-deduct non-cash items:
Exploration cost capitalized in previous years carried to cost	6	27.8	-
Depreciation, depletion and amortization	4	311.8	260.1
Impairment oil and gas assets	10	162.0	1.9
Other*		6.7	50.2
Changes in working capital items and provisions:
- Inventories		-2.0	-2.4
- Trade and other receivables		-147.4	-181.7
- Trade and other payables		-18.1	16.8
- Provisions for other liabilities and charges		92.5	4.7
Cash generated from operations		385.3	472.0
Tax refund received		56.9	33.2
Interest received		7.6	9.7
Interest paid		-78.2	-43.9
Net cash from/-used in operating activities		371.5	471.1
Investing activities
Purchases of intangible assets		-68.5	-7.8
Purchases of tangible assets		-339.4	-130.3
Payments for decommissioning		-22.6	-
Acquisition of Faroe Petroleum plc net of cash acquired**		-428.7	-
Proceeds from license transactions		29.6	-
Proceeds from sale of financial investments		6.6	-
Acquisition of financial investments	11	-	-201.3
Net cash from/-used in investing activities		-823.0	-339.4
Financing activities
Proceeds from borrowings net of issue costs	15	537.9	223.9
Repayment of borrowings	15	-197.6	-31.0
Purchase of treasury shares	14	-82.3	-
Paid dividend	14	-46.6	-25.8
Payments of lease liabilities		-3.2	-
Net cash from/-used in financing activities		208.3	167.1
Net increase/-decrease in cash and cash equivalents		-243.2	298.8
Cash and cash equivalents at beginning of the period		729.1	430.2
Cash and cash equivalents at end of the period	13	485.7	729.1
Of which restricted cash	13	14.3	3.2
Of which held on restricted account in relation to the Faroe Petroleum plc offer	13	-	418.1

* Includes interest income, interest expense and amortization of borrowing issue costs.

** The amount consists of USD 583.0 million paid during 2019 for the acquisition of the remaining Faroe shares less cash acquired of USD 154.5 million, see Note 25.

Consolidated statements of changes in equity

USD million	Note	Share capital	Other reserves	Retained earnings	Total equity
Total equity as of 1 January 2018		35.0	262.7	578.2	875.9
Fair value changes from equity instruments*		-	-	12.1	12.1
Currency translation differences		-	2.6	-1.2	1.4
Other comprehensive income		-	2.6	10.8	13.5
Profit/-loss for the period		-	-	354.3	354.3
Total comprehensive income		-	2.6	365.1	367.7
Payment of dividend		-	-25.8	-	-25.8
Transactions with shareholders		-	-25.8	-	-25.8
Total equity as of 31 December 2018	14	35.0	239.6	943.2	1,217.8

USD million	Note	Share capital	Other reserves	Retained earnings	Total equity
Total equity as of 1 January 2019		35.0	239.6	943.2	1,217.8
Fair value changes from equity instruments*		-	-	25.8	25.8
Currency translation differences		-	-3.7	-23.4	-27.0
Other comprehensive income		-	-3.7	2.4	-1.2
Profit/-loss for the period		-	-	73.5	73.5
Total comprehensive income		-	-3.7	75.9	72.3
Purchase of treasury shares		-1.6	-80.7	-	-82.3
Payment of dividend		-	-46.6	-	-46.6
Transfers		-	72.4	-72.4	-
Transactions with shareholders		-1.6	-54.9	-72.4	-129.0
Total equity as of 31 December 2019	14	33.3	181.0	947.0	1,161.3

* See Note 11 for details regarding fair value changes from equity instruments.

Note 1

Summary of IFRS accounting principles

Principal activities and corporate information

The principal activities of the Group are international oil and gas exploration, development and production.

DNO ASA is a Norwegian public limited liability company organized and existing under the laws of Norway pursuant to the Norwegian Public Limited Liability Companies Act ("allmennaksjeloven"). The Company was incorporated on 6 August 1971 and its registration number in the Norwegian Register of Business Enterprises is 921 526 121. The shares in the Company have been listed on the Oslo Stock Exchange since 1981, currently under the ticker "DNO". The Company's registered office is located at Dokkveien 1, 0250 Oslo, Norway. DNO's activities are mainly undertaken in the Middle East and the North Sea. DNO is included in the consolidated accounts of RAK Petroleum plc (RAK Petroleum).

Statement of compliance

The consolidated financial statements of DNO ASA have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) and additional disclosure requirements in the Norwegian Accounting Act, effective as of 31 December 2019. The consolidated financial statements were approved by the Board of Directors on 17 March 2020.

Basis for preparation

The consolidated financial statements have been prepared on a historical cost basis, with the following exemptions: liabilities related to share-based payments and investments in equity instruments classified as financial investments at fair value through other comprehensive income are recognized at fair value. As permitted by International Accounting Standard (IAS) 1 Presentation of Financial Statements and in conformity with industry practice, the expenses in the consolidated statements of comprehensive income are presented as a combination of nature and function as this gives the most relevant and reliable presentation for the Group. The consolidated financial statements have been prepared based on a going concern assumption.

Due to rounding, the figures in one or more rows or columns included in the financial statements and notes may not add up to the subtotals or totals of that row or column.

Significant accounting estimates and assumptions

The preparation of the Group's financial statements requires management to make judgments, estimates and assumptions that affect the reported amounts of revenues and expenses, assets and liabilities, and the accompanying disclosures, and the disclosure of contingent liabilities at the reporting date. Estimates and assumptions are based on management's best knowledge and historical experience and various other factors that are believed to be reasonable under the circumstances. Uncertainty about these estimates and assumptions could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.

The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a

significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are described below. The Group based its assumptions and estimates on parameters available when the Group financial statements were prepared. However, existing circumstances and assumptions about future developments may change due to market changes or circumstances arising beyond the control of the Group. Such changes are reflected in the assumptions when they occur.

Estimates and assumptions

The key assumptions and key sources of estimation uncertainty for the Group are:

• Risks associated with operating in Kurdistan;
• Reserves and resources estimates;
• Contingencies, provisions and litigations;
• Impairment/reversal of impairment of oil and gas assets;
• Impairment of technical goodwill;
• Measurement of fair values;
• Acquisition accounting;
• Accounting for exploration costs; and
• Notional corporate income tax/deferred taxation in Kurdistan.

Risks associated with operating in Kurdistan

As a result of the historical and legal position of Kurdistan, and the relationships of the Kurdistan Regional Government (KRG) with the Federal Government of Iraq (FGI). DNO and other international oil companies operating in Kurdistan face a number of risks specific to the region.

Most notably, the Tawke Production Sharing Contract (PSC) was entered into with the KRG prior to the adoption of the Iraqi Constitution and the fields were not producing at the time of adoption. A successful attempt by the FGI to revoke or materially alter all PSCs in Kurdistan, including those held by DNO, could disrupt or halt DNO's operations, subject DNO to contractual damages or prevent the execution of DNO's strategy, any of which could have a material adverse effect on the Group's business, results of operations, financial position and prospects.

Export sales have not always followed the PSC terms and there has been uncertainty related to both timing of revenue and receipt of payments.

Reserves and resources estimate

DNO's reserves and contingent resources are estimated and classified by the Company in accordance with the rules and guidelines of the Society of Petroleum Engineers (SPE) and are in conformity with requirements from the Oslo Stock Exchange for the reporting of reserves and resources.

All estimates of reserves and resources involve uncertainty. The Group's estimates are based on internal assessment where DNO is the operator in a license and based on information received from the operators where DNO is partner in a license. International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license, containing the Tawke and Peshkabir fields. International petroleum consultants Gaffney, Cline & Associates (GCA) carried

out an independent assessment of DNO's licenses in the North Sea.

Figures reported in Note 23 are the estimated proven (1P), proven and probable (2P) and proven, probable and possible (3P) quantities of oil and gas that will be recovered from a field or reservoir given the information available at yearend.

Important factors that could cause actual results to differ from the estimates include, but are not limited to: technical, geological and geotechnical conditions; economic and market conditions; oil and gas prices; changes in government regulations; interest rates; and currency exchange rates. Specific parameters of uncertainty related to the field/reservoir include, but are not limited to: reservoir pressure and porosity; recovery factors; water cut development; production decline rates; gas/oil ratios; and oil properties.

Changes in commodity prices and costs may impact economic cut-off and remaining reserves, which may change the timing of assumed decommissioning activities. Future changes to estimated reserves can also have a material effect on depreciation, impairment of oil and gas fields and operating results. The Group may also not be able to commercially develop its contingent resources that are used in impairment assessments or acquisition accounting where the fair value approach is applied.

Contingencies, provisions and litigations

By their nature, contingencies will only be resolved when one or more uncertain future event occurs or fails to occur. The assessment of the existence and potential quantum of contingencies inherently involves the exercise of significant judgment and the use of estimates regarding the outcome of future events. Management uses its judgment to evaluate certain provisions and legal disputes in order to ensure the correct accounting treatment. This includes the assessment of future asset retirement obligations (ARO), any provisions or contingent payments.

Asset retirement obligations

The Group has recognized significant provisions relating to the decommissioning of oil and gas assets at the end of the production period. Obligations associated with decommissioning assets are recognized at present value of future expenditures on the date they incur. At the initial recognition of an obligation, the estimated cost is capitalized as property, plant and equipment (PP&E) and depreciated over the useful life of the asset (typically by unit-of-production).

It is difficult to estimate the costs for decommissioning at initial recognition as these estimates are based on currently applicable laws and regulations and are dependent on technological developments. Decommissioning activities will normally take place in the distant future, and the technology and related costs are constantly changing. The estimates cover expected removal concepts based on known technology and, in the case of offshore decommissioning, estimated costs of maritime operations, hiring of heavy-lift barges and drilling rigs. As a result, the initial recognition of the liability and the capitalized cost associated with decommissioning obligations, and the subsequent adjustment of

these balance sheet items, involve the application of significant judgement. Based on the described uncertainty, there may be significant adjustments in estimates of liabilities that can affect future financial results.

Impairment/reversal of impairment of oil and gas assets

DNO has recognized significant investments in development and production assets (classified under PP&E) and exploration and evaluation assets (classified under intangible assets) in the consolidated statements of financial position. Changes in the circumstances or expectations of future performance of an individual asset or a group of assets may be an indicator that the asset is impaired, requiring the carrying amount to be written down to its recoverable amount. Management must determine whether there are circumstances indicating a possible impairment of the Group's oil and gas assets. The estimation of the recoverable amount for the oil and gas assets includes assessments of expected future cash flows and future market conditions, including entitlement production, future oil and gas prices, cost profiles, country risk factors (i.e., discount rate) and the date of expiration of the licenses.

Impairments, other than those relating to goodwill, are reversed if the conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgment.

Impairment of technical goodwill

Although not an IFRS term, "technical goodwill" is commonly used in the oil and gas industry to describe a category of goodwill arising as an offsetting account to deferred tax recognized in business combinations. DNO has recognized a significant technical goodwill arising from business combinations. There are no specific IFRS guidelines about the allocation of technical goodwill, and the Group has therefore applied the general guidelines for allocating goodwill for the purpose of impairment testing. In general, technical goodwill is allocated to a cashgenerating unit (CGU) or group of CGUs that give rise to the technical goodwill, while any residual goodwill may be allocated across all CGUs based on facts and circumstances in the business combination.

Technical goodwill is exposed to impairment testing whenever there is a significant indicator that the CGU (or groups of CGUs) to which it is allocated is impaired. Moreover, goodwill is not depreciated and hence, impairment of technical goodwill is expected on a recurring basis, unless there are positive changes in underlying assumptions that more than offset the production from the CGU (or groups of CGUs).

When performing the impairment test for technical goodwill, deferred tax recognized in relation to the acquired assets in a business combination reduces the net carrying value prior to the eventual impairment charges. This is done in order to avoid an immediate impairment of all technical goodwill. When deferred tax from the initial recognition decreases, more goodwill is exposed for impairment. Going forward, depreciation of values calculated in the purchase price allocations from business combinations will result in decreased deferred tax liability.

Measurement of fair values

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (IFRS 13 Fair Value Measurement). The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, including assumptions about risk, assuming that market participants act in their economic best interest. There are situations when the Group is required to measure fair values of non-financial assets and liabilities, for example when investing in equity instruments, in a business combination including allocation of purchase price or when the Group measures the recoverable amount of an asset at fair value less costs to sell in an impairment testing situation.

Fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.

The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value. The fair value of oil and gas assets is normally based on discounted cash flow models (income approach), where the determination of different inputs in the model requires significant judgment from management, as described in the section above regarding impairment.

Acquisition accounting

The Group applies the acquisition method for transactions involving business combinations and applies the principles of the acquisition method when an interest or an additional interest is acquired in a joint operation which constitutes a business. Application of the acquisition method may require significant judgement in, among other matters, determining and measuring the fair value of the transaction consideration including contingent consideration elements, identifying all assets acquired and liabilities assumed, establishing their fair values, determining deferred taxes, and allocating the purchase price accordingly, including measurement and allocation of goodwill. The judgements applied in acquisition accounting may materially affect the financial statements both in the transaction period and in future periods.

The assets acquired through business combinations are recognized at fair values and, as such, are sensitive to adverse changes in a number of often volatile economic factors, including future oil and gas prices and the underlying performance of the assets.

Accounting for exploration costs

The Group's accounting policy is to temporarily capitalize drilling expenditures related to exploration wells, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is not considered technically or commercially viable, the costs of the exploration wells are expensed in the income statement. Decisions as to whether an exploration well should remain capitalized or expensed during the period may have a material effect on the financial results for the period.

Notional corporate income tax/deferred taxation in Kurdistan

Under the terms of the PSCs in Kurdistan, DNO is not required to pay any corporate income taxes. The share of profit oil which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of the contractors. Current and deferred taxation for accounting purposes arising from such notional corporate income tax is not recognized for Kurdistan as it has not been possible to measure reliably such notional corporate income tax paid on behalf of DNO. This is an accounting presentational matter and there is no corporate income tax required to be paid, see also Note 8.

Group accounting and consolidation principles Basis for consolidation

The consolidated financial statements include the financial statements of DNO ASA and its subsidiaries. The Company currently holds a 100 percent interest in all of its subsidiaries.

The financial results of subsidiaries acquired or sold during the year are included in the consolidated financial statements from the date when the Company obtains control of the subsidiary or up to the date when the Company loses control of the subsidiary.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company using consistent accounting policies. Where necessary, the accounting policies of the subsidiaries have been adjusted to ensure consistency with the policies adopted by DNO. All intercompany balances and transactions have been eliminated upon consolidation.

Interest in jointly controlled operations (assets)

A joint arrangement is present when DNO holds a long-term interest which is jointly controlled by DNO and one or more other parties under a contractual arrangement in which decisions about the relevant activities require the unanimous consent of the parties sharing control. Such joint arrangements are classified as either joint operations or joint ventures.

Under IFRS 11 Joint Arrangements, a joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities. Oil and gas licenses held by the Group which are within the scope of IFRS 11 have been classified as joint operations. DNO recognizes its investments in joint operations by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the Group's financial statements.

For those licenses that are not deemed to be joint arrangements pursuant to the definition in IFRS 11, either because unanimous consent is not required among the parties involved, or no single group of parties has joint control over the activity, DNO recognizes its share of related expenses, assets, liabilities and cash flows under the respective items in the Group's financial statements in accordance with applicable IFRS standards. In determining whether each separate arrangement related to DNO's joint operations is within or outside the scope of IFRS 11, DNO considers the terms of relevant license agreements, governmental concessions and other legal arrangements impacting how and by whom each arrangement is controlled.

Foreign currency translation and transactions Functional currency

The consolidated financial statements are presented in USD, which is also DNO ASA's functional currency and presentation currency.

Items included in the financial statements of each subsidiary are initially recorded in the subsidiary's functional currency, i.e., the currency that best reflects the economic substance of the underlying events and circumstances relevant to that subsidiary.

Transactions and balances

Foreign currency transactions are translated into functional currency of the Company or subsidiaries using the exchange rates prevailing at the dates of the transactions. Financial assets and financial liabilities in foreign currencies are translated into functional currency at the balance sheet date exchange rates. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies are recognized in profit or loss. Those arising in respect of financial assets and liabilities are recorded on a net basis as a financial item.

Foreign exchange gains or losses resulting from changes in the fair value of non-monetary financial assets classified as equity instruments are recognized directly in other comprehensive income.

Subsidiaries

Statements of comprehensive income and statements of cash flows of subsidiaries and joint operations that have a functional currency different from the parent company are translated into the presentation currency at average exchange rates each month. Statements of financial position items are translated using the exchange rate at reporting date, with the translation differences taken directly to other comprehensive income. When a foreign entity is sold, such translation differences are recognized in profit or loss as part of the gain or loss on sale.

Classification in the statements of financial position

Current assets and short-term liabilities include items due less than one year from the statements of financial position date, and if longer, items related to the operating cycle. The current portion of long-term debt is included under current liabilities. Investments in shares held for trading are classified as current assets, while strategic investments are classified as non-current assets. Other assets and liabilities are classified as non-current assets and noncurrent liabilities.

Fair value

Financial instruments such as investments in equity instruments are measured at fair value at each balance sheet date. Fair value is the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorized within the fair value hierarchy, described as follows:

• Level 1 Quoted market prices in active markets for identical assets or liabilities
• Level 2 Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable
• Level 3 Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

Investments in equity instruments, where available, are measured at quoted market prices at the measurement date.

Property, plant and equipment General

PP&E are recognized at historical cost and adjusted for depreciation, depletion and amortization (DD&A) and impairment charges.

Depreciation of PP&E other than oil and gas assets are generally depreciated on a straight-line basis over expected useful lives, normally varying from three to seven years. Expected useful lives are reviewed at each balance sheet date and, where there are changes in estimates, depreciation periods are changed accordingly.

The carrying amount of the PP&E in the statements of financial position represents the cost less accumulated DD&A and accumulated impairment charges.

Ordinary repairs and maintenance costs, defined as day-to-day servicing costs, are charged to profit or loss during the financial period in which they are incurred. The cost of major repairs and maintenance is included in the asset's carrying amount when it is likely that the Group will derive future financial benefits exceeding the originally assessed standard of performance of the existing asset.

Gains and losses on disposals are determined by comparing the disposal proceeds with the carrying amount and are included in operating profit.

Assets held for sale are reported at the lower of the carrying amount and the fair value, less selling costs.

Exploration and development costs

Capitalized exploration expenditures are classified as intangible assets and reclassified to tangible assets (i.e., PP&E) at the start of the development. For accounting purposes, an oil and gas field is considered to enter the development phase when the technical feasibility and commercial viability of extracting oil and gas from the field are demonstrable, normally at the time of concept selection. All costs of developing commercial oil and gas fields are capitalized, including indirect costs. Capitalized development costs are classified as tangible assets (i.e., PP&E). Predevelopment expenditures up until development project sanction in general do not meet the criteria for capitalization and are expensed as incurred.

Acquired licence rights are recognized as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets when the related fields enter the development or production phase.

Oil and gas assets in production

Capitalized costs for oil and gas assets are depreciated using the unit-of-production (UoP) method. The rate of depreciation is equal to the ratio of oil and gas production for the period over the estimated remaining 2P reserves at the beginning of the period. The future development expenditures necessary to bring those reserves into production are included in the basis for depreciation and are estimated by the management based on current periodend un-escalated price levels. The reserve basis used for depreciation purposes is updated at least once a year. Any changes in the reserves affecting UoP calculations are reflected prospectively.

The Group has previously depreciated its oil and gas assets in Kurdistan over the estimated remaining 1P developed reserves. Following a review of the depreciation method, effective 1 January 2019, the Group changed the reserves basis from 1P developed reserves to 2P reserves. The change in the depreciation method is reflected prospectively as a change in estimate under IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors. This change in accounting estimate resulted in USD 85 million less depreciation of the Kurdistan assets.

Component cost accounting/decomposition

The Group allocates the amount initially recognized in respect of an item of PP&E to its significant parts and depreciates separately each such part over its useful life. DNO has defined the oil and gas field (or group of oil and gas fields) or license level as the lowest level at which separate cash flows can be identified.

Borrowing costs

Interest costs directly attributable to the construction phase of PP&E assets are capitalized during the period required to complete and prepare the asset for its intended use. Borrowing costs consist of interest and other costs that the Group incurs in connection with the borrowing of funds.

Other borrowing costs are expensed when incurred. The capitalization of borrowing costs is recorded based on the average interest rate for the Group in the period. The capitalized borrowing costs cannot exceed the actual borrowing costs in each period.

Intangible assets

General

Intangible assets are stated at cost, less accumulated amortization and accumulated impairment charges. Intangible assets include acquisition costs for oil and gas licenses, expenditures on the exploration for oil and gas resources, technical goodwill and other intangible assets. Goodwill is not depreciated.

The useful lives of intangible assets are assessed as either finite or infinite. Amortization of intangible assets is based on the expected useful economic life and assessed for impairment whenever there is an indication that the intangible asset might be impaired. The impairment assessment of intangible assets with infinite lives is undertaken annually.

Exploration and evaluation assets

The Group uses the successful efforts method to account for its exploration and evaluation assets. All exploration costs (including purchase of seismic, geological and geophysical costs and general and administrative costs), except for acquisition costs of licenses and drilling costs of exploration wells, are expensed as incurred. Acquisition costs of licenses and drilling costs of exploration wells are temporarily capitalized pending the determination of oil and gas resources. These costs include directly attributable employee remuneration, materials and fuel used, rig costs and payments to contractors. Continued capitalization of such costs is assessed for impairment at each reporting date. The main criterion is that there must be plans for future activity in the licence or that a development decision is expected in the near future. If reserves or resources are not found, or if discoveries are assessed not technically or commercially recoverable, the costs of exploration wells and licenses are expensed.

Impairment/reversal of impairment

At the end of each reporting period, the Group assesses whether there is any indication that an asset (exclusive of goodwill) may be impaired. If a significant impairment indicator is concluded to exist, an impairment test is performed.

Indications of impairment may include a decline in the long-term oil and gas price (or short-term oil and gas price for late-life oil and gas fields), changes in future investments or significant downward revision of reserve and resource estimates. For the purposes of impairment assessment, assets are grouped at the lowest levels for which there are separable identifiable cash inflows (i.e., CGU). For oil and gas assets, a CGU may be individual oil and gas fields, or a group of oil and gas fields that are connected to the same infrastructure/production facilities, or a license.

An impairment loss is recognized when the carrying amount exceeds the recoverable amount of an asset. The recoverable amount is the higher of the asset's fair value less costs to sell and its value in use. Fair value less costs to sell determined through either the discounted cash flow method (income approach) or the market transactions method (market approach). The value in use can only be determined through the discounted cash flow method.

A previously recognized impairment loss is reversed through the income statement if the circumstances that gave rise to the impairment no longer exist. It is not reversed to an amount that would be higher than if no impairment loss had been recognized. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Technical goodwill

Technical goodwill is tested for impairment annually or more frequently when there are impairment indicators. Those indicators may be specific to an individual CGU or groups of CGUs to which the technical goodwill is related. When performing the impairment test for technical goodwill, deferred tax recognized in relation to the acquired licences reduces the net carrying value prior to the impairment charges.

Impairment is recognized if the recoverable amount of the CGU (or groups of CGUs) to which the technical goodwill is related is less than the carrying amount.

Impairment of goodwill cannot be reversed in future periods.

Financial instruments

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial instruments are initially recognized at fair value. After initial recognition the measurement and accounting treatment depend on the type of instrument and classification.

