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	13
HSSE performance	14
Organization and personnel	14
Parent company	18
Main events since yearend	18
Responsibility statement	19
Consolidated accounts	22
Parent company accounts	74
Auditor's report	88
Alternative performance measures	93
Glossary and definitions	96

Highlights

DNO¹ achieved a net or Company Working Interest (CWI) production of 95,100 barrels of oil equivalent per day (boepd) across its portfolio in 2020, the second highest level in the Company's 49 year-history, notwithstanding reduced spending to preserve cash following the market turmoil triggered by the Covid-19 pandemic. Production and reserves were both split around 80:20 between the Kurdistan region of Iraq (Kurdistan) and the North Sea.

Primarily because of the oil and gas price crash early in the year, revenues fell by about one-third from USD 971 million in 2019 to USD 615 million in 2020. The lower revenues and non-cash impairments led to a net loss of USD 286 million. However, with solid cash flow from operations of USD 236 million and North Sea tax refunds of USD 236 million, DNO exited 2020 with a cash balance of USD 477 million, essentially unchanged from the start of the year, following repayment of USD 161 million in bond debt.

Notwithstanding reduction of its 2020 operational spend by 35 percent compared to 2019, DNO drilled 17 wells across its portfolio, including six exploration wells which led to three discoveries; Røver Nord and Bergknapp in Norway and Zartik in Kurdistan. The discoveries will be further evaluated and considered for fast-track development and tie-in to existing offshore or onshore infrastructure.

At mid-year 2020, DNO commissioned its USD 110 million gas capture and injection project in the Company-operated Tawke license in Kurdistan. DNO captured, piped and reinjected a total of 2.4 billion cubic feet (bcf) of Peshkabir field associated gas, which otherwise would have been flared, into the Tawke field for pressure maintenance, leading to an estimated 200,000 barrels of incremental oil recovery. Gross production from the Tawke license averaged 110,300 barrels of oil per day (bopd) in 2020. With new drilling and continued gas injection in 2021, the Company aims to maintain license production above 100,000 bopd for the seventh consecutive year.

At yearend 2020, DNO held 98 licenses across its portfolio. 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, while the North Sea offers high quality exploration opportunities and accounts for four-fifths of the Company's contingent (2C) resources. Encouraged by higher oil prices, more visibility on Kurdistan export payments and temporary Norwegian petroleum tax incentives, DNO plans to ramp up its operational spend by 37 percent to USD 700 million in 2021.

¹ DNO ASA and the companies in which it directly or indirectly owns investments are separate and distinct entities. But in this publication, the terms "DNO", "Company" and "Group" may be used for convenience where reference is made in to those companies. Likewise, the words "we", "us", "our" and "ourselves" may be used with respect to the companies of the DNO Group.

Key figures

Key financials (USD million)	2020	2019
Revenues	614.9	971.4
Gross profit	24.9	430.0
Profit/-loss from operating activities	-314.5	75.6
Net profit/-loss	-285.9	73.5
EBITDA	322.8	549.4
EBITDAX	378.8	695.8
Netback	559.1	606.3
Acquisition and development costs	207.9	407.9
Exploration expenses	55.9	146.4

Production and reserves	2020	2019
Gross operated production (boepd)	110,282	126,985
Net production (boepd)	95,101	104,767
CWI 2P reserves (MMboe)	332.3	344.8

Key performance indicators	2020	2019
Lifting costs (USD/boe)	5.2	5.4
Netback (USD/boe)	16.1	16.3

"Net production" is equivalent to "CWI production".

The net production in 2019 includes production from the assets added through the swap agreement with Equinor Energy AS, effective from 1 January 2019.

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 Director of Property Development and Management at 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 Philly Shipyard ASA, 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.

Board of Directors

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 and HSSE committees.

Board of Directors' report

Introduction

2020 full-year results highlights

Gross operated production in 2020 of 110,282 bopd, down from 126,985 boepd in 2019;
Gross production at the Tawke license in Kurdistan, containing the Tawke and Peshkabir fields, averaged 110,282 bopd compared to 123,940 bopd in 2019;
Net or CWI production of 95,101 boepd, down from 104,767 boepd in 2019;
Revenues of USD 615 million in 2020, down from USD 971 million in 2019;
Kurdistan revenues totaled USD 369 million (2019: USD 717 million) and North Sea revenues totaled USD 246 million (2019: USD 254 million);
Operating loss of USD 315 million in 2020, compared to an operating profit of USD 76 million in 2019;
Operational spend of USD 511 million, down from USD 786 million in 2019;
Yearend cash balance of USD 477 million, down from USD 486 million at yearend 2019; and
CWI proven and probable (2P) reserves of 332 million barrels of oil equivalent (MMboe), compared to 345 MMboe at yearend 2019.

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

Our vision and strategic priorities

DNO's vision is to remain a leading, growth-oriented 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. To achieve this vision, our strategic priorities include:

Increasing production through the development of our existing reserves base;
Growing reserves and contingent resources 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 governance responsibilities and commitments and managing risks to the business; and
Being a leader in health, safety, security and environmental best practices in our areas of operation.

Production strength and capacity

DNO reported gross operated production in 2020 of 110,282 bopd, down from 126,985 boepd in 2019. DNO's net production stood at 95,101 boepd in 2020, down from 104,767 boepd in 2019.

With CWI 2P reserves totaling 332 MMboe across its portfolio, DNO has the asset base to sustain material levels of production over the long term.

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, notably in Kurdistan. 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 our most significant oil and gas asset and have the experienced team and operational capabilities 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, to international capital markets to strengthen the Company's balance sheet.

During 2020, DNO had an average lifting cost of USD 5.2 per boe (2019: 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 areas of operations.

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, business conduct and corporate social responsibility. 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 effectively manage risks. 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 working continuously to reduce the environmental impact of our activities including with respect to greenhouse gas (GHG) emissions. Please refer to the Country-by-Country Report 2020 and the Company's latest Corporate Social Responsibility Report for more information. Both reports are available on the Company's website.

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 carried out an independent assessment of the Tawke license (containing the Tawke and Peshkabir fields) and the Baeshiqa license in Kurdistan. International petroleum consultants Gaffney, Cline & Associates carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). The Company internally assessed Yemen Block 47.

At yearend 2020, DNO's CWI 1P reserves stood at 201.0 MMboe, compared to 205.6 MMboe at yearend 2019, after adjusting for production during the year and upward technical revisions. On a 2P reserves basis, DNO's CWI reserves stood at 332.3 MMboe, compared to 344.8 MMboe at yearend 2019. On a 3P reserves basis, DNO's CWI reserves were 506.8 MMboe, compared to 539.9 MMboe at yearend 2019. DNO's CWI 2C resources were 151.7 MMboe, compared to 187.8 MMboe at yearend 2019.

DNO's CWI production in 2020 totaled 34.8 MMboe (of which 28.5 million barrels of oil (MMbbls) in Kurdistan, 6.0 MMboe in Norway and the balance in the UK), compared to 38.2 MMboe in 2019 (of which 31.9 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in the UK).

DNO's CWI yearend 2020 Reserve Life Index (R/P) stood at 5.8 years on a proven (1P) reserves basis, 9.6 years on a 2P reserves basis and 14.6 years on a proven, probable and possible (3P) reserves basis.

The ASRR report for 2020 is available on the Company's website.

Kurdistan

Tawke license

Gross production from the Tawke license, containing the Tawke and Peshkabir fields, averaged 110,282 bopd during 2020 (123,940 bopd in 2019). The Tawke field contributed 57,570 bopd (68,749 bopd in 2019) and Peshkabir field contributed 52,712 bopd (55,191 bopd in 2019).

DNO halted all drilling on the Tawke license in the second quarter of 2020 following the onset of the Covid-19 pandemic and the collapse of oil and gas prices. In June 2020, DNO fast tracked a well intervention campaign to ramp up production following stabilization of oil prices and resumption of Kurdistan export payments.

Also in June 2020, the Company commissioned the Peshkabirto-Tawke gas reinjection project (the first enhanced oil recovery project in Kurdistan) to unlock additional oil reserves at the Tawke field while significantly reducing associated gas flaring and CO2 emissions at the Peshkabir field. In the second half of 2020, DNO captured, piped and reinjected 2.4 bcf of Peshkabir field gas, which otherwise would have been flared, into the

Tawke field for pressure maintenance, leading to an estimated 200,000 barrels of incremental oil recovery in 2020.

Four development wells were spud in the Tawke license last year.

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

Erbil license

The Company relinquished its operatorship and participation in the Erbil license on 21 May 2020.

Baeshiqa license

In July 2020, the Company completed drilling of Zartik-1, the third exploration well on the Baeshiqa license on the Zartik structure, around 15 kilometers southeast of the Baeshiqa-2 discovery well. The well tested hydrocarbons at surface from several Jurassic zones, with one zone flowing naturally at rates averaging over 2,000 bopd of medium gravity oil.

DNO held a 32 percent operated interest in the Baeshiqa license with partners ExxonMobil Kurdistan Region of Iraq Limited (ExxonMobil) (32 percent), Turkish Energy Company Limited (16 percent) and the Kurdistan Regional Government (KRG) (20 percent).

RESERVES

On a CWI basis at yearend 2020, 1P reserves in DNO's Kurdistan portfolio totaled 159.9 MMbbls (156.9 MMbbls at yearend 2019), 2P reserves totaled 267.8 MMbbls (274.7 MMbbls at yearend 2019) and 3P reserves totaled 410.9 MMbbls (437.9 MMbbls at yearend 2019). The CWI 2C resources were 27.3 MMbbls, compared to 33.5 MMbbls at yearend 2019.

At the Tawke license, at yearend 2020 gross 1P reserves stood at 234.4 MMbbls (159.9 MMbbls on a CWI basis), compared to 227.6 MMbbls (156.9 MMbbls on a CWI basis) at yearend 2019. At yearend 2020 gross 2P reserves stood at 393.9 MMbbls (267.8MMbbls on a CWI basis), compared to 400.0 MMbbls (274.7 MMbbls on a CWI basis) at yearend 2019. At yearend 2020 gross 3P reserves stood at 604.9 MMbbls (410.9 MMbbls on a CWI basis), compared to 640.7 MMbbls (437.9 MMbbls on a CWI basis) at yearend 2019.

The Baeshiqa license contains two large structures with multiple independent stacked target reservoirs, including in the Cretaceous, Jurassic and Triassic formations. The structures have the potential to be part of a single accumulation of hydrocarbons at one or more of the geological formation intervals. This potential has not been established by the exploration and appraisal activities to date and so is excluded from the resource figures.

At the license level and at yearend 2020, gross 2C resources stood at 42.5 MMbbls (15.3 MMbbls on a CWI basis). No reserves were recorded at the Baeshiqa license at yearend 2020, pending conclusion of the ongoing appraisal activities.

At the Baeshiqa structure and following a discovery in 2019, testing and appraisal of the Baeshiqa-2 exploration well was concluded in 2020. The well tested hydrocarbons to surface from multiple Jurassic and Triassic zones. Gross 2C resources at the Baeshiqa structure were recorded at 37.8 MMbbls (13.6

MMbbls on a CWI basis) at yearend 2020. No 2C resources were recorded for the Baeshiqa structure at yearend 2019.

At the Zartik structure, the Company completed drilling and testing of the Zartik-1 exploration well. The well tested hydrocarbons to surface from several Jurassic zones. Gross 2C resources at the Zartik structure were recorded at 4.7 MMbbls (1.7 MMbbls on a CWI basis) at yearend 2020. No 2C resources were recorded for the Zartik structure at yearend 2019.

North Sea

DNO has diversified production across 11 fields in the North Sea of which eight are in Norway and three in the UK. Net production averaged 17,352 boepd during 2020 (17,368 boepd in 2019), of which 16,465 boepd were attributable to Norway and 887 boepd to the UK (16,478 boepd and 890 boepd in 2019).

Temporary Norwegian petroleum tax incentives are driving stepped-up investment plans. The Company is moving toward concept selection for the Brasse field, actively evaluating the Iris/Hades, Røver Nord, Alve Gjøk, Orion/Syrah and Trym South discoveries for project sanction in 2022 and accelerating infill drilling at the Ula, Tambar and Brage producing fields in 2021.

Across DNO's North Sea portfolio, 12 wells were spud in 2020, including five exploration wells and seven development wells, all in Norway. Four wells were permanently plugged and abandoned in the UK. The appraisal of the Bergknapp discovery, among Norway's largest discoveries in 2020, is scheduled for second quarter of 2021. Røver Nord, which was the last exploration well spud in 2020 but drilled to target in early 2021, also yielded a significant and likely commercial discovery.

The Company maintains an active North Sea exploration program targeting four-to-six wildcat wells per year.

The Company announced in January 2021 that its whollyowned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which four are operatorships, under Norway's Awards in Predefined Areas (APA) 2020 licensing round.

RESERVES

At yearend 2020, DNO held 76 licenses in Norway in various stages of exploration, development and production. Across its Norway portfolio and on a CWI basis, DNO's 1P reserves totaled 40.0 MMboe, 2P reserves stood at 63.1 MMboe, 3P reserves totaled 94.0 MMboe and 2C resources stood at 118.7 MMboe. Gross 2C resources at License PL836 S. containing the Bergknapp discovery were reported at 59.4 MMboe (17.8 MMboe on a CWI basis).

At yearend 2019, on a CWI basis DNO's then portfolio of 87 licenses in Norway held 1P reserves of 47.5 MMboe, 2P reserves of 68.3 MMboe, 3P reserves of 99.5 MMboe and 2C resources of 138.9 MMboe.

In the UK at yearend 2020, DNO held 16 licenses. Across its UK portfolio on a CWI basis, DNO's 1P reserves totaled 1.0 MMboe, 2P reserves stood at 1.4 MMboe, 3P reserves totaled 1.9 MMboe and 2C resources stood at 0.9 MMboe.

At yearend 2019, DNO held 12 licenses in the UK with 1P reserves of 1.2 MMboe, 2P reserves of 1.8 MMboe, 3P reserves of 2.6 MMboe and 2C resources of 10.5 MMbbls on a CWI basis.

Yemen

Production start-up at the Yaalen field at Block 47 in Yemen, currently under force majeure, remains on hold. At yearend 2020, gross 2C resources at Block 47 stood at 6.2 MMbbls (4.8 MMbbls on a CWI basis), unchanged from yearend 2019.

Business development

Following DNO's reentry into the North Sea and the acquisitions of Origo Exploration Holding AS (Origo) and Faroe Petroleum plc (Faroe) in 2017 and 2019 respectively, DNO is now a full cycle North Sea player with a significant portfolio of exploration, production and development projects and an experienced North Sea oil and gas team.

In 2020, DNO continued to expand its North Sea portfolio through a combination of licensing rounds and acquisitions. Most notably, at the high potential Edinburgh exploration prospect, one of the largest undrilled structures in the North Sea, DNO through a string of transactions pushed cross-border alignment and equalized the equity level of the partners across all four UK/Norway licenses, retaining a 45 percent interest for the Company.

In the Middle East, DNO further increased its growth potential by acquiring an additional 32 percent interest in the Baeshiqa license in Kurdistan from ExxonMobil (subject to government approval), doubling DNO's operated stake to 64 percent (80 percent paying interest). This agreement was announced following the end of the reporting period. The Company plans to continue an exploration and appraisal program on the license while fast tracking early production from existing wells in 2021.

DNO continues to develop a pipeline of new business opportunities with a focus on 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 2020 stood at USD 614.9 million, down a third from USD 971.4 million in 2019 in the wake of weak oil prices triggered by the Covid-19 pandemic and global economic contraction. Kurdistan revenues stood at USD 369.1 million (USD 717.1 million in 2019), while the North Sea generated revenues of USD 245.8 million (USD 253.5 million in 2019).

The Group reported an operating loss of USD 314.5 million in 2020, compared to an operating profit of USD 75.6 million in 2019. The operating loss in 2020 was impacted by lower

revenues and non-cash impairments, partly offset by lower expensed exploration.

