DNO ASA — Annual Report (ESEF) 2022

Mar 16, 2023

DNO ASA Annual Report and Accounts 2022

Content Highlights

3 Key figures
4 Board of Directors
5 Board of Directors’ report
6 Introduction
6 Operations review
7 Business development
8 Financial performance
9 Corporate governance
10 Enterprise risk management
12 HSSE performance
14 Organization and personnel
14 Parent company
17 Main events since yearend
17 Responsibility statement
18 Consolidated accounts
74 Parent company accounts
87 Country-by-Country report
88 Auditor’s report
94 Alternative performance measures
97 Glossary and definitions

Annual Report and Accounts 2022

DNO

Highlights

Driven by high oil and gas prices and solid operational performance in 2022, DNO reported record revenues of USD 1,377 million and operating profit of USD 431 million, tempered by non-cash North Sea impairments of USD 371 million. Following an all-time high free cash flow of USD 619 million, DNO exited the year with net cash of USD 388 million. In 2022, the Company reduced its borrowings through bond repurchases of USD 264 million and repayment of USD 60 million under its reserve-based lending facility. Cash was returned to shareholders through dividends (paid quarterly) totaling USD 73 million and share buybacks totaling USD 12 million, representing a fourfold increase in shareholder distributions from a year earlier.

Gross operated Kurdistan production averaged 107,600 barrels of oil per day (bopd) in 2022, mostly from the Company’s flagship Tawke license (DNO 75 percent interest) of which the Peshkabir field contributed 62,000 bopd and the Tawke field 45,000 bopd. Coming on stream mid-2022, the operated Baeshiqa license (DNO 64 percent) delivered the balance. Of the total, 80,700 bopd were net to DNO’s interests. Elsewhere, net production from the North Sea averaged 13,300 barrels of oil equivalent per day (boepd). With an additional 3,300 boepd from the Company’s new West Africa assets offshore Côte d’Ivoire, the Company's net production totaled 97,300 boepd across the portfolio.

At yearend 2022, the legacy Tawke field had delivered three consecutive quarters of production growth, the first quarterly increases since 2015 as new wells were drilled, workovers conducted on existing ones and gas injection stepped up to counter natural field decline. In 2022, DNO completed a USD 25 million expansion of the Peshkabir-to-Tawke gas project, Kurdistan’s only gas capture and enhanced recovery injection project. Since 2020, the project has captured 1.2 million tonnes of CO2e through avoided flaring.

In the North Sea, DNO and its license partners submitted field development plans for Andvare (DNO 32 percent) and Berling (DNO 30 percent). Two of six exploration wells drilled in 2022 led to commercial discoveries, namely Ofelia (DNO 10 percent) and Kveikje (DNO 29 percent). At yearend 2022, DNO held 82 licenses across its portfolio.

In Kurdistan, DNO continues to produce what are among the lowest cost barrels in the global oil and gas industry while the North Sea and West Africa offer growth opportunities. DNO remains committed to explore for and produce oil and gas in a commercially attractive but also socially responsible and environmentally sensitive manner.

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

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DNO Annual Report and Accounts 2022

Key figures

Key financials (USD million)	2022	2021
Revenues	1,377.0	1,004.1
EBITDAX	1,116.0	739.3
EBITDA	1,019.5	606.9
Operating profit/-loss	431.4	320.9
Net profit/-loss	384.9	203.9
Free cash flow	618.8	362.0
Operational spend	741.4	663.8
Net cash/-debt	388.2	-153.4
Lifting costs (USD/boe)	6.5	5.3

Key operational data	2022	2021
Gross operated production (boepd)	107,637	108,713
Net production (boepd)*	97,310	94,477
Sales volume (boepd)	38,444	42,171
Net 2P reserves (MMboe)*	292.1	321.4

* Net production in 2022 and net 2P reserves at yearend 2022 include West Africa segment (equity accounted investment), effective from 1 January 2022. For reconciliation and more information about key figures, see the section on alternative performance measures.

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Board of Directors

DNO 5

Board of Directors

Bijan Mossavar-Rahmani
Executive Chairman

Bijan Mossavar-Rahmani has served as DNO’s Executive Chairman of the Board of Directors since 2011 and is a member of the nomination and remuneration committees. Mr. Mossavar-Rahmani’s full-time role encompasses strategic, managerial and operational responsibilities at DNO, of which he is the largest shareholder. An experienced industry executive, he has served as Chairman of the Board of RAK Petroleum plc between 2013-2022, co-founder and Chairman of Foxtrot International LDC since 1998 and founder and first Chief Executive Officer of Apache International Inc. between 1988-1992.