Financial assets

Financial assets are classified at initial recognition and subsequently measured at:

• Amortized cost;
• Fair value through other comprehensive income (FVTOCI); and
• Fair value through profit or loss (FVTPL).

Financial assets at amortized cost

Financial assets are measured at amortized cost if both of the following conditions are met:

• The financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and
• The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Financial assets at amortized cost are subsequently measured using the effective interest rate (EIR) method and are subject to impairment. Gains and losses are recognized in profit or loss when the asset is derecognized, modified or impaired. The Group's financial assets at amortized cost include trade and other receivables.

Financial assets designated at FVTOCI

Upon initial recognition, equity investments can be irrevocably classified as equity instruments designated at FVTOCI. Gains and losses on these financial assets are not recycled to profit or loss at later periods. Equity instruments designated at FVTOCI are not subject to an impairment assessment.

Financial assets at FVTPL

Financial assets at FVTPL include financial assets held for trading, financial assets designated upon initial recognition at FVTPL or financial assets mandatorily required to be measured at fair value. Financial assets at FVTPL are carried in the statements of financial position at fair value with net changes in fair value recognized in profit or loss. Dividends on listed equity investments are also recognized as other income in profit or loss when the right of payment has been established. The Group does not have significant assets designated at FVTPL.

Derecognition of financial assets

A financial asset is derecognized when the Group:

• No longer has the right to receive cash flows from the asset;
• Retains the right to receive cash flows from the asset but has assumed an obligation to pay them in full without material delay to a third party under a pass-through arrangement; or
• Has transferred its rights to receive cash flows from the asset and either has transferred substantially all the risks and rewards of the asset or has neither transferred nor retained substantially all the risks and rewards of the asset but has transferred the control of the asset.

Impairment of financial assets

An allowance is recognized for expected credit losses (ECLs) for all debt instruments not held at FVTPL. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that are expected to be received, discounted at an approximation of the original effective interest rate.

ECLs are recognized in two stages. For credit exposures with no significant increase in credit risk since initial recognition, ECLs are provided for credit losses that result from default events that are possible within the next 12 months. For credit exposures with significant increase in credit risk since initial recognition, a loss allowance is provided for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default.

For trade receivables, a simplified approach is applied in calculating ECLs. Changes in credit risk are not tracked but instead a loss allowance based on lifetime ECLs at each reporting date is recognized. Expected credit losses are based on a multifactor and holistic analysis and depend on historical experience with the customers adjusted for forward-looking factors specific to the customers and the economic environment.

Financial assets are assessed with regards to default when contractual payments are past the established payment due date and there is internal or external information indicating that the Group is unlikely to receive the outstanding contractual amounts in full. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows.

Further disclosures on impairment of financial assets are provided in Note 9.

Financial liabilities

Financial liabilities are classified at initial recognition as financial liabilities at FVTPL, loans and borrowings or payables.

All financial liabilities are recognized initially at fair value and in the case of loans/borrowings and payables, net of directly attributable transaction costs.

The Group's financial liabilities include trade and other payables and loans.

The subsequent measurement of financial liabilities depends on the classification. No financial liabilities have been designated at FVTPL. Interest-bearing loans are after initial recognition measured at amortized cost using the effective interest rate method. Gains and losses are recognized in profit or loss when the liabilities are derecognized as well as through the amortization process. Amortized cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the effective interest rate. The amortization cost is included as finance expense in the statements of comprehensive income. This applies mainly to bond loans, see Note 15.

A financial liability is derecognized when the obligation under the liability is discharged, cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such a modification is treated as a derecognition of the original liability and a recognition of a new liability. The difference in the respective carrying amounts is recognized in the statements of comprehensive income.

Cash and cash equivalents

Cash and short-term deposits in the statements of financial position comprise cash held in banks, cash in hand and shortterm deposits with an original maturity of three months or less.

Equity

Ordinary shares

Ordinary shares are classified as equity. Costs directly attributable to the issue of ordinary shares and share options are recognized as a reduction of equity, net of any tax effects.

Repurchase of share capital (treasury shares)

When share capital recognized as equity is repurchased, the amount of the consideration paid, which includes directly attributable costs, is net of any tax effects and is recognized as a deduction in equity. Repurchased shares are classified as treasury shares and are presented as a deduction from total equity. When treasury shares are subsequently sold or reissued, the amount received is recognized as an increase in equity and the resulting surplus or deficit of the transaction is transferred to/from retained earnings.

Dividend

Liability to pay a dividend is recognized when the distribution is authorized by the shareholders. A corresponding amount is recognized directly in equity.

Financial income and expenses

Financial income comprises: interest income; dividend income; gains on the disposal of financial investments; foreign exchange gains; and changes in the fair value of financial assets through

profit or loss. Interest income is recognized as it accrues in profit or loss using the effective interest method. Dividend income is recognized in profit or loss on the date that the Group's right to receive payment is established, which in the case of quoted securities is the ex-dividend date.

Financial expenses comprise: interest expenses on loans; unwinding of the discount on provisions; changes in the fair value of financial assets measured at FVTPL; impairment losses recognized on financial assets; foreign exchange losses and losses on financial assets recognized in profit or loss.

Foreign exchange gains or losses from financial instruments are reported as financial income or financial expenses.

Inventories

Inventories, other than inventories of oil, are valued at the lower of cost and net realizable value. Cost is determined by the first-in, first-out (FIFO) method. Net realizable value is the estimated selling price in the ordinary course of business, less the estimated costs of completion and estimated selling expenses.

Revenue recognition

Revenues presented in the consolidated statements of comprehensive income consist of Revenue from contracts with customers (see Note 3).

Revenue from contracts with customers is recognized when the customer obtains control of the oil and gas, which normally will be when title passes at the point of delivery.

A liability (overlift) arises when the Group sells more than its share of the oil and gas production. Similarly, an asset (underlift) arises when the sale is less than the Group's share of the oil and gas production.

Effective 1 January 2019, overlift/underlift balances are valued at production cost including depreciation (the sales method), previously valued at net realizable value. The movements in overlift/underlift are presented as an adjustment to Cost of goods sold, previously presented as Other revenues. This change was made due to the discussion in the IFRS Interpretations Committee (IFRIC) on the topic "Sale of output by a joint operator (IFRS 11)", which was concluded in March 2019.

Tariff income from processing of oil and gas in the North Sea is recognized as earned in line with underlying agreements.

Revenues from the sale of services are recognized when services are performed.

Other revenues are recognized when the goods or services are delivered and material risk and control are transferred.

Revenue recognition in Kurdistan

DNO generates revenues in Kurdistan through the sale of oil produced from the Tawke license which is exported by pipeline through Turkey. The title is considered to have passed on delivery of oil to the export pipeline at Fish Khabur. Considering the

uncertainties related to timing of payments for oil deliveries, revenues were recognized upon receipt of cash payment until September 2018. Following an assessment of facts and circumstances, effective 1 October 2018, the Group recognizes revenues in Kurdistan in line with invoiced oil sales following monthly deliveries to the KRG and not upon cash receipt. The PSCs held by the Group are considered to be within the scope of the standard and sale of oil and gas to customers is recognized as Revenue from contracts with customers. Based on business practice, the KRG is responsible for exporting the oil produced in Kurdistan and it is assessed that DNO has a customer relationship with the KRG. It is considered that the contracts with customers contain a single performance obligation which is considered to be delivery of produced oil and gas to the customer.

The price for oil deliveries to the KRG is based on Brent prices with deductions for oil quality and transportation fees.

Production Sharing Contracts

A PSC is an agreement between a contractor and a host government, whereby the contractor bears all of the risks and costs for exploration, development and production in return for a stipulated share of production.

The contractor recovers the sum of its investment and operating costs from a percentage of production (cost oil). In addition, the contractor is entitled to receive a share of production in excess of cost oil (profit oil). The sum of cost oil attributable to the contractor's share of costs and the share of profit oil represents the contractor's entitlement under a PSC. The sum of royalties and the government's share of profit oil, including that of a government-controlled enterprise, represents the government take under a PSC.

Presenting its operations governed by PSCs according to the sales method, DNO only recognizes as revenue its sales after deduction of government take.

Income taxes

Tax income/expense consists of taxes receivable/payable and changes in deferred tax. Taxes receivable/payable are based on the amounts receivable or payable to the tax authorities. Deferred tax liability is calculated on all taxable temporary differences, unless there is a recognition exception. A deferred tax asset is recognized only to the extent that it is probable that the future taxable income will be available against which the asset can be utilized. Unrecognized deferred tax assets are re-assessed at each reporting date and are recognized to the extent that it has become probable that future taxable profits will allow the deferred tax asset to be recovered.

Deferred tax assets and deferred tax liabilities are recognized irrespective of when the differences are reversed. They are recognized at their nominal value and classified as non-current assets/liabilities in the statements of financial position. Deferred tax assets and deferred tax liabilities are offset in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied

by the same taxing authority on the same entity or different entities that intend to realize the asset and settle the liability at the same time.

Tax payable and deferred tax are recognized directly in the equity to the extent that they relate to items charged directly to equity. For treatment of tax in relation to business combinations, see the Business combinations section.

DNO's PSCs provide that the corporate income tax to which the contractor is subject is deemed to have been paid to the government as part of the payment of profit oil to the government or its representatives. For accounting purposes, if such notional income tax is to be classified as income tax in accordance with IAS 12 Income Taxes, the Group would present this as an income tax expense with a corresponding increase in revenues. Furthermore, it would be assessed whether any deferred tax asset or liability is required to be recognized equal to the difference between book values and the tax values of the qualifying assets and liabilities, multiplied by the applicable tax rate.

Business combinations

In accordance with IFRS 3 Business Combinations, an acquisition is considered a business combination, when the acquired asset or groups of assets constitute a business (i.e., an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors).

Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred.

For accounting purposes, the acquisition method is used in connection with the purchase of businesses. Acquisition cost equals the fair value of the assets used as consideration, including contingent consideration, equity instruments issued and liabilities assumed in connection with the transfer of control. Acquisition cost is measured against the fair value of the acquired assets and assumed liabilities. Identifiable intangible assets are included in connection with acquisitions if they can be separated from other assets or meet the legal contractual criteria. If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets (when the acquiring entity achieves control of the transferring entity), goodwill arises.

If the fair value of the acquired net assets exceeds the acquisition cost on the acquisition date, the excess amount is taken to profit or loss immediately.

Goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergy effects of the acquisition. The allocation of goodwill may vary depending on the basis of its initial recognition.

The goodwill that is recognized by the Group is related to technical goodwill and is recognized due to the requirement to

recognize deferred tax for the difference between the assigned fair values and the related tax base. The fair values of the Group's licences in the North Sea are based on cash flows after tax. This is because these licences are sold only on an after-tax basis. The purchaser is therefore not entitled to a tax deduction for the consideration paid above the seller's tax values. In accordance with IAS 12, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the fair values of the acquired assets and the transferred tax depreciation basis (i.e., tax values).

The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which gives rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities, or a license.

The estimation of fair value may be adjusted up to 12 months after the acquisition date if new information emerges about facts and circumstances that existed at the time of the takeover and which, had they been known, would have affected the calculation of the amounts that were included from that date.

Acquisition-related costs, except costs to issue debt or equity securities, are expensed as incurred. Taxes payable and deferred tax are recognized directly in the equity to the extent that they relate to items charged directly to the equity.

License acquisitions, farm-in/out and license swaps License acquisitions

For acquisition of oil and gas licenses, individual assessment is made whether the acquisition should be treated as a business combination or as an asset purchase. The conclusion may materially affect the financial statements both in the transaction period and in future periods. Generally, purchase of a license in development or production phase is regarded as a business combination, while purchase of a license in the exploration phase is regarded as an asset purchase.

Farm-in and farm-out

A farm-in or farm-out of an oil and gas license takes place when the owner of a working interest (the farmor) transfers all or a portion of its working interest to another party (the farmee) in return for an agreed upon consideration and/or action, such as conducting subsurface studies, drilling wells or developing the asset. Any cash consideration received directly from the farmee is credited against costs previously capitalized in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal. The farmee capitalizes or expenses its costs as incurred according to the accounting method it is using. There are no accruals for future commitments in farm-in/farm-out agreements in the exploration and evaluation phase and no profit or loss is recognized by the farmor. In the development or production phase, a farm-in/farm-out agreement will be treated as a transaction recorded at fair value as represented by the costs carried by the farmee. Any gain or loss arising from the farmin/farm-out is recognized in the statements of comprehensive income.

License swaps

License swaps are calculated at the fair value of the asset being exchanged, unless the transaction lacks commercial substance, or neither the fair value of the asset received, nor the fair value of the asset divested, can be effectively measured. In the exploration phase, the Group normally recognizes license swaps based on historical cost basis, as the fair value is often difficult to measure. If the transaction is determined to be a business combination, the requirements of IFRS 3 apply.

Employee benefits

Pensions

The Group's pension obligations in Norway are limited to certain defined contribution plans which are paid to pension insurance plans and charged to profit or loss in the period in which they are incurred. Once the contributions are paid there are no further obligations.

Share-based payments

Cash-settled share-based payments are recognized in the income statement as expenses during the vesting period and as a liability. The liability is measured at fair value and revaluated using the Black & Scholes pricing model at each balance sheet date and at the date of settlement, with any change in the fair value recognized in the income statement for the period.

Provisions and contingent liabilities

A provision is recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is likely that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the obligation amount. When the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognized as a separate asset, but only if the reimbursement is certain. The expense related to any provision is presented in profit or loss, net of any reimbursement. Provisions are reviewed at each balance sheet date and adjusted to reflect the current best estimate.

The amount of the provision is the present value of the riskadjusted expenditures expected to be required to settle the obligation, determined using the estimated risk-free interest rate and a credit margin as the discount rate. Where discounting is used, the carrying amount of the provision increases in each period to reflect the unwinding of the discount by the passage of time. This increase is recognized as other financial expenses.

Contingent liabilities are not recognized but are disclosed unless the possibility of an outflow of resources is remote.

Asset retirement obligations

Provisions for ARO are initially recognized at the present value of the estimated future costs determined in accordance with local conditions and requirements.

A corresponding ARO asset (included in PP&E) of an amount equivalent to the provision is also recognized initially. This is

subsequently depreciated as part of the capital costs of the production and transportation facilities.

The ARO provisions and the discount rates are reviewed at each balance sheet date. The discount rates used in the calculation of the present value of the ARO are pre-tax risk-free rates with the addition of a credit margin. The risk-free rate used has a maturity date that is expected to coincide with the time the removal will be affected and denominated in the same currency as the expected future expenditures. According to IFRIC 1 Changes in Existing Decommissioning, Restoration and Similar Liabilities, changes in the measurement of the ARO resulting from a change in the timing or amount of the outflow of resources embodying economic benefits required to settle the obligation, or a change in the discount rate, are added to or deducted from the cost of the related asset. Changes in the estimated ARO provisions impact the ARO asset in the period in which the estimate is revised.

Segment reporting

Management monitors the operating results of its operating segments separately for the purpose of making decisions about resource allocation and performance assessment. Segment financial performance is evaluated based on the income statements, financial position as well as through other key performance indicators. For DNO, its operating segments correspond to its reportable segments. The reportable segments provide products or services within a particular economic environment that are subject to risks and returns different from those of components operating in other economic environments. The Group has identified its reportable segments based on the nature of the risk and return within its business and by the geographical location of the Group's assets and operations. Transfer pricing between the segments and companies is set using the arm's length principle in a manner similar to transactions with third parties.

Earnings per share

Calculation of basic earnings per share is based on the net profit or loss attributable to ordinary shareholders using the weighted average number of shares outstanding during the year after deduction of the average number of treasury shares held over the period. The calculation of diluted earnings per share is consistent with the calculation of basic earnings per share, while giving effect to all dilutive potential ordinary shares that were outstanding during the period.

Related parties

Parties are related if one party has the ability to directly, jointly or indirectly control the other party or exercise significant influence over the party in making financial and operating decisions. Management is also considered to be a related party.

Transactions between related parties are transfers of resources, services or obligations, regardless of whether a price is charged. All transactions between the related parties are recorded at market value.

Changes in accounting policies

The accounting policies adopted are consistent with those of the previous financial year with the exception of changes described below.

Other amendments and interpretations may apply for the first time in 2019 but are not considered to have any material impact on the Group's financial statements.

Changes in accounting policies entered into force during 2019:

IFRS 16 Leases

IFRS 16 Leases was issued in January 2016 and replaced IAS 17 Leases. IFRS 16 sets out the principles for the recognition, measurement, presentation and disclosure of leases and requires lessees to account for all leases under a single on-balance sheet model similar to the accounting for finance leases under IAS 17. At the commencement date of a lease, a lessee recognizes a liability to make lease payments and an asset representing the right to use the underlying asset during the lease term (right-ofuse asset, RoU asset). The standard includes a number of optional practical expedients related to recognition and initial application. Lessees are required to separately recognize the interest expense on the lease liability and the depreciation expense on the RoU asset.

The Group implemented IFRS 16 on 1 January 2019. The following implementation and application policy choices were made:

IFRS 16 transition choices

• Follow the modified retrospective approach, which requires no restatement of comparative information.
• Apply the standard to contracts that were previously identified as leases applying IAS 17 and IFRIC 4 and therefore will not apply the standard to contracts that were not previously identified as containing a lease under IAS 17 and IFRIC 4 Determining Whether an Arrangement Contains a Lease. For leases previously classified as operating leases under IAS 17, the lease liabilities at the date of initial application are measured as the present value of the remaining lease payments. The discount rate is the lessee's incremental borrowing rate at that date. The RoU assets are measured at an amount equal to the lease liability.
• Leases for which the lease term ends within 12 months of 1 January 2019 are not reflected as leases under IFRS 16.
• RoU assets are initially reflected at an amount equal to the corresponding lease liability.

IFRS 16 policy application choices

• Short term leases (12 months or less) and leases of low value assets have not been reflected in the balance sheet but expensed or capitalized as incurred, depending on the activity in which the leased asset is used.
• Non-lease components within lease contracts are accounted for separately for all underlying classes of assets and reflected in the relevant cost category or capitalized as incurred, depending on the activity involved.

On transition date to IFRS 16, the Group recognized in the balance sheet USD 12.9 million in RoU assets and USD 12.7 million in lease liabilities. The Group's RoU assets mainly relate to office rent including warehouse and equipment. The Group also leases computers and IT equipment with contract terms of one to three years but has elected to apply the practical expedient on low value assets and does not recognize lease liabilities or RoU assets and the leases are instead expensed when the costs are incurred. The value of these leases was USD 0.1 million. A practical expedient has been applied to not recognize lease liabilities and RoU assets for short-term leases. The value of these leases was USD 0.7 million.

On transition date to IFRS 16, the effect due to discounting of nominal future lease obligations was USD 3.7 million (at a 10.0 percent weighted average discount rate).

The RoU assets are depreciated linearly over the lifetime of the related lease contract.

The identified lease liabilities have no significant impact on the Group's financing, loan covenants or dividend policy. The Group does not have any residual value guarantees.

Extension options are included in the lease liability when, based on the management's judgement, it is reasonably certain that an extension will be exercised.

In the consolidated statements of comprehensive income, operating lease costs are replaced by depreciation and interest expense.

In the consolidated cash flow statement, lease payments related to lease liabilities in accordance with IFRS 16 are presented as cash flow used in financing activities.

Note 2 Segment information

The Group identifies and reports its segments based on information provided to the executive management and the Board of Directors. The segment information is used as the basis for allocation of resources and decision making. The Group has identified its reportable segments based on the nature of the risks and returns within its business and by the location of the Group's assets and operations. Inter-segment sales are based on the arm's length principle and are eliminated at the consolidated level. Segment profit/-loss includes profit/-loss from inter-segment sales.

Effective 1 January 2019, the Group reported two operating segments: Kurdistan and the North Sea (which includes the Group's oil and gas activities in Norway and the UK). The change in reporting of operating segments compared to 2018 was due to the acquisition of Faroe Petroleum plc (renamed DNO North Sea plc) and the relinquishment of Oman Block 8 in early 2019.

The operating segments correspond to the reportable segments. Remaining operating segments are included in the Other category based on a materiality assessment. The 2018 figures are restated for comparison purposes. The country-by-country reporting for companies in extractive industries in line with the Norwegian Accounting Act is available on the Company's website.

USD million
Twelve months ended as of 31 December 2019	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segments eliminated	Total Group
COMPREHENSIVE INCOME INFORMATION
Revenues	3	717.1	253.5	0.8	971.4	-	971.4
Inter-segment sales		-	0.5	-	0.5	-0.5	-
Cost of goods sold	4	-324.9	-213.0	-	-537.9	-3.5	-541.4
Gross profit		392.1	41.1	0.8	434.0	-4.0	430.0
Other income		-	-0.7	-	-0.7	0.2	-0.5
Administrative expenses	5	-0.4	-7.3	-7.9	-15.6	-10.6	-26.1
Other operating expenses	5	-1.7	-	-17.6	-19.3	-	-19.3
Impairment of oil and gas assets	10	-12.8	-149.2	-	-162.0	-	-162.0
Exploration expenses	6	-2.1	-141.4	0.2	-143.3	-3.2	-146.4
Profit/-loss from operating activities		375.2	-257.4	-24.5	93.3	-17.6	75.6
Net financial income/-expense	7	15.3	-34.2	1.1	-17.8	-105.7	-123.5
Tax income/-expense	8	0.6	118.0	-	118.7	2.7	121.3
Net profit/-loss		391.0	-173.6	-23.4	194.1	-120.6	73.5

FINANCIAL POSITION INFORMATION

Non-current assets	794.7	1,288.9	-	2,083.6	31.1	2,114.7
Current assets	345.0	406.6	5.0	756.5	400.6	1,157.2
Total assets	1,139.6	1,695.5	5.0	2,840.1	431.8	3,271.9
Non-current liabilities	57.7	702.4	0.3	760.3	727.2	1,487.5
Current liabilities	96.2	335.7	27.6	459.5	163.5	623.0
Total liabilities	153.8	1,038.1	27.9	1,219.9	890.6	2,110.5

OTHER SEGMENT INFORMATION

EBITDA*	606.2	-18.7	-24.5	562.9	-13.6	549.4
EBITDAX*	608.2	122.7	-24.7	706.2	-10.4	695.8
Netback*	606.2	38.2	-24.5	619.8	-13.6	606.3
Lifting costs	-106.7	-92.4	-	-199.1	-	-199.1
Lifting costs (USD/boe)*	3.3	17.7	-	5.4	-	5.4
Netback (USD/boe)*	19.0	7.3	-	16.3	-	16.3
DD&A**	-217.6	-89.2	-	-306.8	-5.0	-311.8
DD&A (USD/boe)	-15.5	-17.1	-	-16.0	-	-16.0
Acquisition and development costs***	-235.6	-170.0	-2.4	-407.9	-	-407.9

* See the section on alternative performance measures.