The Group ended the year with USD 477.1 million in cash and USD 472.5 million in net interest-bearing debt, compared to USD 485.7 million and USD 513.3 million at yearend 2019, respectively.

Net cash flows from operating activities for the year was USD 389.1 million, compared to USD 371.5 million in 2019. The North Sea tax refunds of USD 236.3 million received during the year contributed to the solid 2020 cash flows from operating activities. The difference between the cash generated from operations and the operating loss relates mainly to depreciation, depletion and amortization (DD&A) and impairments.

Cost of goods sold

In 2020, the total cost of goods sold was USD 590.0 million, compared to USD 541.4 million in 2019. The increase in cost of goods sold, was related to higher DD&A from USD 311.8 million in 2019 to USD 361.4 million in 2020 driven by higher DD&A per boe (from USD 16.0 per boe in 2019 to USD 17.9 per boe in 2020) and higher North Sea net production² in 2020.

Lifting costs in 2020 totaled USD 181.1 million, compared to USD 199.1 million in 2019. Lifting costs per barrel in Kurdistan stood at USD 3.3 in 2020 (USD 3.3 per barrel in 2019). Lifting costs per boe in the North Sea stood at USD 13.6 in 2020 (USD 17.7 per boe in 2019).

Impairment charges

The Group's total pre-tax impairment charges stood at USD 276.0 million in 2020 (USD 162.0 million in 2019). The 2020 impairments were mainly related to the impairment of technical goodwill and exploration assets in the North Sea.

Exploration costs expensed

Total expensed exploration costs for the year was USD 55.9 million, compared to USD 146.4 million in 2019. The decrease in expensed exploration costs was driven primarily by lower exploration drilling activities and higher capitalized exploration costs following discoveries (Bergknapp and Røver Nord) in the North Sea.

Acquisition and development costs

Total acquisition and development costs stood at USD 207.9 million in 2020, compared to USD 407.9 million in 2019. The lower 2020 acquisition and development costs came as a result of the Group's cost cutting measures and deferral of non-critical or discretionary drilling and capital projects following plunging oil and gas prices triggered by the Covid-19 pandemic and global economic contraction.

Assets, liabilities and equity

At yearend 2020, total assets stood at USD 2,708.7 million, compared to USD 3,271.9 million at yearend 2019. The decrease in total assets was mainly due to impairments of technical goodwill and oil and gas assets, higher DD&A and lower acquisition and development costs. Total property, plant and equipment (PP&E), intangible assets and goodwill decreased from USD 2,030.0 million at yearend 2019 to USD 1,644.7 million at yearend 2020.

Total liabilities decreased from USD 2,110.5 million at yearend 2019 to USD 1,863.0 million at yearend 2020 mainly due to the repayment of bonds (DNO01 and FAPE01). The equity ratio stood at 31.2 percent at yearend 2020 (35.5 percent at yearend 2019).

Going concern

As required under the Norwegian Accounting Act, the Company's Board of Directors conducted a review of the going concern assumption considering all relevant information available up to the date the DNO ASA consolidated and Company accounts are issued and taking into account all available information about the future, for at least 12 months from the reporting date. The Board of Directors' review included in particular assessment of the Group's projected cash reserves and access to financing arrangements considering its operational outlook and work programs, while maintaining appropriate headroom in respect of liquidity and financial covenant compliance throughout the assessment period. In making these assessments, the Board of Directors continued to monitor the uncertainty caused by the ongoing Covid-19 pandemic and its effects on global economy, while also noting the significant improvement in the price of Brent since the reporting date and the Group's reported remaining proven and probable oil and gas reserves that permit cash flow generation covering the forecast period. Stress testing was carried out at lower Brent price scenarios. Sufficient liquidity and covenant compliance can be maintained through the going concern assessment period in the base case and the stress test.

Following its review, the Board of Directors confirms, pursuant to the Norwegian Accounting Act section 3-3a, that the requirements of the going concern assumption are met and that these financial statements have been prepared on that basis.

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 2020, this ratio was 31.2 percent.

² For accounting purposes, the net production from the assets added through the assets swap with Equinor Energy AS in 2019 was accounted for post completion date of 30 April 2019.

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.

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. No dividend distribution took place in the first half of 2020 as the Company acted quickly to shore up its balance sheet in the face of unprecedented market convulsions and plunging oil and gas prices. At the 2020 AGM, 99.8 percent of the votes cast approved the resolution to authorize the Board of Directors to approve a dividend distribution of up to NOK 0.20 per share in the second half of 2020 and a distribution of dividend of up to NOK 0.20 per share in the first half of 2021. Due to continued uncertainty relating to Covid-19 pandemic, the authorization was not utilized in the second half of 2020.

OTHER AUTHORIZATIONS TO THE BOARD OF DIRECTORS

At a 28 February 2020 Extraordinary General Meeting, the Board of Directors was authorized to cancel the 108,381,415 treasury shares held by the Company, equaling 10 percent of the then outstanding shares. The share capital reduction was completed on 8 September 2020 resulting in a new registered share capital of NOK 243,858,186.50 divided on 975,432,746 shares, each with a nominal value of NOK 0.25.

At the 2020 AGM, the Board of Directors was given the authority to acquire treasury shares with a total nominal value of up to NOK 24,385,818 in a new share repurchase program. 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 2021 AGM, but not beyond 30 June 2021. As of 31 December 2020, the Company held no treasury shares.

The Board of Directors was also given the authority to increase the Company's share capital by up to NOK 36,578,727, which corresponds to 146,314,908 new shares. The authorization is valid until the 2021 AGM, but not beyond 30 June 2021.

In addition, the Board of Directors was given the authority to raise convertible bonds with an aggregate principal amount of up to USD 300,000,000. Upon conversion of bonds issued pursuant to this authorization, the Company's share capital may be increased by up to NOK 36,578,727. The authorization is valid until the AGM in 2021, but not beyond 30 June 2021.

Equal treatment of shareholders and transactions with related parties

The Company has one class of shares and each share represents one vote. 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, usually held by the end of May 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 consist 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 2020, 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 process and making recommendations to ensure its integrity. The committee is also responsible for monitoring internal control, risk management and internal audit of the Company within its limits as an independent party and reviewing and monitoring the appointment, independence and performance of the external auditor.

HSSE COMMITTEE

The HSSE (health, safety, security and environment) committee consists of Mr. Lars Arne Takla (chair) and Ms. Shelley Watson. Its mandate is to review the Company's management of operational HSSE risks and 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 for approval 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 through the audit committee. The Company has an internal audit function and a compliance function whose responsibilities include 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 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 two 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 receipt of payments.

In early 2020, monthly entitlement and override payments were withheld by the KRG which was itself hit by lower oil revenues and economic dislocations caused by the pandemic. After a four-month hiatus, entitlement payments were resumed in March 2020. In December 2020, a plan was put in place by the KRG in respect of the withheld entitlement and override payments from 2019 and 2020 (USD 259.0 million at yearend 2020) such that if Brent prices exceed USD 50 per barrel on average in any month, one-half of the incremental revenue will be paid to the Tawke partners and shared prorata to their interests in the license by the KRG towards the withheld amounts. Moreover, as part of the plan, override payments will resume with the January 2021 invoice. The Company expects to recover the full value of the withheld payments of Tawke

license 2019 and 2020 invoices and negotiations continue to further improve the terms of recovery of the arrears, including but not limited to interest payments reflecting the Company's cost of debt. On 9 March 2021, the Company announced the receipt of USD 6.2 million as the first payment towards the withheld amounts.

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.

DNO does not exist in a vacuum. The outbreak of the Covid-19 pandemic and plunging oil and gas prices had adverse effects on the Group's operations and financial results in 2020.

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 some of our operations are 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. 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 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 2020:

Only one Serious Vehicle Accident took place despite distances driven of 2.4 million kilometers. There were no recordable injuries as a result of this accident;
Total GHC emissions from operated assets in Kurdistan and the North Sea and from all DNO's offices and travel, stood at 422,643 tonnes of CO2 equivalent, down from 639,200 tonnes in 2019. The decrease was largely due to the commissioning of the USD 110 million project to capture Peshkabir associated gas and reinject it into the Tawke field to significantly reduce flaring;
DNO's total GHG emissions in 2020 were made up of 416,231 tonnes of CO2 in Scope 1 emissions, 662 tonnes of CO2 in Scope 2 emissions, and 5,750 tonnes of CO2 in Scope 3 emissions,³ .
The number of spills/leaks stood at 23 in 2020, compared to 30 in 2019. The total volume spilled in 2020 was six barrels of oil compared to 65 barrels in 2019, most of which was removed and remediated; and
Security incidents stood at zero, down from one in 2019.

We seek to ensure the integrity of our facilities, starting with design and continuing with robust maintenance focused in particular on safety critical equipment.

There was one Lost Time Injury during the year, compared to zero in 2019. Our Total Recordable Injury Frequency during 2020 was 0.6, compared to 0.9 in 2019.

We continue to work with our employees and third-party contractors on programs to improve safety performance.

Organization and personnel

At yearend 2020, DNO had a workforce of 1,257 employees, of which 12 percent were women. A total of 57 individuals were based at the Company's headquarters in Oslo and 1,200 were engaged across our international operations, including in business unit offices in Erbil, Stavanger, Dubai and Aberdeen. Our workforce is characterized by strong cultural, religious and national diversity, with some 43 nationalities represented.

At yearend 2020, the Board of Directors consisted of five members, two of whom are women (40 percent). Executive management consisted of two women (20 percent) and eight men.

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

Sickness absence in the Group in 2020 was 1.1 percent, compared to 2.0 percent in 2019.

Covid-19

Since mid-March 2020, the Company implemented various prevention measures, including work from home, testing and quarantine as appropriate at each location and as guided by local authorities.

Workforce diversity in DNO Norway

In Norway, DNO had a workforce of 144 employees at yearend 2020, of which 45 percent were women. A total of 28 employees have worked part time during 2020, of which 57 percent were women. A total of 11 employees were on parental leave. Women had an average of 25 weeks of parental leave and men had an average of 15 weeks of parental leave.

Workforce diversity and measures to secure equality and address any potential discrimination will continue, with new initiatives to be considered in 2021.

Working environment in DNO Norway

DNO has a Working Environment Committee (AMU/WEC) as required under the Norwegian Working Environment Act. The committee has an important role in monitoring and improving the working environment and in ensuring that the Company complies with laws and regulations in this area. The Company is committed to maintaining an open and constructive dialogue with the employee representatives and has arranged meetings on a regular basis throughout the year. In the Board of Directors' view, the working environment in DNO during 2020 was good as confirmed through WEC meetings and employee satisfaction surveys conducted during 2020.

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 6-16a and section 5-6 third paragraph. The guidelines for 2021 will be presented in the 2021 AGM for approval and the guidelines and the voting results will be published on the Company's website.

³ The GHG reporting is consolidated and presented in accordance with the requirements of The GHG Protocol Corporate Accounting and Reporting Standard. The Scope 1 and Scope 3 emissions are based on IPCC 2006 emission factors. The Scope 2 emissions are based on a conservative emissions factor derived from the average electricity consumption across DNO offices.

Remuneration policy for 2020

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 did not set any upper or lower limit for the fixed salary of executive management for 2020 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-tracking incentive scheme

The Board of Directors continued a share-tracking incentive scheme utilizing synthetic shares in 2020. The purpose of the program was to: (i) align the interests of executive management and other employees with those of shareholders'; (ii) reward value creation; and (iii) provide retention incentives. The Board of Directors determines whether to set allocation criteria, conditions or thresholds for the scheme.

Severance agreements

Severance payment agreements may be entered into selectively.

Binding sections

For 2020, remuneration related to share-based incentive schemes was subject to a separate vote by the AGM and was binding once approved. Other sections of the remuneration policy were non-binding guidelines for the Board of Directors and were therefore only subject to a consultative vote at the AGM. In 2021, the distinction between binding and nonbinding sections will be eliminated in accordance with provisions of the Norwegian Public Limited Liability Companies Act, section 6- 16a.

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, Corporate Secretary, Chief Compliance Officer

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.

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.

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.

ØRJAN GJERDE General Manager DNO North Sea

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.

TONJE PARELI GORMLEY General Counsel - Middle East

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 from the London Metropolitan University.

AERNOUT VAN DER GAAG

University of Groningen.

Finance Director North Sea and Group Planning 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

Parent company

The parent company, DNO ASA, reported a net loss of USD 319.1 million in 2020, compared to a net loss of USD 18.1 million in 2019. The increase in the net loss compared to last year was mainly due to lower dividends from subsidiaries and higher impairments of the book value of shares in subsidiaries. Total assets as of 31 December 2020 were USD 1,091.6 million, down from USD 1,473.4 million at yearend 2019. The decrease in total assets was mainly due to higher impairments of the book value of shares in subsidiaries. The parent company's cash balance at yearend 2020 was USD 299.7 million, down from USD 389.0 million at yearend 2019. Total liabilities decreased from USD 996.3 million at yearend 2019 to USD 951.3 million at yearend 2020 mainly due to the repayment of bonds (DNO01), partially offset by an increase in long-term intercompany liabilities. Total equity at yearend 2020 was USD 140.3 million, down from USD 477.1 million in 2019 mainly due to higher net loss in 2020. The equity ratio was 12.8 percent (32.4 percent at yearend 2019).

The Board of Directors will recommend that the shareholders approve the transfer of the net loss of USD 319.1 million from retained earnings at the forthcoming AGM.

Main events since yearend

On 19 January 2021, the Company announced that its whollyowned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which four are operatorships, under Norway's Awards in Predefined Areas (APA) 2020 licensing round. Of the 10 new licenses, six are in the North Sea and four in the Norwegian Sea.

On 28 January 2021, DNO received USD 32.5 million for its share of December 2020 oil deliveries to the export market from the Tawke license in Kurdistan.

On 5 February 2021, the Company announced an oil and gas discovery on the Røver Nord prospect in the Norwegian North Sea license PL923 in which DNO holds a 20 percent interest. Preliminary estimates of gross recoverable resources are in the range of 45-70 MMboe, well above pre-drill estimates. The partners are considering fast-track development of the discovery with tie-back to nearby Troll area infrastructure, as well as additional drilling to test other identified prospects on the license.

On 9 March 2021, DNO received USD 42.4 million net to the Company from the KRG, of which USD 31.9 million represented DNO's share of January 2021 oil deliveries to the export market from the Tawke license in Kurdistan. Of the balance, USD 4.3 million was the override payment to the Company for January 2021 and USD 6.2 million was a payment towards the Company's arrears of USD 259.0 million relating to withheld payment of Tawke license 2019 and 2020 entitlement and override invoices.