In addition to his industry positions, he is active in philanthropy, education and the arts. He is a Trustee of the New York Metropolitan Museum of Art where he chairs the Audit Committee and the Visiting Committee on Islamic Art and is a member of the Executive Committee and the Finance Committee, a Director of the Persepolis Foundation and a member of Harvard University’s Global Advisory Council and of Princeton University’s Nassau Hall Society. 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).

Gunnar Hirsti
Deputy Chairman

Gunnar Hirsti was elected to DNO’s Board of Directors in 2007, chairs the audit committee and is a member of the remuneration committee. Mr. 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. He 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.

Elin Karfjell
Director

Elin Karfjell was elected to DNO’s Board of Directors in 2015 and is a member of the audit committee. Ms. Karfjell is Director Property Management and Development of Statsbygg and has held various management positions across a broad range of industries, including Managing Partner of Atelika AS and Chief Executive Officer of Fabi Group, Chief Financial Officer of Atea AS and partner of Ernst & Young AS and Arthur Andersen. Current directorships include Philly Shipyard ASA, North Energy ASA and Contesto AS. Ms. Karfjell is a state authorized public accountant with a Bachelor of Science in Accounting from Oslo and Met and a Higher Auditing degree from the Norwegian School of Economics and Business Administration.

Anita Marie Hjerkinn Aarnæs
Director

Anita Marie Hjerkinn Aarnæs was elected to DNO’s Board of Directors in 2022 and is a member of the HSSE committee. Ms. Hjerkinn Aarnæs is Managing Partner Nordics at The Board Practice. She has extensive international experience with strategy development, governance and organizational effectiveness across industries and in particular within the energy sector.# Board of Directors

Board of Directors’ report

Introduction

2022 full-year results highlights

• Revenues of USD 1,377 million in 2022, up from USD 1,004 million in 2021;
• Kurdistan revenues totaled USD 820 million (2021: USD 594 million) and North Sea revenues totaled USD 557 million (2021: USD 410 million);
• Operating profit of USD 431 million in 2022 (2021: USD 321 million);
• Operational spend of USD 741 million, up from USD 664 million in 2021;
• Yearend cash deposits of USD 954 million, up from USD 737 million at yearend 2021;
• Gross production at the Tawke license in Kurdistan, containing the Tawke and Peshkabir fields, averaged 107,102 bopd compared to 108,713 bopd in 2021;
• Across portfolio, net production of 97,310 boepd, up from 94,477 boepd in 2021;
• Of which newly acquired West Africa assets in Côte d’Ivoire contributed 3,327 boepd of net production from equity accounted investment; and
• Net proven and probable (2P) reserves of 292 million barrels of oil equivalent (MMboe), compared to 321 MMboe at yearend 2021.

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

Our vision and strategic priorities

DNO is a Norwegian oil and gas operator active in the Middle East, the North Sea and West Africa. DNO’s vision is to remain a leading, growth-oriented exploration and production company seeking to deliver attractive returns to shareholders by finding and producing oil and gas at low cost and at an acceptable level of risk in a socially responsible and environmentally sensitive manner. 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;
• Being a leader in health, safety, security and environmental best practices in our areas of operation; and
• Minimize gas flaring to conserve resources and control emissions.

Production strength and capacity

DNO reported gross operated production in 2022 of 107,637 bopd, slightly down from 108,713 boepd in 2021. DNO’s net production stood at 97,310 boepd in 2022, up from 94,477 boepd in 2021. With net 2P reserves totaling 292 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, the North Sea and West Africa 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 assets 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.

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 respect fundamental human rights, provide decent working conditions and are committed to the health, safety and security of our employees, contractors and the communities in which we operate. The Norwegian Transparency Act, which entered into force on 1 July 2022, requires the Company to report on how it ensures compliance with fundamental human rights and decent working conditions in its operations, in its supply chain and with its business partners. The Company will publish and make available its first such report on its website by the deadline date of 30 June 2023. In addition, the Company is continuously working to reduce the environmental impact of our activities including with Board of Directors’ report Annual Report and Accounts 2022 DNO 7 respect to greenhouse gas (GHG) emissions. Please refer to the Company’s latest Corporate Social Responsibility (CSR) Report, available on the Company’s website, for more information.