** DD&A of oil and gas production assets.

*** Acquisition and development costs exclude changes in estimated asset retirement obligations.

Note 2 Segment information

USD million

Twelve months ended as of 31 December 2018	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segments eliminated	Total Group
COMPREHENSIVE INCOME INFORMATION
Revenues	3	811.3	-	18.0	829.3	-	829.3
Inter-segment sales		-	0.9	0.1	1.1	-1.1	-
Cost of goods sold	4	-338.8	-0.2	-9.8	-348.8	-1.8	-350.6
Gross profit		472.4	0.8	8.4	481.6	-2.8	478.7
Other income		-	-1.4	-	-1.4	6.1	4.8
Administrative expenses	5	-0.2	-2.7	-5.6	-8.5	-28.1	-36.7
Other operating expenses	5	-0.8	-	-2.6	-3.4	-	-3.4
Impairment of oil and gas assets	10	-	-	-1.9	-1.9	-	-1.9
Exploration expenses	6	-1.5	-45.9	-17.4	-64.8	0.1	-64.7
Profit/-loss from operating activities		469.9	-49.2	-19.2	401.5	-24.8	376.8
Net financial income/-expense	7	-3.7	-2.6	5.8	-0.6	-53.7	-54.3
Tax income/-expense	8	-4.0	32.8	-1.5	27.2	4.6	31.8
Net profit/-loss		462.2	-19.0	-14.9	428.3	-74.0	354.3
FINANCIAL POSITION INFORMATION
Non-current assets		785.3	8.3	-	793.7	235.1	1,028.8
Current assets		280.5	39.8	10.3	330.5	645.0	975.5
Total assets		1,065.8	48.1	10.3	1,124.2	880.1	2,004.3
Non-current liabilities		60.7	2.6	0.4	63.7	580.1	643.8
Current liabilities		60.8	42.4	19.0	122.2	20.5	142.7
Total liabilities		121.5	45.0	19.4	185.9	600.5	786.5
OTHER SEGMENT INFORMATION
EBITDA*		728.1	-49.2	-17.1	661.7	-23.0	638.8
EBITDAX*		729.6	-3.3	0.3	726.6	-23.1	703.5
Netback*		545.3	-16.0	-18.7	510.6	-21.5	489.1

Netback*	545.3	-16.0	-18.7	510.6	-21.5	489.1
Lifting costs	-80.6	-	-9.6	-90.4	-	-90.4
Lifting costs (USD/boe)*	-2.8	-	-13.4	-3.0	-	-3.0
Netback (USD/boe)*	18.7	-	-26.0	16.4	-	16.4
DD&A**	-258.2	-	-	-258.2	-1.9	-260.1
DD&A (USD/boe)	-21.9	-	-	-21.4	-	-21.4
Acquisition and development costs***	-135.4	-1.3	-	-136.8	-1.2	-138.0

* See the section on alternative performance measures.

** DD&A of oil and gas production assets.

*** Acquisition and development costs exclude changes in estimated asset retirement obligations.

Note 3 Revenues

	1 January - 31 December
USD million	2019	2018
Sale of oil	918.1	829.3
Sale of gas	36.5	-
Sale of natural gas liquids (NGL)	13.0	-
Tariff income	3.7	-
Total revenues from contracts with customers	971.4	829.3

In 2019, sale of oil from Kurdistan was USD 717.1 million and in the North Sea USD 201.0 million. Sale of gas was USD 36.5 million, entirely from the North Sea. Sale of NGL in the North Sea was USD 12.2 million and in Oman USD 0.8 million. Tariff income was USD 3.7 million, entirely from the North Sea.

The 2018 revenues included a recognition of an additional revenue from the sale of oil of USD 182.8 million following a change in Kurdistan revenue recognition.

Note 4 Cost of goods sold/Inventory

		1 January - 31 December
USD million	2019	2018
Lifting costs	-199.1	-90.4
Tariff and transportation expenses	-37.7	-
Production cost based on produced volumes	-236.8	-90.4
Movement in overlift/underlift	7.2	-
Production cost based on sold volumes	-229.6	-90.4
Depreciation, depletion and amortization	-311.8	-260.1
Total cost of goods sold	-541.4	-350.6

Lifting costs consist of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. Tariff and transportation expenses consist of charges incurred by the Group for the use of infrastructure owned by other companies in the North Sea.

		Years ended 31 December
USD million	2019	2018
Spare parts	28.2	8.3
Total inventory	28.2	8.3

Total inventory of USD 28.2 million at yearend 2019 was related to Kurdistan (USD 12.3 million) and the North Sea (USD 15.9 million). In 2019, the provision for obsolete inventory in Kurdistan was USD 18.1 million (unchanged from yearend 2018).

Note 5 Administrative/Other operating expenses

This note should be read in conjunction with Note 21 on related parties.

		1 January - 31 December
USD million	2019	2018
Salaries, bonuses, etc.	-50.6	-34.4
Employer's payroll tax expenses	-7.5	-2.7
Pensions	-3.7	-2.2
Other personnel costs	-4.7	-4.7
Reclassification of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets	77.0	36.0
General and administration expenses	-36.6	-28.7
Total administrative expenses	-26.1	-36.7
Other expenses	-19.3	-3.4
Total other operating expenses	-19.3	-3.4

Salaries and social expenses directly attributable to license activities are reclassified to lifting costs and exploration costs, or PP&E and intangible assets (i.e., capitalized exploration).

Other expenses in 2019 were mainly related to provisions in Yemen, see Note 17.

DNO has a defined contribution scheme for its Norway-based employees, with USD 3.7 million expensed in 2019 (USD 2.2 million in 2018). The Group's obligations are limited to the annual pension contributions. DNO meets the Norwegian legal requirements for mandatory occupational pension ("obligatorisk tjenestepensjon").

An employee share savings plan was introduced in 2013. The plan was closed for new contributions in the second quarter of 2016 but was kept open until 31 August 2019 for vesting of restricted synthetic shares and settlement of unrestricted synthetic shares. As of 31 December 2019, the Company's liability under this plan was nil (USD 0.5 million at yearend 2018). The expense for 2019 amounted to USD 0.3 million.

Members of the executive management and employees have been awarded synthetic shares during the year as part of their variable remuneration. At yearend 2019, the Company's liability for synthetic shares as part of other variable remuneration amounted to USD 2.4 million (USD 3.3 million at yearend 2018). For more information about remuneration to executive management, see Note 3 in the parent company accounts.

Movement in synthetic Company shares during the year

	1 January - 31 December
Number of shares	2019	2018
Outstanding as of 1 January	2,765,772	2,773,373
Granted during the year	1,347,733	1,763,027
Forfeited/reversed during the year	23,465	204,641
Settled during the year	898,435	1,565,987
Expired during the year	-	-
Outstanding as of 31 December	3,191,605	2,765,772
Unrestricted as of 31 December	125,032	800,435
Weighted average remaining contractual life for the synthetic shares (years)	3.99	3.36
Weighted average settlement price for synthetic shares settled during the year (NOK)	14.84	12.46
Settlement price for synthetic shares at the end of the year (NOK)	11.57	12.55

Note 5 Administrative/Other operating expenses

Remuneration to Board of Directors and executive management

	1 January - 31 December
USD million	2019	2018
Managing Director
Remuneration	-0.67	-0.67
Bonus	-0.21	-0.22
Pension	-0.02	-0.02
Other remuneration	-0.07	-0.30
Remuneration to Managing Director	-0.98	-1.21
Other executive management
Remuneration	-3.20	-2.45
Bonus	-0.51	-0.59
Pension	-0.14	-0.12
Other remuneration	-0.45	-0.48
Remuneration to other executive management	-4.30	-3.64
Total remuneration to executive management	-5.27	-4.86
Number of managers included	11	7
Total remuneration to Board of Directors	-1.06	-1.10
Total remuneration to Board of Directors and executive management	-6.33	-5.95

Total remuneration of USD 0.9 million (not included in the above table) was paid to Jon Sargeant, a former member of the executive management. For further details on remuneration to the executive management, see Note 3 in the parent company accounts.

Members of the executive management, Bjørn Dale, Haakon Sandborg, Nicholas Whiteley, Ute Quinn and Aernout van der Gaag have severance payment agreements ranging from six months to 12 months of their respective annual base salaries.

Shares and options held by Board of Directors and executive management

	Years ended 31 December
	2019 2018
Directors and executive management	Shares	Options	Shares	Options
Bijan Mossavar-Rahmani, Executive Chairman*	-	-	-	-
Lars Arne Takla, Deputy Chairman	30,000	-	30,000	-
Elin Karfjell, Director (Elika AS)	33,000	-	33,000	-
Gunnar Hirsti, Director (Hirsti Invest AS)	250,000	-	250,000	-
Shelley Watson, Director*	-	-	-	-
Bjørn Dale, Managing Director	-	-	-	-
Chris Spencer, Deputy Managing Director (Chris's Corporation AS)	32,000	-	29,000	-
Haakon Sandborg, Chief Financial Officer	-	-	-	-
Ute Quinn, Group General Counsel and Corporate Secretary	-	-	-	-
Nicholas Whiteley, Group Exploration and Subsurface Director	-	-	-	-
Ørjan Gjerde, Group Commercial Director	-	-	-	-
Tom Allan, General Manager Kurdistan Region of Iraq	-	-	-	-
Rune Martinsen, General Manager DNO North Sea	-	-	-	-
Geir Arne Skau, Human Resources Director	-	-	-	-
Aernout van der Gaag, Deputy Chief Financial Officer	-	-	-	-
Tonje Pareli Gormley, General Counsel - Middle East	-	-	-	-

* Bijan Mossavar-Rahmani and Shelley Watson hold an indirect interest in the Company through their interest in RAK Petroleum.

Executive management have been awarded synthetic shares during the year as part of their variable remuneration, see Note 3 in the parent company accounts.

Auditor fees

	1 January - 31 December
USD million (excluding VAT)	2019	2018
Auditor fees	-0.82	-0.55
Other financial auditing	-0.01	-0.03
Tax advisory services	-0.07	-0.04
Other advisory services	-0.02	-0.01
Total auditor fees	-0.92	-0.63

Note 6 Exploration expenses

	1 January - 31 December
USD million	2019	2018
Exploration expenses (G&G and field surveys)	-17.6	-13.8
Seismic costs	-22.0	-18.0
Exploration expenses capitalized in previous years carried to cost	-27.8	-
Exploration expenses capitalized during the year carried to cost	-47.9	-8.2
Other exploration expenses	-31.2	-24.8
Total exploration expenses	-146.4	-64.7

Total exploration expenses of USD 146.4 million in 2019 were mainly related to exploration activities in the North Sea, including purchase of seismic data and expensing of exploration wells previously capitalized. Total exploration expenses of USD 64.7 million in 2018 were mainly related to exploration activities in the North Sea and provisions made for exploration in Tunisia.

Note 7 Financial income and financial expenses

		1 January - 31 December
USD million	2019	2018
Interest income	9.6	10.0
Financial income	9.6	10.0
Interest expenses	-89.1	-46.1
Currency exchange losses charged to the income statement (net)	-0.8	-1.8
Impairment of financial assets	-	0.2
Other financial expenses	-43.2	-16.6
Financial expenses	-133.1	-64.3
Net financial income/-expenses	-123.5	-54.3

Other financial expenses relate to the amortization of issue costs, premium on bond buybacks and accretion expenses (i.e., unwinding of discount) related to the ARO provisions.

Note 8 Income taxes

Tax income/-expense

		1 January - 31 December
USD million	2019	2018
Changes in deferred taxes	6.8	3.9
Income taxes receivable/-payable	114.5	27.9
Total tax income/-expense	121.3	31.8

Income tax receivable/-payable

		Years ended 31 December
USD million	2019	2018
Tax receivables	164.8	28.3
Income taxes payable	-0.2	-0.5
Net tax receivable/-payable	164.5	27.8

The tax income, tax receivable and recognized deferred tax assets/-liabilities relate to activities on the Norwegian Continental Shelf (NCS) and the United Kingdom Continental Shelf (UKCS). The Company's subsidiary, DNO Norge AS, which carries out the Group's activity on the NCS, is currently not in a tax payable position and can claim a 78 percent refund of the eligible exploration expenses limited to taxable losses for the year. The refund is paid out in November-December of the subsequent year. Tax receivables at yearend include an exploration tax receivable on the NCS, a tax receivable in relation to decommissioning spend on the UKCS and a tax receivable in relation to cessation of petroleum activity on the NCS of DNO North Sea (Norge) AS.

Reconciliation of tax income/-expense

		1 January - 31 December
USD million	2019	2018
Profit/-loss before income tax	-47.8	322.5
Expected income tax according to nominal tax rate in Norway, 22 percent (23 percent in 2018)	-4.1	-75.7
Expected income tax according to nominal tax rate in Norway, 56 percent (55 percent in 2018)	139.9	24.1
Expected income tax according to nominal tax outside Norway	27.0	2.7
Taxes paid in kind under PSCs	-	-1.5
Foreign exchange variations between functional and tax currency	0.0	-21.9
Adjustment of previous years	0.1	-
Adjustment of deferred tax assets not recognized	-30.2	-14.7
Change in previous years	1.2	-
Other items including other permanent differences	-12.6	117.4
Change in tax rate	-	-4.0
Tax loss carried forward utilized	-	5.5
Tax income/-expense	121.3	31.8
Effective income tax rate	-253.6%	-9.9%
Taxes charged to equity	-	-

Tax effects on temporary differences

		Years ended 31 December
USD million	2019	2018
Tangible assets	-285.5	-
Intangible assets (including capitalized exploration expenses)	-197.5	-0.2
ARO provisions	283.1	-
Losses carried forward	166.5	101.4
Non-deductible interests carried forward	11.5	9.9
Other temporary differences	21.5	-1.1
Net deferred tax assets/-liabilities	-0.3	110.1
Valuation allowance	-153.6	-103.1
Net deferred tax assets/-liabilities	-153.9	7.0
Recognized deferred tax assets	63.7	7.0
Recognized deferred tax liabilities	-217.6	-

Note 8 Income taxes

Under the terms of the PSCs in Kurdistan, the Company's subsidiary DNO Iraq AS is not required to pay any corporate income taxes. The share of profit oil which the government is entitled to is deemed to include a portion representing the notional corporate income tax paid by the government on behalf of DNO Iraq AS. Current and deferred taxation arising from such notional corporate income tax is not calculated for Kurdistan, as there is uncertainty related to the tax laws of the KRG and there is currently no well-established tax regime for international oil companies. As such, it has not been possible to reliably measure such notional corporate income taxes deemed to have been paid on behalf of DNO Iraq AS. This is an accounting presentational issue and there is no tax required to be paid by DNO Iraq AS. See also Note 1.

Profits/-losses by Norwegian companies from upstream activities outside of Norway are not taxable/deductible in Norway in accordance with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses are taxable in Norway. This is presented as a permanent tax difference in the reconciliation above.

The impairment charges during 2019 relating to technical goodwill are not deductible for tax purposes and are presented as permanent tax differences in the reconciliation of tax income/expense above. The impairment charge relating to the Schooner and Ketch fields in the UKCS increased the temporary tax difference and deferred tax asset on the ARO provision.

A deferred tax asset has been recognized on petroleum activities in Norway and the UK in relation to carry forward losses and temporary differences as it has been considered probable that taxable profits or tax refunds will be available to utilize these deferred tax assets. A valuation allowance was recognized relating to carried forward losses in Norway (ordinary tax regime) and the UK due to the uncertainty regarding future taxable profits. The increase in deferred tax assets/-liabilities compared to 2018 is mainly due to the acquisition of Faroe, see Note 25.

There are no tax consequences attached to items recorded in other comprehensive income.

The following nominal tax rates apply in the jurisdictions where the subsidiaries of the Group are taxable: Ordinary tax regime in Norway (22 percent), the NCS (78 percent), ordinary tax regime in the UK (19 percent) and the UKCS (40 percent).

Reconciliation of change in deferred tax assets/-liabilities

		Years ended 31 December
USD million	2019	2018
Net deferred tax assets/-liabilities at 1 January	7.0	3.5
Change in deferred taxes in the income statement	6.8	3.9
Deferred taxes related to business combinations and other transactions	-111.7	-
Reclassification to tax receivable	-66.4	-
Currency and other movements	10.5	-0.4
Net deferred tax assets/-liabilities at 31 December	-153.9	7.0

Reconciliation of change in tax receivable/-payable

		Years ended 31 December
USD million	2019	2018
Tax receivable/-payable at 1 January	27.8	33.0
Tax receivable/-payable in the income statement	114.5	28.2
Tax receivable/-payable related to transactions posted directly to balance sheet	15.5	0.8
Tax payment/-refund	-56.9	-33.2
Prior period adjustment	-0.2	-
Reclassification from deferred tax asset	66.4	-
Currency and other movements	-2.6	-1.0
Tax receivable/-payable at 31 December	164.5	27.8

Financial risk management, objectives and policies

Overview

The Group's principal financial liabilities are comprised of interest-bearing liabilities and trade and other payables. The main purpose of these financial liabilities is to finance DNO's operations. The Group's principal financial assets include trade and other receivables, tax receivables and cash and cash equivalents. The Group also holds investments in equity instruments.

DNO is exposed to a range of risks affecting its financial performance including market risk, liquidity risk and credit risk. The Group seeks to minimize potential adverse effects of such risks through sound business practices and risk management programs.

Market risk

The Group is exposed to market risks driven by fluctuations in oil and gas prices, foreign currency exchange rates, interest rates and the value of equity instruments held by the Company.

Oil and gas price risk

DNO's revenues are for the most part generated from the sale of oil. The Group had no oil and gas price hedging arrangements at yearend.

The following table illustrates the impact on 2018 and 2019 profit/-loss before income tax from oil and gas price fluctuations deemed reasonable and possible, with all other variables held constant. In addition to driving revenues, price fluctuations or the expectations of price fluctuations could impact DNO's capital expenditure levels and impairment assessments. See Note 10 for a sensitivity analysis related to the impairment assessment of oil and gas assets.

	Change in yearend	Effect on profit
	oil and gas price	before tax
	USD (percent)	(USD mill)
2019	+/- 15.0	+/- 97.4
2018	+/- 15.0	+/- 97.8

Foreign currency exchange rate risk

DNO's cash flows from operating activities mainly derive from oil sales, operating expenses and capital expenditures which are primarily denominated in USD. The Group had no currency hedging arrangements at yearend 2019 although it monitors its foreign currency risk exposure on a continuous basis and evaluates hedging alternatives.

The following tables illustrate the impact on DNO's profit/-loss before income tax and other comprehensive income in 2018 and 2019 from foreign currency exchange rate fluctuations deemed reasonable and possible in NOK and GBP exchange rates, with all other variables held constant. The Group's profit/-loss before income tax is also exposed to foreign currency exchange rate fluctuations related to the use of different functional currencies (i.e., different from the Group's functional currency) in the subsidiaries of DNO North Sea (GBP and NOK). The other currencies (e.g., AED, IQD, EUR) are not included as the exposure is deemed immaterial.

	Change in NOK (percent)	Effect on profit before tax (USD mill)	Effect on OCI (USD mill)
2019	+ 10.0	-2.0	-44.4
2019	- 10.0	2.0	45.1
2018	+ 10.0	-3.4	-2.0
2018	- 10.0	2.8	2.4

	Change in GBP (percent)	Effect on profit before tax (USD mill)	Effect on OCI (USD mill)
2019	+ 10.0	1.1	-22.9
2019	- 10.0	-1.1	21.8
2018	+ 10.0	-0.2	-19.0
2018	- 10.0	0.3	23.3

	Change in subsidiaries' functional currency (percent)	Effect on profit before tax (USD mill)	Effect on OCI (USD mill)
2019	+ 10.0	-6.8	-
2019	- 10.0	6.8	-
2018	+ 10.0	-	-
2018	- 10.0	-	-

Interest rate risk

As most of the Group's financing derives from bond loans which are issued in USD and at fixed interest rates, the Group does not engage in interest rate hedging. Interest rate exposure on the revolving exploration financing facility (EFF) and the reserve based lending facility (RBL) is considered limited and no hedging arrangement was in place during 2019. The Group is also exposed to interest rate risk on its cash deposits held at floating interest rates.

The following table illustrates the impact on DNO's profit/-loss before income tax in 2018 and 2019 from a change in interest rates on that portion of interest-bearing liabilities and cash deposits deemed reasonable and possible, with all other variables held constant.

Increase/decrease in basis points		Effect on profit before tax (USD mill)
2019	+/- 100	+/-3.5
2018	+/- 100	+/-5.1

Equity price risk

The Group's listed equity investments are recorded at fair value at the end of each period and are exposed to market price risk arising from uncertainties about future values of the equity instruments. Fair value changes are included in other comprehensive income, see Note 1 and Note 11 for more information.

As of 31 December 2019, the exposure to equity investments at fair value was USD 21.0 million (USD 230.8 million at yearend 2018).

The following table illustrates the impact on DNO's profit/-loss before income tax and other comprehensive income from a change in the equity price deemed reasonable and possible, with all other variables held constant.

	Increase/decrease in share price (percent)	Effect on profit before tax (USD mill)	Effect on OCI (USD mill)
2019	+/- 10.0	-	+/-2.1
2018	+/- 10.0	-	+/-23.1

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group's business activities may not be available. Prudent liquidity risk management implies maintaining sufficient cash balances, credit facilities and other financial resources to maintain financial flexibility under dynamic market conditions. The Group's principal sources of liquidity are operating cash flows from its producing assets in Kurdistan and the North Sea. In addition to its operating cash flows, the Group relies on the debt capital markets for both short- and long-term funding. At yearend 2019, the Group had outstanding senior unsecured debt in the form of bonds totaling USD 961.2 million and had available EFF in an aggregate amount of NOK 1 billion (equivalent to USD 114 million as of 31 December 2019) with an accordion option of NOK 500 million (equivalent to USD 57 million as of 31 December 2019). In addition, the Group had available RBL in relation to its Norway and UK licenses with a total facility amount of USD 350 million. The Group's finance function prepares projections on a regular basis in order to plan the Group's liquidity requirements. These plans are updated regularly for various scenarios and form part of the basis for decision making for the Company's Board of Directors and executive management.

Excessive risk concentration

Concentrations arise when a number of counterparties are engaged in similar business activities, or activities in the same geographical region, or have economic features that would cause their ability to meet contractual obligations to be similarly affected by changes in economic, political or other conditions. DNO's revenues currently derive from production in the Tawke license in Kurdistan and from several licenses in the North Sea. The Group actively seeks to reduce such risk through organic growth and business and asset acquisitions aimed at further diversifying its revenue sources. The Faroe acquisition transformed DNO into a more diversified company with an additional source of revenue and potential business development opportunities and as such, the concentration risk is significantly reduced compared to previous years.

The tables below summarize the maturity profile of the Group's financial liabilities based on contractual undiscounted cash flows.

USD million At 31 December 2019	On demand	Less than 3 months	3 to 12 months	1 to 3 years	Over 3 years
Interest-bearing liabilities*	-	18.0	287.0	144.0	936.0
Other liabilities	-	13.1	14.8	-	-
Taxes payable	-	-	-	0.2	-
Trade and other payables	2.1	284.6	2.2	-	-
Total liabilities	2.1	315.7	304.0	144.2	936.0

USD million At 31 December 2018	On demand	Less than 3 months	3 to 12 months	1 to 3 years	Over 3 years
Interest-bearing liabilities*	-	10.1	46.4	313.8	414.6
Other liabilities	-	-	7.4	-	-
Taxes payable	-	0.5	-	-	-
Trade and other payables	4.9	50.9	-	-	-
Total liabilities	4.9	61.5	53.8	313.8	414.6

* Face value of the bond loans are USD 961.2 million at yearend 2019 (USD 600 million at yearend 2018).

For changes in liabilities arising from financing activities, see Note 15.

Credit risk

Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the Group. The Group's exposure to credit risk is mainly related to its outstanding trade debtors. Other counterparty credit risk exposure to DNO is related to its cash deposits with banks and financial institutions. The table below provides an overview of financial assets exposed to credit risk at yearend.