Responsibility statement

DNO ASA's consolidated financial statements for the period 1 January to 31 December 2020 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 2020 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 2020 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 2021

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

Elin Karfjell Gunnar Hirsti Bjørn Dale Director Director Managing Director

Consolidated statements of comprehensive income 22 Consolidated statements of financial position 23 Consolidated cash flow statements 24 Consolidated statements of changes in equity 25

Note disclosures

Note 1	Summary of IFRS accounting principles	26
Note 2	Segment information	36
Note 3	Revenues	38
Note 4	Cost of goods sold/Inventory	38
Note 5	Administrative/Other operating expenses	39
Note 6	Exploration expenses	41
Note 7	Financial income and financial expenses	41
Note 8	Income taxes	42
Note 9	Financial instruments	44
Note 10	Property, plant and equipment/Intangible assets	49
Note 11	Financial investments	55
Note 12	Other non-current receivables/Trade and receivables	55
Note 13	Cash and cash equivalents	56
Note 14	Equity	56
Note 15	Interest-bearing liabilities	58
Note 16	Provisions for other liabilities and charges/Lease liabilities	59
Note 17	Commitments and contingencies	61
Note 18	Trade and other payables	62
Note 19	Earnings per share	62
Note 20	Group companies	63
Note 21	Related party disclosure	63
Note 22	Significant events after the reporting date	64
Note 23	Company Working Interest and Net Entitlement reserves (unaudited)	65
Note 24	Oil and gas license portfolio	67
Note 25	Business combinations	71

Board of Directors' report

Annual Report and Accounts 2020 DNO 21

Parent company accounts

Income statement	74
Balance sheet	74
Cash flow statement	76
Note disclosures	77


Auditor's report	88

Consolidated statements of comprehensive income

	1 January - 31 December
USD million	Note
		2020	2019

Revenues	2, 3	614.9	971.4
Cost of goods sold	4	-590.0	-541.4
Gross profit		24.9	430.0
Other income/-expenses		-	-0.5
Administrative expenses	5	-4.8	-26.1
Other operating expenses	5	-2.7	-19.3
Impairment oil and gas assets	10	-276.0	-162.0
Exploration expenses	6	-55.9	-146.4
Profit/-loss from operating activities		-314.5	75.6

Financial income	7	19.8	9.6
Financial expenses	7	-131.0	-133.1
Profit/-loss before income tax		-425.8	-47.8

Tax income/-expense	8	139.8	121.3
Net profit/-loss		-285.9	73.5

Other comprehensive income
Currency translation differences		-3.6	-27.0
Items that may be reclassified to profit or loss in later periods		-3.6	-27.0

Net fair value changes from financial instruments	11	-8.4	25.8
Items that are not reclassified to profit or loss in later periods		-8.4	25.8
Total other comprehensive income, net of tax		-12.0	-1.2

Total comprehensive income, net of tax		-298.0	72.3

Net profit/-loss attributable to:
Equity holders of the parent		-285.9	73.5
Non-controlling interests		-	-
Total comprehensive income attributable to:
Equity holders of the parent		-298.0	72.3
Non-controlling interests		-	-

Earnings per share, basic (USD per share)	19	-0.29	0.07
Earnings per share, diluted (USD per share)	19	-0.29	0.07

Weighted average number of shares outstanding (excluding treasury shares) (millions)		975.73	1,036.37

Consolidated statements of financial position

	Years ended 31 December
USD million	Note	2020	2019

ASSETS
Non-current assets
Goodwill	10	162.0	333.9
Deferred tax assets	8	47.4	63.7
Other intangible assets	10	308.6	346.6
Property, plant and equipment	10	1,174.1	1,349.5
Financial investments	11	12.6	21.0
Other non-current receivables	12	182.4	-
Total non-current assets		1,887.1	2,114.7
Current assets
Inventories	4	41.9	28.2
Trade and other receivables	12	239.6	478.5
Tax receivables	8	63.1	164.8
Cash and cash equivalents	13	477.1	485.7
Total current assets		821.6	1,157.2

TOTAL ASSETS		2,708.7	3,271.9
EQUITY AND LIABILITIES Equity
Shareholders' equity	14	845.6	1,161.3
Total equity		845.6	1,161.3

Non-current liabilities
Deferred tax liabilities	8	178.8	217.6
Interest-bearing liabilities	15	934.2	836.0
Lease liabilities	16	13.9	11.1
Provisions for other liabilities and charges	16	440.1	422.8
Total non-current liabilities		1,566.9	1,487.5
Current liabilities
Trade and other payables	18	180.3	288.9
Income taxes payable	8	-	0.2
Current interest-bearing liabilities	15	-	225.6
Current lease liabilities	16	3.8	3.3
Provisions for other liabilities and charges	16	112.0	105.1
Total current liabilities		296.1	623.0

Total liabilities		1,863.0	2,110.5
TOTAL EQUITY AND LIABILITIES		2,708.7	3,271.9

Oslo, 17 March 2021

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 statements

		1 January - 31 December
USD million	Note
		2020	2019
Operating activities
Profit/-loss before income tax		-425.8	-47.8
Adjustments to add/-deduct non-cash items:
Exploration cost capitalized in previous years carried to cost	6	0.4	27.8
Depreciation, depletion and amortization	4	361.4	311.8
Impairment oil and gas assets	10	276.0	162.0
Other*		107.6	6.7
Changes in working capital items and provisions:
- Inventories		-13.7	-2.0
- Trade and other receivables	12	41.1	-147.4
- Trade and other payables		-108.5	-18.1
- Provisions for other liabilities and charges		-2.7	92.5
Cash generated from operations		235.8	385.3
Tax refund received		236.3	56.9
Interest received		2.7	7.6
Interest paid		-85.7	-78.2
Net cash from/-used in operating activities		389.1	371.5

Investing activities
Purchases of intangible assets		-45.7	-68.5
Purchases of tangible assets		-162.2	-339.4
Payments for decommissioning		-30.7	-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
Net cash from/-used in investing activities		-238.6	-823.0
Financing activities
Proceeds from borrowings net of issue costs	15	152.3	537.9
Repayment of borrowings	15	-290.3	-197.6
Purchase of treasury shares	14	-17.8	-82.3
Paid dividend	14	-	-46.6
Payments of lease liabilities		-3.4	-3.2
Net cash from/-used in financing activities		-159.1	208.3

Net increase/-decrease in cash and cash equivalents		-8.6	-243.2
Cash and cash equivalents at beginning of the period		485.7	729.1
Cash and cash equivalents at end of the period	13	477.1	485.7

Of which restricted cash	13	13.6	14.3

* Other in 2020 includes adjustments for interest income (USD -5.4 million), interest expense (USD 87.3 million), accretion expense in relation to ARO provision (USD 17.0 million), amortization of borrowing issue costs (USD 7.6 million) and other non-cash changes (USD 1.1 million).

Consolidated statements of changes in equity

				Other comprehensive income
			Other paid-in	Fair value	Currency
	Share			Share capital/Other changes equity	translation	Retained	Total
USD million	capital	premium	reserves	instruments	difference	earnings	equity
Total shareholders' equity as of 31 December 2018	35.0	247.7	24.7	-	-32.9	943.2	1,217.8
Reallocation of equity	-	-	25.8	18.7	-1.5	-43.0	-
Total shareholders' equity as of 1 January 2019	35.0	247.7	50.5	18.7	-34.4	900.2	1,217.8
Fair value changes from equity instruments	-	-	-	25.8	-	-	25.8
Currency translation differences	-	-	-	-	-27.0	-	-27.0
Other comprehensive income	-	-	-	25.8	-27.0	-	-1.2
Profit/-loss for the period	-	-	-	-	-	73.5	73.5
Total comprehensive income	-	-	-	25.8	-27.0	73.5	72.3
Purchase of treasury shares	-1.6	-	-80.7	-	-	-	-82.3
Payment of dividend	-	-	-	-	-	-46.6	-46.6
Transactions with shareholders	-1.6	-	-80.7	-	-	-46.6	-129.0
Transfers	-	-	-	-	-	-	-
Total shareholders' equity as of 31 December 2019	33.3	247.7	-30.2	44.5	-61.4	927.4	1,161.3

				Other comprehensive income
			Other paid-in	Fair value	Currency
	Share			Share capital/Other changes equity	translation	Retained	Total
USD million	capital	premium	reserves	instruments	difference	earnings	equity
Total shareholders' equity as of 31 December 2019	33.3	247.7	-30.2	-	-36.6	947.0	1,161.3
Reallocation of equity	-	-	-	44.5	-24.8	-19.7	-
Total shareholders' equity as of 1 January 2020	33.3	247.7	-30.2	44.5	-61.4	927.4	1,161.3
Fair value changes from equity instruments	-	-	-	-8.4	-	-	-8.4
Currency translation differences	-	-	-	-	-3.6	-	-3.6
Other comprehensive income	-	-	-	-8.4	-3.6	-	-12.0
Profit/-loss for the period	-	-	-	-	-	-285.9	-285.9
Total comprehensive income	-	-	-	-8.4	-3.6	-285.9	-298.0
Purchase of treasury shares	-0.4	-	-17.3	-	-	-	-17.7
Payment of dividend	-	-	-	-	-	-	-
Transactions with shareholders	-0.4	-	-17.3	-	-	-	-17.7
Transfers	-	-	47.5	-	-	-47.5	-
Total shareholders' equity as of 31 December 2020	32.9	247.7	0.0	36.1	-65.0	593.9	845.6

Reallocation of equity is related to change in the presentation of other comprehensive income. Total equity is unchanged.

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

On 8 September 2020, the Company announced that the reduction of its registered share capital by cancellation of all 108,381,415 treasury shares, approved by shareholders at a 28 February 2020 Extraordinary General Meeting, had been completed. The Company's new registered share capital is NOK 243,858,186.50 divided on 975,432,746 shares, each with a nominal value of NOK 0.25. As of 31 December 2020, the Company held no treasury shares.

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 2020. The consolidated financial statements were approved by the Board of Directors on 17 March 2021.

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.

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.

Going concern

carried out at lower Brent price scenarios. Sufficient liquidity and covenant compliance can be maintained through the going concern assessment period in the base case and the stress test.

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 receipt of payments. In early 2020, monthly entitlement and override payments were withheld by the KRG which was itself hit by lower oil revenues and economic dislocations caused by the pandemic. After a fourmonth hiatus, entitlement payments were resumed in March 2020. In December 2020, a plan was put in place by the KRG in respect of the withheld entitlement and override payments from 2019 and 2020 (USD 259.0 million at yearend 2020) such that if Brent prices exceed USD 50 per barrel in average in any month, one-half of the incremental revenue will be paid by the KRG to the Tawke partners, and shared prorata to their interests in the license, towards payments of the withheld amounts. Moreover, as part of the plan, override payments will resume with the January 2021 invoice. The Company expects to recover the full nominal value of the withheld payments and discussions continue to further improve the terms of recovery of the arrears, including but not limited to interest payments reflecting the Company's cost of debt. See Note 9 for further details on estimates and judgement on recoverability. Management monitors development and continuously ensures that revenue recognition criteria in IFRS 15 are met.

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. International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license (containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the Baeshiqa and Zartik structures) in the Kurdistan region of Iraq. International petroleum consultants Gaffney, Cline & Associates (GCA) carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). The Group's estimates are based on internal assessment for contingent resources on Yemen Block 47.

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 can 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, regulatory requirements and related costs may change. 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 amount 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 subject to impairment testing whenever there is an 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. When deferred tax from the initial recognition decreases, more goodwill is exposed for impairment. After initial recognition, 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 its 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 DNO. 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 section Income taxes and 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 the 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 the sale.

Classification in the statements of financial position

Current assets and short-term liabilities include items due less than one year from the balance sheet 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 non-current liabilities.

Fair value

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 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 license rights are recognized as intangible assets at the time of acquisition. Acquired license 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.

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.

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.

Leases

IFRS 16 Leases was issued in January 2016 and replaced IAS 17 Leases. The Group implemented IFRS 16 on 1 January 2019.

The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

The Group applies a single recognition and measurement approach for all leases, except for short-term leases (12 months or less) and leases of low-value assets. Short term leases 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.

At the commencement date of a lease, the Group recognizes a liability to make lease payments and an asset representing the right to use the underlying asset (right-of-use (RoU) asset) during the lease term.

The RoU assets are measured to cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The RoU assets are depreciated linearly over the lifetime of the related lease contract.

Lease liabilities are measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses the implicit interest rate and if not readily determinable, its incremental borrowing rate at the lease commencement date.

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, relating to contracts contain a lease, are replaced by depreciation and interest expense.

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

The Group's RoU assets mainly relate to office rent 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.

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 or more often if indicators exist.

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 license 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 an 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 licenses 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; changes in the fair value of financial assets through profit or loss; and other financial income. Interest income is recognized as it accrues in profit or loss using the effective interest method. Dividend income is recognized in the 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

Note 1

Summary of IFRS accounting principles

of financial assets measured at FVTPL; impairment losses recognized on financial assets; foreign exchange losses; losses on financial assets recognized in the profit or loss; and other financial expenses.

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

Inventories

Inventories 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.

Overlift/underlift balances are valued at production cost including depreciation (the sales method). The movements in overlift/underlift are presented as an adjustment to Cost of goods sold.

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

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

Other revenues are recognized when the goods or services are delivered and 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. In addition, pursuant to a receivables settlement agreement with the KRG in August 2017, DNO is entitled to production overrides (override) representing three percent of gross Tawke license revenues until 31 July 2022. The Group recognizes revenues in Kurdistan in line with the invoiced oil sales and overrides following monthly deliveries to the KRG. 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 adjustments up or down 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.

DNO presents its operations governed by PSCs according to the sales method and only recognizes its sales as revenue 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 from 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 reassessed 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 licenses in the North Sea are based on cash flows after tax. This is because these licenses 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 measured 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 reliably measured. In the exploration phase, the Group normally recognizes license swaps based on historical cost basis. 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

Note 1

Summary of IFRS accounting principles

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.

Other amendments and interpretations may apply for the first time in 2020 but are not considered to have any material impact on the Group's financial statements.

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.

The Group reports the following two operating segments: Kurdistan and the North Sea (which includes the Group's oil and gas activities in Norway and the UK). The operating segments correspond to the reportable segments. Remaining operating segments are included in the Other category based on a materiality assessment.

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
Full-Year ending 31 December 2020	Note	Kurdistan	North Sea	Other	Total reporting	Un allocated/ segments eliminated	Total Group
COMPREHENSIVE INCOME INFORMATION
Revenues	3	369.1	245.8	-	614.9	-	614.9
Inter-segment sales		-	1.4	-	1.4	-1.4	-
Cost of goods sold	4	-334.0	-253.4	-	-587.3	-2.7	-590.0
Gross profit		35.2	-6.2	-	29.0	-4.1	24.9
Other income		-	-0.0	-	-0.0	-	-0.0
Administrative expenses	5	-0.6	-2.1	-4.2	-6.9	2.1	-4.8
Other operating expenses	5	-1.4	-	-1.3	-2.7	-	-2.7
Impairment of oil and gas assets	10	-	-276.0	-	-276.0	-	-276.0
Exploration expenses	6	-1.6	-60.1	-0.0	-61.7	5.7	-55.9
Profit/-loss from operating activities		31.6	-344.4	-5.4	-318.3	3.7	-314.5

Net financial income/-expense	7	-15.9	-26.3	1.3	-40.9	-70.3	-111.2
Tax income/-expense	8	-	141.7	0.5	142.2	-2.4	139.8
Net profit/-loss		15.7	-229.0	-3.7	-217.0	-68.9	-285.9
FINANCIAL POSITION INFORMATION
Non-current assets		830.5	1,031.6	-	1,862.1	25.0	1,887.1
Current assets		173.1	335.9	3.9	512.8	308.8	821.6
Total assets		1,003.6	1,367.4	3.9	2,374.9	333.8	2,708.7
Non-current liabilities		60.6	710.1	-	770.7	796.2	1,566.9
Current liabilities		73.9	178.8	28.9	281.6	14.5	296.1
Total liabilities		134.5	888.9	28.9	1,052.3	810.8	1,863.0
OTHER SEGMENT INFORMATION (key figures)

EBITDA	271.1	49.0	-5.4	314.7	8.1	322.8
EBITDAX	272.7	109.2	-5.4	376.4	2.4	378.8
Netback	271.1	285.3	-5.4	551.0	8.1	559.1
Lifting costs	-94.5	-86.6	-	-181.1	-	-181.1
Lifting costs (USD/boe)	3.3	13.6	-	5.2	-	5.2
Netback (USD/boe)	9.5	44.9	-	16.1	-	16.1
DD&A	-234.9	-116.3	-	-351.2	-10.2	-361.4
DD&A (USD/boe)	-17.7	-18.3	-	-17.9	-	-17.9
Acquisition and development costs	-92.6	-114.5	-	-207.1	-0.9	-207.9

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

Note 2 Segment information

USD million

Full-Year ending 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 (key figures)
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

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

Note 3 Revenues

	1 January - 31 December
USD million	2020	2019
Sale of oil	566.6	918.1
Sale of gas	27.5	36.5
Sale of natural gas liquids (NGL)	14.8	13.0
Tariff income	6.0	3.7
Total revenues from contracts with customers	614.9	971.4

In 2020, sale of oil from Kurdistan was USD 369.1 million and in the North Sea USD 197.5 million. Sale of gas was USD 27.5 million, sale of NGL was USD 14.8 million and tariff income was USD 6.0 million, all entirely from the North Sea.