Board of Directors’ report

Operations review

Annual Statement of Reserves and Resources

The Company’s Annual Statement of Reserves and Resources (ASRR) has been prepared in accordance with the Oslo Stock Exchange listing and disclosure requirements Circular No. 1/2013. International petroleum consultants DeGolyer and MacNaughton (D&M) carried out an independent assessment of the Tawke license (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 RPS Energy Consultants (RPS) carried out an independent assessment of DNO's licenses in Norway and the United Kingdom (UK). The Company used reserves and resources numbers reported by the operating entity of its licenses in Côte d’Ivoire. For the producing Block CI-27 in Côte d’Ivoire, the numbers were based on an independent assessment carried out by international petroleum consultant Gaffney, Cline & Associates (GCA) at yearend 2016, adjusted for production and technical revisions to reflect yearend 2022 values. The Company internally assessed Yemen Block 47.

At yearend 2022, DNO’s net 1P reserves stood at 220.3 MMboe, compared to 196.1 MMboe at yearend 2021, after adjusting for production during the year, upward technical revisions and addition of assets in Côte d’Ivoire. On a 2P reserves basis, DNO’s net reserves stood at 292.1 MMboe, compared to 321.4 MMboe at yearend 2021. On a 3P reserves basis, DNO’s net reserves were 386.7 MMboe, compared to 420.6 MMboe at yearend 2021. DNO’s net 2C resources were 152.5 MMboe, compared to 189.5 MMboe at yearend 2021.

DNO’s net production in 2022 totaled 35.4 MMboe (of which 29.3 million barrels of oil (MMbbls) were from the Tawke license in Kurdistan, 4.8 MMboe in Norway, 1.2 MMboe in Côte d’Ivoire and the balance in the UK), compared to 34.5 MMboe in 2021 (of which 29.8 MMbbls in Kurdistan, 4.5 MMboe in Norway and the balance in the UK).

The Company’s net yearend 2022 Reserve Life Index (R/P) stood at 6.2 years on a 1P reserves basis, 8.3 years on a 2P reserves basis and 10.9 years on a 3P reserves basis. The ASRR report for 2022 is available on the Company’s website.

Kurdistan

Tawke license

Gross production from the Tawke license, containing the Tawke and Peshkabir fields, averaged 107,102 bopd during 2022 (108,713 bopd in 2021). The Tawke field contributed 45,065 bopd (46,933 bopd in 2021) and Peshkabir field contributed 62,037 bopd (61,780 bopd in 2021). Following a production decline in the first quarter of 2022, the legacy Tawke field delivered three consecutive quarters of production growth in 2022, the first quarterly increases since 2015 as new wells were drilled, workovers conducted on existing ones and gas injection continued to counter natural field decline. During the fourth quarter of 2022, DNO completed a USD 25 million expansion of the Peshkabir-to-Tawke gas project, Kurdistan’s only gas capture and enhanced recovery injection project. Since 2020, the project has captured 1.2 million tonnes of CO 2 e through avoided flaring. DNO holds a 75 percent operated interest in the Tawke license with partner Genel Energy International Limited holding the remaining 25 percent.

Baeshiqa license

After a fast-track field development, production commenced from the Zartik-1 discovery well in June 2022 with the Baeshiqa-2 discovery well coming onstream in late September.However, Baeshiqa license ramp-up has been slower than previously expected with a gross production average of 536 bopd for the year. At yearend, DNO held a 64 percent operated interest in the Baeshiqa license (80 percent paying interest) with partners being Turkish Energy Company Limited (TEC) with a 16 percent interest (20 percent paying interest) and the Kurdistan Regional Government (KRG) with a 20 percent carried interest.

RESERVES

On a net basis at yearend 2022, 1P reserves in the Company’s Kurdistan portfolio totaled 190.9 MMbbls (162.2 MMbbls at yearend 2021), 2P reserves totaled 245.3 MMbbls (267.4 MMbbls at yearend 2021) and 3P reserves totaled 316 MMbbls (348.5 MMbbls at yearend 2021). Net 2C resources were 62.4 MMbbls, compared to 71.3 MMbbls at yearend 2021.