	Years ended 31 December
USD million	2019	2018
Trade and other receivables	478.5	209.8
Tax receivables	164.8	28.3
Cash and cash equivalents	485.7	729.1
Total	1,129.0	967.2

Trade debtors

In accordance with IFRS 9, receivables are recognized and carried at their anticipated realizable value, which implies that a provision for a loss allowance on lifetime expected credit losses (ELCs) of the receivable is recognized. A provision for loss allowance for ELCs is performed at each reporting date and is based on a multifactor and holistic analysis depending on several considerations. The Group considers reasonable and supportable information that is available without undue cost or effort and that is relevant for the assessment of credit risk.

Normal payment terms apply to amounts owed to DNO by the KRG for oil sales. DNO has received the payment due to it from oil sales on a monthly basis from the KRG since late 2015. One-off events may lead to short-term delays to payments, but the Company sees no significant increase in credit risk. As such, it is not considered necessary to provide for any loss allowance on credit losses. The table below shows the aging of trade debtors and information about credit risk exposure using a provision matrix.

	Contract	Days past due (trade debtors)
USD million	assets Current		< 30 days	30-60 days 61-90 days		> 90 days	Total
As of 31 December 2019
Trade debtors (Note 12)	-	130.1	63.9	54.8	52.3	-	301.1
Expected credit loss rate (percent)	-	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-	-
As of 31 December 2018
Trade debtors (Note 12)	-	109.9	72.9	-	-	-	182.8
Expected credit loss rate (percent)	-	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-	-

Of the total trade debtors of USD 301.1 million at yearend 2019, USD 298.2 million were owed by the KRG, see Note 12. The remaining USD 2.9 million were mainly related to oil and gas companies operating in the North Sea. Since yearend 2019, DNO has received payments for Tawke oil sales totaling USD 107.1 million net to DNO.

Cash deposits

Credit risk from balances with banks and financial institutions is managed by the Group's treasury function. The Group limits its counterparty credit risk by maintaining its cash deposits with multiple banks and financial institutions with high credit ratings.

Capital management

For the purpose of the Group's capital management, capital is defined as the total equity of DNO. The Group manages and adjusts its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximize shareholder value. If required, the capital structure may be adjusted through equity or debt transactions, asset restructuring or through a variety of other measures.

The Group monitors capital on the basis of the equity ratio, which is calculated as total equity divided by total assets. It is DNO's policy that this ratio should be 30 percent or higher. The financial covenants of the bond loans require a minimum of USD 40 million of liquidity and that the Group maintains either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million. In addition, the financial covenants of FAPE01 apply to the DNO North Sea plc sub-group and require a liquidity of minimum USD 15 million and at least USD 100 million in net assets for the sub-group.

There is also a restriction from declaring or making any dividend payments if the liquidity of the Company is less than USD 80 million immediately after such distribution is made, see Note 15. The equity ratio has declined primarily due to recognition of assumed liabilities from the Faroe acquisition and issuance of new bond loans. The table below shows the book equity ratio at yearend.

No changes were made in the objectives, policies or processes for managing capital during 2019 and 2018.

	Years ended 31 December
USD million	2019	2018
Total equity	1,161.3	1,217.8
Total assets	3,271.9	2,004.3
Equity ratio	35.5%	60.8%

Fair value measurement

Assets and liabilities for which fair value is measured or disclosed in the financial statements are categorized within the fair value hierarchy as described below.

Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2: inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3: inputs for the asset or liability that are not based on observable market data (unobservable inputs).

The following table shows the carrying amounts and fair values of financial assets and financial liabilities, including their levels in the fair value hierarchy. It does not include the carrying amounts and fair value information for financial assets and financial liabilities not measured or disclosed at fair value if the carrying amount is a reasonable approximation of fair value.

Carrying amount
		Financial assets designated	Financial liabilities at amortized		Fair value hierarchy
2019 - USD million	Note	at FVTOCI*	cost	Total	Date of valuation	Level 1	Level 2	Level 3
Financial assets measured or disclosed at fair value
Financial investments	11	21.0	-	21.0	31 December 2019	21.0	-	-
Financial assets not measured or disclosed at fair value
Trade and other receivables	12	-	-	-		-	-	-
Tax receivables	8	-	-	-		-	-	-
Cash and cash equivalents	13	-	-	-		-	-	-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)	15	-	836.0	836.0	31 December 2019	833.0	-	37.8
Interest-bearing liabilities (current)	15	-	225.6	225.6	31 December 2019	143.8	-	85.6
Financial liabilities not measured or disclosed at fair value
Trade and other payables	18	-	-	-		-	-	-
Income tax payable	8	-	-	-		-	-	-
Provisions for other liabilities and charges	16	-	-	-		-	-	-

* Financial assets designated at FVTOCI with no recycling of cumulative gains and losses upon derecognition (equity instruments).

Carrying amount
		Financial assets designated	Financial liabilities at amortized		Fair value hierarchy
2018 - USD million	Note	at FVTOCI	cost	Total	Date of valuation	Level 1	Level 2	Level 3
Financial assets measured or disclosed at fair value
Financial investments	11	230.8	-	230.8	31 December 2018	230.8	-	-
Financial assets not measured or disclosed at fair value
Trade and other receivables	12	-	-	-		-	-	-
Tax receivables	8	-	-	-		-	-	-
Cash and cash equivalents	13	-	-	-		-	-	-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)	15	-	575.7	575.7	31 December 2018	596.8	-	-
Interest-bearing liabilities (current)	15	-	18.4	18.4	31 December 2018	-	-	18.4
Financial liabilities not measured or disclosed at fair value
Trade and other payables	18	-	-	-		-	-	-
Income tax payable	8	-	-	-		-	-	-
Provisions for other liabilities and charges	16	-	-	-		-	-	-

Depreciation, depletion and amortization (DD&A) is charged to cost of goods sold in the statements of comprehensive income.

PROPERTY, PLANT AND EQUIPMENT

			Total
	Development	Production	oil & gas	Other	RoU
2019 - USD million	assets	assets	assets	PP&E	assets	Total
As of 1 January 2019
Acquisition costs	42.1	2,019.6	2,061.7	17.6	-	2,079.3
Accumulated impairments	-42.1	-286.1	-328.2	-0.1	-	-328.4
Accumulated depreciation	-	-976.8	-976.8	-16.0	-	-992.8
Net book amount	-	756.7	756.7	1.4	-	758.1
Period ended 31 December 2019
Opening net book amount	-	756.7	756.7	1.4	-	758.1
Implementation of new IFRS standard	-	-	-	-	12.9	12.9
Translation differences	-2.1	1.2	-0.9	0.1	-0.1	-0.9
Additions*	26.9	358.8	385.7	0.3	2.8	388.7
Business combinations**	202.7	501.8	704.5	-	2.0	706.5
Transfers	-	-	-	-	-	-
Disposals acquisition costs***	-149.2	-332.7	-481.9	-	-	-482.0
Disposals depreciation/impairments***	-	322.9	322.9	-	-	323.0
Impairments	-	-48.5	-48.5	-	-	-48.5
Depreciation	-	-303.1	-303.1	-1.8	-3.5	-308.4
Closing net book amount	78.3	1,257.1	1,335.4	0.1	14.0	1,349.5
As of 31 December 2019
Acquisition costs	120.4	2,871.6	2,992.0	18.0	17.5	3,027.5
Accumulated impairments	-42.1	-334.6	-376.7	-0.1	-	-376.9
Accumulated depreciation	0.0	-1,279.9	-1,279.9	-17.8	-3.5	-1,301.2
Net book amount	78.3	1,257.1	1,335.4	0.1	14.0	1,349.5

Depreciation method UoP 3-7 years linear

* Includes changes in estimate of asset retirement, see Note 16.

** For business combinations, see Note 25.

*** Disposal under development assets is related to assets divested as part of the Equinor Assets Swap, see Note 25. Disposal under production assets is mainly related to Oman.

DD&A is charged to cost of goods sold in the statements of comprehensive income.

INTANGIBLE ASSETS

					Total Other
2019 - USD million	Goodwill	License interest	Exploration assets	Other	intangible assets	Total
As of 1 January 2019
Acquisition costs	-	103.9	17.4	11.2	132.5	132.5
Accumulated impairments	-	-20.1	-10.8	-	-30.9	-30.9
Accumulated depreciation	-	-60.8	-	-8.0	-68.8	-68.8
Net book amount	-	23.1	6.5	3.2	32.8	32.8
Period ended 31 December 2019
Opening net book amount	-	23.1	6.5	3.2	32.8	32.8
Translation differences	-18.2	-	-7.0	-	-7.0	-25.3
Additions	-	-	66.2	2.6	68.8	68.8
Business combinations*	553.4	-	268.1	-	268.1	821.5
Transfers	-	-	-	-	-	-
Disposals cost price**	-72.6	-8.1	-5.3	-	-13.4	-86.0
Disposals impairments/depreciation	-	8.1	5.1	-	13.2	13.2
Exploration cost capitalized in previous years carried to cost	-15.3	-	-12.6	-	-12.6	-27.8
Impairments	-113.5	-	-	-	-	-113.5
Depreciation	-	-2.8	-	-0.6	-3.4	-3.4
Closing net book amount	333.9	20.3	321.1	5.3	346.6	680.5
As of 31 December 2019
Acquisition costs	462.6	95.7	339.4	13.8	448.9	911.5
Accumulated impairments	-128.8	-12.0	-18.3	-	-30.2	-159.0
Accumulated depreciation	-	-63.6	-	-8.6	-72.1	-72.2
Net book amount	333.9	20.3	321.1	5.3	346.6	680.5
Depreciation method		UoP		3 - 7 years linear

* For business combinations, see Note 25.

** Disposal acquisition costs under goodwill is related to assets divested as part of the Equinor Assets Swap, see Note 25.

For pledges over the North Sea oil and gas assets, see Note 15.

PROPERTY, PLANT AND EQUIPMENT

			Total
	Development	Production	oil & gas	Other	RoU
2018 - USD million	assets	assets	assets	PP&E	assets	Total
As of 1 January 2018
Acquisition costs	42.1	1,869.1	1,911.2	21.1	-	1,932.3
Accumulated impairments	-42.1	-286.1	-328.2	-0.1	-	-328.2
Accumulated depreciation	-	-724.9	-724.9	-15.8	-	-740.7
Net book amount	-	858.1	858.1	5.2	-	863.3
Period ended 31 December 2018
Opening net book amount	-	858.1	858.1	5.2	-	863.3
Translation differences	-	-	-	-0.1	-	-0.1
Additions*	-	148.8	148.8	0.4	-	149.3
Transfers	-	-	-	-2.8	-	-2.8
Disposal cost price	-	1.7	1.7	-1.3	-	0.4
Disposal impairments/depreciations	-	-1.7	-1.7	1.0	-	-0.7
Impairments	-	-	-	-	-	-
Depreciation	-	-250.3	-250.3	-1.1	-	-251.4
Closing net book amount	-	756.7	756.7	1.5	-	758.1
As of 31 December 2018
Acquisition costs	42.1	2,019.6	2,061.7	17.6	-	2,079.3
Accumulated impairments	-42.1	-286.1	-328.2	-0.1	-	-328.3
Accumulated depreciation	-	-976.8	-976.8	-16.0	-	-992.8
Net book amount	-	756.7	756.7	1.5	-	758.1

Depreciation method UoP 3-7 years linear

* Includes changes in estimate of asset retirement, see Note 16.

INTANGIBLE ASSETS

				Total Other
2018 - USD million Goodwill	License interest	Exploration assets	Other	intangible assets	Total
As of 1 January 2018
Acquisition costs -	103.8	10.8	-	114.6	114.6
Accumulated impairments -	-19.7	-10.8	-	-30.5	-30.5
Accumulated depreciation -	-52.8	-	-	-52.8	-52.8
Net book amount -	31.4	-	-	31.4	31.4
Period ended 31 December 2018
Opening net book amount -	31.4	-	-	31.4	31.4
Translation differences -	-	-0.1	-	-0.1	-0.1
Additions -	0.1	6.6	1.2	7.9	7.9
Transfers -	-	-	2.8	2.8	2.8
Disposal cost price -	-	-	-	-	-
Disposal impairments/depreciations -	-	-	-	-	-
Impairments -	-0.4	-	-	-0.4	-0.4
Depreciation -	-7.9	-	-0.8	-8.7	-8.7
Closing net book amount -	23.1	6.5	3.2	32.8	32.8
As of 31 December 2018
Acquisition costs -	103.9	17.4	11.2	132.6	132.6
Accumulated impairments -	-20.1	-10.8	-	-30.9	-30.9
Accumulated depreciation -	-60.8	-	-8.0	-68.8	-68.8
Net book amount -	23.1	6.5	3.2	32.8	32.8

Depreciation method UoP 3 - 7 years linear

Impairment testing

At each reporting date, the Group assesses whether there is an indication that an asset may be impaired. An assessment of the recoverable amount is made when an impairment indicator exists. Goodwill is tested for impairment annually or more frequently when there are impairment indicators. Impairment is recognized when the carrying amount of an asset or a CGU, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and the value in use. Impairment assessment of DNO's assets in Kurdistan is based on the value in use approach. For oil and gas assets and goodwill recognized in relation to the acquisition of Faroe, the impairment assessment at yearend 2019 was based on the fair value approach (level 3 in fair value hierarchy, IFRS 13). For both the value in use and fair value, the impairment testing is performed based on discounted cash flows. The expected future cash flows are discounted to the net present value by applying a discount rate after tax. Cash flows are projected for the estimated lifetime of the fields or license, which may exceed periods longer than five years.

Below is an overview of the key assumptions applied for impairment assessment purposes as of 31 December 2019.

Oil and gas prices

Forecasted oil and gas prices are based on management's estimates and market data. This includes consideration of forward curve pricing over the period for which there is deemed to be a sufficient liquid market (first year), price forecasts that are based on observable broker and analyst consensus (next four years) and thereafter prices are inflated by two percent per year.

The nominal oil and gas price assumptions used for impairment assessments at yearend 2019 were as follows:

	2020	2021	2022	2023	2024	2025
Brent Blend (USD/bbl)	63.7	64.2	66.7	69.5	71.6	73.0
NBP (pence/therm)	36.7	47.5	47.9	48.7	50.0	51.0

Oil and gas price differential

The estimated net oil and gas price is based on the above nominal price assumptions adjusted for price differentials due to quality and transportation for each individual field.

Oil and gas reserves and resources

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves, and additional risked contingent resources when the impairment assessments are based on the fair value approach. For more information about reserves and resources estimate, see Note 1 and Note 23.

Discount rate

The discount rate is derived from the Company's weighted average cost of capital (WACC). Main elements of the WACC include:

• For the value in use calculations, the capital structure considered in the WACC calculation is derived from DNO's debt and equity to enterprise value ratio at yearend. For the fair value calculations, the capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures.
• The cost of equity is calculated on a country-by-country basis using the Capital Asset Pricing Model (CAPM) and adding a country risk premium. The beta factor is based on publicly available data about the Company's beta in the value in use calculations, whereas the beta factors used for the fair value calculations are based on publicly available market data about the identified peer group.
• For the value in use calculations, the cost of debt is based on yield-to-maturity on the Company's outstanding bond loans with an upward adjustment to reflect a potential extension, whereas for fair value calculations the cost of debt is based on an identified peer group's bond loan issues.

For the value in use calculations, the relevant post-tax nominal discount rates at yearend 2019 were 13.0 percent (14.8 percent at yearend 2018) for the Kurdistan assets, 7.4 percent for the Norway assets and 8.1 percent for the UK assets. For the fair value calculations, the relevant post-tax nominal discount rates at yearend 2019 were 7.5 percent for the Norway assets and 8.1 percent for the UK assets.

Inflation and currency rates

The long-term inflation rate is assumed to be 2.0 percent independent of the underlying country or currency, which is unchanged from 2018. DNO has applied the forward curve for currency rates for year 2020 and kept a constant exchange rate thereafter.

Impairment charge and reversal

The following table shows the recoverable amount and carrying amount for the CGUs which were impaired in 2019 and 2018.

Impairments	Impairment (-)/	2019 Recoverable/ carrying	Impairment (-)/	2018 Recoverable/ carrying
USD million	reversal (+)	amount	reversal (+)	amount
Erbil license, Kurdistan	-12.8	-	-	16.2
Brasse, North Sea	-89.4	39.6	-	-
Ringhorne East, North Sea	-13.9	41.7	-	-
Schooner and Ketch, North Sea	-32.6	-	-	-
Other CGUs	-13.3	61.8	-1.9	-
Total	-162.0	143.1	-1.9	16.2

During 2019, a total impairment charge of USD 162.0 million was recognized, of which USD 13.9 million was related to impairment of technical goodwill with no tax impact on the Ringhorne East field in the North Sea, triggered by updated production profiles, USD 89.4 million was related to impairment of technical goodwill with no tax impact on the Brasse discovery in the North Sea, triggered by a reduction in reserves estimates, USD 32.6 million was related to an upward revision in the cost estimate for decommissioning the Schooner and Ketch fields in the North Sea, USD 12.8 million was related to an impairment of the Erbil license in Kurdistan as DNO plans to relinquish operatorship and participation in the Erbil license effective from 21 May 2020 and USD 13.3 million was related to other CGUs.

During 2018, the impairment charge of USD 1.9 million was comprised of the SL18 exploration license in Somaliland (USD 0.4 million) and the Sfax Offshore Exploration Permit in Tunisia (USD 1.5 million). DNO exited these licenses in 2018.

Sensitivities

The table below illustrates how oil and gas assets would have been affected by changes in the various assumptions, holding the remaining assumptions unchanged. The estimated recoverable amount related to the Tawke license is substantially higher than the carrying amount and the same sensitivity tests would not imply any impairment charges.

	Change in oil and gas assets:
Assumption (USD million)	Change	Increase in assumption:	Decrease in assumption:
Oil and gas price	+/- 15%	17.9	-109.2
Production profile (reserves and resources)	+/- 5%	11.0	-27.2
Decommissioning cost estimate	+/- 15%	22.7	-22.7
Discount rate (WACC)	+/- 1%	-19.9	8.7
Currency rate (USD/NOK)	+/- 1.0 NOK	18.4	-73.2

License expiry for development and production assets

In Kurdistan, the Tawke license expires in 2026 but DNO has the right to one automatic five-year extension (i.e., to 2031) and, if commercial production is still possible, DNO is entitled to, upon request to the KRG, a further five-year extension (i.e., to 2036). Based on DNO's current assessments, production from the Tawke license will be commercial for the duration of its contractual term and through subsequent extensions. In the North Sea, the following relevant license expiry dates applied in relation to yearend 2019 impairment assessments; the Ula Area licenses have license expiry dates that ranges between 2027 and 2036; the Ringhorne East license expires in 2030; the Brage license expires in 2030; the Trym license expires in 2027; the Alve license expires in 2029; the Marulk license expires in 2025; the Vilje license expires in 2021 (subject to extension); the Enoch license expires in 2024; the East Foinaven license expires in 2029; and the Fenja license expires in 2039.

Note 11 Financial investments

Financial investments are comprised of equity instruments and are recorded at fair value (market price, where available) at the end of the reporting period. Fair value changes are included in other comprehensive income (FVTOCI), see Note 1 for details.

	Years ended 31 December
USD million	2019	2018
Book value as of 1 January	230.8	17.4
Additions	226.3	201.3
Fair value changes through other comprehensive income (FVTOCI)	25.8	12.1
Disposals	-461.8	-
Book value as of 31 December	21.1	230.8
Financial investments include the following:
USD million	2019	2018
Listed shares:

Faroe Petroleum plc	-	209.2
Panoro Energy ASA	-	3.6
Total financial investments	21.0	230.8

At yearend 2019, the Company held a total of 15,849,737 shares (4.8 percent of total issued Class A shares) in RAK Petroleum. RAK Petroleum is listed on the Oslo Stock Exchange. Through its subsidiary, RAK Petroleum Holdings B.V., RAK Petroleum is the largest shareholder in DNO ASA with 40.45 percent of the total issued shares, see Note 14. The Company's Executive Chairman Bijan Mossavar-Rahmani, the largest shareholder in RAK Petroleum, also serves as Executive Chairman of RAK Petroleum. Change in fair value is recognized in other comprehensive income with USD 3.1 million in 2019 (USD 0.5 million in 2018).

During 2018, the Company acquired 111,494,028 shares in Faroe which represented 29.9 percent of the outstanding shares at yearend 2018. At yearend 2018, Faroe was listed on the UK's AIM of the London Stock Exchange. On 11 January 2019, the Company obtained control of Faroe and subsequently de-listed the company from the AIM on 14 February 2019, see Note 25. Change in fair value prior to control being obtained was USD 19.6 million and is recognized in other comprehensive income in 2019 (USD 10.5 million in 2018).

On 8 November 2019, the Company sold its shareholding in Panoro Energy ASA (Panoro). Changes in fair value up until the sale of shares was USD 3.1 million and is recognized in other comprehensive income in 2019 (USD 0.6 million in 2018).

Disposals relate to the step acquisition of Faroe and the sale of the Company's shares in Panoro. Prior to DNO obtaining control, the acquisition of Faroe shares was accounted for as an equity instrument.

Note 12 Trade and other receivables

		Years ended 31 December
USD million	2019	2018
Trade debtors	301.1	182.8
Underlift	37.6	1.1
Other short-term receivables	139.8	25.9
Total trade and other receivables	478.5	209.8

The trade debtors at yearend 2019 relate mainly to oil deliveries from the Tawke license in Kurdistan for the period August through December 2019. DNO has since yearend received payments for Tawke oil sales for August and September 2019, totaling USD 107.1 million net to DNO.

The underlift receivable of USD 37.6 million at yearend 2019 relates mainly to DNO's North Sea licenses, valued at production cost including depreciation, which will be realized based on market value when the volumes are lifted. Other short-term receivables mainly relate to items of working capital in licenses in Kurdistan and the North Sea and accrual for earned income not invoiced in the North Sea.

Note 13 Cash and cash equivalents

		Years ended 31 December
USD million	2019	2018
Cash and cash equivalents, restricted	14.3	3.2
Cash held in restricted account, Faroe offer	-	418.1
Cash and cash equivalents, non-restricted	471.5	307.8
Total cash and cash equivalents	485.7	729.1

Restricted cash consists of deposits on escrow account, employees' tax withholdings and deposits for rent.

In November 2018, in compliance with the UK regulations, the Company was required to present a guarantee of available funds to complete the settlement of the Faroe offer. The guarantee was issued by a bank backed by the transfer of an amount of USD 418.1 million to a deposit account held in the name of the Company and pledged in favor of the bank. The guarantee was cancelled in February 2019 following the acquisition of over 98 percent of the Faroe shares.

Non-restricted cash is entirely related to bank deposits in USD, NOK, GBP, EUR and DKK as of 31 December 2019.

Note 14 Equity

	Share capital
--	---------------

USD million	Number of shares (1,000)	Ordinary shares	Treasury shares	Total
As of 1 January 2018	1,048,814	36.0	-1.0	35.0
Treasury shares sold/-purchased	-	-	-	-
Share issues	-	-	-	-
As of 31 December 2018	1,048,814	36.0	-1.0	35.0

	Number of	Ordinary	Treasury
USD million	shares (1,000)	shares	shares	Total
As of 1 January 2019	1,048,814	36.0	-1.0	35.0
Treasury shares sold/-purchased	-58,700.0	-	-1.6	-1.6
Share issues	-	-	-	-
As of 31 December 2019	990,114	36.0	-2.6	33.3

Total outstanding shares were 990,114,161 at par value of NOK 0.25 per share as of 31 December 2019. All shares have equal rights.