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.

Note 4 Cost of goods sold/Inventory

		1 January - 31 December
USD million	2020	2019
Lifting costs	-181.1	-199.1
Tariff and transportation expenses	-36.2	-37.7
Production cost based on produced volumes	-217.3	-236.8
Movement in overlift/underlift	-11.3	7.2
Production cost based on sold volumes	-228.6	-229.6
Depreciation, depletion and amortization	-361.4	-311.8
Total cost of goods sold	-590.0	-541.4

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 in the North Sea for the use of infrastructure owned by other companies.

		Years ended 31 December
USD million	2020	2019
Spare parts	41.9	28.2
Total inventory	41.9	28.2

Total inventory of USD 41.9 million at yearend 2020 was related to Kurdistan (USD 22.1 million) and the North Sea (USD 19.8 million). In 2020, the provision for obsolete inventory in Kurdistan was USD 18.1 million (unchanged from yearend 2019).

Note 5 Administrative/Other operating expenses

	1 January - 31 December
USD million	2020	2019
Salaries, bonuses, etc.	-42.0	-50.6
Employer's payroll tax expenses	-5.2	-7.5
Pensions	-3.7	-3.7
Other personnel costs	-1.1	-4.7
General and administration expenses	-38.9	-36.6
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets	86.0	77.0
Total administrative expenses	-4.8	-26.1

Other expenses	-2.7	-19.3
Total other operating expenses	-2.7	-19.3

This note should be read in conjunction with Note 21 on related parties. 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 relation to Yemen, see Note 17.

DNO has a defined contribution scheme for its Norway-based employees, with USD 3.7 million expensed in 2020 (USD 3.7 million in 2019). The Group's obligations are limited to the annual pension contributions. DNO meets the Norwegian legal requirements for mandatory occupational pension ("obligatorisk tjenestepensjon").

Certain members of the executive management and staff have been awarded synthetic shares during the year as part of their variable remuneration. At yearend 2020, the Company's liability for synthetic shares as part of other variable remuneration amounted to USD 1.3 million (USD 2.4 million at yearend 2019). 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	2020	2019
Outstanding as of 1 January	3,191,605	2,765,772
Granted during the year	1,561,975	1,347,733
Forfeited/reversed during the year	551,116	23,465
Settled during the year	1,365,313	898,435
Expired during the year	-	-
Outstanding as of 31 December	2,837,151	3,191,605
Unrestricted as of 31 December	626,951	125,032
Weighted average remaining contractual life for the synthetic shares (years)	3.85	3.99
Weighted average settlement price for synthetic shares settled during the year (NOK)	6.11	14.98
Settlement price for synthetic shares at the end of the year (NOK)	6.87	11.57

Note 5 Administrative/Other operating expenses

Remuneration to Board of Directors and executive management

		1 January - 31 December
USD million	2020	2019
Managing Director
Salary	-0.63	-0.67
Bonus	-0.20	-0.21
Pension	-0.02	-0.02
Other remuneration	-0.07	-0.07
Remuneration to Managing Director	-0.92	-0.98
Other executive management
Salary	-3.71	-3.20
Bonus	-0.89	-0.51
Pension	-0.15	-0.14
Other remuneration	-0.71	-0.45
Remuneration to other executive management	-5.46	-4.30
Total remuneration to executive management	-6.38	-5.27
Number of managers included	10	11
Total remuneration to Board of Directors	-1.00	-1.06
Total remuneration to Board of Directors and executive management	-7.38	-6.33

Total remuneration of USD 0.5 million (not included in the above table) was in 2020 paid to Rune Martinsen, 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, Chris Spencer, 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
	2020		2019
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)	350,000	-	250,000	-
Shelley Watson, Director*	-	-	-	-
Bjørn Dale, Managing Director	-	-	-	-
Chris Spencer, Deputy Managing Director (Chris's Corporation AS)	32,000	-	32,000	-
Haakon Sandborg, Chief Financial Officer	-	-	-	-
Ute Quinn, Group General Counsel	-	-	-	-
Nicholas Whiteley, Group Exploration and Subsurface Director	-	-	-	-
Ørjan Gjerde, General Manager DNO North Sea	-	-	-	-
Tom Allan, General Manager Kurdistan Region of Iraq	-	-	-	-
Geir Arne Skau, Human Resources Director	10,750	-	10,750	-
Aernout van der Gaag, Finance Director North Sea and Group Planning	-	-	-	-
Tonje Pareli Gormley, General Counsel - Middle East	-	-	-	-

* Bijan Mossavar-Rahmani and Shelley Watson hold indirect interests in the Company through their shareholdings in RAK Petroleum plc (see Note 11).

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)	2020	2019
Auditor fees	-0.74	-0.82
Other financial auditing	-0.01	-0.01
Tax advisory services	-0.05	-0.07
Other advisory services	-0.01	-0.02
Total auditor fees	-0.81	-0.92

Note 6 Exploration expenses

		1 January - 31 December
USD million	2020	2019
Exploration expenses (G&G and field surveys)	-16.1	-17.6
Seismic costs	-2.9	-22.0
Exploration expenses capitalized in previous years carried to cost	-0.4	-27.8
Exploration expenses capitalized during the year carried to cost	-17.1	-47.9
Other exploration expenses	-19.5	-31.2
Total exploration expenses	-55.9	-146.4

Exploration expenses in 2020 were mainly related to exploration activities in the North Sea, including expensing of exploration wells previously capitalized.

Note 7 Financial income and financial expenses

		1 January - 31 December
USD million	2020	2019
Interest income	5.4	9.6
Currency exchange gains recognized in the income statement (net)	14.4	-
Financial income	19.8	9.6

Interest expenses	-87.3	-89.1
Currency exchange losses charged to the income statement (net)	-	-0.8
Other financial expenses	-43.7	-43.2
Financial expenses	-131.0	-133.1

Net financial income/-expenses	-111.2	-123.5

Other financial expenses in 2020 relate mainly to the amortization of borrowing issue costs, time value effects from discounting receivables (see Note 12) and accretion expenses (i.e., unwinding of discount) related to the ARO provisions and lease liabilities (see Note 16).

Note 8 Income taxes

Tax income/-expense

		1 January - 31 December
USD million	2020	2019
Changes in deferred taxes	11.1	6.8
Income taxes receivable/-payable	128.8	114.5
Total tax income/-expense	139.8	121.3

Income tax receivable/-payable

		Years ended 31 December
USD million	2020	2019
Tax receivables	63.1	164.8
Income taxes payable	-	-0.2
Net tax receivable/-payable	63.1	164.5

During 2020, the Norwegian Parliament approved certain time limited changes to the taxation of oil and gas companies operating on the Norwegian Continental Shelf (NCS) with effect from the income year 2020. The changes comprise of immediate expensing of investments in the special petroleum tax, increased uplift on capital investments from 20.8 percent over four years to 24.0 percent in the first year and cash refund of tax value of losses incurred in the income years 2020 and 2021. The temporary changes, other than the cash refund of tax losses, will also apply to investments where the Plan for Development and Operation (PDO) is delivered within 31 December 2022 and approved within 31 December 2023.

The tax income, tax receivables and recognized deferred tax assets/-liabilities relate to activity on the NCS and the UK Continental Shelf (UKCS). Tax receivables consist of tax value of incurred losses on the NCS for 2020 (USD 47.6 million) and decommissioning tax refund on the UKCS (USD 15.5 million). During 2020, DNO received tax refunds of USD 226.5 million in Norway and USD 9.8 million in the UK. The refund of tax losses in 2020 on the NCS is paid out in six instalments every two months. The first three instalments were received in the second half of 2020 and the remaining three instalments of USD 15.9 million each will be received in the first half of 2021. The decommissioning tax refund on the UKCS is expected during third quarter 2021.

Reconciliation of tax income/-expense

		1 January - 31 December
USD million	2020	2019

Profit/-loss before income tax	-425.8	-47.8
Expected income tax according to nominal tax rate in Norway, 22 percent	83.6	-4.1
Expected income tax according to nominal tax rate in Norway, 56 percent	182.5	139.9
Expected income tax according to nominal tax outside Norway	19.0	27.0
Foreign exchange variations between functional and tax currency	-19.9	-
Adjustment of previous years	0.8	0.1
Adjustment of deferred tax assets not recognized	-17.2	-30.2
Change in previous years	0.4	1.2
Other items including other permanent differences	-110.5	-12.6
Change in tax rate	0.4	-
Tax loss carried forward utilized	0.7	-
Tax income/-expense	139.8	121.3

Effective income tax rate	-32.8%	-253.6%
Taxes charged to equity	-	-

Other items above consist mainly of permanent differences on impairment of goodwill which is not tax deductible, and permanent differences on tax exempted profits/losses from upstream activities outside of Norway carried out by the Company's Norwegian subsidiaries.

Note 8 Income taxes

Tax effects on temporary differences

		Years ended 31 December
USD million	2020	2019
Tangible assets	-267.4	-285.5
Intangible assets (including capitalized exploration expenses)	-197.9	-197.5
ARO provisions	313.2	283.1
Losses carried forward	170.3	166.5
Non-deductible interests carried forward	11.5	11.5
Other temporary differences	-5.2	21.5
Net deferred tax assets/-liabilities	24.4	-0.3
Valuation allowance	-155.8	-153.6
Net deferred tax assets/-liabilities	-131.4	-153.9
Recognized deferred tax assets	47.4	63.7
Recognized deferred tax liabilities	-178.8	-217.6

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 outstanding 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.

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.

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	2020	2019
Net deferred tax assets/-liabilities at 1 January	-153.9	7.0
Change in deferred taxes in the income statement	11.1	6.8
Deferred taxes related to business combinations and other transactions	-	-111.7
Reclassification from tax receivable	1.6	-66.4
Currency and other movements	9.0	10.5
Net deferred tax assets/-liabilities at 31 December	-131.4	-153.9

Reconciliation of change in tax receivable/-payable

		Years ended 31 December
USD million	2020	2019
Tax receivable/-payable at 1 January	164.5	27.8
Tax receivable/-payable related to transactions posted directly to balance sheet	-	15.5
Tax receivable/-payable in the income statement	128.8	114.5
Tax payment/-refund	-236.3	-56.9
Prior period adjustment	-2.4	-0.2
Reclassification to deferred tax asset	-1.6	66.4
Currency and other movements	10.0	-2.6
Tax receivable/-payable at 31 December	63.1	164.5

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 and gas. The Group had no oil and gas price hedging arrangements at yearend.

The following table illustrates the impact on 2019 and 2020 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)
2020 +/- 15.0	+/- 72.9
2019 +/- 15.0	+/- 97.4

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 2020 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 2019 and 2020 from foreign currency exchange rate fluctuations deemed reasonable and possible in NOK and GBP exchange rates, with all other variables held constant. The other currencies (e.g., AED, IQD, EUR) are not included as the exposure is deemed immaterial.

	Change in	Effect on profit	Effect on OCI
	NOK (percent)	before tax (USD mill)	(USD mill)
2020	+ 10.0	-7.8	-65.4
2020	- 10.0	7.8	74.4
2019	+ 10.0	-2.0	-44.4
2019	- 10.0	2.0	45.1

	Change in	Effect on profit	Effect on OCI
	GBP (percent)	before tax (USD mill)	(USD mill)
2020	+ 10.0	1.0	-31.4
2020	- 10.0	-1.0	30.0
2019	+ 10.0	1.1	-22.9
2019	- 10.0	-1.1	21.8

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 2020. 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 2019 and 2020 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	Effect on profit
	in basis points	before tax (USD mill)
2020	+/- 100	+/-2.4
2019	+/- 100	+/-3.5

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 2020, the exposure to equity investments at fair value was USD 12.6 million (USD 21.0 million at yearend 2019).

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)
2020	+/- 10.0	-	+/-1.3
2019	+/- 10.0	-	+/-2.1

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, see Note 15. 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 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	On	Less than	3 to 12	1 to 3	Over 3
At 31 December 2020	demand	3 months	months	years	years
Interest-bearing liabilities*	-	17.1	51.4	516.6	564.0
Other liabilities	-	11.3	14.0	-	-
Taxes payable	-	-	-	-	-
Trade and other payables	2.0	169.8	8.5	-	-
Total liabilities	2.0	198.2	73.9	516.6	564.0

USD million	On	Less than	3 to 12	1 to 3	Over 3
At 31 December 2019	demand	3 months	months	years	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

* Face value of the bond loans are USD 800.0 million at yearend 2020 (USD 961.2 million at yearend 2019).

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	2020	2019

Trade debtors (non-current portion) (Note 12)	182.0	-
Trade debtors (Note 12)	96.2	301.1
Other receivables (Note 12)	143.3	177.4
Tax receivables	63.1	164.8
Cash and cash equivalents	477.1	485.7
Total	961.7	1,129.0

Trade debtors

The impairment model in IFRS 9 is based on the premise of providing for expected credit losses. Expected credit losses (ECL) under IFRS 9, 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. Measurement of ECLs under IFRS 9 shall reflect an unbiased and probability-weighted amount that is determined by evaluating the range of possible outcomes as well as incorporating the time value of money. The entity should consider reasonable and supportable information about past events, current conditions and reasonable and supportable forecasts of future economic conditions when measuring expected credit losses.

Trade receivables from oil sales and override invoices in Kurdistan

Normal payment terms apply to amounts owed to DNO by the KRG for oil sales and override invoices from the Tawke license in Kurdistan. Since late 2015, DNO received the payment due to it from oil sales and overrides on a monthly basis from the KRG until the August 2019 invoice. The payments for August, September and October 2019 oil sales and override invoices were received in January, February and April 2020 respectively, and entitlement payments resumed from the March 2020 invoice. At yearend 2020, entitlement invoices (USD 212.2 million for the period of November 2019-February 2020) and override invoices (USD 46.8 million for the period of November 2019-December 2020) together totaling USD 259.0 million were still withheld by the KRG.

In December 2020, a plan was put in place by the KRG in respect of the withheld entitlement and override payments from 2019 and 2020 such that if Brent prices exceed USD 50 per barrel on average in any month, one-half of the incremental revenue will be paid to the Tawke partners and shared prorata to their interests in the license by the KRG towards the withheld amounts. Moreover, override payments will resume from the January 2021 invoice. The Company expects at a minimum to recover the full nominal value of the withheld receivables and discussions continue to further improve the terms of recovery of the arrears, including but not limited to interest payments reflecting the Company's cost of debt. However, due to the IFRS 9 requirement to incorporate the time value of money, the Company has reduced the book value of these receivables by USD 16.0 million (recognized as other financial expense) when comparing the book value of the receivables to the estimated present value. The calculation of present value in accordance with IFRS 9, takes into account the most recent production forecasts for the Tawke license and the Company's Brent price assumptions (see Note 10) to determine the expected timing of payments towards the withheld receivables plus contractual interests under IFRS 9, and reflects the probability-weighted amount for a range of possible scenarios including probability-weighted Brent price scenarios with a probability assigned to each. The discount rate that is applied reflects the Company's cost of debt. In addition, USD 182.0 million was reclassified from short-term to non-current receivables based on the forecasted repayment plan.

The table below shows the aging of trade debtors and information about credit risk exposure using a provision matrix.