At the Tawke license containing the Tawke and Peshkabir fields, at yearend 2022 gross 1P reserves stood at 254.5 MMbbls (190.9 MMbbls on a net basis), compared to 216.2 MMbbls (162.2 MMbbls on a net basis) at yearend 2021. At yearend 2022 gross 2P reserves stood at 327.1 MMbbls (245.3 MMbbls on a net basis), compared to 356.6 MMbbls (267.4 MMbbls on a net basis) at yearend 2021. At yearend 2022 gross 3P reserves stood at 421.3 MMbbls (316 MMbbls on a net basis), compared to 464.7 MMbbls (348.5 MMbbls on a net basis) at yearend 2021. At yearend 2022 gross 2C resources stood at 32.4 MMbbls (24.3 MMbbls on a net basis), compared to 47.6 MMbbls (35.7 MMbbls on a net basis) at yearend 2021.

The Baeshiqa license contains two large structures with multiple independent stacked target reservoirs, including in Cretaceous, Jurassic and Triassic formations. The structures at Baeshiqa and Zartik have the potential to be part of a single accumulation of hydrocarbons at one or more of the geological formation intervals. At yearend 2022 gross 2C resources at the Baeshiqa structure stood at 56.7 MMbbls (36.3 MMbbls on a net basis), compared to 48.4 MMbbls (31 MMbbls on a net basis) at yearend 2021. At yearend 2022 gross 2C resources at the Zartik structure stood at 2.8 MMbbls (1.8 MMbbls on a net basis), compared to 7.4 MMbbls (4.7 MMbbls on a net basis) at yearend 2021. At the license level and at yearend 2022, gross 2C resources stood at 59.5 MMbbls (38.1 MMbbls on a net basis), compared to 55.7 MMbbls (35.7 MMbbls on a net basis) at yearend 2021. Baeshiqa license volumes were recorded as contingent resources at yearend 2022, pending processing of the 3D seismic acquired in 2022 and additional drilling.

Board of Directors’ report

Annual Report and Accounts 2022 DNO 9

North Sea

DNO had diversified production across 10 fields in the North Sea of which eight are in Norway and two in the UK. Net production averaged 13,314 boepd during 2022 (12,942 boepd in 2021), of which 13,035 boepd were attributable to Norway and 279 boepd to the UK (12,469 boepd and 473 boepd, respectively, in 2021).

Before yearend 2022, DNO submitted field development plans under a favorable Norwegian temporary tax program for Andvare (DNO 32 percent) and Berling (30 percent following acquisition of another 10 percent in the fourth quarter of 2022). A third DNO field development that was matured towards a 2022 investment decision was the operated Brasse project (50 percent) also offshore Norway, via a tieback to Oseberg platform, but the Company decided not to progress the project. Instead, together with OKEA ASA (OKEA), the Company initiated a fast-track, low-cost review of an alternative tieback of Brasse to the Brage platform together with OKEA, which is Brage operator and has become a partner in Brasse with 50 percent.

Two of six exploration wells drilled in 2022 led to commercial discoveries (Ofelia 10 percent and Kveikje 29 percent). DNO-operated decommissioning of the Oselvar field in Norway and the Schooner and Ketch fields in the UK was largely completed in 2022, with limited infrastructure remaining to be removed from the UK fields.

In January 2023, the Company’s wholly-owned subsidiary DNO Norge AS was awarded participation in 11 exploration licenses, of which one is an operatorship, under Norway's Awards in Predefined Areas (APA) 2022 licensing round.

RESERVES

At yearend 2022, DNO held 68 licenses in Norway in various stages of exploration, development and production. Across its Norway portfolio and on a net basis, DNO’s 1P reserves totaled 24.6 MMboe, 2P reserves stood at 35.6 MMboe, 3P reserves totaled 48.1 MMboe and 2C resources stood at 80 MMboe. In 2022, DNO had an active exploration program in Norway resulting in the Kveikje discovery in license PL293B and the Ofelia discovery in PL929. Gross 2C resources at these licenses stood at 31.7 MMboe (9.2 MMboe on a net basis) and 19.2 MMboe (1.9 MMboe on a net basis), respectively.

On a net basis, at yearend 2021 DNO’s portfolio of 73 licenses in Norway held 1P reserves of 33.2 MMboe, 2P reserves of 52.3 MMboe, 3P reserves of 70.2 MMboe and 2C resources of 112.2 MMboe.