At the 2019 AGM, the Board of Directors was given the authority to increase the Company's share capital by up to NOK 40,643,031, which corresponds to 162,572,124 new shares. The authorization is valid until the 2020 AGM, but not beyond 30 June 2020; the shareholders' preferential rights to the new shares pursuant to section 10-4 in the Norwegian Public Limited Liability Companies Act may be waived. The Board of Directors was also given the authority to acquire treasury shares with a total nominal value of up to NOK 27,095,354. The maximum amount to be paid per share is NOK 100 and the minimum amount is NOK 1. Purchases of treasury shares are made on the Oslo Stock Exchange. The authorization is valid until the 2020 AGM, but not beyond 30 June 2020.

The Board of Directors was also given the authority to raise convertible bonds with an aggregate principal amount of up to USD 300,000,000, see also Note 15. Upon conversion of bonds issued pursuant to this authorization, the Company's share capital may be increased by up to NOK 40,643,031. The authorization is valid until the AGM in 2020, but not beyond 30 June 2020.

As of 31 December 2019, the Company held 93,700,000 treasury shares. See also Note 22 for information on the cancellation of treasury shares in February 2020.

Note 14

Equity

Other reserves

		Other paid-in
	Share	capital/other	Currency
USD million	premium	reserves	translation	Total
Balance as of 1 January 2018	247.7	50.6	-35.5	262.7
Treasury shares:	-	-	-	-
- Sale of treasury shares	-	-	-	-
- Purchase of treasury shares	-	-	-	-
Issue of share capital	-	-	-	-
Payment of dividend	-	-25.8	-	-25.8
Currency translation differences - Group	-	-	2.6	2.6
Transfers		-
Balance as of 31 December 2018	247.7	24.7	-32.9	239.6
Balance as of 1 January 2019	247.7	24.7	-32.9	239.6
Treasury shares:	-	-	-	-
- Sale of treasury shares	-	-	-	-
- Purchase of treasury shares	-	-80.7	-	-80.7
Issue of share capital	-	-	-	-
Payment of dividend	-	-46.6	-	-46.6
Currency translation differences - Group	-	-	-3.7	-3.7
Transfer from retained earnings	-	72.4	-	72.4
Balance as of 31 December 2019	247.7	-30.2	-36.6	181.0

		Interest
The Company's shareholders as of 31 December 2019	Shares	(percent)
RAK Petroleum Holdings B.V.	438,379,418	40.45
Folketrygdfondet	22,667,793	2.09
State Street Bank and Trust Comp (Nominee)	21,859,928	2.02
Verdipapirfondet Pareto Investment	11,300,000	1.04
JPMorgan Chase Bank, N.A., London (Nominee)	10,588,197	0.98
State Street Bank and Trust Comp (Nominee)	8,237,338	0.76
JPMorgan Chase Bank, N.A., London (Nominee)	5,902,015	0.54
Nordnet Bank AB (Nominee)	5,498,621	0.51
Verdipapirfondet Nordea Kapital	5,016,256	0.46
Citibank N.A (Nominee)	4,934,987	0.46
Citibank N.A (Nominee)	4,801,785	0.44
Storebrand Norge I Verdipapirfond	4,559,431	0.42
Citibank N.A (Nominee)	4,541,893	0.42
Verdipapirfondet Nordea Avkastning	4,460,833	0.41
Ayanza Bank AS (Nominee)	4,098,398	0.38
HSBC Trinkaus & Burkhardt AG (Nominee)	4,006,324	0.37
J.P.Morgan Bank Luxenbourg S.A (Nominee)	3,721,885	0.34
Univest	3,497,540	0.32
Citibank N.A (Nominee)	3,391,712	0.31
Credit Suisse Securitites (Nominee)	3,343,902	0.31
Other shareholders	415,305,905	38.32
Total number of shares excluding treasury shares	990,114,161	91.35
Treasury shares as of 31 December 2019 (DNO ASA)	93,700,000	8.65
Total number of shares including treasury shares	1,083,814,161	100.00

A total dividend of USD 46.6 million was distributed in 2019 (USD 25.8 million in 2018).

Note 15 Interest-bearing liabilities

						Effective interest	Fair value		Carrying amount
	Ticker	Facility	Facility	Interest		rate
USD million	OSE	currency	amount	(percent)	Maturity	(percent)	2019	2018	2019	2018
Non-current
Bond loan (ISIN NO0010740392)	DNO01	USD	140.0	8.750	18.06.20	12.5	-	200.5	-	200.0
Bond loan (ISIN NO0010823347)	DNO02	USD	400.0	8.750	31.05.23	9.7	408.6	396.3	400.0	400.0
Bond loan (ISIN NO0010852643)	DNO03	USD	400.0	8.375	29.05.24	9.0	401.6	-	400.0	-
Bond loan (ISIN NO0010811268)	FAPE01	USD	21.2	8.000	28.04.23	8.9	22.7	-	21.2	-
Capitalized borrowing issue costs									-23.0	-24.3
Reserve based lending facility	-	USD	350.0	see below	07.11.26	-	37.8		37.8	-
Total non-current interest-bearing liabilities							870.8	596.8	836.0	575.7
Current
Bond loan (ISIN NO0010740392)	DNO01	USD	140.0	8.750	18.06.20	12.5	143.8	-	140.0	-
Exploration financing facility	-	NOK	1,000.0	see below	see below	-	85.6	18.4	85.6	18.4
Total current interest-bearing liabilities							229.4	18.4	225.6	18.4
Total interest-bearing liabilities							1,100.1	615.2	1,061.6	594.1

All the bonds are issued by DNO ASA except for FAPE01 which is issued by the Company's subsidiary, DNO North Sea plc. The facility amount and carrying amount for FAPE01 is shown net of bonds held by DNO ASA.

On 29 May 2019, DNO ASA completed the placement of USD 400 million of a new, five-year senior unsecured bond issued at 100 percent of par with a coupon rate of 8.375 percent. In connection with the bond placement, the Company agreed to buy back USD 60 million in nominal value of DNO01 at 104.16 percent of par plus accrued interest. The financial covenants of the bonds issued by DNO ASA require minimum USD 40 million of liquidity, and that the Group maintains either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million. There is also a restriction on declaring or making any dividend payments if the liquidity of the Company is less than USD 80 million immediately following such distribution. The financial covenants of FAPE01 apply to the DNO North Sea plc sub-group and require a liquidity of minimum USD 15 million and at least USD 100 million in net assets.

During 2019, DNO ASA acquired USD 64.6 million of FAPE01 bonds at a price range of 107.25 to 107.50 percent of par plus accrued interest.

The Group has available a revolving exploration financing facility (EFF) with a total amount of NOK 1 billion. An additional tranche of NOK 500 million is available on an uncommitted accordion basis. Utilization requests need to be delivered for each proposed loan. The facility is secured against the Norwegian tax refund and is repaid when the refund is received which is approximately 11 months after the end of the financial year. The interest rate equals NIBOR plus a margin of 1.70 percent. Utilizations can be made until 31 December 2022. Amount utilized as of the reporting date is disclosed in the table above.

The Group has a reserve based lending (RBL) facility in relation to its Norway and UK licenses with a total facility amount of USD 350 million which is available for both debt and issuance of letters of credit. An additional tranche of USD 350 million is available on an uncommitted accordion basis. Interest charged on utilizations is based on the LIBOR, NIBOR or EURIBOR rates (depending on the currency of the drawdown) plus a margin ranging from 2.75 to 3.25 percent. The facility will amortize over the loan life with a final maturity date of 7 November 2026. The security under the RBL includes, without limitation, a pledge over the shares in DNO North Sea plc and its subsidiaries, assignment of claims under shareholder loans, intra-group loans and insurances, a pledge of certain bank accounts and mortgages over the license interests. There are also restrictions on loans and dividend payments to DNO ASA. The amount utilized as of the reporting date is disclosed in the table above. In addition, USD 90.6 million is utilized in respect of letters of credit.

The current EFF and RBL facilities were established on 7 November 2019 and replaced previous facilities.

There have been no breaches of the financial covenants of any interest-bearing liability in the current period.

The short-term bank credit facility of USD 200 million which the Group had available was cancelled in November 2019.

Note 15 Interest-bearing liabilities

Changes in liabilities arising from financing activities split on cash and non-cash changes

	At 1 Jan	Cash	Non-cash changes			At 31 Dec
USD million	2019	flows	Amortization	Currency	Acquisition	2019
Bond loans	600.0	261.2	-	-	100.0	961.2
Borrowing issue costs	-24.3	-8.6	9.9	-	-	-23.0
Reserve based lending facility	-	37.4	-	0.4	-	37.8
Exploration financing facility	18.4	50.3	-	-0.9	17.7	85.6
Total	594.1	340.3	9.9	-0.5	117.7	1,061.6
	At 1 Jan	Cash	Non-cash changes			At 31 Dec
USD million	2018	flows	Amortization	Currency	Acquisition	2018
Bond loans	400.0	200.0	-	-	-	600.0
Borrowing issue costs	-27.2	-10.5	13.4	-	-	-24.3
Exploration financing facility	17.6	3.4	-	-2.6	-	18.4
Total	390.4	192.9	13.4	-2.6	-	594.1

Note 16 Provisions for other liabilities and charges/Lease liabilities

		Years ended 31 December
USD million	2019	2018
Non-current
Asset retirement obligations (ARO)	415.7	49.4
Other long-term obligations	7.1	18.7
Total non-current provisions for other liabilities and charges	422.8	68.1
Lease liabilities	11.1	-
Total non-current lease liabilities	11.1	-
Current
Asset retirement obligations (ARO)	77.1	-
Other provisions and charges	27.9	7.4
Total current provisions for other liabilities and charges	105.1	7.4
Current lease liabilities	3.3	-
Total current lease liabilities	3.3	-
Total provisions for other liabilities and charges and lease liabilities	542.3	75.6

Asset retirement obligations

The provisions for ARO are based on the present value of estimated future cost of decommissioning oil and gas assets in Kurdistan and the North Sea. The discount rates before tax applied at yearend 2019 were between 3.5 percent and 3.7 percent (4.0 percent in 2018). The credit margin included in the discount rates at yearend 2019 was 1.9 percent.

The increase in ARO provisions in 2019 compared to 2018 is primarily due to the recognition of ARO provisions from the Faroe transaction.

Note 16 Provisions for other liabilities and charges/Lease liabilities

	Asset retirement	Other non
USD million	obligations	current
Provisions as of 1 January 2018	31.9	13.8
Increase/-decrease in existing provisions	1.8	1.9
Amounts charged against provisions	-	-0.4
Effects of change in the discount rate	17.4	1.6
Accretion expenses (unwinding of discount)	1.2	0.6
Reclassification and transfer	-2.8	1.1
Provisions as of 31 December 2018	49.4	18.7
ARO provisions from business combinations	406.8	-
ARO provisions divested assets	-7.6	-
Decommissioning spend	-21.5	-
Increase/-decrease in existing provisions	32.9	-12.4
Amounts charged against provisions	-	0.2
Effects of change in the discount rate	15.7	-
Accretion expenses (unwinding of discount)	18.0	-
Reclassification and transfer	-0.8	0.6
Provisions as of 31 December 2019	492.8	7.1

Lease liabilities

On transition to IFRS 16, the Group recognized USD 12.7 million as lease liabilities. The identified lease liabilities have no significant impact on the Group's financing, loan covenants or dividend policy. The Group does not have any residual value guarantees. Extension options are included in the lease liability when, based on the management's judgement, it is reasonably certain that an extension will be exercised.

The following table shows the undiscounted non-cancellable minimum lease obligations that are not recognized in the financial position:

		1 January - 31 December
USD million	2019	2018
Within one year	4.4	3.7
Two to five years	13.0	15.0
After five years	-	-
Total undiscounted lease liabilities end of the period	17.5	18.6

The Group's future minimum lease payments under non-cancellable operating leases are related to office rent including warehouse and equipment. The difference between the recognized lease liabilities in the financial position and the undiscounted lease liabilities is due to discounting and adjustment for short-term leases and low-value leases. The Group's lease contracts related to drilling rigs in Kurdistan are cancellable and are therefore not included in the lease table above or recognized as lease liabilities. The estimated value of leases related to these cancellable contracts was USD 18 million (gross, undiscounted) at yearend 2019 (USD 16 million at yearend 2018).

Note 17 Commitments and contingencies

Contingent liabilities and contingent assets

Disputes with Ministry of Oil and Minerals of Yemen – Block 53, Block 43 and Block 32

The Ministry of Oil and Minerals (MOM) of Yemen filed an arbitration claim against operator Dove Energy and the other partners (including DNO Yemen AS) for allegedly wrongful withdrawal from Block 53. An arbitral award was rendered in July 2019 partially in the Ministry's favor in the amount of USD 29 million (out of a USD 171 million claim). DNO Yemen AS has filed for annulment proceedings in the Paris Court of Appeals. A provision of USD 14 million was recognized at yearend 2019 related to this arbitration award.

DNO Yemen AS was involved in a dispute with MOM with respect to DNO Yemen AS' relinquishment of Block 43 in 2016. An arbitral award was rendered on 18 February 2020 in DNO Yemen AS' favor for USD 6.8 million (almost entirely dismissing the USD 131 million counterclaim of the MOM). In accordance with IAS 37, the asset related to this arbitration award will be recognized in 2020.

DNO Yemen AS remains involved in a dispute with MOM with respect to DNO Yemen AS' relinquishment of Block 32 in 2016. In accordance with IAS 37.92, the Group does not provide further information with respect to this arbitration dispute and the associated risk for the Group, especially with regards to the measures taken in this context, in order not to impair the outcome of the proceedings. In accordance with IAS 37, no provision was made at yearend 2019 related to this dispute.

Unresolved issues following relinquishment of operatorship and participation in Oman Block 8

On 3 January 2019, the Company announced that its subsidiary DNO Oman Block 8 Limited had relinquished operatorship and participation in Oman Block 8 to the Oman's Ministry of Oil and Gas as a result of the expiry of the Exploration and Production Sharing Agreement (EPSA). DNO held a 50 percent interest in the license alongside LG International Corp. (LGI), which held the remaining 50 percent interest. The relinquishment has given rise to certain contested issues between Oman and the Contractor (DNO Oman Block 8 Limited and LGI) which are unresolved as of the reporting date. No provisions have been made at yearend 2019.

Other claims

During the normal course of its business, the Group may be involved in other legal proceedings and unresolved claims. The Group has made provisions in its consolidated financial statements for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37. Other than what is set out above, DNO is not aware of any governmental, legal or arbitral proceedings (including any such proceedings which are pending or threatened) initiated against DNO and which may have significant effects on DNO's results of operations, cash flows or financial position.

Capital commitments

Based on work plans as of 31 December 2019 and contingent on future market conditions including development in the oil price (see Note 22), the Group's estimated capital commitments at yearend amounted to USD 400 million. The estimated capital commitment figure reflects the Group's share of planned drilling and facility investments in its licenses and execution of these work plans is subject to revisions, see Note 22.

Guarantees as of 31 December 2019

The Company has issued parent company guarantees to authorities in Norway and the UK on behalf of certain subsidiaries that participate in licenses on the NCS and the UKCS. The Company, together with its partners, has issued a joint and several parent company guarantee to the KRG relating to the exploration work obligations that the parties will undertake in the Baeshiqa PSC.

Liability for damages/insurance

Installations and operations are covered by various insurance policies.

Note 18 Trade and other payables

	Years ended 31 December
USD million	2019	2018
Trade payables	62.8	46.0
Public duties payable	4.6	3.1
Prepayments from customers	50.1	-
Other accrued expenses	163.3	67.3
Total trade and other payables	288.9	116.4

Trade payables are non-interest bearing and are normally settled within 30 days.

Trade payables and other accrued expenses at yearend 2019 include items of working capital related to participation in licenses in Kurdistan and the North Sea and prepayment from customers in the North Sea.

Note 19 Earnings per share

	1 January - 31 December
	2019	2018
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)	73.5	354.3
Weighted average number of ordinary shares excluding treasury shares (millions)	1,036.4	1,048.8
Effect of dilution:
Options	-	-
Weighted average number of ordinary shares excluding treasury shares (millions)	1,036.4	1,048.8
Earnings per share, basic (USD per share)	0.07	0.34
Earnings per share, diluted (USD per share)	0.07	0.34

Basic earnings per share are calculated by dividing the net profit/-loss attributable to equity holders by the weighted average number of ordinary shares in issue during the period, excluding ordinary shares purchased and held as treasury shares.

The Company did not have any potential dilutive shares at yearend 2019.

Note 20 Group companies

		Ownership and voting
USD million	Office	interest (percent)
Shares in Company subsidiaries
DNO Iraq AS	Norway	100
DNO UK Limited	UK	100
DNO Invest AS	Norway	100
DNO Mena AS	Norway	100
DNO Oman AS	Norway	100
DNO Somaliland AS	Norway	100
DNO Technical Services AS	Norway	100
Northstar Exploration Holding AS	Norway	100
DNO Exploration UK Limited	UK	100
DNO Yemen AS	Norway	100
DNO North Sea plc	UK	100
Shares in subsidiaries owned through subsidiaries DNO Mena AS
DNO Al Khaleej Limited	Guernsey	100
DNO Oman Limited	Bermuda	100
DNO Oman Block 8 Limited	Guernsey	100
DNO Oman Block 30 Limited	Guernsey	100
DNO Technical Services Limited	Guernsey	100
DNO Tunisia Limited	Guernsey	100
DNO North Sea plc
DNO North Sea (Norge) AS	Norway	100
DNO Norge AS	Norway	100
DNO North Sea (UK) Limited	UK	100
DNO North Sea (ROGB) Limited	UK	100
DNO North Sea (Energy) Limited	UK	100
Færoya Kolventi P/F	Denmark	100
DNO North Sea SIP EBT Limited	UK	100

The Company's subsidiary DNO Iraq AS has operations in Kurdistan. Activities on the NCS are carried out through DNO Norge AS, while activities on the UKCS are carried out through DNO North Sea (UK) Limited and DNO North Sea (ROGB) Limited. DNO Technical Services AS and DNO North Sea plc provide technical support and services to the various companies in the Group. DNO North Sea (Norge) AS transferred its business to DNO Norge AS during 2019. The other subsidiaries had minimal activity during the year.

Note 21 Related party disclosure

The following table provides details of the Group's related party transactions in 2019. See also Note 5 on remuneration.

			1 January - 31 December
Related party (USD million)	Transaction	2019	2018
RAK Petroleum plc	Service agreement	-1.6	-1.3
Total related party transactions		-1.6	-1.3

RAK Petroleum, through its subsidiary RAK Petroleum Holdings B.V., is the Company's largest shareholder and the Company's Executive Chairman Bijan Mossavar-Rahmani also serves as Executive Chairman of RAK Petroleum. The Company has an agreement with RAK Petroleum for services including administrative and commercial support and other expenses. The total fee charged in 2019 was USD 1.6 million (USD 1.3 million in 2018).

There are additional transactions between Group companies, see Note 19 in the parent company accounts.

A portion of the overhead expenses in the Company are charged to the subsidiaries through the hourly rate for services provided by the Company.

Note 22 Significant events after the reporting date

DNO receives 10 awards in Norway's APA licensing round

On 14 January 2020, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which two are operatorships, under Norway's Awards in Predefined Areas (APA) 2019 licensing round. Of the 10 new licenses, five are in the North Sea, two in the Norwegian Sea and three in the Barents Sea.

Extraordinary general meeting held; resolution passed by shareholders

On 28 February 2020, the Company announced that shareholders overwhelmingly approved the resolution to cancel all 108,381,415 own shares held by the Company at an Extraordinary General Meeting. The cancelled shares represented 10 percent of the Company's shares issued.

Coronavirus outbreak

The outbreak of the coronavirus (COVID-19) and the significant decline in oil prices in the first quarter of 2020 will have adverse effects on the Group's operations and financial results this year, but the extent and duration of these conditions over the longer term remain largely uncertain and dependent on future developments that cannot be accurately predicted at this time. Both are considered nonadjusting events, as national and international responses to coronavirus and the failure of Saudi Arabia and Russia to agree on cuts in oil production to help bolster price occurred in 2020. Future oil price assumptions are key estimates in DNO's financial statements and a change in these assumptions may impact the recoverable amount of the Group's oil and gas assets, reserve and resource estimates, operational spend level, and distribution of future dividends. Continuing low oil prices may also reduce the Group's revenues and increase the credit risk related to the Group's trade receivables.

DNO is closely monitoring the impact of the ongoing COVID-19 pandemic, including on border closures, travel restrictions and interruptions to supply chains and third-party services, among others, and will implement measures to minimize the adverse impact on our staff, operations, liquidity and financial results

Note 23 Company Working Interest and net entitlement reserves (unaudited)

CWI reserves by region/field as of 31 December 2019

		Proven (1P)				Proven and probable (2P)				Proven, probable and possible (3P)
Mmboe	Oil	NGL	Gas	Total	Oil	NGL	Gas	Total	Oil	NGL	Gas	Total
Tawke	121.3	-	-	121.3	194.4	-	-	194.4	287.1	-	-	287.1
Peshkabir	35.6	-	-	35.6	80.3	-	-	80.3	150.8	-	-	150.8
Total Kurdistan	156.9	-	-	156.9	274.7	-	-	274.7	437.9	-	-	437.9
Blane (Ula area)	1.0	-	-	1.0	1.6	-	-	1.6	2.2	-	-	2.2
East Foinaven	0.1	-	-	0.1	0.1	-	-	0.1	0.2	-	-	0.2
Enoch	0.1	-	-	0.1	0.1	-	-	0.1	0.2	-	-	0.2
Total UK	1.2	-	-	1.2	1.8	-	-	1.8	2.6	-	-	2.6
Alve	0.6	0.9	3.4	4.9	0.8	1.3	4.7	6.8	1.0	1.5	5.6	8.1
Brage	1.5	0.1	0.2	1.7	2.2	0.2	0.3	2.6	3.5	0.3	0.4	4.3
Brasse	8.0	1.6	2.6	12.3	11.1	2.3	3.8	17.3	15.5	3.2	5.3	24.0
Fenja	4.1	0.2	1.0	5.3	5.1	0.3	1.4	6.8	6.1	0.7	1.9	8.7
Marulk	-	0.1	0.5	0.6	0.1	0.3	1.7	2.1	0.3	0.8	3.2	4.4
Ringhorne East	4.2	-	-	4.2	5.5	-	-	5.5	8.0	-	-	8.0
Oda (Ula area)	2.8	-	0.2	3.0	4.1	-	0.3	4.3	5.6	-	0.4	6.0
Tambar (Ula area)	3.2	0.1	0.5	3.7	5.0	0.2	0.8	5.9	7.6	0.3	1.3	9.2
Tambar East (Ula area)	-	-	-	-	0.2	-	-	0.2	0.2	-	-	0.3
Ula (Ula area)	8.1	0.2	-	8.3	11.0	0.3	-	11.3	15.9	0.5	-	16.4
Trym	0.2	-	1.0	1.3	0.5	-	1.9	2.4	1.0	-	4.2	5.2
Vilje	2.2	-	-	2.2	3.2	-	-	3.2	4.9	-	-	4.9
Total Norway	34.8	3.3	9.4	47.5	48.6	4.9	14.8	68.3	69.8	7.3	22.3	99.5
Total Group				205.6				344.8				539.9

Development of CWI reserves by segment

		Kurdistan			North Sea			Total Group
MMboe	1P	2P	3P	1P	2P	3P	1P	2P	3P
As of 1 January 2018	239.8	384.1	665.7	-	-	-	239.8	384.1	665.7
Production	-29.1	-29.1	-29.1	-	-	-	-29.1	-29.1	-29.1
Acquisitions	-	-	-	-	-	-	-	-	-
Divestments	-	-	-	-	-	-	-	-	-
Extensions and discoveries	-	-	-	-	-	-	-	-	-
New developments	-	-	-	-	-	-	-	-	-
Revision of previous estimates	28.9	21.2	-97.7	-	-	-	28.9	21.2	-97.7
As of 31 December 2018	239.7	376.1	538.9	-	-	-	239.7	376.1	538.9
Production	-31.9	-31.9	-31.9	-6.3	-6.3	-6.3	-38.2	-38.2	-38.2
Acquisitions	-	-	-	72.1	106.0	148.2	72.1	106.0	148.2
Divestments	-	-31.8	-62.3	-13.4	-18.4	-23.2	-13.4	-50.2	-85.6
Extensions and discoveries	-	-	-	-	-	-	-	-	-
New developments	-	-	-	-	-	-	-	-	-
Revision of previous estimates	-50.8	-37.8	-6.8	-3.7	-11.1	-16.6	-54.6	-48.9	-23.4
As of 31 December 2019	156.9	274.7	437.9	48.7	70.1	102.1	205.6	344.8	539.9

NE reserves by segment

		Kurdistan			North Sea			Total Group
MMboe	1P	2P	3P	1P	2P	3P	1P	2P	3P
As of 31 December 2018	88.0	133.8	163.0	-	-	-	88.0	133.8	163.0
As of 31 December 2019	59.9	95.6	120.2	48.7	70.1	102.1	108.5	165.8	222.2

Note 23 Company Working Interest and net entitlement reserves (unaudited)

The reserves are according to the Annual Statement of Reserves and Resources (ASRR) dated 17 March 2020, classified as in the Norwegian Petroleum Directorate class 1-3.