USD million	Contract	Days past due (trade debtors)
	assets	Current	< 30 days	30-60 days	61-90 days	> 90 days	Total
As of 31 December 2020
Trade debtors (nominal value) (Note 12)	-	42.0	2.7	2.8	3.3	243.4	294.2
Expected credit loss rate (percent)	-	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-	-
As of 31 December 2019
Trade debtors (nominal value) (Note 12)	-	130.1	63.9	54.8	52.3	-	301.1
Expected credit loss rate (percent)	-	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-	-

Total trade debtors of USD 294.2 million in nominal value (book value of USD 278.2 million) at yearend 2020 relate mainly to entitlement and override invoices from the Tawke license, see Note 12 for further details. On 9 March 2021, the Company announced the first receipt of USD 6.2 million for payment towards the withheld receivables.

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 and debt 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.

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 a net loss in 2020. The table below shows the book equity ratio at yearend.

No changes were made in the objectives, policies or processes for managing capital during 2020 and 2019.

		Years ended 31 December
USD million	2020	2019

Total equity	845.6	1,161.3
Total assets	2,708.7	3,271.9
Equity ratio	31.2%	35.5%

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
2020 - 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	12.6	-	12.6	31 December 2020	12.6	-	-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)	15	-	934.2	934.2	31 December 2020	746.5	-	149.6
Interest-bearing liabilities (current)	15	-	-	-		-	-	-

* 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
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 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

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
2020 - USD million	assets	assets	assets	PP&E	assets	Total

As of 1 January 2020
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	-	-376.8
Accumulated depreciation	-	-1,279.9	-1,279.9	-17.8	-3.6	-1,301.3
Net book amount	78.3	1,257.1	1,335.4	0.1	14.0	1,349.5

Period ended 31 December 2020
Opening net book amount	78.3	1,257.1	1,335.4	0.1	14.0	1,349.5
Translation differences	8.8	-3.6	5.2	0.6	-	5.8
Additions*	22.8	169.0	191.8	0.4	7.0	199.2
Transfers	-	-	-	-	-	-
Disposals acquisition costs	-	-	-	-5.0	-1.9	-6.9
Disposals depreciation/impairments	-	-	-	7.0	1.1	8.1
Impairments	-	-24.0	-24.0	-	-	-24.0
Depreciation	-	-352.4	-352.4	-1.2	-4.0	-357.6
Closing net book amount	109.9	1,046.1	1,155.9	2.0	16.2	1,174.1
As of 31 December 2020

Acquisition costs	152.0	3,037.0	3,189.0	13.7	22.9	3,225.6
Accumulated impairments	-42.1	-358.6	-400.7	-0.1	-	-400.8
Accumulated depreciation	0.0	-1,632.3	-1,632.3	-11.7	-6.7	-1,650.8
Net book amount	109.9	1,046.1	1,155.9	2.0	16.2	1,174.1

Depreciation method UoP Linear (2-7 years)

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

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

INTANGIBLE ASSETS

		License	Exploration		Total Other intangible
2020 - USD million	Goodwill	interest	assets	Other	assets	Total

As of 1 January 2020
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	-72.0
Net book amount	333.9	20.3	321.1	5.2	346.6	680.5

Period ended 31 December 2020 Opening net book amount	333.9	20.3	321.1	5.2	346.6	680.5
Translation differences	-10.8	-	5.9	-	5.9	-4.7
Additions	-	-	45.2	0.5	45.7	45.7
Disposals cost price	-	-0.4	-0.9	-	-1.3	-1.3
Disposals impairments/depreciation	-	5.8	0.9	-	6.7	6.7
Exploration cost capitalized in previous years carried to cost	-	-	-0.4	-	-0.4	-0.4
Impairments	-161.1	-	-90.9	-	-90.9	-252.0
Depreciation	-	-2.8	-	-1.0	-3.8	-3.8
Closing net book amount	162.0	23.0	280.9	4.7	308.6	470.6
As of 31 December 2020
Acquisition costs	474.3	97.1	389.2	14.3	500.5	951.4
Accumulated impairments	-312.3	-7.7	-108.3	-	-116.0	-404.9
Accumulated depreciation	-	-66.4	-	-9.5	-75.9	-75.9
Net book amount	162.0	23.0	280.9	4.7	308.6	470.6

Depreciation method UoP Linear (3-7 years)

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

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	-	-328.2
Accumulated depreciation	-	-976.8	-976.8	-16.0	-	-992.7
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	-	-	-	-	-	-
Disposal cost price	-149.2	-332.7	-481.9	-	-	-482.0
Disposal impairments/depreciations	-	322.9	322.9	-	-	322.9
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	-	-1279.9	-1279.9	-17.8	-3.5	-1301.2
Net book amount	78.3	1,257.1	1,335.4	0.1	14.0	1,349.5

Depreciation method UoP Linear (3-7 years)

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

**For business combination, see Note 25.

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	-8.0	-38.9	-38.9
Accumulated depreciation	-	-60.8	-	-	-60.8	-60.8
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	-0.0	-7.0	-	-7.0	-25.2
Additions	0.1	-	66.2	2.6	68.8	68.8
Business Combinations*	553.4		268.1		268.1	821.5
Transfers	-	-	-	-	-	-
Disposal cost price	-72.6	-8.1	-5.3	-	-13.4	-86.0
Disposal impairments/depreciations	-	8.1	5.1	-	13.2	13.2
Exploration cost capitalized in previous years carried to cost	-15.3		-12.6		-12.6	-27.9
Impairments	-113.5	-	-	-	-	-113.5
Depreciation	-	-2.8	-	-0.6	-3.4	-3.4
Closing net book amount	333.9	20.3	321.1	5.2	346.6	680.5

As of 31 December 2019
Acquisition costs	462.6	95.7	339.4	13.8	449.0	911.6
Accumulated impairments	-128.7	-12.0	-18.3	-	-30.2	-159.0
Accumulated depreciation	-	-63.6	-	-8.6	-72.2	-72.1
Net book amount	333.9	20.3	321.1	5.2	346.6	680.5

Depreciation method UoP Linear (3-7 years)

*For business combination, see Note 25.

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 2020 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 2020.

Oil and gas prices

Forecasted oil and gas prices are based on management's estimates and market data. The near-term price assumptions are based on forward curve pricing over the period for which there is deemed to be a sufficient liquid market and observable broker and analyst consensus. The long-term price assumptions reflect management's best estimate of the oil and gas price development over the life of the Group's oil and gas fields based on its view of current market conditions and future developments. Management's assessment also includes comparison with long-term oil and gas price assumptions communicated by peer companies and other external forecasts. Oil and gas price assumptions applied for impairment testing are reviewed and, where necessary, adjusted on a periodic basis.

The nominal oil and gas price assumptions applied for impairment assessments at yearend 2020 were as follows (yearend 2019 in brackets):

	2021	2022	2023	2024
Brent (USD/bbl)	52.8 (64.2)	59.1 (66.7)	59.1 (69.5)	64.7 (71.6)
NBP (pence/therm)	41.3 (47.5)	37.8 (47.9)	41.4 (48.7)	45.1 (50.0)

For periods after year 2024, the long-term oil and gas price assumptions applied were USD 65.0 per barrel and 45 pence sterling per therm, respectively (in real terms, basis year 2020).

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 rate at yearend 2020 was 13.0 percent (13.0 percent at yearend 2019) for the Kurdistan assets. For the fair value calculations, the relevant post-tax nominal discount rates at yearend 2020 were 7.6 percent for the Norway assets (7.5 percent at yearend 2019) and 7.8 percent for the UK assets (8.1 percent at yearend 2019).

Inflation and currency rates

The long-term inflation rate is assumed to be 2.0 percent independent of the underlying country or currency (unchanged from yearend 2019). DNO has applied the forward curve as basis for currency rates for year 2021 of USD/NOK 8.5 (USD/NOK 8.75 at yearend 2019) and kept it constant thereafter.

Impairment charge and reversal

The following table shows the recoverable amounts and impairment charges or reversal for the CGUs which were impaired in 2020 and 2019, and how it was recognized in the income statement and balance sheet.

Full-Year ended 31 December 2020		Income statement:				Balance sheet:
(in USD million) CGU, Segment	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax income -expense	Impairment -charge/ reversal (post-tax)	Goodwill	Other intangible assets	Property, plant and equipment	Deferred tax asset/ -liability	Currency effects
SE Tor, North Sea	-	-66.4	28.5	-37.9	-28.6	-37.9	-	28.7	1.6
Agar, North Sea	-	-14.7	7.0	-7.7	-4.2	-10.5	-	6.9	3.5
Iris and Hades, North Sea	11.7	-82.7	33.2	-49.5	-40.2	-42.5	-	33.1	3.5
Fenja, North Sea	66.1	-18.6	-	-18.6	-18.6	-	-	-	1.4
Ringhorne East, North Sea	13.3	-27.1	-	-27.1	-27.1	-	-	-	1.3
Ula area, North Sea	247.8	-19.3	-	-19.3	-19.3	-	-	-	2.2
Brage, North Sea	25.6	-6.7	-	-6.7	-6.7	-	-	-	0.1
Marulk, North Sea	15.1	-4.3	1.1	-3.2	-2.8	-	-1.4	1.1	0.6
Vilje, North Sea	32.9	-8.4	-	-8.4	-8.4	-	-	-	1.6
Trym area, North Sea	13.6	-5.2	-	-5.2	-5.2	-	-	-	0.1
Oselvar, North Sea	-	-19.8	15.5	-4.3	-	-	-19.8	15.5	0.3
Schooner and Ketch, North Sea	-	2.1	-1.0	1.1	-	-	2.1	-1.0	0.0
Other CGUs, North Sea	-	-4.9	2.2	-2.7	-	-	-4.9	2.2	0.4
Total	426.1	-276.0	86.5	-189.5	-161.1	-90.9	-24.0	86.5	16.6

Full-Year ended 31 December 2019		Income statement:			Balance sheet:
(in USD million) CGU, Segment	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax income -expense	Impairment -charge/ reversal (post-tax)	Goodwill	Other intangible assets	Property, plant and equipment	Deferred tax asset/ -liability	Currency effects
Erbil license, Kurdistan	-	-12.8	-	-12.8	-	-	-12.8	-	-
Brasse, North Sea	39.6	-89.4	-	-89.4	-89.4	-	-	-	2.4
Ringhorne East, North Sea	41.7	-13.9	-	-13.9	-13.9	-	-	-	0.4
Marulk, North Sea	19.7	-4.5	-	-4.5	-4.5	-	-	-	0.2
Vilje, North Sea	37.5	-2.0	-	-2.0	-2.0	-	-	-	0.1
Schooner and Ketch, North Sea	-	-32.6	15.7	-16.9	-	-	-32.6	15.7	1.0
Other CGUs, North Sea	4.6	-6.8	0.8	-6.0	-3.7	-	-3.1	0.8	-1.1
Total	143.1	-162.0	16.5	-145.5	-113.5	-	-48.5	16.5	3.0

During 2020, a total impairment charge of USD 276.0 million (USD 189.5 million post-tax) was recognized, driven by:

Relinquishment of DNO's participation in a license (Agar discovery);
Reduction in resource estimates following appraisal and evaluation of potential (SE Tor discovery and Iris and Hades discoveries);
Reduction in reserves estimates (Fenja development and Ringhorne East);
Revised oil and gas price assumptions (Ula area CGU, Marulk, Vilje and Trym area CGU);
Revised oil and gas price assumptions and update in cost profiles (Brage);
Upward revision in the cost estimate for decommissioning (Oselvar field); and
Partially offset by a downward revision in the cost estimate for decommissioning (Schooner and Ketch fields).

During 2019, a total impairment charge of USD 162.0 million (USD 145.6 million post-tax) was recognized, driven by:

Relinquishment of DNO's participation in a license (Erbil license);
Reduction in reserves estimates (Brasse discovery and Ringhorne East);
Revised oil and gas price assumptions and update in cost profiles (Marulk and Vilje); and
Upward revision in the cost estimate for decommissioning (Schooner and Ketch fields).

Sensitivities

The table below illustrates how the net profit/-loss in 2020 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.

		Net profit/-loss effects:
Assumption (USD million)	Change	Increase in assumption:	Decrease in assumption:
Oil and gas price	+/- 15%	15.8	-75.4
Production profile (reserves and resources)	+/- 5%	4.8	-16.3
Discount rate (WACC)	+/- 1%	-10.7	2.5
Currency rate (USD/NOK)	+/- 1.0 NOK	12.5	-51.7

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 were applied in relation to yearend 2020 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; the Fenja license expires in 2039; the Brasse license expires in 2022 (subject to extension when PDO is submitted and approved); and the Iris and Hades license expires in 2022 (subject to extension when PDO is submitted and approved).

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	2020	2019

Book value as of 1 January	21.0	230.8
Additions	-	226.3
Fair value changes through other comprehensive income (FVTOCI)	-8.4	25.8
Disposals	-	-461.8
Book value as of 31 December	12.6	21.0

Financial investments include the following:

USD million	2020	2019
Listed shares:
RAK Petroleum plc	12.6	21.0
Total financial investments	12.6	21.0

At yearend 2020, the Company held a total of 15,849,737 shares (5.1 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 44.94 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 8.4 million in 2020 (USD 3.1 million in 2019).

On 11 January 2019, the Company obtained control of Faroe (renamed to DNO North Sea plc) and subsequently de-listed the company from the UK Alternative Investment Market on 14 February 2019. Prior to DNO obtaining control, the acquisition of Faroe shares in the first quarter of 2019 was accounted for as an equity instrument (shown as an addition in the above table for 2019). Change in fair value prior to control being obtained was USD 19.6 million and was recognized in other comprehensive income in the first quarter 2019.

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 was recognized in other comprehensive income in 2019.

Disposals in 2019 relate to the step acquisition of Faroe and the sale of the Company's shares in Panoro Energy ASA in the fourth quarter of 2019.

Note 12 Other non-current receivables/Trade and other receivables

	Years ended 31 December
USD million	2020	2019

Trade debtors (non-current portion)	182.0	-
Other long-term receivables	0.4	-
Total other non-current receivables	182.4	-

Trade debtors	96.2	301.1
Underlift	27.4	37.6
Other short-term receivables	115.9	139.8
Total trade and other receivables	239.6	478.5

Total book value of trade debtors of USD 278.2 million (USD 294.2 million in nominal value) at yearend 2020 relate mainly to outstanding entitlement invoices (total of USD 244.7 million for the months November 2019-February 2020 and December 2020) and override invoices (total of USD 46.8 million for the period of November 2019-December 2020) from the Tawke license in Kurdistan. Due to the IFRS 9 requirement to incorporate the time value effects of expected cash flows, the Company has reduced the book value of the receivables from the Tawke license by USD 16.0 million. In addition, USD 182.0 million was reclassified from short-term to non-current receivables, see Note 9 for details. Since the reporting date, DNO has received USD 32.5 million for its share of the Tawke license December 2020 entitlement invoice and USD 6.2 million towards the withheld Tawke license 2019 and 2020 entitlement and override payments.

Note 12 Other non-current receivables/Trade and other receivables

The underlift receivable of USD 27.4 million as of 31 December 2020 relates mainly to North Sea underlifted volumes, valued at the lower of production cost including depreciation and the market value at the reporting date, 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	2020	2019

Cash and cash equivalents, restricted	13.6	14.3
Cash and cash equivalents, non-restricted	463.5	471.5
Total cash and cash equivalents	477.1	485.7

Restricted cash consists of deposits on escrow account, employees' tax withholdings and deposits for rent. Non-restricted cash is entirely related to bank deposits in USD, NOK, GBP, EUR and DKK as of 31 December 2020.

Note 14

Equity

Share capital
	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

	Number of	Ordinary	Treasury
USD million	shares (1,000)	shares	shares	Total
As of 1 January 2020	990,114	36.0	-2.6	33.3
Treasury shares sold/-purchased	-14,681.3	-	-0.4	-0.4
Share issues	-	-	-	-
Cancellation of treasury shares	-	-3.1	3.1	-
As of 31 December 2020	975,433	32.9	-	32.9

The Board of Directors was given the authority to approve a dividend distribution of NOK 0.20 per share in the second half of 2020 and a distribution of dividend of NOK 0.20 per share in the first half of 2021 (each dividend distribution shall not exceed NOK 224.35 million in total) based on the approved 2019 parent company accounts. The Board of Director's authority to approve a dividend distribution for the second half of 2020 was valid until 31 December 2020, while the authority to approve a dividend distribution for the first half of 2021 may be executed starting 1 January 2021 until the date of the 2021 AGM. The authorization was not utilized in the second half of 2020.