In the UK, DNO held seven licenses at yearend 2022. On a net basis, 1P reserves totaled 0.4 MMboe, 2P reserves stood at 0.9 MMboe and 3P reserves totaled 1.3 MMboe. No 2C resources were booked for DNO’s licenses in the UK at yearend 2022. At yearend 2021, DNO held 11 licenses in the UK with 1P reserves of 0.7 MMboe, 2P reserves of 1.6 MMboe, 3P reserves of 1.9 MMboe and 2C resources of 1.1 MMbbls, all on a net basis.

West Africa

In October 2022, DNO acquired Mondoil Enterprises LLC and its 33.33 percent indirect interest in privately-held Foxtrot International LDC whose principal assets are operated stakes in offshore production of gas and associated liquids in Côte d'Ivoire. Foxtrot International holds a 27.27 percent interest in and operatorship of Block CI-27 containing the country’s largest reserves of gas, produced together with condensate and oil, from four offshore fields tied back to two fixed platforms, meeting more than three-quarters of the country’s gas needs. Foxtrot International also operates an exploration license offshore Côte d’Ivoire, Block CI-12 in which it holds a 24 percent interest.

RESERVES

At the producing Block CI-27, at yearend 2022 gross 1P reserves stood at 48.2 MMboe, gross 2P reserves stood at 113.6 MMboe, gross 3P reserves stood at 234.6 MMboe and gross 2C resources stood at 17.9 MMboe. Gross production totaled 13.4 MMboe in 2022. At the exploration Block CI-12, at yearend 2022 gross 2C resources stood at 45.3 MMboe.

On a net basis, at yearend 2022 DNO’s portfolio in Côte d’Ivoire held 1P reserves of 4.4 MMboe, 2P reserves of 10.3 MMboe, 3P reserves of 21.3 MMboe and 2C resources of 5.2 MMboe.

Yemen

Production start-up at the Yaalen field at Block 47 in Yemen remains on hold due to force majeure. At yearend 2022, gross 2C resources at Block 47 stood at 6.2 MMbbls (4.8 MMbbls on a net basis), unchanged from yearend 2021.

Business development

In August 2022, DNO announced a transaction agreement between DNO and its then largest shareholder RAK Petroleum plc (RAK Petroleum) by which the Company would acquire Mondoil Enterprises LLC and its 33.33 percent indirect interest in privately-held Foxtrot International LDC, whose principal assets are operated stakes in four gas fields offshore Côte d'Ivoire. The move into Côte d'Ivoire represented a first step into another highly prospective region beyond the Kurdistan region of Iraq and the North Sea. As agreed, following closing of the all-share transaction, RAK Petroleum distributed by way of a capital repayment the entirety of its DNO shareholding to its shareholders. The above transaction was negotiated by the independent members of DNO’s Board of Directors and supported by third party valuation. In addition to its attractive business metrics, the transaction increased the Company’s free float to attract institutional investors and augmented DNO’s gas exposure to reduce its carbon footprint.

In the North Sea, DNO continued to high-grade its portfolio through a combination of licensing round awards, license transactions and relinquishments of licenses deemed unattractive following evaluation. Ahead of sanctioning the Berling development project offshore Norway before yearend Board of Directors’ report 10 DNO Annual Report and Accounts 2022 2022, DNO increased its stake to 30 percent by acquiring an additional 10 percent from Sval Energi AS. At the end of 2022, the Company initiated a change in the Brasse partnership following the decision not to proceed with the previously proposed development concept, bringing in Brage operator OKEA ASA as the new partner (50 percent interest) to undertake a fast-track, low-cost review of potential tieback of Brasse to the Brage platform.

DNO continues to develop a pipeline of new business opportunities to supplement its current position in the Middle East, the North Sea and West Africa. It actively pursues growth opportunities across the exploration and production lifecycle, including exploration, development and production, both organically as well as through potential mergers and acquisitions.