International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license in the Kurdistan region of Iraq containing the Tawke and Peshkabir fields. International petroleum consultants Gaffney, Cline & Associated (GCA) carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). The Company internally assessed the remaining licenses.

The estimation of oil and gas reserves involves uncertainty. The figures above represent management's best judgment of the most likely quantity of economically recoverable oil and gas estimated at yearend 2019, given the information at the time of reporting. The estimates have a large spread especially for fields for which there is limited data available. The uncertainty will be reduced as more information becomes available through production history and reservoir appraisal. In addition, for fields in the decline phase with limited remaining volumes, fluctuations in oil prices will have a significant impact on the profitability and hence the economic cut-off for production.

At yearend 2019, DNO's CWI 1P reserves stood at 205.6 MMboe, compared to 239.7 MMbbls at yearend 2018, after adjusting for production during the year and technical revisions, offset partly by reserves added through the acquisition of Faroe in 2019. On a 2P reserves basis, DNO's CWI reserves stood at 344.8 MMboe, compared to 376.1 MMboe at yearend 2018. On a 3P reserves basis, DNO's CWI reserves were 539.9 MMboe, compared to 538.9 MMbbls at yearend 2018. DNO's CWI 2C resources were 187.8 MMboe, compared to 76.8 MMboe at yearend 2018.

DNO's gross operated production in 2019 averaged 126,985 boepd, up from 117,607 boepd in 2018. DNO's CWI production in 2019 was 38.2 MMboe (of which 31.9 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in the UK), up from 29.9 MMboe in 2018 (of which 29.1 MMbbls in Kurdistan and the balance in Oman).

DNO's CWI yearend 2019 Reserve Life Index (R/P) stood at 5.4 years on a 1P reserves basis, 9.0 years on a 2P reserves basis and 14.1 years on a 3P reserves basis.

CWI and NE reserves in DNO's licenses governed by PSCs (Kurdistan and Yemen) are net to DNO after royalty and include DNO's additional share of cost oil covering its advances towards the government carried interest (if any). CWI reserves reflect pre-tax shares while NE reserves reflect post-tax shares. NE reserves are based on economic evaluation of the license agreements, incorporating projections of future production, costs and oil and gas prices. NE reserves may therefore fluctuate over time, even if there are no changes in the underlying gross and CWI volumes.

CWI and NE reserves in DNO's licenses not governed by PSCs (Norway and the UK) are equivalent and reflect pre-tax shares.

Following the Kurdistan Receivables Settlement Agreement effective 1 August 2017, DNO's interest in the Tawke license increased to 75 percent plus three percent of aggregate license revenues until 31 July 2022. CWI and NE reserves in the tables above include the reserves attributable to DNO from this settlement agreement.

Note 24 Oil and gas license portfolio

At yearend 2019, DNO held interests in three licenses in Kurdistan, all of which are PSCs. The Tawke PSC contains the producing Tawke and Peshkabir fields. The Erbil PSC contains the Benenan and Bastora fields. The Baeshiqa license contains two large structures with multiple independent stacked target reservoirs, including in the Cretaceous, Jurassic and Triassic formations.

At yearend 2019, DNO also held 87 offshore licenses in Norway, 12 offshore licenses in the UK, two offshore licenses in Netherlands, one offshore licence in Ireland and one license in Yemen.

As is customary in the oil and gas industry, most of the Group's assets are held in partnership with other companies. Below is an overview of the Group's licenses, which are held through several wholly-owned subsidiary companies.

As of 31 December 2019:

Region/license	Participating interest (percent)	Operator	Partner(s)
Kurdistan
Tawke PSC	75.0	DNO Iraq AS	Genel Energy International Limited
Erbil PSC	40.0	DNO Iraq AS	Gas Plus Erbil Limited, Kurdistan Regional Government
Baeshiqa PSC	32.0	DNO Iraq AS	ExxonMobil Kurdistan Region of Iraq Limited, Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL006 C	85.0	DNO Norge AS	Aker BP ASA
PL006 E	85.0	DNO Norge AS	Aker BP ASA
PL006 F	85.0	DNO Norge AS	Aker BP ASA
PL018 ES	11.7	Total E&P Norge AS	DNO Norge AS
PL019	20.0	Aker BP ASA	DNO Norge AS
PL019 E	20.0	Aker BP ASA	DNO Norge AS
PL019 H	20.0	Aker BP ASA	DNO Norge AS
PL036 D	28.9	Aker BP ASA	DNO Norge AS, PGNiG Upstream Norway AS
PL048 D	9.3	Equinor Energy AS	DNO Norge AS, Aker BP ASA, CapeOmega AS
PL053 B	14.3	Wintershall Dea Norge AS	DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055	14.3	Wintershall Dea Norge AS	DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055 B	14.3	Wintershall Dea Norge AS	DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055 D	14.3	Wintershall Dea Norge AS	DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL065	45.0	Aker BP ASA	DNO Norge AS
PL065 B	45.0	Aker BP ASA	DNO Norge AS
PL1006	30.0	Equinor Energy AS	DNO Norge AS
PL1007	40.0	DNO Norge AS	OMV (Norge) AS, Spirit Energy Norway AS, Equinor Energy AS
PL1015	30.0	INEOS E&P Norge AS	DNO Norge AS
PL1021	50.0	Wintershall Dea Norge AS	DNO Norge AS
PL1022	30.0	Aker BP ASA	DNO Norge AS, Concedo ASA
PL1024	30.0	Repsol Norge AS	DNO Norge AS
PL1027	20.0	Lundin Norway AS	DNO Norge AS, Wintershall Dea Norge AS, INPEX Norge AS
PL1029	40.0	Lundin Norway AS	DNO Norge AS, Spirit Energy Norway AS
PL122	17.0	Vår Energi AS	DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 B	17.0	Vår Energi AS	DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 C	17.0	Vår Energi AS	DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 D	17.0	Vår Energi AS	DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL147	50.0	DNO Norge AS	Spirit Energy Norway AS
PL159 B	32.0	Equinor Energy AS	DNO Norge AS, INEOS E&P Norge AS
PL159 G	32.0	Equinor Energy AS	DNO Norge AS, INEOS E&P Norge AS
PL169 E	87.0	DNO Norge AS	Vår Energi AS
PL185	14.3	Wintershall Dea Norge AS	DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL248 F	20.0	Wintershall Dea Norge AS	DNO Norge AS, Petoro AS
PL248 GS	20.0	Wintershall Dea Norge AS	DNO Norge AS, Petoro AS
PL248 HS	20.0	Wintershall Dea Norge AS	DNO Norge AS, Petoro AS
PL274	55.0	DNO Norge AS	CapeOmega AS
PL274 CS	55.0	DNO Norge AS	CapeOmega AS
PL293 B	20.0	Equinor Energy AS	DNO Norge AS, Idemitsu Petroleum Norge AS
PL300	45.0	Aker BP ASA	DNO Norge AS
PL405	15.0	Spirit Energy Norway AS	DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL433	15.0	Spirit Energy Norway AS	DNO Norge AS, ONE-Dyas Norge AS, PGNiG Upstream Norway AS
PL586	7.5	Neptune Energy Norge AS	DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL644	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740	50.0	DNO Norge AS	Vår Energi AS
PL740 B	50.0	DNO Norge AS	Vår Energi AS
PL740 C	50.0	DNO Norge AS	Vår Energi AS

Note 24

Oil and gas license portfolio

PL749	20.0	Spirit Energy Norway AS	DNO Norge AS, Petoro AS, Neptune Energy Norge AS
PL767	10.0	Lundin Norway AS	DNO Norge AS, INPEX Norge AS
PL767 B	10.0	Lundin Norway AS	DNO Norge AS, INPEX Norge AS
PL811	20.0	Spirit Energy Norway AS	DNO Norge AS, A/S Norske Shell, Aker BP ASA
PL825	50.0	DNO Norge AS	Equinor Energy AS, Spirit Energy Norway AS
PL827 S	30.0	Equinor Energy AS	DNO Norge AS
PL836 S	30.0	Wintershall Dea Norge AS	DNO Norge AS, Spirit Energy Norway AS
PL845	20.0	ConocoPhillips Skandinavia AS	DNO Norge AS, INEOS E&P Norge AS, Wintershall Dea Norge AS
PL859	20.0	Equinor Energy AS	DNO Norge AS, Petoro AS, ConocoPhillips Skandinavia AS, Lundin Norway AS
PL870	20.0	Equinor Energy AS	DNO Norge AS
PL881	30.0	Wellesley Petroleum AS	DNO Norge AS
PL888	40.0	DNO Norge AS	Wellesley Petroleum AS, ConocoPhillips Skandinavia AS
PL902	10.0	Lundin Norway AS	DNO Norge AS, Petoro AS, Aker BP ASA
PL902 B	10.0	Lundin Norway AS	DNO Norge AS, Petoro AS, Aker BP ASA
PL906	20.0	Aker BP ASA	DNO Norge AS, Equinor Energy AS
PL921	15.0	Equinor Energy AS	DNO Norge AS, Petoro AS, Lundin Norway AS
PL922	20.0	Spirit Energy Norway AS	DNO Norge AS, Neptune Energy Norge AS, Total E&P Norge AS
PL923	20.0	Equinor Energy AS	DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL924	15.0	Equinor Energy AS	DNO Norge AS, Lundin Norway AS
PL926	60.0	DNO Norge AS	Concedo ASA, Lundin Norway AS
PL929	10.0	Neptune Energy Norge AS	DNO Norge AS, Pandion Energy AS, Wintershall Dea Norge AS, Lundin Norway AS
PL931	40.0	Wellesley Petroleum AS	DNO Norge AS
PL943	30.0	Equinor Energy AS	DNO Norge AS, Capricorn Norge AS
PL950	10.0	Lundin Norway AS	DNO Norge AS, INPEX Norge AS, Petoro AS
PL951	20.0	Aker BP ASA	DNO Norge AS, Vår Energi AS, Concedo ASA
PL953	30.0	Wintershall Dea Norge AS	DNO Norge AS, Concedo ASA
PL967	60.0	DNO Norge AS	Equinor Energy AS
PL968 PL969	40.0 45.0	DNO Norge AS A/S Norske Shell	Petoro AS, MOL Norge AS, Aker BP ASA DNO Norge AS, Spirit Energy Norway AS
PL975	60.0	DNO Norge AS	Source Energy AS
PL983	20.0	Equinor Energy AS	DNO Norge AS, Total E&P Norge AS, Petoro AS
PL984	40.0	DNO Norge AS	Source Energy AS, Vår Energi AS
PL986	20.0	Aker BP ASA	DNO Norge AS, Petoro AS, Wellesley Petroleum AS
PL987	20.0	Suncor Energy Norge AS	DNO Norge AS, Lundin Norway AS, Vår Energi AS
PL988	30.0	Lundin Norway AS	DNO Norge AS, Vår Energi AS
PL990	30.0	Equinor Energy AS	DNO Norge AS, Wellesley Petroleum AS
PL991	60.0	DNO Norge AS	Lundin Norway AS
PL994	30.0	Neptune Energy Norge AS	DNO Norge AS, Petrolia NOCO AS
PL995	60.0	DNO Norge AS	INEOS E&P Norge AS
UK
P111	54.3	Repsol Sinopec Resources UK Ltd	DNO North Sea (U.K.) Ltd, DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd.
P1763	12.5	Apace Beryl I Ltd	DNO North Sea (U.K.) Ltd , Azinor Catalyst Ltd, Nautical Petroleum Ltd
P2074	25.0	Chrysaor CNS Ltd	DNO Exploration UK Ltd, Chrysaor Ltd, Ineos UK SNS Ltd
P219	18.2	Repsol Sinopec North Sea Ltd	DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK Ltd
P2312	15.0	Nautical Petroleum Ltd	DNO North Sea (U.K.) Ltd, Suncor Energy UK Ltd
P2401	45.0	DNO North Sea (U.K.) Ltd	Shell U.K. Ltd, Spirit Energy Resources Ltd
P2472	70.0	DNO North Sea (U.K.) Ltd	One-Dyas E&P Ltd
P255	45.0	Shell U.K. Ltd	DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
P454	5.9	Neptune E&P UKCS Ltd	DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
P558	10.0	Britoil Ltd	DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P611	5.9	Neptune E&P UKCS Ltd	DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
P803	10.0	BP Exploration Operating Company	DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
		Ltd
Ireland
FEL3/19	20.0	CNOOC Petroleum Europe Ltd	DNO North Sea (U.K.) Ltd
Netherlands
D15	5.0	Neptune E&P UKCS Ltd	DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
D18a	2.5	Neptune E&P UKCS Ltd	DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
Yemen
Block 47	64.0	DNO Yemen AS	The Yemen Company, Geopetrol Hadramaut Incorporated

Note 24 Oil and gas license portfolio

As of 31 December 2018:

Region/license	Participating interest (percent)	Operator	Partner(s)
Kurdistan
Tawke PSC	75.0	DNO Iraq AS	Genel Energy International Limited
Erbil PSC	40.0	DNO Iraq AS	Gas Plus Erbil Limited, Kurdistan Regional Government
Baeshiqa PSC	32.0	DNO Iraq AS	ExxonMobil Kurdistan Region of Iraq Limited, Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL248 F	20.0	Wintershall Norge AS	DNO Norge AS, Petoro AS
PL248 GS	20.0	Wintershall Norge AS	DNO Norge AS, Petoro AS
PL248 HS	20.0	Wintershall Norge AS	DNO Norge AS, Petoro AS
PL293 B	20.0	Equinor Energy AS	DNO Norge AS, Idemitsu Petroleum Norge AS
PL767	10.0	Lundin Norway AS	DNO Norge AS, INPEX Norge AS
PL825	10.0	Faroe Petroleum Norge AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL827 S	30.0	Equinor Energy AS	DNO Norge AS
PL859	20.0	Equinor Energy AS	DNO Norge AS, Petoro AS, Lundin Norway AS, ConocoPhillips Skandinavia AS
PL889	20.0	Neptune Energy Norge AS	DNO Norge AS, Concedo ASA
PL902	10.0	Lundin Norway AS	DNO Norge AS, Aker BP ASA, Petoro AS
PL921	15.0	Equinor Energy AS	DNO Norge AS, Lundin Norway AS, Petoro AS
PL922	20.0	Spirit Energy Norge AS	DNO Norge AS, Total E&P Norge AS, Neptune Energy Norge AS
PL923	20.0	Equinor Energy AS	DNO Norge AS, Petoro AS, Wellesley Petroleum AS
PL924	15.0	Equinor Energy AS	DNO Norge AS, Lundin Norway AS
PL926	20.0	Faroe Petroleum Norge AS	DNO Norge AS, Lundin Norway AS, Concedo ASA
PL929	10.0	Neptune Energy Norge AS	DNO Norge AS, Lundin Norway AS, DEA Norge AS, Pandion Energy AS
PL931	40.0	Wellesley Petroleum AS	DNO Norge AS
PL943	30.0	Equinor Energy AS	DNO Norge AS, Capricorn Norge AS
PL950	10.0	Lundin Norway AS	DNO Norge AS, Petoro AS, INPEX Norge AS
PL951	20.0	Aker BP ASA	DNO Norge AS, Vår Energi AS, Concedo ASA
PL953	30.0	Wintershall Norge AS	DNO Norge AS, Concedo ASA
Oman
Block 8	50.0	DNO Oman Block 8 Limited	LG International Corp.
UK
P1998	22.5	Apache North Sea Limited	DNO Exploration UK Limited, Euroil Exploration Limited
P2074	25.0	Chrysaor CNS Limited	DNO Exploration UK Limited, Ineos UK SNS Limited
Yemen
Block 47	64.0	DNO Yemen AS	The Yemen Company, Geopetrol Hadramaut Incorporated

Note 25 Business combinations

The Company completed two transactions during 2019 as described below. Both transactions were regarded as business combinations and were accounted for by using the acquisition method in accordance with IFRS 3. The general principle in IFRS 3 is that the identifiable assets acquired and liabilities assumed are measured at their acquisition date fair values. Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 3 and IFRS 13. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that the fair value is a market-based measurement, not an entity-specific measurement. When measuring the fair value, the Group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired producing and development assets (i.e., PP&E) as well as discovery assets (i.e., intangible assets) were valued using the income-based approach. Future cash flows were calculated on the basis of expected production profiles and estimated proven and probable remaining reserves, and additional risked contingent resources.

The provisional fair values from the tables below are based on currently available information about fair values as of the acquisition dates. If new information becomes available within 12 months from the acquisition dates (measurement period), the Group may change the fair value assessment in the purchase price allocation (PPA) in accordance with guidance in IFRS 3. Eventual changes in fair values will be recorded retrospectively from the acquisition dates. During 2019, no material measurement period changes were booked.

Acquisition of Faroe Petroleum plc (Faroe)

During 2018, the Company acquired 111,494,028 shares in Faroe which represented 29.9 percent of the outstanding shares at yearend 2018. On 8 January 2019, the Company announced the terms of a cash offer for the entire issued and to be issued share capital of Faroe at a price of 160 pence in cash for each Faroe share. The offer became unconditional in all respects on 11 January 2019, which was when the Company obtained control over Faroe by achieving more than 50 percent ownership. The business combination was achieved in stages (i.e., step acquisitions) and change in fair value of the investment prior to control being obtained was recognized in other comprehensive income in 2019. The Company acquired 100 percent of the entire issued share capital of Faroe during February 2019 and de-listed the company from the AIM on 14 February 2019. The consideration payable by the Company was funded from existing cash resources. The Company's main reason for the acquisition was to firmly establish itself in the North Sea. The Faroe acquisition strengthened the Group's portfolio and operational capabilities in the North Sea, transforming the Group into a more diversified company with a strong, second leg. Through the transaction, the Group obtained attractive exploration, development and production projects and an experienced North Sea oil and gas team.

Purchase price allocation (PPA)

The acquisition date for accounting purposes was 11 January 2019, which was when the Company obtained control over Faroe by achieving more than 50 percent ownership. Consistent with common practice, the Company designated 1 January 2019 as the acquisition date. A PPA was performed as of this acquisition date to allocate the consideration to provisional fair values of acquired assets and assumed liabilities of Faroe. Provisional fair values of the acquired assets and liabilities assumed as of the acquisition date were as shown in the table below:

	Fair value at
USD million	acquisition-date
Deferred tax assets*	45.9
Other intangible assets	268.1
Property, plant and equipment	563.0
Right-of-use assets	2.0
Inventories	17.9
Trade and other receivables	121.0
Tax receivables	31.2
Cash and cash equivalents	154.5
Total assets	1,203.5
Deferred tax liabilities*	134.6
Interest-bearing liabilities (non-current)	100.0
Lease liabilities	2.0
Provisions for other liabilities and charges	408.6
Trade and other payables	180.8
Income tax payable	0.5
Current interest-bearing liabilities	17.7
Total liabilities	844.2
Total identifiable net assets at fair value	359.3
Consideration	812.0
Goodwill	452.7

* Deferred tax assets/liabilities are presented on a net basis in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same tax authority.

Note 25 Business combinations

The PPA above does not include effects from the Equinor Assets Swap as the transaction was completed on 30 April 2019, following approval by Norwegian authorities (see below). The note on disclosure information related to assets held for sale was included in the first quarter 2019 interim report.

The goodwill recognized in the transaction was mainly related to technical goodwill due to the requirement to recognize deferred taxes for the temporary difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. The fair values of licences in the North Sea are based on cash flows after tax. This is because these licences are sold only on an after-tax basis. The purchaser is therefore not entitled to a tax deduction for the consideration paid above the seller's tax values. In accordance with IAS 12, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the fair values of the acquired assets and the transferred tax depreciation basis (i.e., tax values). The offsetting entry to this deferred tax is technical goodwill. This goodwill will be not be deductible for tax purposes. Acquisition-related costs of USD 10.4 million were expensed as incurred in 2018 and 2019 accounts.

Total revenues and net profit/-loss after income tax of Faroe since the acquisition date included in the consolidated statement of comprehensive income for 2019 were USD 254 million and USD -156 million, respectively.

Assets swap agreement with Equinor Energy AS (Equinor)

On 30 April 2019, the Company completed a swap agreement with Equinor Energy AS, a wholly-owned subsidiary of Equinor ASA following approval by the Norwegian authorities. The swap agreement was signed on 4 December 2018 and represented a balanced swap with no cash consideration. The effective date of the transaction was 1 January 2019.

As part of the transaction, DNO's interests in the non-producing Njord and Hyme redevelopment and Bauge development assets (divested assets) acquired through the Faroe transaction were exchanged for interests in four Equinor-held producing assets on a cashless basis, including interests in the Alve, Marulk, Ringhorne East and Vilje fields (acquired assets). The Company received a USD 46 million payment from Equinor reflecting net income from the acquired assets, reimbursement of investments related to the divested assets and working capital adjustments from 1 January 2019 to transaction completion on 30 April 2019. The divested assets were derecognized and no gain or loss was recorded in the Group accounts as the fair values of the divested assets corresponded to the fair values of the acquired assets.