Note 14

Equity

		Interest
The Company's shareholders as of 31 December 2020	Shares	(percent)
RAK Petroleum Holdings B.V.	438,379,418	44.94
Folketrygdfondet	28,000,317	2.87
State Street Bank and Trust Comp (Nominee)	14,332,804	1.47
JPMorgan Chase Bank, N.A., London (Nominee)	10,817,250	1.11
Avanza Bank AB (Nominee)	9,081,666	0.93
Nordnet Bank AB (Nominee)	8,128,125	0.83
Danske Bank A/S (Nominee)	6,942,411	0.71
Nordea Bank Abp (Nominee)	5,535,595	0.57
Salt Value AS	5,453,046	0.56
The Bank of New York Mellon SA/NV (Nominee)	5,259,153	0.54
Clearstream Bankin S.A (Nominee)	4,473,881	0.46
Skandinaviska Enskilda Banken AB (Nominee)	4,173,824	0.43
Verdipapirfondet Pareto Investment	4,086,000	0.42
The Bank of New York Mellon (Nominee)	3,958,209	0.41
Credit Suisse Securities (USA) LLC (Nominee)	3,483,902	0.36
State Street Bank and Trust Comp (Nominee)	3,183,867	0.33
Verdipapirfondet DNB Norge Indeks	3,180,544	0.33
Citibank, N.A. (Nominee)	3,029,878	0.31
Storebrand Norge I Verdipapirfond	3,006,799	0.31
State Street Bank and Trust Comp (Nominee)	2,942,689	0.30
Other shareholders	407,983,368	41.83
Total number of shares excluding treasury shares	975,432,746	100.00
Treasury shares as of 31 December 2020 (DNO ASA)	0.00	0.00
Total number of outstanding shares	975,432,746	100.00

No dividend was distributed in 2020 (USD 46.6 million in 2019).

Note 15 Interest-bearing liabilities

						Effective
	Ticker	Facility	Facility	Interest		interest rate	Fair value		Carrying amount
USD million	OSE	currency	amount	(percent)	Maturity	(percent)	2020	2019	2020	2019
Non-current
Bond loan (ISIN NO0010823347)	DNO02	USD	400.0	8.750	31.05.23	9.7	376.5	408.6	400.0	400.0
Bond loan (ISIN NO0010852643)	DNO03	USD	400.0	8.375	29.05.24	9.0	370.0	401.6	400.0	400.0
Bond loan (ISIN NO0010811268)	FAPE01	USD	-	8.000	-	8.9	-	22.7	-	21.2
Capitalized borrowing issue costs									-15.4	-23.0
Reserve based lending facility	-	USD	350.0	see below	see below	-	149.6	37.8	149.6	37.8
Total non-current interest-bearing liabilities							896.1	870.8	934.2	836.0
Current
Bond loan (ISIN NO0010740392)	DNO01	USD	-	8.750	-	12.5	-	143.8	-	140.0
Exploration financing facility	-	NOK	250.0	see below	see below	-	-	85.6	-	85.6
Total current interest-bearing liabilities							-	229.4	-	225.6
Total interest-bearing liabilities							896.1	1,100.1	934.2	1,061.6

All the bonds are issued by DNO ASA except for FAPE01 which was issued by a subsidiary, DNO North Sea plc. Facility amount for the bonds is shown net of bonds held by the Company.

During 2020, DNO ASA acquired USD 14.2 million of FAPE01 bonds at a price range of 104.00 to 107.13 percent of par plus accrued interest and USD 1.5 million of DNO01 at a price of 89 percent of par plus accrued interest. The DNO01 bond was redeemed at maturity on 18 June 2020 and the remaining FAPE01 bonds of USD 7.0 million were redeemed on 18 December 2020 at a price of 103.2 percent 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 Group has available a revolving exploration financing facility (EFF) in an aggregate amount of NOK 250 million with an uncommitted accordion option of NOK 750 million. Utilization requests need to be delivered for each proposed loan. The facility is secured against the Norwegian exploration tax refund and is repaid when the refund is received which is approximately eleven 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. Due to temporary changes to the taxation of oil and gas companies in Norway, the Group has chosen to not utilize the EFF in relation to exploration spend in 2020 and instead enroll in the new scheme with refund of tax losses every two months, see Note 6. Drawdowns on the EFF in relation to spend in 2019 and 2020 were repaid during 2020.

The Group has a reserve-based lending (RBL) facility in relation to its Norway and UK licenses in an aggregate 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. The borrowing base amount of the facility as of 1 Jan 2021 is USD 242 million. 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 entities that participate in the facility are required to submit quarterly a liquidity test and maintain a consolidated net debt divided by EBITDAX ratio of maximum 3.75 until end of 2021 and 3.5 thereafter. 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 93.1 million is utilized in respect of letters of credit.

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

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
USD million	2020	flows	Amortization	Currency	Acquisition	2020
Bond loans	821.2	-21.2	-	-	-	800.0
Bond loans (current)	140.0	-139.8	-0.2	-	-	-
Borrowing issue costs	-23.0	-	7.6	-	-	-15.4
Reserve based lending facility	37.8	109.2	-	2.6	-	149.6
Exploration financing facility	85.6	-86.1	-	0.5	-	-
Total	1,061.6	-137.9	7.4	3.1	-	934.2

	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

Note 16 Provisions for other liabilities and charges/Lease liabilities

		Years ended 31 December
USD million	2020	2019

Non-current
Asset retirement obligations (ARO)	436.6	415.7
Other long-term obligations	3.4	7.1
Total non-current provisions for other liabilities and charges	440.1	422.8

Lease liabilities	13.9	11.1
Total non-current lease liabilities	13.9	11.1

Current
Asset retirement obligations (ARO)	86.7	77.1
Other provisions and charges	25.3	27.9
Total current provisions for other liabilities and charges	112.0	105.1

Current lease liabilities	3.8	3.3
Total current lease liabilities	3.8	3.3

Total provisions for other liabilities and charges and lease liabilities	569.7	542.3

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 2020 were between 3.2 percent and 3.7 percent (yearend 2019: between 3.5 percent and 3.7 percent). The credit margin included in the discount rates at yearend 2020 was 2.8 percent (yearend 2019: 1.9 percent).

Note 16 Provisions for other liabilities and charges/Lease liabilities

	Asset	Other
	retirement	non
USD million	obligations	current
Provisions as of 1 January 2019	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
ARO provisions from business combinations	-	-
ARO provisions divested assets	-	-
Decommissioning spend	-30.7	-
Increase/-decrease in existing provisions	38.3	-3.6
Amounts charged against provisions	-	-0.1
Effects of change in the discount rate	2.9	-
Accretion expenses (unwinding of discount)	17.0	-
Reclassification and transfer	3.0	-
Provisions as of 31 December 2020	523.3	3.4

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. Lease payments related to short-term leases and leases of lowvalue assets are recognized under lifting costs and exploration costs, or PP&E and intangible assets (i.e., capitalized exploration). Total lease payments related to short-term leases and low-value assets were USD 31.2 million (2019: USD 41.9 million) with most of the lease payments related to drilling rigs.

The following table summarizes the Group's maturity profile of the lease liabilities based on contractual undiscounted lease payments and are related to office rent and equipment.

		1 January - 31 December
USD million	2020	2019
Within one year	4.7	4.4
Two to five years	13.8	13.0
After five years	1.1	-
Total undiscounted lease liabilities end of the period	19.6	17.5

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 Limited 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 14.0 million was recognized at yearend 2019 related to this arbitration award (unchanged at yearend 2020).

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 6.7 million (almost entirely dismissing the USD 131 million counterclaim of the MOM). In accordance with IAS 37, the asset related to this arbitration award is not recognized in the balance sheet as of 31 December 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 2020 related to this dispute.

Disputes with Ministry of Oil and Gas (MOG) of Oman – Block 8

On 3 January 2019, the Company announced that its subsidiary DNO Oman Block 8 Limited (DNO Oman Block 8) had relinquished operatorship and participation in Block 8 to Oman's Ministry of Oil and Gas (MOG) as a result of the expiry of the Exploration and Production Sharing Agreement (EPSA). DNO Oman Block 8 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 MOG and the Contractor (DNO Oman Block 8 and LGI) which are currently under arbitration proceedings and as such unresolved as of the reporting date. In accordance with IAS 37, no provision was made at yearend 2020.

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 and abandonment expenditures

Based on work plans as of yearend 2020 and contingent on future market conditions including development in the oil price, the Group's projected capital commitments and abandonment expenditures at yearend 2020 amounted to USD 490 million. The projected capital commitments and abandonment expenditures reflects the Group's share of planned drilling and facility investments and decommissioning plan in its licenses in 2021. Execution of these work plans is subject to revisions.

Guarantees related to assets in operation as of 31 December 2020

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 license.

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	2020	2019

Trade payables	58.3	62.8
Public duties payable	4.1	4.6
Prepayments from customers	9.2	50.1
Overlift	6.4	8.1
Other accrued expenses	102.4	163.3
Total trade and other payables	180.3	288.9

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

Trade payables and other accrued expenses at yearend 2020 include items of working capital related to participation in licenses in Kurdistan and the North Sea and prepayment from customers in the North Sea.

The overlift payable of USD 6.4 million at yearend 2020 relates mainly to DNO's North Sea licenses, valued at production cost including depreciation.

Note 19 Earnings per share

	1 January - 31 December
	2020	2019

Net profit/-loss attributable to ordinary equity holders of the parent (USD million)	-285.9	73.5
Weighted average number of ordinary shares excluding treasury shares (millions)	975.73	1,036.37

Effect of dilution:
Options	-	-

Earnings per share, basic (USD per share)	-0.29	0.07
Earnings per share, diluted (USD per share)	-0.29	0.07

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 2020.

Note 20 Group companies

		Ownership and voting
USD million	Office	interest (percent)

Shares in the Company's subsidiaries
DNO Iraq AS	Norway	100
DNO UK Limited	UK	100
DNO Mena AS	Norway	100
Northstar Oman AS	Norway	100
DNO Technical Services 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 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

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. The Company, DNO Technical Services AS and DNO North Sea plc provide technical support and services to the various companies in the Group. The other subsidiaries from the table above had minimal activity during the year. DNO Invest AS, DNO Somaliland AS, Northstar Exploration Holding AS and DNO Al Khaleej Limited were liquidated during 2020.

DNO North Sea SIP EBT Limited UK 100

Note 21 Related party disclosure

The following table provides details of the Group's related party transactions in 2020. See also Note 5 on remuneration.

			1 January - 31 December
Related party (USD million)	Transaction	2020	2019

RAK Petroleum plc	Service agreement	-0.5	-1.6
Total related party transactions		-0.5	-1.6

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 2020 was USD 0.5 million (USD 1.6 million in 2019).

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 19 January 2021, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 10 exploration licenses, of which four are operatorships, under Norway's Awards in Predefined Areas (APA) 2020 licensing round. Of the 10 new licenses, six are in the North Sea and four in the Norwegian Sea.

Payments from Kurdistan

On 28 January 2021, DNO received USD 32.5 million for its share of December 2020 oil deliveries to the export market from the Tawke license in Kurdistan.

North Sea discovery

Note 23 Company Working Interest and Net Entitlement reserves (unaudited)

Company Working Interest (CWI) reserves by region/field as of 31 December 2020

	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	117.8	-	-	117.8	182.2	-	-	182.2	274.1	-	-	274.1
Peshkabir	42.1	-	-	42.1	85.6	-	-	85.6	136.8	-	-	136.8
Total Kurdistan	159.9	-	-	159.9	267.8	-	-	267.8	410.9	-	-	410.9
Blane (Ula area)	1.0	-	-	1.0	1.2	-	-	1.2	1.4	-	-	1.4
East Foinaven	0.0	-	-	0.0	0.1	-	-	0.1	0.3	-	-	0.3
Enoch	0.0	-	-	0.0	0.1	-	-	0.1	0.3	-	-	0.3
Total UK	1.0	-	-	1.0	1.4	-	-	1.4	1.9	-	-	1.9
Alve	0.8	1.3	4.5	6.6	1.2	1.8	6.4	9.4	1.7	2.6	9.5	13.8
Brage	1.4	0.1	0.2	1.7	2.2	0.2	0.4	2.8	3.2	0.3	0.4	3.9
Brasse	7.9	1.5	2.4	11.8	11.2	2.1	3.4	16.7	14.4	2.7	4.4	21.6
Fenja	2.1	0.2	0.9	3.2	3.8	0.3	1.2	5.2	4.7	0.3	1.5	6.5
Marulk	0.0	0.1	0.6	0.8	0.1	0.2	1.1	1.4	0.1	0.2	1.3	1.6
Ringhorne East	1.0	-	-	1.0	1.3	-	-	1.3	1.6	-	-	1.6
Oda (Ula area)	2.2	0.0	0.1	2.4	3.0	0.0	0.2	3.2	4.6	0.0	0.3	5.0
Tambar (Ula area)	3.9	0.1	0.6	4.6	6.6	0.2	1.1	7.9	10.9	0.4	1.9	13.2
Tambar East (Ula area)	-	-	-	-	0.2	0.0	0.0	0.2	0.2	0.0	0.0	0.3
Ula (Ula area)	3.8	0.1	-	4.0	7.4	0.2	-	7.6	12.3	0.4	-	12.6
Trym	0.2	-	1.4	1.7	0.5	-	2.9	3.4	1.3	-	7.6	8.9
Vilje	2.3	-	-	2.3	4.0	-	-	4.0	5.0	-	-	5.0
Total Norway	25.8	3.4	10.8	40.0	41.4	5.0	16.7	63.1	60.2	6.9	26.9	94.0
Total Group				201.0				332.3				506.8

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 2019	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	48.6	70.1	102.1	205.6	344.8	539.9
Production	-28.5	-28.5	-28.5	-6.4	-6.4	-6.4	-34.8	-34.8	-34.8
Acquisitions	-	-	-	-	-	-	-	-	-
Divestments	-	-	-	-	-	-	-	-	-
Extensions and discoveries	-	-	-	-	-	-	-	-	-
New developments	-	-	-	-	-	-	-	-	-
Revision of previous estimates	31.4	21.6	1.4	-1.2	0.7	0.2	30.2	22.3	1.7
As of 31 December 2020	159.9	267.8	410.9	41.1	64.4	95.9	201.0	332.3	506.8

Net Entitlement (NE) reserves by segment

	Kurdistan			North Sea			Total Group
MMboe	1P	2P	3P	1P	2P	3P	1P	2P	3P

As of 31 December 2019	59.9	95.6	120.2	48.6	70.1	102.1	108.5	165.8	222.2
As of 31 December 2020	69.4	96.7	120.1	41.1	64.4	95.9	110.5	161.2	216.0

Note 23 Company Working Interest and Net Entitlement reserves (unaudited)

The reserves are according to the Annual Statement of Reserves and Resources (ASRR) dated 16 February 2021, 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 (containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the Baeshiqa and Zartik structures) in the Kurdistan region of Iraq. International petroleum consultants Gaffney, Cline & Associates (GCA) carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). The Company internally assessed Yemen Block 47.

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 2020, 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 2020, DNO's CWI 1P reserves stood at 201.0 MMboe, compared to 205.6 MMbbls at yearend 2019, after adjusting for production during the year and upward technical revisions. On a 2P reserves basis, DNO's CWI reserves stood at 332.3 MMboe, compared to 344.8 MMboe at yearend 2019. On a 3P reserves basis, DNO's CWI reserves were 506.8 MMboe, compared to 539.9 MMbbls at yearend 2019. DNO's CWI 2C resources were 151.7 MMboe, compared to 187.8 MMboe at yearend 2019.

DNO's CWI production in 2020 was 34.8 MMboe (of which 28.5 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in the UK), down from 38.2 MMboe in 2019 (of which 31.9 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in the UK).

The Company's CWI yearend 2020 Reserve Life Index (R/P) stood at 5.8 years on a 1P reserves basis, 9.6 years on a 2P reserves basis and 14.6 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 table above include the reserves attributable to DNO from this settlement agreement.

Note 24 Oil and gas license portfolio

At yearend 2020, DNO held interests in two licenses in Kurdistan, both of which are PSCs. The Tawke PSC contains the producing Tawke and Peshkabir fields. The Baeshiqa license contains two large structures, Baeshiqa and Zartik, with multiple independent stacked target reservoirs, including in the Cretaceous, Jurassic and Triassic formations. The structures have the potential to be part of a single accumulation of hydrocarbons at one or more of the geological formation intervals, but this potential has not been established by the exploration and appraisal activities to date.

At yearend 2020, DNO also held 76 offshore licenses in Norway, 16 offshore licenses in the UK, two offshore licenses in Netherlands, one offshore license in Ireland and one onshore 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 2020:

	Participating
Region/license	interest (percent)	Operator	Partner(s)
Kurdistan
Tawke PSC	75.0	DNO Iraq AS	Genel Energy International Limited
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	100.0	DNO Norge AS
PL019	20.0	Aker BP ASA	DNO Norge AS
PL019 E	20.0	Aker BP ASA	DNO Norge AS
PL019 F	45.0	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, Petrolia NOCO AS, Aker BP ASA
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
PL055 E	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
PL1021	50.0	Wintershall Dea Norge AS	DNO Norge AS
PL1022	30.0	Aker BP ASA	DNO Norge AS, Concedo ASA
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
PL1036	60.0	DNO Norge AS	Source Energy AS
PL1048	50.0	Lundin Energy Norway AS	DNO Norge AS
PL1056	20.0	A/S Norske Shell	DNO Norge AS, Petoro AS, Wintershall Dea Norge AS, Aker BP ASA
PL1070	30.0	Total E&P Norge AS	DNO Norge AS, Vår Energi As
PL1076	50.0	Equinor Energy AS	DNO Norge AS
PL1077	40.0	Equinor Energy AS	DNO Norge AS
PL1083	30.0	Lundin Energy Norway AS	DNO Norge AS, Petoro 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	29.0	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

Note 24

Oil and gas license portfolio

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
PL827 S	49.0	Equinor Energy AS	DNO Norge AS
PL836 S	30.0	Wintershall Dea Norge AS	DNO Norge AS, Spirit Energy Norway 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
PL923	20.0	Equinor Energy AS	DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL924	15.0	Wellesley Petroleum AS	DNO Norge AS, Equinor Energy AS, Lundin Energy 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
PL943	30.0	Equinor Energy AS	DNO Norge AS, Sval Energi AS
PL967	60.0	DNO Norge AS	Equinor Energy AS
PL968	40.0	DNO Norge AS	Petoro AS, MOL Norge AS, Aker BP ASA
PL969	45.0	A/S Norske Shell	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	Vår Energi AS, Source Energy AS
PL984 BS	40.0	DNO Norge AS	Vår Energi AS, Source Energy AS
PL986	20.0	Aker BP ASA	DNO Norge AS, Petoro AS
PL987	20.0	Suncor Energy Norge AS	DNO Norge AS, Lundin Norway AS, Vår Energi AS
PL987 B	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
PL991	60.0	DNO Norge AS	Lundin Norway AS
PL994	30.0	Neptune Energy Norge AS	DNO Norge AS, Petrolia NOCO 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
P2312	15.0	Nautical Petroleum Ltd	Ltd DNO North Sea (U.K.) Ltd, Suncor Energy UK Ltd

P2401	45.0	Shell 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 Ltd	DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P2551	100.0	DNO North Sea (U.K.) Ltd
P2537	30.0	Chrysaor Production (U.K.) Limited	DNO North Sea (U.K.) Ltd
P2548	100.0	DNO North Sea (U.K.) Ltd
P2533	50.0	Zennor Exploration Ltd	DNO North Sea (U.K.) 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 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 PL159 B	50.0 32.0	DNO Norge AS Equinor Energy AS	Spirit Energy Norway 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
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

Note 24

Oil and gas license portfolio

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	40.0	DNO Norge AS	Petoro AS, MOL Norge AS, Aker BP ASA
PL969	45.0	A/S Norske Shell	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 Ltd	DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 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 25 Business combinations

No business combinations were recognized in 2020. In 2019, the Company completed two transactions regarded as business combinations and were accounted for by using the acquisition method in accordance with IFRS 3.

The fair values in the tables below were based on the available information about fair values as of the acquisition dates. No material changes booked during the measurement period.

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 (see Note 11). 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.

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. A PPA was performed as of this acquisition date to allocate the consideration to fair values of acquired assets and assumed liabilities of Faroe. air values of the acquired assets and liabilities assumed as of the acquisition date were as shown in the table below:

USD million	Fair value at 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.

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.

Note 25 Business combinations

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 licenses in the North Sea are based on cash flows after tax. This is because these licenses 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.

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 fair values of acquired assets and assumed liabilities of the acquired assets. 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

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.

Parent company accounts

Income statement		74
Balance sheet		74
Cash flow statement		76


Note disclosures
Note 1	Accounting principles	77
Note 2	Operating revenues	78
Note 3	Salaries, pensions, remuneration, shares, options and severance	78
Note 4	Other operating expenses	81
Note 5	Net financial income/-expenses	81
Note 6	Taxes	82
Note 7	Property, plant and equipment/Intangible assets	83
Note 8	Investment in shares/Other investments	83
Note 9	Other receivables	84
Note 10	Cash and cash equivalents	84
Note 11	Equity	84
Note 12	Guarantees, leasing liabilities and commitments	85
Note 13	Interest-bearing liabilities	85
Note 14	Current liabilities	85
Note 15	Financial instruments	85
Note 16	Related party disclosure	86
Note 17	Contingencies and events after the balance sheet date	86
Note 18	Earnings per share	86
Note 19	Intercompany	86

Annual Report and Accounts 2020 DNO 73

Income statement

		1 January - 31 December
USD thousand	Note	2020	2019

Operating revenues	2, 19	22,888	20,468
Total operating revenues		22,888	20,468

Depreciation	7	-1,071	-957
Payroll and other social expenses	3	-15,037	-18,623
Other operating expenses	4	-9,315	-17,862
Total operating expenses		-25,423	-37,442

Operating profit/-loss		-2,535	-16,974

Net financial income/-expense	5	-316,539	-1,093

Profit/-loss before income tax		-319,074	-18,067

Tax income/-expense	6	-	-

Net profit/-loss		-319,074	-18,067

Earnings per share, basic (USD per share)	18	-0.33	-0.02
Earnings per share, diluted (USD per share)	18	-0.33	-0.02

Weighted average number of shares outstanding (excluding treasury shares) (millions)		975.73	1,036.37

Balance sheet

ASSETS

	Years ended 31 December
USD thousand	Note	2020	2019

Fixed assets
Intangible assets	7	4,704	4,827
Property, plant and equipment	7	327	399
Total intangible and tangible assets		5,031	5,226

Financial assets
Shares in subsidiaries	8	684,412	942,379
Intercompany receivables	19	83,015	28,386
Other long-term receivables	3	42	61
Investment in shares	8	12,594	21,030
Other investments	8	-	69,386
Total financial assets		780,063	1,061,242

Total non-current assets		785,094	1,066,468
Current assets
Intercompany receivables		4,743	12,724
Other receivables	9	2,075	5,154
Cash and cash equivalents	10	299,665	389,028
Total current assets		306,483	406,906

TOTAL ASSETS		1,091,577	1,473,374

EQUITY AND LIABILITIES

		Years ended 31 December
USD thousand	Note	2020	2019

Paid-in capital
Share capital		32,936	35,991
Treasury shares		-	-2,641
Share premium		247,743	247,743
Total paid-in capital	11	280,679	281,093
Retained earnings
Retained earnings		-140,415	195,986
Total retained earnings	11	-140,415	195,986
Total equity	11	140,264	477,079

Non-current liabilities
Intercompany liabilities	19	150,137	55,162
Interest-bearing liabilities	13	787,359	780,753
Other non-current liabilities		301	686
Total non-current liabilities		937,797	836,601
Current liabilities
Trade payables and provisions for other liabilities and charges	14	13,516	19,533
Intercompany liabilities		-	161
Current interest-bearing liabilities	13	-	140,000
Total current liabilities		13,516	159,694
Total liabilities		951,313	996,295

TOTAL EQUITY AND LIABILITIES		1,091,577	1,473,374

Oslo, 17 March 2021

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	2020	2019

Operating activities
Profit/-loss before income tax		-319,074	-18,067
Taxes paid	6	-	-
Depreciation and impairment of tangible and intangible assets	7	1,071	957
Impairment/reversal of impairment of financial assets	5	245,203	183,338
Changes in working capital items and accruals/provisions		4,516	-9,917
Other*		97,728	29,221
Net interest paid/-received	5, 14	-67,118	-55,532
Dividend received	5	261	-
Net cash flow from/-used in operating activities		-37,412	130,000

Investing activities
Payments made for intangible and tangible assets	7	-876	-2,404
Payments made for acquisitions of shares, including capital increase in subsidiaries	8	-	-582,999
Proceeds from sales of financial investments	8	-	6,644
Loans to subsidiaries	19	26,693	27,745
Purchase of bonds	8	-15,001	-69,386
Net cash flow from/-used in investing activities		10,816	-620,400

Financing activities
Proceeds from interest-bearing liabilities net of issue costs	13	-	394,521
Repayment of interest-bearing liabilities (bonds)	13	-140,000	-60,000
Loans from subsidiaries	19	94,975	35,590
Purchase of treasury shares and options	11	-17,741	-82,265
Paid dividend	11	-	-46,629
Net cash flow from/-used in financing activities		-62,766	241,216

Cash and cash equivalents at the beginning of the period		389,028	638,212
Net increase/-decrease in cash and cash equivalents		-89,363	-249,184
Cash and cash equivalents at the end of the period	10	299,665	389,028

Of which restricted cash		2,203	2,225

* Includes adjustments for interest income, interest expense, amortization of borrowing issue costs and other non-cash items.

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 drawdown 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 classified as financial assets are valued at their cost price and impaired in the case of permanent and significant decline in value. Listed shares 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	2020	2019
Operating revenues	22,888	20,468
Total operating revenues	22,888	20,468

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	2020	2019

Payroll and other social expenses
Salaries, bonuses and other salary expenses	-10,490	-13,779
Employer's payroll tax expense	-2,415	-2,642
Pensions	-2,093	-2,579
Other personnel costs	-39	-336
Reclassification to oil and gas license activities	-	713
Total payroll and other social expenses	-15,037	-18,623
Average number of man-labor years	66	75

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)	2020	2019

Bijan Mossavar-Rahmani, Executive Chairman, member of the nomination and remuneration committees	760.6	813.5
Lars Arne Takla, Deputy Chairman, member of the HSSE committee	63.7	68.1
Elin Karfjell, Director, member of the audit committee	54.0	57.8
Gunnar Hirsti, Director, member of the audit and remuneration committees	59.9	64.0
Shelley Watson, Director, member of the audit and HSSE committees	54.0	57.8
Total	992.3	1,061.2

Total remuneration to the Board of Directors consist of regular fees (USD 954,289) and fees for participation in the board committees (USD 37,973). Separately, a fee of USD 2,921 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	629.7	198.7	69.1	897.5	18.5	-
Chris Spencer, Deputy Managing Director	475.5	154.8	47.5	677.8	18.5	-
Haakon Sandborg, Chief Financial Officer	421.6	155.8	37.9	615.4	18.5	-
Ute Quinn, Group General Counsel ***	420.2	45.4	38.3	503.9	18.5	42.4
Nicholas Whiteley, Group Exploration and Subsurface Director	420.2	156.2	84.9	661.3	18.5	-
Ørjan Gjerde, General Manager DNO North Sea	412.6	39.9	25.9	478.5	18.5	-
Tom Allan, General Manager Kurdistan Region of Iraq	528.8	-	356.8	885.7	-	-
Geir Arne Skau, Human Resources Director	297.4	63.8	25.1	386.3	18.5	-
Aernout van der Gaag, Finance Director North Sea and Group Planning	396.8	194.0	66.7	657.5	18.5	-
Tonje Pareli Gormley, General Counsel - Middle East	334.8	76.6	31.2	442.6	18.5	-

* Total remuneration of USD 0.5 million was paid to Rune Martinsen, a former member of the executive management.

** Figure represents actual bonus paid in 2020 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 2.29 percent at yearend 2020).

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 2020

	Out-	Movements 1 January - 31 December			Out-		Unrest Weighted
	standing		Forfeited/			standing	ricted	average
Number of shares	at 1 Jan	Granted	Reversed	Settled		Expired at 31 Dec at 31 Dec		price*

Bjørn Dale, Managing Director	190,545	72,513	-	190,545	-	72,513	-	7.99
Chris Spencer, Deputy Managing Director	196,125	469,183	-	75,343	-	589,965	88,443	5.69
Haakon Sandborg, Chief Financial Officer	216,271	58,010	-	192,016	-	82,265	-	6.03
Ute Quinn, Group General Counsel	150,313	58,010	-	14,807	-	193,516	-	7.99
Nicholas Whiteley, Group Exploration and Subsurface Director	237,217	38,673	-	97,466	-	178,424	115,496	6.21
Ørjan Gjerde, General Manager DNO North Sea	64,348	-	-	47,043	-	17,305	-	7.07
Tom Allan, General Manager Kurdistan Region of Iraq	105,007	342,485	-	-	-	447,492	-	-
Geir Arne Skau, Human Resources Director	84,070	58,406	-	38,672	-	103,804	45,398	4.37
Aernout van der Gaag, Finance Director North Sea and Group Planning	235,597	18,262	-	97,837	-	156,022	114,853	7.90
Tonje Pareli Gormley, General Counsel - Middle East	149,321	96,996	-	74,536	-	171,781	-	4.48

The weighted average settlement price for synthetic shares settled during 2020 was NOK 6.57. The weighted average remaining contractual life of the synthetic shares was four 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 2020, see Note 5 in the consolidated accounts.

Severance agreements

Auditor fees

	1 January - 31 December
All figures are exclusive of VAT (USD thousand)	2020	2019

Auditor fees	-266	-275
Other financial audit services	-4	-2
Total auditing fees	-270	-277
Other assistance	-	-
Tax assistance	-	-3
Total auditor fees	-270	-279

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

The board's declaration for 2020

According to the Norwegian Public Limited Liability Companies Act section 6-16a cf. section 5-6 third paragraph, the Board of Directors presented 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 guidelines for 2021 will be presented in the 2021 AGM for approval and the guidelines and the voting results will be published on the Company's website.

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

Fixed salary

The Board of Directors did not set any upper or lower limit for the fixed salary of executive management for 2020 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.

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 continued a share-based incentive scheme utilizing synthetic shares in 2020. The purpose of the program was to: (i) align the interests of executive management and other employees with those of shareholders'; (ii) reward value creation; and (iii) provide retention incentives. The Board of Directors determines 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

Executive management remuneration in 2020

Executive management remuneration for 2020 was in accordance with the directives approved by the AGM in 2020.