Purchase price allocation (PPA)

The acquisition date for accounting purposes was 30 April 2019, which was when the Norwegian authorities approved the transaction. A PPA was performed as of this acquisition date to allocate the consideration to provisional fair values of acquired assets and assumed liabilities of the acquired assets. Provisional fair values of the acquired assets and liabilities assumed as of the acquisition date were as shown in the table below:

	Fair value at
USD million	acquisition-date
Property, plant and equipment	141.5
Trade and other receivables	2.2
Tax receivables	-22.6
Cash and cash equivalents	29.6
Total assets	150.9
Deferred tax liabilities*	89.1
Provisions for other liabilities and charges	14.0
Total liabilities	103.1
Total identifiable net assets at fair value	47.8
Fair value of divested/acquired assets	148.5
Goodwill	100.7

* Deferred tax assets/liabilities are presented on a net basis in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same tax authority.

The goodwill recognized in the transaction was related to technical goodwill due to the requirement to recognize deferred taxes for the temporary difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licenses under development and licenses in production can only be sold on a post-tax value pursuant to the Norwegian Petroleum Taxation Act, Section 10. The assessment of fair value of such licenses is therefore based on cash flows after tax. In accordance with IAS 12, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the fair values of the acquired assets and the transferred tax depreciation basis (i.e., tax values). The offsetting entry to this deferred tax is technical goodwill. This goodwill is not deductible for tax purposes.

Total revenues and net profit after income tax from the Equinor Assets Swap since the acquisition date included in the consolidated statement of comprehensive income for 2019 were around USD 97 million and USD 9 million, respectively. For comparison purposes, assuming that the acquisition had taken place effective 1 January 2019, it is estimated that revenues in 2019 would have increased by USD 25 million and net profit after income tax would have increased by USD 5 million.

Parent company accounts

Income statement 71 Balance sheet 71 Cash flow statement 73

70 DNO Annual Report and Accounts 2019

Note disclosures Note 1 Accounting principles 74 Note 2 Operating revenues 75 Note 3 Salaries, pensions, remuneration, shares, options and severance 75 Note 4 Other operating expenses 78 Note 5 Net financial income/-expenses 78 Note 6 Taxes 79 Note 7 Property, plant and equipment/Intangible assets 80 Note 8 Investment in shares/Other investments 80 Note 9 Trade and other receivables 81 Note 10 Cash and cash equivalents 81 Note 11 Shareholders' equity 81 Note 12 Guarantees, leasing liabilities and commitments 82 Note 13 Interest-bearing liabilities 82 Note 14 Current liabilities 82 Note 15 Financial instruments 82 Note 16 Related party disclosure 83 Note 17 Contingencies and events after the balance sheet date 83 Note 18 Earnings per share 83 Note 19 Intercompany 83

Income statement

			1 January - 31 December
USD thousand	Note	2019	2018
Operating revenues	2, 19	20,468	15,185
Total operating revenues		20,468	15,185
Depreciation	7	-957	-1,086
Payroll and other social expenses	3	-18,623	-22,719
Other operating expenses	4	-17,862	-19,661
Total operating expenses		-37,442	-43,466
Operating profit/-loss		-16,974	-28,281
Net financial income/-expense	5	-1,093	456,490
Profit/-loss before income tax		-18,067	428,209
Tax income/-expense	6	-	-
Net profit/-loss		-18,067	428,209
Earnings per share, basic (USD per share)	18	-0.02	0.41
Earnings per share, diluted (USD per share)	18	-0.02	0.41
Weighted average number of shares outstanding (excluding treasury shares) (millions)		1,036.37	1,048.81

Balance sheet

ASSETS

			Years ended 31 December
USD thousand	Note	2019	2018
Fixed assets
Intangible assets	7	4,827	3,198
Property, plant and equipment	7	399	581
Total intangible and tangible assets		5,226	3,779
Financial assets
Shares in subsidiaries	8	942,379	302,859
Intercompany receivables	19	28,386	56,131
Other long-term receivables	3	61	82
Other investments	8	69,386	-
Investment in shares	8	21,030	230,779
Total financial assets		1,061,242	589,851
Total non-current assets		1,066,468	593,630
Current assets
Trade and other receivables	9	5,154	3,641
Intercompany receivables		12,724	7,761
Cash and cash equivalents	10	389,028	638,212
Total current assets		406,906	649,614
TOTAL ASSETS		1,473,374	1,243,244

EQUITY AND LIABILITIES

		Years ended 31 December
USD thousand	Note	2019	2018
Paid-in capital
Share capital		35,991	35,991
Treasury shares		-2,641	-1,022
Share premium		247,743	220,730
Total paid-in capital	11	281,093	255,699
Retained earnings
Retained earnings		195,986	344,264
Total retained earnings	11	195,986	344,264
Total shareholders' equity	11	477,079	599,963
Non-current liabilities
Intercompany liabilities	19	55,162	19,572
Interest-bearing liabilities	13	780,753	575,724
Other non-current liabilities		686	2,223
Total non-current liabilities		836,601	597,519
Current liabilities
Provisions for other liabilities and charges	14	19,533	19,922
Intercompany liabilities		161	1,697
Current interest-bearing liabilities	13	140,000	-
Dividend	11	-	24,143
Total current liabilities		159,694	45,762
Total liabilities		996,295	643,281
TOTAL EQUITY AND LIABILITIES		1,473,374	1,243,244

Oslo, 17 March 2020

Bijan Mossavar-Rahmani Lars Arne Takla Shelley Watson Executive Chairman Deputy Chairman Director

Elin Karfjell Gunnar Hirsti Bjørn Dale Director Director Managing Director

Cash flow statement

		1 January - 31 December
USD thousand	Note	2019	2018
Operating activities
Profit/-loss before income tax		-18,067	428,209
Taxes paid	6	-	-
Depreciation and impairment of tangible and intangible assets	7	957	1,086
Impairment/reversal of impairment of financial assets	5	183,338	45,987
Changes in working capital items and accruals/provisions		19,304	46,166
Net interest paid/-received		-55,532	-33,138
Net cash flow from/-used in operating activities		130,000	488,310
Investing activities
Payments made for intangible and tangible assets	7	-2,404	-1,247
Payments made for acquisitions of shares, including capital increase in subsidiaries	8	-582,999	-201,336
Proceeds from sales of financial investments	8	6,644	-
Loans to subsidiaries	19	27,745	-40,981
Purchase of bonds	8	-69,386	-
Net cash flow from/-used in investing activities		-620,400	-243,564
Financing activities
Proceeds from interest-bearing liabilities net of issue costs	13	394,521	189,500
Repayment of interest-bearing liabilities and bonds	13, 19	-24,410	-158,729
Purchase of treasury shares and options	11	-82,265	-
Paid dividend	11	-46,629	-25,807
Net cash flow from/-used in financing activities		241,216	4,964
Cash and cash equivalents at the beginning of the period		638,212	388,502
Net increase/-decrease in cash and cash equivalents		-249,184	249,710
Cash and cash equivalents at the end of the period	10	389,028	638,212
Of which restricted cash		2,225	3,063
Of which held on restricted account in relation to the Faroe offer		-	418,100

Note 1 Accounting principles

General

The financial statements of DNO ASA (the Company) are presented in accordance with the Norwegian Accounting Act and Norwegian accounting standards. The notes are an integral part of the financial statements. For more information about the accounting principles, see Note 1 in the consolidated accounts.

Use of estimates

Preparation of the financial statements requires management to make judgements, estimates and assumptions that affect the application of policies and reported revenues and expenses, assets and liabilities, and the disclosures. Actual results could differ from those estimates.

Currency

The financial statements are presented in USD, which is also the functional currency that best reflects the economic substance of the underlying events and circumstances relevant to the Company. Monetary items denominated in foreign currencies are converted using exchange rates on the balance sheet date. Realized and unrealized currency gains and losses are included in the profit or loss. Foreign currency transactions are recorded using exchange rates on the date of transaction.

Consolidated financial statements

The consolidated financial statements of the Group have been prepared in accordance with IFRS as adopted by the EU and additional disclosure requirements in the Norwegian Accounting Act and have been presented separately from the parent company accounts.

Investments in subsidiaries

Investments in subsidiaries are recorded at historical cost. If the market value of the investment is lower than the carrying value, an impairment charge is recorded and a new cost basis of the investment is established. The impairment charge is reversed if the basis for the impairment ceases to exist.

Valuation and classification of balance sheet items

Current assets and short-term liabilities include items due less than one year from draw-down and items related to the operating cycle. Other assets or liabilities are classified as fixed assets or long-term liabilities. Other financial investments including investments in bonds are classified as non-current assets. They are initially valued at cost price and subsequently may be impaired to fair value.

Shares

Shares classified as financial assets are valued at their cost price and impaired in the case of permanent and significant decline in value. Equity instruments are valued at fair value.

Fixed assets

Intangible assets and PP&E are stated at cost, less accumulated amortization and accumulated impairment charges. Intangible assets and PP&E are depreciated using a straight-line method

based on estimated useful life. Estimated useful life varies between three and seven years. Impairment charge is recognized when the book value exceeds the fair value of the asset.

Income taxes

Tax income/-expense consists of taxes receivable/-payable and changes in deferred tax. Tax receivables/payables are based on amounts receivable from or payable to tax authorities. Deferred tax liability is calculated on all taxable temporary differences, unless there is a recognition exception. A deferred tax asset is recognized only to the extent that it is probable that the future taxable income will be available against which the asset can be utilized.

Share-based payments

Cash-settled share-based payments are recognized in the income statement as expenses during the vesting period and as a liability. The liability is measured at fair value and revaluated using the Black & Scholes pricing model at each balance sheet date and at the date of settlement, with any change in fair value recognized in the profit or loss for the period.

Pensions

The Company records pension schemes according to the Norwegian accounting standard for pension costs. The Company has contribution plans for employees as provided for under Norwegian law. For such plans, only the contributions paid during the period are expensed.

Revenue recognition

Revenues from services are recorded when the service has been performed.

Allowance for doubtful accounts

Trade receivables are recognized and carried at their anticipated realizable value, which implies that a provision for a loss allowance on expected credit losses of the receivable is recognized.

Contingent assets/liabilities

According to Norwegian accounting standards relating to contingent items, provisions are made for contingent liabilities that are probable and quantifiable, while contingent assets are not recognized.

Cash flow statement

The cash flow statement is based on the indirect method. Cash equivalents include bank deposits.

Dividend

In accordance with Norwegian accounting standards, the Company recognizes a liability to pay dividend for proposed ordinary dividend and additional or extraordinary dividend resolved after yearend but before or on the date of approval of the financial statements by the Board of Directors.

Note 2 Operating revenues

		1 January - 31 December
USD thousand	2019	2018
Operating revenues	20,468	15,185
Total operating revenues	20,468	15,185

Operating revenues relate to services provided by the Company to its subsidiaries.

Note 3 Salaries, pensions, remuneration, shares, options and severance

	1 January - 31 December
USD thousand	2019	2018
Payroll and other social expenses
Salaries, bonuses, etc.	-13,779	-14,684
Employer's payroll tax expense	-2,642	-2,456
Pensions	-2,579	-2,114
Other personnel costs	-336	-3,501
Reclassification to oil and gas license activities	713	36
Total payroll and other social expenses	-18,623	-22,719
Average number of man-labor years	75	66

Pensions

DNO has a defined contribution scheme for its Norway-based employees. DNO meets the Norwegian requirements for mandatory occupational pensions ("obligatorisk tjenestepensjon").

Remuneration to the Board of Directors and executive management

Remuneration to the Board of Directors (USD thousand)	2019	2018
Bijan Mossavar-Rahmani, Executive Chairman, member of the nomination and remuneration committees	813.5	840.5
Lars Arne Takla, Deputy Chairman, Chair of the HSSE committee	68.1	70.4
Elin Karfjell, Director, member of the audit committee	57.8	59.7
Gunnar Hirsti, Director, Chair of the audit committee and member of the remuneration committee	64.0	66.2
Shelley Watson, Director, member of the audit committee	57.8	59.7
Total	1,061.2	1,096.4

Total remuneration to the Board of Directors consist of regular fees (USD 1,020,600) and fees for participation in the board committees (USD 40,600). Separately, a fee of USD 3,125 was paid to each of Anita Marie Hjerkinn Aarnæs and Kåre Tjønneland for service on the nomination committee.

						Loan
Remuneration to Managing Director and executive management (USD thousand)*	Salary	Bonus**	Other	Total	Pension	balance
Bjørn Dale, Managing Director	674.0	210.4	73.0	957.4	19.4	-
Chris Spencer, Deputy Managing Director	468.7	68.2	54.0	590.8	19.4	-
Haakon Sandborg, Chief Financial Officer	442.6	51.1	44.5	538.2	19.4	-
Ute Quinn, Group General Counsel and Corporate Secretary ***	433.0	51.1	44.5	528.7	19.4	61.1
Nicholas Whiteley, Group Exploration and Subsurface Director	441.9	215.9	96.3	754.1	19.4	-
Ørjan Gjerde, Group Commercial Director	338.9	36.5	25.9	401.3	12.8	-
Tom Allan, General Manager Kurdistan Region of Iraq (from September 2019)	150.9	-	101.0	251.9	-	-
Rune Martinsen, General Manager DNO North Sea (from December 2019)	37.9	-	0.1	38.0	-	-
Geir Arne Skau, Human Resources Director (from May 2019)	185.8	-	15.0	200.8	12.9	-
Aernout van der Gaag, Deputy Chief Financial Officer	404.3	48.3	41.7	494.3	19.4	-
Tonje Pareli Gormley, General Counsel - Middle East	294.2	35.5	26.0	355.6	19.4	-

* Total remuneration of USD 0.9 million was paid to Jon Sargeant, a former member of the executive management.

** Figure represents actual bonus paid in 2019 and includes synthetic share awards that were vested during the year.

*** Loan amount is to be repaid over 48 months including interest through salary deductions. The interest rate equals the Norwegian statutory rate applicable to employee loans (interest rate of 2.3 percent at yearend 2019).

Note 3 Salaries, pensions, remuneration, shares, options and severance

The following table is an overview of members of the executive management that have been awarded synthetic shares during the year as part of their remuneration.

Movement in synthetic Company shares during 2019

	Out- standing	Movements 1 January - 31 December Forfeited/			Out- standing	Unrest ricted	Weighted average
Number of shares	at 1 Jan	Granted	Reversed	Settled	Expired	at 31 Dec	at 31 Dec	price*
Bjørn Dale, Managing Director	246,761	5,622	-	61,838	-	190,545	664	16.90
Chris Spencer, Deputy Managing Director	159,511	36,614	-	-	-	196,125	-	-
Haakon Sandborg, Chief Financial Officer	244,016	29,635	-	57,380	-	216,271	-	12.76
Ute Quinn, Group General Counsel and Corporate Secretary	14,424	135,889	-	-	-	150,313	-	-
Nicholas Whiteley, Group Exploration and Subsurface Director	282,114	30,603	-	75,500	-	237,217	1,081	16.90
Ørjan Gjerde, Group Commercial Director	45,817	18,531	-	-	-	64,348	-	-
Tom Allan, General Manager Kurdistan Region of Iraq	-	105,007	-	-	-	105,007	-	-
Rune Martinsen, General Manager DNO North Sea	-	284,630	-	-	-	284,630	-	-
Geir Arne Skau, Human Resources Director	-	84,070	-	-	-	84,070	-	-
Aernout van der Gaag, Deputy Chief Financial Officer	207,141	28,456	-	-	-	235,597	103,919	-
Tonje Pareli Gormley, General Counsel - Middle East	72,590	76,731	-	-	-	149,321	-	-

* The weighted average settlement price for synthetic shares settled during 2019 in NOK.

The weighted average settlement price for synthetic shares at yearend 2019 was NOK 15.68. The weighted average remaining contractual life of the synthetic shares was 4.00 years.

The synthetic share awards are subject to a two-year vesting period and require continued employment in the Company for a period of two years after the grant date. Following vesting, the employee is free to settle the shares in cash. Payments in cash for the year are included in Other remuneration above. For an overview of synthetic shares at yearend 2019, see Note 5 in the consolidated accounts.

Severance agreements

Members of the executive management, Bjørn Dale, Haakon Sandborg, Nicholas Whiteley, Ute Quinn and Aernout van der Gaag have severance payment agreements ranging from six months to 12 months of their respective annual base salaries.

Auditor fees

		1 January - 31 December
All figures are exclusive of VAT (USD thousand)	2019	2018
Auditor fees	-275	-270
Other financial audit services	-2	-30
Total auditing fees	-277	-300
Other assistance	-	-10
Tax assistance	-3	-29
Total auditor fees	-279	-339

Declaration regarding determination of salary and other remuneration to the Managing Director and the rest of the executive management

The board's declaration for 2019

According to the Norwegian Public Limited Liability Companies Act section 6-16a cf. section 5-6 third paragraph, the Board of Directors present a declaration regarding determination of salary and other remuneration to the Managing Director and executive management for the coming financial year to the AGM.

The remuneration, possible bonus and other incentive arrangements shall reflect the duties and responsibilities of the employees and contribute to adding long term value for shareholders.

Fixed salary

No upper or lower limit for the determination of fixed salary to executive management has been set by the Board of Directors for the coming financial year beyond the main principles set out above.

Note 3

Salaries, pensions, remuneration, shares, options and severance

Variable elements

In addition to the fixed salary, variable remuneration elements can be used to recruit, retain and reward employees. Variable remuneration to the executive management can include cash bonuses and share-based compensation, including synthetic shares. Annual bonuses are awarded based on corporate results and individual performance during the year.

Other variable elements include newspapers, mobile phone and broadband communication subscriptions paid in accordance with established rates.

Share savings plan

An employee share savings plan was introduced in 2013. The plan was closed for new contributions in the second quarter 2016 but was kept open until 31 August 2019 for vesting of restricted synthetic shares and settlement of unrestricted synthetic shares.

Pensions

The Company has a contribution-based pension system under which Norway-based employees are entitled to a pension contribution of 12.5 percent of their annual salary. Any excess of the maximum legally allowable pension contribution is paid out to the employees as additional salary.

Share-based incentive scheme

The Board of Directors can implement a share-based incentive scheme involving the allocation of options to acquire shares. The principles of the program shall be to: (i) align the interests of executive management and other employees with shareholders' interests, and (ii) implement share-based rewards for value creation. The Board of Directors can decide whether to set allocation criteria, conditions or thresholds for the scheme.

Severance agreements

Severance payment agreements may be entered into selectively if the Board of Directors finds this to be useful in recruitment.

Binding parts of this declaration

Remuneration as it relates to the employee share savings plan or the options-based incentive scheme must be subject to a separate vote by the AGM and is binding once approved. Other sections of the remuneration policy are non-binding guidelines for the Board of Directors and are therefore only subject to a consultative vote at the AGM.

Executive management remuneration in 2019

Executive management remuneration for 2019 was in accordance with the directives approved by the AGM in 2019.

Remuneration committee

The Board of Directors has established a remuneration committee composed of two members, the current members are Bijan Mossavar-Rahmani and Gunnar Hirsti. Its mandate is to consider matters relating to compensation of executive management and to make related recommendations to the Board of Directors.

See Note 5 in the consolidated accounts for further information on administrative expenses.

Note 4 Other operating expenses

	1 January - 31 December
USD thousand	2019	2018
Lease expense on buildings and equipment	-2,362	-2,476
Other office expenses	-86	-106
IT expenses	-4,086	-3,605
Travel expenses	-930	-1,062
Legal expenses	-330	-607
Consultant fees	-7,892	-10,112
Other general and administrative costs	-2,175	-1,693
Total other operating expenses	-17,862	-19,661

Consultant fees in both 2019 and 2018 included transaction costs related to the Faroe acquisition.

Note 5 Net financial income/-expenses

		1 January - 31 December
USD thousand	2019	2018
Dividend and group contribution received from group companies	267,936	563,471
Interest received	8,407	7,832
Interest received from group companies	0	3,254
Other financial income	-	-4
Gain on foreign exchange	3,717	791
Change in fair value of financial investments	25,786	12,058
Total financial income	305,846	587,402
Interest expenses	-69,200	-45,207
Interest expenses group companies	-21,665	-5,911
Loss on foreign exchange	-1,332	-1,889
Impairment of financial assets	-183,338	-52,040
Other financial expenses	-17,660	-14,191
Loss on disposal of shares	-13,744	-11,674
Total financial expenses	-306,939	-130,912
Net financial income/-expenses	-1,093	456,490

In 2019, the impairment of financial assets of USD 183.3 million was comprised of DNO North Sea plc (USD 167.0 million), DNO Mena AS (USD 6.5 million), DNO Exploration UK Limited (USD 0.3 million), DNO Somaliland AS (USD 0.6 million) and DNO Yemen AS (USD 8.8 million). The change in fair value of financial investments of USD 25.8 million recognized in 2019 was comprised of an increase in fair value related to the Company's shares in RAK Petroleum (USD 3.1 million), an increase in fair value related to the Company's shares in Faroe (renamed DNO North Sea plc) prior to control being obtained on 11 January 2019 (USD 19.7 million) and an increase in fair value related to the Company's shares in Panoro Energy ASA (Panoro) (USD 3.0 million). The Company's shareholding in Panoro was sold on 8 November 2019. Other financial expenses in 2019 and 2018 were mainly related to amortization of bond issue costs and other bond related costs. Loss on disposal of shares in 2019 was related to the sale of shares in DNO Norge AS to DNO North Sea plc (USD 13.7 million).

In 2018, the impairment of financial assets of USD 52.0 million was comprised of DNO Mena AS (USD 28.4 million), DNO Norge AS (USD 11.1 million), DNO Exploration UK Limited (USD 6.0 million), Northstar Exploration Holding AS (USD 0.2 million), DNO Technical Services AS (USD 0.7 million), DNO Somaliland AS (USD 0.3 million), DNO Yemen AS (USD 4.8 million), DNO Al Khaleej Limited (USD 0.1 million) and DNO Oman Limited (USD 0.6 million). The change in fair value of financial investments of USD 12.1 million recognized in 2018 was comprised of an increase in fair value related to the Company's shares in RAK Petroleum (USD 0.5 million), an increase in fair value related to the Company's shares in Faroe (USD 12.1 million) and a decrease in fair value related to the Company's shares in Panoro (USD 0.5 million). Other financial expenses were mainly related to amortization of bond issue costs. Loss on disposal of shares in 2018 was mainly related to an accounting loss related to the sale of shares in DNO Tunisia AS (USD 11.3 million) and the liquidation of DNOILCO AS (USD 0.3 million).

Note 6

Taxes

Tax income/-expense

	1 January - 31 December
USD thousand	2019	2018
Change in deferred taxes	-	-
Income tax receivable/-payable	-	-
Tax income/-expense	-	-

Reconciliation of tax income/-expense

		1 January - 31 December
USD thousand	2019	2018
Profit/-loss before income tax	-18,067	428,212
Expected income tax according to nominal tax rate of 22 percent (23 percent in 2018)	3,975	-98,489
Foreign exchange variations between functional and tax currency	4,891	-1,228
Adjustment in previous years	-	-
Adjustment of deferred tax assets not recognized	-24,321	-12,859
Impairment financial assets	-43,191	-15,516
Tax-free dividend from subsidiaries	52,571	125,677
Change in previous years	-	-
Other items	6,075	6,289
Change in tax rate	-	-3,874
Tax loss carried forward (utilized)	-	-
Tax income/-expense	-	-
Effective income tax rate	0%	0%

Tax effects of temporary differences and losses carried forward

		Years ended 31 December
USD thousand	2019	2018
Tangible assets	-	-
Intangible assets	-31	-231
Losses carried forward	91,939	70,415
Non-deductible interests carried forward	11,020	9,766
Other temporary differences	-1,508	-175
Deferred tax assets/-liabilities	101,420	79,775
Valuation allowance	-101,420	-79,775
Net deferred tax assets/-liabilities	-	-
Recognized deferred tax assets	-	-
Recognized deferred tax liabilities	-	-

Effective from 1 January 2019, the corporate tax rate is 22 percent and has been used to calculate deferred taxes in 2018 and 2019. The corporate tax rate was 23 percent in 2018.