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	2020	2019

Lease expense on buildings and equipment	-2,008	-2,362
Other office expenses	-54	-86
IT expenses	-4,381	-4,086
Travel expenses	-230	-930
Legal expenses	0	-330
Consultant fees	-1,589	-7,892
Other general and administrative costs	-1,052	-2,175
Total other operating expenses	-9,315	-17,862

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

Note 5 Net financial income/-expenses

		1 January - 31 December
USD thousand	2020	2019

Dividend and group contribution received from group companies	13,625	267,936
Interest received	7,539	8,407
Interest received from group companies	1,387	-
Gain on foreign exchange	8,427	3,717
Change in fair value of financial investments	-	25,786
Total financial income	30,978	305,846

Interest expenses	-74,286	-69,200
Interest expenses group companies	-4,029	-21,665
Loss on foreign exchange	-5,993	-1,332
Impairment of financial assets	-245,203	-183,338
Other financial expenses	-9,570	-17,660
Loss on disposal of shares	-	-13,744
Change in fair value of financial investments	-8,436	-
Total financial expenses	-347,516	-306,939

Net financial income/-expenses	-316,539	-1,093

In 2020, the impairment of financial assets of USD 245.2 million was mainly related to DNO North Sea plc (USD 249.7 million), DNO Yemen AS (USD 2.9 million), DNO Mena AS (USD 2.3 million) and DNO Exploration UK Limited (USD 0.5 million), partially offset by received liquidation settlement related to the liquidation of DNO Somaliland AS, Northstar Exploration Holding AS and DNO Invest AS in 2020 (USD 10.2 million). The change in fair value of financial investments of USD 8.4 million recognized in 2020 was due to the decrease in fair value related to the Company's shares in RAK Petroleum. Other financial expenses in 2020 were mainly related to amortization of bond issue costs and a loss related to the FAPE01 redemption.

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 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).

Note 6

Taxes

Tax income/-expense

	1 January - 31 December
USD thousand	2020	2019

Change in deferred taxes	-	-
Income tax receivable/-payable	-	-
Tax income/-expense	-	-

Reconciliation of tax income/-expense

	1 January - 31 December
USD thousand	2020	2019

Profit/-loss before income tax	-319,074	-18,067
Expected income tax according to nominal tax rate of 22 percent	70,196	3,975
Foreign exchange variations between functional and tax currency	-7,581	4,891
Adjustment of deferred tax assets not recognized	1,676	-24,321
Impairment financial assets	-48,425	-43,191
Tax-free dividend from subsidiaries	-	52,571
Other items	-17,141	6,075
Tax loss carried forward (utilized)	1,275	-
Tax income/-expense	-	-
Effective income tax rate	0%	0%

Tax effects of temporary differences and losses carried forward

Years ended 31 December USD thousand 2020 2019 Tangible assets -51 - Intangible assets - -31 Losses carried forward 87,705 91,939 Non-deductible interests carried forward 11,278 11,020 Other temporary differences -1,223 -1,508 Deferred tax assets/-liabilities 97,709 101,420 Valuation allowance -97,709 -101,420 Net deferred tax assets/-liabilities - - Recognized deferred tax assets - - Recognized deferred tax liabilities - -

The corporate tax rate in Norway is 22 percent and has been used to calculate deferred taxes.

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 2020	13,530	3,161	16,691
Additions	841	35	876
Costs as of 31 December 2020	14,371	3,196	17,567
Accumulated depreciation as of 1 January 2020	-8,703	-2,762	-11,465
Depreciation	-964	-107	-1,071
Accumulated depreciation and impairments as of 31 December 2020	-9,667	-2,869	-12,536
Book value as of 31 December 2020	4,704	327	5,031
Book value as of 31 December 2019	4,827	399	5,226

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	-48,392	-3,743	-
DNO UK Limited	UK	100	GBP 100	-	-	-
DNO Iraq AS	Norway	100	NOK 1,200	1,004,174	10,705	279,848
DNO Mena AS*	Norway	100	NOK 2,000	3,926	-	3,914
Northstar Oman AS	Norway	100	NOK 202	-14,465	-10	-
DNO Technical Services AS	Norway	100	NOK 200	5,318	-6	5,359
DNO Exploration UK Limited	UK	100	GBP 30,912	-1,487	589	-
DNO North Sea plc (Faroe Petroleum plc)*	UK	100	GBP 37,289	395,291	-229,862	395,291
Total				1,344,365	-222,327	684,412

* 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 2020, the book value of shares in subsidiaries was partially written off by USD 252.0 million related to DNO North Sea plc (USD 249.7 million) and DNO Mena AS (USD 2.3 million). DNO Somaliland AS, Northstar Exploration Holding AS and DNO Invest AS were liquidated in 2020. See Note 5 for further details.

In 2019, the book value in shares in subsidiaries was partially written off by USD 168.3 million related to DNO North Sea plc (USD 167.0 million) and DNO Mena AS (USD 1.3 million). 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.

Equity and profit/loss for the subsidiaries in the table above are presented as reported for consolidation purposes. Statutory accounts for the subsidiaries are finalized after the release of the parent company accounts.

Other investments

See Note 11 in the consolidated accounts for further information on the Company's financial investments in equity instruments.

During 2020, the Company acquired FAPE01 bonds including premium for USD 15.0 million. FAPE01 bonds held by the Company were at the end of 2020 transferred to its subsidiary, DNO North Sea plc, at a price of 103.2 percent of par.

Note 9 Other receivables

	Years ended 31 December
USD thousand	2020	2019

Prepayments and accrued income	1,599	5,122
Other short-term receivables	476	32
Other receivables	2,075	5,154

Note 10 Cash and cash equivalents

	Years ended 31 December
USD thousand	2020	2019

Cash and cash equivalents, restricted	2,203	2,225
Cash and cash equivalents, non-restricted	297,462	386,803
Total cash and cash equivalents	299,665	389,028

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 2020.

Note 11

Equity

		Treasury			Other
	Share	shares	Treasury	Share	paid-in	Retained
USD thousand	capital	(numbers)	shares	premium	capital	earnings	Total equity

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 for the year				-		-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

Shareholders' equity as of 1 January 2020	35,991	93,700,000	-2,641	247,743	-	195,986	477,079
Purchase of treasury shares	-	14,681,415	-414	-	-	-17,327	-17,741
Dividend	-	-	-	-	-	-	-
Profit/-loss	-	-	-	-	-	-319,074	-319,074
Cancellation of treasury shares	-3,055	-108,381,415	3,055	-	-	-	-
Shareholders' equity as of 31 December 2020	32,936	-	-	247,743	-	-140,415	140,264

See Note 14 in the consolidated accounts for further information on the Company's equity and shareholders.

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 2.0 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)	2020	2019	2020	2019

Non-current
Bond loan (ISIN NO0010823347)	DNO02	USD	400,000	8.750	31.05.23	9.7	376,500	408,640	400,000	400,000
Bond loan (ISIN NO0010852643)	DNO03	USD	400,000	8.375	29.05.24	9.0	370,000	401,560	400,000	400,000
Capitalized borrowing issue costs									(12,641)	(19,247)
Total non-current interest-bearing liabilities							746,500	810,200	787,359	780,753

Current
Bond loan (ISIN NO0010740392)	DNO01	USD	-	8.750	18.06.20	12.5	-	143,808	-	140,000
Total current interest-bearing liabilities							-	143,808	-	140,000

Total interest-bearing liabilities							746,500	954,008	787,359	920,753

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

Note 14 Current liabilities

		Years ended 31 December
USD thousand	2020	2019

Trade payables	2,225	774
Public duties payable	1,665	2,175
Accrued expenses and other current liabilities	9,626	16,584
Trade payables and provisions for other liabilities and charges	13,516	19,533
Intercompany liabilities	-	161
Current portion of bond loans	-	140,000
Total current liabilities	13,516	159,694

Accrued expenses and other current liabilities include accrued interest for bond loans of USD 5.9 million (USD 6.3 million in 2019) and accruals for incurred costs of USD 1.2 million (USD 6.4 million in 2019).

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	2020	2019

Net profit/-loss attributable to ordinary equity holders of the parent	-319,074	-18,067

Weighted average number of ordinary shares (excluding treasury shares) (millions)	975.73	1,036.37

Effect of dilution:
Options	-	-

Weighted average number of ordinary shares (excluding treasury shares) (millions)
adjusted for the effect of dilution	975.73	1,036.37

Earnings per share, basic (USD per share)	-0.33	-0.02
Earnings per share, diluted (USD per share)	-0.33	-0.02

Note 19 Intercompany

Long-term intercompany receivables/liabilities			Years ended 31 December
	Functional		Receivables		Liabilities
USD thousand	currency	2020	2019	2020	2019

DNO Iraq AS	USD	-	-	137,216	35,341
DNO Oman Block 30 Limited	USD	536	504	-	-
DNO Oman Block 8 Limited	USD	-	-	12,921	13,361
DNO Oman Limited	USD	277	591	-	-
Northstar Exploration Holding AS	NOK	-	-	-	6,460
DNO Mena AS	USD	881	-	-	-
DNO North Sea plc	GBP	81,322	27,291	-	-
Total long-term intercompany receivables and liabilities		83,015	28,386	150,137	55,162

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 arm's length.

Note 19 Intercompany

Intercompany sales/purchases 1 January - 31 December

	Functional	Sales		Purchases
USD thousand	currency	2020	2019	2020	2019

DNO Technical Services AS	USD	348	695	-1,360	-277
DNO Iraq AS	USD	18,191	16,445	-	-
DNO Yemen AS	USD	107	152	-	-
DNO Oman Limited	USD	17	48	-	-1
DNO Oman Block 8 Limited	USD	80	505	-	-
Northstar Oman AS	USD	-	8	-	-
DNO Somaliland AS	USD	-	35	-	-
DNO Norge AS	NOK	3,328	1,881	-575	-15
DNO North Sea plc	GBP	673	334	-	-
Other	USD	142	185	-	-
Intercompany sales/purchases		22,888	20,288	-1,935	-293

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, dividend and group contribution 1 January - 31 December

		Interest income, dividend and group contribution		Interest expense
	Functional
USD thousand	currency	2020	2019	2020	2019

DNO Iraq AS	USD	12,772	240,541	-2,452	-19,365
DNO Mena AS	USD	853	27,395	-	-
DNO Oman Limited	USD	-	-	-	18
DNO Oman Block 8 Limited	USD	-	-	-1,242	-1,133
DNO North Sea Plc	GBP	1,387	-	-	-
Northstar Exploration Holding AS	NOK	-	-	-335	-1,185
Intercompany interest income/-expense		15,012	267,936	-4,029	-21,665

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	2020	2019
Revenues	614.9	971.4
Lifting costs	-181.1	-199.1
Tariffs and transportation	-36.2	-37.7
Movement in overlift/underlift	-11.3	7.2
Exploration expenses	-55.9	-146.4
Administrative expenses	-4.8	-26.1
Other operating income/expenses	-2.7	-19.8
EBITDA	322.8	549.4

EBITDAX

USD million	2020	2019
EBITDA	322.8	549.4
Exploration expenses	55.9	146.4
EBITDAX	378.8	695.8

Netback

USD million	2020	2019
EBITDA	322.8	549.4
Taxes received/-paid	236.3	56.9
Netback	559.1	606.3

	2020	2019
Netback (USD million)	559.1	606.3
Net production (MMboe)*	34.8	37.1
Netback (USD/boe)	16.1	16.3

* For accounting purposes, the net production from the assets added through the Equinor Assets Swap was accounted post completion date of 30 April 2019.

Lifting costs

	2020	2019
Lifting costs (USD million)	-181.1	-199.1
Net production (MMboe)*	34.8	37.1
Lifting costs (USD/boe)	5.2	5.4

* See comment above under Netback.

Acquisition and development costs

USD million	2020	2019
Purchases of intangible assets	-45.7	-68.5
Purchases of tangible assets	-162.2	-339.4
Acquisition and development costs*	-207.9	-407.9

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

Operational spend

USD million	2020	2019
Lifting costs	-181.1	-199.1
Tariff and transportation expenses*	-36.2	-37.7
Exploration expenses	-55.9	-146.4
Exploration costs capitalized in previous years carried to cost (Note 6 in the consolidated accounts)	0.4	27.8
Acquisition and development costs	-207.9	-407.9
Payments for decommissioning*	-30.7	-22.6
Operational spend	-511.4	-786.0

* From 1 January 2020, tariff and transportation expenses and payments for decommissioning are included in this APM. Comparison numbers are restated.

Alternative performance measures

Equity ratio

USD million	2020	2019
Equity	845.6	1,161.3
Total assets	2,708.7	3,271.9
Equity ratio	31.2%	35.5%

Free cash flow

USD million	2020	2019
Cash generated from operations	235.8	385.3
Acquisition and development costs	-207.9	-407.9
Payments for decommissioning	-30.7	-22.6
Free cash flow	-2.8	-45.2

Marketable securities

USD million	2020	2019
Financial investments	12.6	21.0
Treasury shares*	-	123.5
Marketable securities	12.6	144.5

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

Net debt

USD million	2020	2019
		485.7
		999.0
Net cash/-debt	-472.5	-513.3

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)

	2020	2019
Net production (MMboe)	34.8	38.2
1P reserves	201.0	205.6
2P reserves	332.3	344.8
3P reserves	506.8	539.9
1P Reserve Life Index (R/P in years)	5.8	5.4
2P Reserve Life Index (R/P in years)	9.6	9.0
3P Reserve Life Index (R/P in years)	14.6	14.1

The net production in 2019 includes production from the assets added through the swap agreement with Equinor Energy AS, 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 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, as reconciled above, 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, as reconciled above, 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 after taxes received/-paid 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 net 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 after taxes received/-paid without regard to significant events and/or decisions in the period that are expected to occur less frequently, per net 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 net 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, tariff and transportation expenses, exploration expenses, acquisition and development costs and payments for decommissioning. Management believes that this measure is useful because it provides a complete overview of the Group's total operational costs, capital investments and payments for decommissioning 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

ASRR Annual Statement of Reserves and

bbls Barrels of oil

Resources

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

CWI

Company Working Interest.

DKK

Danish kroner

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

Glossary and definitions

PPA

Purchase Price Allocation

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

98 DNO Annual Report and Accounts 2020

AI assistant

DNO ASA — Annual Report 2020

3580_10-k_2021-03-18_b8dd8c7f-f5e9-4677-830d-24f23f52532d.pdf

Content

Highlights

Key figures

Board of Directors

Bijan Mossavar-Rahmani Executive Chairman

Lars Arne Takla Deputy Chairman

Elin Karfjell

Board of Directors

Gunnar Hirsti Director

Shelley Watson

Board of Directors' report

Introduction

2020 full-year results highlights

Our vision and strategic priorities

Production strength and capacity

Organic reserves and resource growth

Operational control and financial flexibility

Encouraging an entrepreneurial culture

Mergers and acquisitions

Corporate governance and managing risk

Operations review

Annual Statement of Reserves and Resources

Kurdistan

Tawke license

Erbil license

Baeshiqa license

RESERVES

North Sea

RESERVES

Yemen

Business development

Financial performance

Revenues, operating profit and cash

Cost of goods sold

Impairment charges

Exploration costs expensed

Acquisition and development costs

Assets, liabilities and equity

Going concern

Corporate governance

Equity and dividends

SHAREHOLDERS' EQUITY

DIVIDEND POLICY

OTHER AUTHORIZATIONS TO THE BOARD OF DIRECTORS

Equal treatment of shareholders and transactions with related parties

Freely negotiable shares

General meetings

Board of Directors' composition and independence

The Board of Directors' work

The Board of Directors' committees

AUDIT COMMITTEE

HSSE COMMITTEE

REMUNERATION COMMITTEE

NOMINATION COMMITTEE

REMUNERATION OF DIRECTORS

Remuneration of executive management

Responsibility for risk management and internal control

Information and communication

Takeover

Auditor

Enterprise risk management

Financial risk

Entitlement risk

Operational risk

Environmental risk

Security risk

Compliance risk

Political risk

Stakeholder risk

HSSE performance

During 2020:

Organization and personnel

Covid-19

Workforce diversity in DNO Norway

Working environment in DNO Norway

Executive remuneration policy

Remuneration policy for 2020

DNO ASA Annual Report 2020