The tax value of tax losses carried forward is USD 91.9 million at yearend 2019. The carry forward period for unused losses in Norway is indefinite. Non-deductible interest can be carried forward for a period of up to 10 years and will expire in the period 2026 to 2028. A deferred tax asset has not been recognized for these losses as there is uncertainty regarding future taxable profits.

	Intangible
USD thousand	assets	PP&E	Total
Costs as of 1 January 2019	11,218	3,069	14,287
Additions	2,312	92	2,404
Costs as of 31 December 2019	13,530	3,161	16,691
Accumulated depreciation as of 1 January 2019	-8,020	-2,488	-10,508
Depreciation	-683	-274	-957
Accumulated depreciation and impairments as of 31 December 2019	-8,703	-2,762	-11,465
Book value as of 31 December 2019	4,827	399	5,226
Book value as of 31 December 2018	3,198	581	3,779

Intangible assets and PP&E are depreciated using the linear method based on estimated useful life of three to seven years.

Note 8

Investment in shares/Other investments

		Ownership	Company's		Company's
		and voting	share	Company's	profit/	Book
		interest	capital in	equity in	-loss in	value in
Subsidiaries owned by the Company	Office	(percent)	1,000	USD 1,000	USD 1,000	USD 1,000
DNO Yemen AS	Norway	100	NOK 291,000	-44,634	-21,739	-
DNO UK Limited	UK	100	GBP 100	-109	-12	-
DNO Iraq AS	Norway	100	NOK 1,200	1,011,176	391,047	279,848
DNO Invest AS	Norway	100	NOK 2,075	307	4	308
DNO Mena AS*	Norway	100	NOK 2,000	6,228	-	6,216
DNO Oman AS	Norway	100	NOK 202	-14,455	-15	-
DNO Somaliland AS	Norway	100	NOK 202	-3,164	-56	-
DNO Technical Services AS	Norway	100	NOK 200	5,615	-16	5,620
Northstar Exploration Holding AS	Norway	100	NOK 70,347	6,510	-4	5,385
DNO Exploration UK Limited	UK	100	GBP 30,912	-2,082	-917	-
DNO North Sea plc (Faroe Petroleum plc)*	UK	100	GBP 37,289	626,392	-173,795	645,002
Total				1,591,784	194,497	942,379

* DNO Mena AS and DNO North Sea plc own shares in other subsidiaries, see Note 20 in the consolidated accounts. The figures in the table above include the respective subgroup's equity and any excess values recognized at the Group level.

In 2019, the book value in shares in subsidiaries was partially written off by USD 168.3 million. The partial write-off was related to DNO North Sea plc (USD 167.0 million) and DNO Mena AS (USD 1.3 million). The Company acquired the entire issued share capital of Faroe during January and February 2019. On 19 December 2019, the Company sold its shares in DNO Norge AS to DNO North Sea plc for a consideration of USD 27.3 million (NOK 249.4 million). An accounting loss of USD 13.7 million (NOK 118.5 million) related to this sale was recognized.

In 2018, the book value in shares in subsidiaries was partially written off USD 46.4 million. The partial write-off was related to DNO Mena AS (USD 28.4 million), DNO Norge AS (USD 6.0 million), DNO Technical Services AS (USD 0.7 million) and Northstar Exploration Holding AS (USD 0.2 million).

Other investments

At yearend 2019, the Company held a total of 15,849,737 shares (4.8 percent of total issued Class A shares) in RAK Petroleum. RAK Petroleum is listed on the Oslo Stock Exchange. At yearend 2019, the fair value increased to USD 21.0 million, from USD 17.9 million at yearend 2018.

During 2018, the Company acquired 111,494,028 shares in Faroe which represented 29.9 percent of the outstanding shares at yearend 2018. At yearend 2018, Faroe was listed on the UK's AIM of the London Stock Exchange. On 11 January 2019, the Company obtained control of Faroe and subsequently de-listed the company from the AIM on 14 February 2019, see Note 25 in the consolidated accounts.

On 8 November 2019, the Company sold its shareholding in Panoro.

During 2019, the Company purchased USD 64.6 million in nominal value of FAPE01 bonds (ISIN NO0010811268) originally issued by Faroe. The bonds were purchased at a price of 107.409 and amounted to USD 69.4 million, plus accrued interest with a coupon rate of 8.0 percent. The FAPE01 bonds mature on 28 April 2023. At yearend 2019, the fair value of the bonds was USD 69.2 million.

Note 9 Trade and other receivables

	Years ended 31 December
USD thousand	2019	2018
Prepayments and accrued income	5,122	3,556
Other short-term receivables	32	85
Trade and other receivables	5,154	3,641

Note 10 Cash and cash equivalents

	Years ended 31 December
USD thousand	2019	2018
Cash and cash equivalents, restricted	2,225	3,063
Cash held in restricted account, Faroe offer	-	418,100
Cash and cash equivalents, non-restricted	386,803	217,049
Total cash and cash equivalents	389,028	638,212

Restricted cash relates to employees' tax withholdings and deposits for rent.

Non-restricted cash is entirely related to bank deposits in USD, NOK and GBP as of 31 December 2019.

Note 11 Shareholders' equity

		Treasury			Other
	Share	shares	Treasury	Share	paid-in	Retained
USD thousand	capital	(numbers)	shares	premium	capital	earnings	Total
Shareholders' equity as of 1 January 2018	35,991	35,000,000	-1,022	247,743	22,937	-83,945	221,704
Purchase of treasury shares	-	-	-	-	-	-	-
Dividend	-	-	-	-2,870	-22,937	-	-25,807
Additional dividend	-	-	-	-24,143	-	-	-24,143
Profit/-loss	-	-	-	-	-	428,209	428,209
Shareholders' equity as of 31 December 2018	35,991	35,000,000	-1,022	220,730	-	344,264	599,963
Shareholders' equity as of 1 January 2019	35,991	35,000,000	-1,022	220,730	-	344,264	599,963
Purchase of treasury shares	-	58,700,000	-1,619	-80,714	-	-	-82,332
Dividend	-	-	-	-22,485	-	-	-22,485
Profit/-loss	-	-	-	-	-	-18,067	-18,067
Transfers	-	-	-	130,211	-	-130,211	-
Shareholders' equity as of 31 December 2019	35,991	93,700,000	-2,641	247,743	-	195,986	477,079

For other information regarding the Company's equity and shareholders, see Note 14 in the consolidated accounts.

On 6 February 2019, the Company announced that, pursuant to the authorization granted at the EGM held on 13 September 2018, the Board of Directors approved an additional dividend payment of NOK 0.20 per share to be made on or about 27 March 2019 to all shareholders of record as of 18 March 2019. The dividend was accrued for in the 2018 parent accounts.

At the 2019 AGM, a resolution was approved to authorize the Board of Directors to approve a dividend distribution of NOK 0.20 per share in the second half of 2019 and a distribution of dividend of NOK 0.20 per share in the first half of 2020.

In October 2019, the Company's Board of Directors approved a dividend payment of NOK 0.20 per share to be made on or about 4 November 2019 to all shareholders of record as of 28 October 2019. The dividend payment was made on 4 November 2019.

Note 12 Guarantees, leasing liabilities and commitments

See Note 17 in the consolidated accounts for information regarding other guarantees and commitments.

The Company's future minimum lease payments under non-cancellable operating leases are related to office rent. The lease period expires on 30 September 2024 and the yearly rent is USD 1.9 million.

Note 13 Interest-bearing liabilities

						Effective
						interest	Fair value		Carrying amount
	Ticker	Facility	Facility	Interest		rate
USD thousand	OSE	currency	amount	(percent)	Maturity	(percent)	2019	2018	2019	2018
Non-current
Bond loan (ISIN NO0010740392)	DNO01	USD	140,000	8.750	18.06.20	12.5	-	200,500	-	200,000
Bond loan (ISIN NO0010823347)	DNO02	USD	400,000	8.750	31.05.23	9.7	408,640	396,300	400,000	400,000
Bond loan (ISIN NO0010852643)	DNO03	USD	400,000	8.375	29.05.24	9.0	401,560	-	400,000	-
Capitalized borrowing issue costs									(19,247)	(24,276)
Total non-current interest-bearing liabilities							810,200	596,800	780,753	575,724
Bond loan (ISIN NO0010740392)	DNO01	USD	140,000	8.750	18.06.20	12.5	143,808	-	140,000	-
Total current interest-bearing liabilities							143,808	-	140,000	-
Total interest-bearing liabilities							954,008	596,800	920,753	575,724

See Note 15 in the consolidated accounts for further information on interest-bearing liabilities.

Note 14 Current liabilities

		Years ended 31 December
USD thousand	2019	2018
Trade creditors	774	468
Public duties payable	2,175	1,822
Accrued expenses and other current liabilities	16,584	17,632
Total provisions for other liabilities and charges	19,533	19,922
Intercompany liabilities	161	1,697
Current portion of bond loans	140,000	-
Dividend accrual	-	24,143
Total current liabilities	159,694	45,762

Accrued expenses and other current liabilities include accrued interest for bond loans of USD 6.3 million (USD 3.5 million in 2018) and accruals for incurred costs of USD 6.4 million (USD 10.3 million in 2018). For dividend accrual in 2018, see Note 11.

Note 15 Financial instruments

See Note 9 in the consolidated accounts for information on financial instruments.

Note 16 Related party disclosure

Overhead expenses in the parent company are allocated to the subsidiaries based on their proportional use of the services provided by the parent company.

See Note 21 in the consolidated accounts for further information on transactions with related parties and Note 19 in parent company accounts for intercompany transactions and balances at yearend.

Note 17 Contingencies and events after the balance sheet date

See Note 17 and Note 22 in the consolidated accounts for information on contingencies and events after the balance sheet date.

Note 18 Earnings per share

		1 January - 31 December
USD thousand	2019	2018
Net profit/-loss attributable to ordinary equity holders of the parent	-18,067	428,209
Weighted average number of ordinary shares (excluding treasury shares) (millions)	1,036.37	1,048.81
Effect of dilution:
Options	-	-
Weighted average number of ordinary shares (excluding treasury shares) (millions)
adjusted for the effect of dilution	1,036.37	1,048.81
Earnings per share, basic (USD per share)	-0.02	0.41
Earnings per share, diluted (USD per share)	-0.02	0.41

Note 19

Intercompany

Long-term intercompany receivables/liabilities					Years ended 31 December
	Functional		Receivables		Liabilities
USD thousand	currency	2019	2018	2019	2018
DNO Iraq AS	USD	-	55,627	35,341	-
DNO Oman Block 30 Limited	USD	504	504	-	-
DNO Oman Block 8 Limited	USD	-	-	13,361	12,907
DNO Oman Limited	USD	591	-	-	-
Northstar Exploration Holding AS	NOK	-	-	6,460	5,331
DNO Mena AS	USD	-	-	-	1,334
DNO North Sea plc	GBP	27,291	-	-	-
Total long-term intercompany receivables and liabilities		28,386	56,131	55,162	19,572

Except for loans to companies with exploration activities, the intercompany receivables and liabilities are interest bearing. The intercompany interest rates used by DNO ASA and its subsidiaries are based on country specific weighted average cost of capital.

Note 19 Intercompany

Intercompany sales/purchases 1 January - 31 December

USD thousand	Functional	Sales		Purchases
	currency	2019	2018	2019	2018
DNO Technical Services AS	USD	695	181	-277	-
DNO Iraq AS	USD	16,445	12,747	-	-
DNO Yemen AS	USD	152	120	-	-
DNO Al Khaleej Limited (liquidated)	USD	-	-	-	-321
DNO Oman Limited	USD	48	87	-1	-
DNO Oman Block 8 Limited	USD	505	870	-	-
DNO Oman AS	USD	8	13	-	-
DNO Somaliland AS	USD	35	189	-	-
Hylledokk AS (liquidated)	EUR	-	379	-	-
DNO Norge AS	NOK	1,881	533	-15	-46
DNO North Sea plc	GBP	334	-	-	-
Other	USD	185	66	-	-39
Intercompany sales/purchases		20,288	15,185	-293	-406

The Company's other related parties consist of other subsidiaries in the Group. The Company sells and purchases services to and from its subsidiaries.

Intercompany interest income/-expense and dividend		1 January - 31 December
		Interest income/		Interest expense
	Functional	dividend
USD thousand	currency	2019	2018	2019	2018
DNO Iraq AS	USD	240,541	526,227	-19,365	-
DNO Tunisia AS	USD	-	-	-	-799
DNO Mena AS	USD	27,395	40,480	-	-
DNO Oman Limited	USD	-	18	18	-
DNO Oman Block 8 Limited	USD	-	-	-1,133	-5,047
Northstar Exploration Holding AS	NOK	-	-	-1,185	-65
Intercompany interest income/-expense		267,936	566,725	-21,665	-5,911

See Note 5 for more details on financial items.

-

-

-

Alternative performance measures

DNO discloses alternative performance measures (APMs) as a supplement to the Group's financial statements prepared based on issued guidelines from the European Securities and Markets Authority (ESMA). DNO believes that the APMs provide useful supplemental information to management, investors, securities analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of DNO's business operations, financing and future prospects and to improve comparability between periods. Reconciliations of relevant APMs, definitions and explanations of the APMs are provided below.

EBITDA

USD million	2019	2018
Revenues	971.4	829.3
Lifting costs	-199.1	-90.4
Tariffs and transportation	-37.7	-
Movement in overlift/underlift	7.2	-
Exploration expenses	-146.4	-64.7
Administrative expenses	-26.1	-36.7
Other operating income/expenses	-19.8	1.4
EBITDA	549.4	638.8

EBITDAX

USD million	2019	2018
EBITDA	549.4	638.8
Exploration expenses	146.4	64.7
EBITDAX	695.8	703.5

Netback

USD million	2019	2018
EBITDA	549.4	638.8
Change in revenue recognition, Kurdistan	-	-182.8
Taxes received/-paid	56.9	33.2
Netback	606.3	489.1
	2019	2018
Netback (USD million)	606.3	489.1

Company Working Interest production (MMboe)*	37.1	29.8
Netback (USD/boe)	16.3	16.4

* For accounting purposes, the CWI production from the assets added through the Equinor Assets Swap was accounted post completion date of 30 April 2019. See Note 25 for details.

Lifting costs

	2019	2018
Lifting costs (USD million)	-199.1	-90.4
Company Working Interest production (MMboe)*	37.1	29.8
Lifting costs (USD/boe)	5.4	3.0

* See comment above under Netback.

Acquisition and development costs

USD million	2019	2018
Purchases of intangible assets	-68.5	-7.8
Purchases of tangible assets	-339.4	-130.3
Acquisition and development costs*	-407.9	-138.0

* Acquisition and development costs exclude estimate changes on asset retirement obligations.

Operational spend

USD million	2019	2018
Lifting costs	-199.1	-90.4
Exploration expenses	-146.4	-64.7
Exploration costs capitalized in previous years carried to cost (Note 6 in the consolidated accounts)	27.8	-
Acquisition and development costs	-407.9	-138.0
Operational spend	-725.6	-293.2

Alternative performance measures

Equity ratio

USD million	2019	2018
Equity	1,161.3	1,217.8
Total assets	3,271.9	2,004.3
Equity ratio	35.5%	60.8%

Free cash flow

USD million	2019	2018
Cash generated from operations	385.3	472.0
Acquisition and development costs	-407.9	-138.0
Payments for decommissioning	-22.6	-
Free cash flow	-45.2	334.0

Marketable securities

USD million	2019	2018
Financial investments	21.0	230.8
Treasury shares*	123.5	50.5
Marketable securities	144.5	281.3

* Number of treasury shares at yearend multiplied by the DNO share price at yearend.

Net debt

USD million	2019	2018
Cash and cash equivalents	485.7	729.1
Bond loans	961.2	600.0
Net cash/-debt	-475.5	129.1

Exploration financing facility has been excluded as it is covered by the exploration tax refund booked as an asset in the statement of financial position.

Reserve Life Index (R/P)

Company Working Interest production (MMboe) 38.2 29.8 1P reserves 205.6 239.7 2P reserves 344.8 376.1 3P reserves 539.9 538.9 1P Reserve Life Index (R/P in years) 5.4 8.2	2019	2018
2P Reserve Life Index (R/P in years) 9.0 12.9
3P Reserve Life Index (R/P in years) 14.1 18.5

The CWI production in 2019 includes production from the assets added through the Equinor Assets Swap, effective from of 1 January 2019.

Definitions and explanations of APMs

ESMA issued guidelines on APMs that came into effect on 3 July 2016. The Company has defined and explained the purpose of the following APMs:

EBITDA (Earnings before interest, tax, depreciation and amortization)

EBITDA, as reconciled above, can also be found by excluding the DD&A and impairment of oil and gas assets from the profit/-loss from operating activities. Management believes that this measure provides useful information regarding the Group's ability to fund its capital investments and provides a helpful measure for comparing its operating performance with those of other companies.

EBITDAX (Earnings before interest, tax, depreciation, amortization and exploration expenses)

EBITDAX, can be found by excluding the exploration expenses from the EBITDA. Management believes that this measure provides useful information regarding the Group's profitability and ability to fund its exploration activities and provides a helpful measure for comparing its performance with those of other companies.

Netback

Netback comprises EBITDA adjusted for taxes received/-paid. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities before tax for the period without regard to significant events and/or decisions in the period that are expected to occur less frequently. This measure is also helpful for comparing the Group's operational performance between time periods and with those of other companies.

Alternative performance measures

Netback (USD/boe)

Netback (USD/boe) is calculated by dividing netback in USD by the CWI production for the relevant period. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities before tax for the period without regard to significant events and/or decisions in the period that are expected to occur less frequently, per CWI boe produced. This measure is also helpful for comparing the Group's operational performance between time periods and with that of other companies.

Lifting costs (USD/boe)

Lifting costs comprise of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. DNO's lifting costs per boe are calculated by dividing DNO's share of lifting costs across producing assets by CWI production for the relevant period. Management believes that the lifting cost per boe is a useful measure because it provides an indication of the Group's level of operational cost effectiveness between time periods and with those of other companies.

Acquisition and development costs

Acquisition and development costs comprise the purchase of intangible and tangible assets irrespective of whether paid in the period. Management believes that this measure is useful because it provides an overview of capital investments used in the relevant period.

Operational spend

Operational spend is comprised of lifting costs, exploration expenses and acquisition and development costs. Management believes that this measure is useful because it provides a complete overview of the Group`s total operational costs and capital investments used in the relevant period.

Equity ratio

The equity ratio is calculated by dividing total equity by the total assets. Management uses the equity ratio to monitor its capital and financial covenants. The equity ratio also provides an indication of how much of the Group's assets are funded by equity.

Free cash flow

Free cash flow comprises cash generated from operations less acquisition and development costs. Management believes that this measure is useful because it provides an indication of the profitability of the Group's operating activities excluding the non-cash items of the income statement and includes operational spend. This measure also provides a helpful measure for comparing with that of other companies.

Marketable securities

Marketable securities are comprised of the sum of market value of financial investments and treasury shares. Management believes that this measure is useful because it provides an overview of liquid assets that can be converted to cash in a short period of time.

Net debt

Net debt comprises cash and cash equivalents less bond loans. Management believes that net debt is a useful measure because it provides indication of the minimum necessary debt financing (if the figure is negative) to which the Group is subject at the balance sheet date.

Reserve Life Index

The Reserve Life Index measures the length of time it will take to deplete a resource at given production rates. The ratio is used to measure how long an oil and gas field will last, or more precisely how long the Group's oil and gas reserves will last, and is calculated by dividing the quantity of reserves by the production of petroleum from those reserves during the relevant period.

Glossary and definitions

AED United Arab Emirates dirham

AGM Annual General Meeting

AIM UK Alternative Investment Market

ASRR Annual Statement of Reserves and Resources

bbls Barrels of oil

Board of Directors The Board of Directors of the Company

boe Barrels of oil equivalent

bopd or boepd Barrels of oil per day or barrels of oil equivalent per day

CAPM Capital Asset Pricing Model

Company DNO ASA

Contingent resources

Quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations but not currently considered to be commercially recoverable or where a field development plan has not yet been submitted

Contractor

A company or companies operating in a country under a PSC on behalf of the host government for which it receives either a share of production or a fee

Cost oil

Share of oil produced which is applied to the recovery of costs under a Production Sharing Contract

Crude oil, crude or oil

A mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated

DKK

Danish kroner

CWI Company Working Interest

D&M DeGolyer and MacNaughton

DD&A Depreciation, depletion and amortization

DNO DNO ASA and its consolidated subsidiaries

Group The Company and its consolidated subsidiaries

E&P Exploration and production

EBITDA Earnings before interest, tax, depreciation and amortization

EBITDAX Earnings before interest, tax, depreciation, amortization and exploration expenses

ESMA European Securities and Markets Authority

EU The European Union

EUR Euros

Farm-in To acquire an interest in a license from another party

Farm-out

To assign an interest in a license to another party

Faroe Faroe Petroleum plc

Gas

A mixture of light hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions

GBP Pound sterling

HSSE Health, safety, security and environment

Hydrocarbons

Compounds containing only the elements of hydrogen and carbon, which may exist as solid, liquid or gas

IAS/IFRS International Financial Reporting Standards

IQD Iraqi dinar

KRG Kurdistan Regional Government

Kurdistan Kurdistan region of Iraq

License or permit Area of specified size licensed to a company by the government for production of oil or gas

MMbbls Million barrels of oil

MMboe Million barrels of oil equivalent

NCS Norwegian Continental Shelf

Net entitlement The portion of future production (and thus resources) legally accruing to a contractor under the terms of the development and production contract

Net entitlement reserves Reserves based on net entitlement production

Netback EBITDA adjusted for taxes received/-paid

NOK Norwegian kroner

Norwegian Public Limited Liability Companies Act The Norwegian Public Limited Liability

Companies Act of 13 June 1997 no. 45 ("allmennaksjeloven")

Operator

A company responsible for managing an exploration, development, or production operation

Oslo Stock Exchange Oslo Børs ASA

Petroleum A complex mixture of naturally occurring

hydrocarbon compounds found in rock.

PP&E Property, plant and equipment

PPA Purchase Price Allocation

Glossary and definitions

Profit oil

Production remaining after royalty and cost oil, which is split between the government and the contractors under a Production Sharing Contract

PSC

A Production Sharing Contract or a PSC is an agreement between a contractor and a host government, whereby the contractor bears all risk and cost for exploration, development and production in return for a stipulated share of production

Royalty

Royalty refers to payments that are due to the host government or mineral owner in return for depletion of the reservoirs and the producer contractor for having access to the petroleum resources

SPE Society of Petroleum Engineers

UAE The United Arab Emirates

UK The United Kingdom

UKCS The United Kingdom Continental Shelf

USD United States dollar

WACC

Weighted Average Cost of Capital

DNO ASA

DOKKVEIEN 1 / AKER BRYGGE / 0250 OSLO / NORWAY / PHONE + 47 23 23 84 80 / FAX +47 23 23 84 81/ www.dno.no

Annual Report and Accounts 2019 DNO 95