Financial performance

Revenues, operating profit and cash

Total revenues in 2022 stood at USD 1,377 million, up 37 percent from USD 1,004.1 million in 2021 driven by high oil and gas prices and solid operational performance. Kurdistan revenues stood at USD 820.1 million (USD 594.3 million in 2021), while the North Sea generated revenues of USD 556.9 million (USD 409.8 million in 2021). The Group reported an operating profit of USD 431.4 million, up 34 percent from USD 320.9 million in 2021. The operating profit in 2022 was driven by higher revenues partially offset by North Sea asset impairments. The Group ended the year with USD 954.3 million in cash and USD 388.2 million in net cash (USD 736.6 million in cash and USD 153.4 million in net debt at yearend 2021). Net cash flows from operating activities for the year was USD 1,056.3 million, up from USD 728.8 million in 2021.The increase in net cash flows from operating activities was mainly driven by higher oil and gas prices, partly offset by North Sea tax instalments of USD 21.1 million net paid in 2022 (USD 174.7 million in tax refunds received in 2021). The difference between the cash generated from operations from the cash flow statement and the operating profit relates mainly to depreciation, impairments and exploration write-offs. Investing activities of USD 415 million (USD 362 million in 2021) consist of USD 374.8 million in asset investments and USD 70 million in decommissioning, partly offset by USD 29.8 million cash inflow from financial and equity accounted investments. Net cash outflows from financing activities of USD 419.1 million (USD 105.4 million in 2021) was driven by debt repayment of USD 323.7 million and shareholder distributions (dividends and share buybacks) of USD 84.5 million.

Cost of goods sold
In 2022, the total cost of goods sold was USD 460.9 million, compared to USD 443.1 million in 2021. The increase in cost of goods sold was mainly due to first production at the Baeshiqa license and higher production costs from the North Sea, partly offset by North Sea net underlifting during 2022.

Impairment charges
The Group’s total impairment charges stood at USD 371.3 million in 2022 and was entirely related to the North Sea (USD 80.1 million in 2021).

Exploration costs expensed
Total expensed exploration costs for the year were USD 96.5 million, down from USD 132.3 million in 2021.

Capital expenditures
Total capital expenditures for the year were USD 374.8 million in 2022 (USD 280.6 million in 2021), of which USD 212.2 million were in Kurdistan and USD 161.1 million in the North Sea (USD 94.9 million and USD 185.1 million in 2021, respectively).

Assets, liabilities and equity
At yearend 2022, total assets stood at USD 2,803 million, compared to USD 2,947.8 million at yearend 2021. The decrease in total assets compared to last year was mainly due to higher impairments on goodwill and oil and gas assets, partly offset by higher cash generation. Total property, plant and equipment (PP&E), intangible assets and goodwill decreased from USD 1,605.5 million at yearend 2021 to USD 1,262 million at yearend 2022. Total liabilities decreased from USD 1,929 million at yearend 2021 to USD 1,433.6 million at yearend 2022, primarily driven by debt repayments, deferred tax income effects from North Sea asset impairments and reduction in ARO liabilities, partly offset by higher North Sea income tax payable driven by higher oil and gas prices. The equity ratio stood at 48.9 percent at yearend 2022 (34.6 percent at yearend 2021).

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 covering at least 12 months from the end of the reporting period. 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. Following its review, the Board of Directors confirmed, 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.

Board of Directors’ report
Annual Report and Accounts 2022
DNO
11

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 full- year 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 2022, this ratio was 48.9 percent.

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 2021 AGM, all 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 from the date of the AGM until 31 December 2021 and a distribution of dividend of up to NOK 0.20 per share from 1 January 2022 until the date of the 2022 AGM. Accordingly, the Board of Directors decided to distribute a dividend of NOK 0.20 in March 2022. At the 2022 AGM, 99.9 percent of the votes cast approved the resolution to authorize the Board of Directors to approve total dividend distributions of up to NOK 1 per share from the date of the 2022 AGM until the date of the 2023 AGM. Following this, the Board of Directors decided to distribute quarterly dividends of NOK 0.25 in August and November 2022, as well as in February 2023.

OTHER AUTHORIZATIONS TO THE BOARD OF DIRECTORS
At the 2022 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 which corresponds to 97,543,373 new shares. 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 was time-limited until the 2023 AGM, and not beyond 30 June 2023. The Board of Directors was also given the authority to increase the Company’s share capital by up to NOK 24,385,818 which corresponds to 97,543,373 new shares. The authorization was time-limited until the 2023 AGM, and not beyond 30 June 2023. 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 24 , 385 , 818. The authorization is valid until the 2023 AGM, but not beyond 30 June 2023.

At an Extraordinary General Meeting (EGM) in September 2022, a proposal to increase the Company’s share capital received support of over 99 percent of the votes cast. In accordance with the EGM approval and a transaction agreement negotiated by the independent members of DNO’s Board of Directors, DNO in October 2022 issued 78,943,763 new shares to RAK Petroleum, its then largest shareholder, as consideration for the transfer of West Africa assets between the companies. Prior to the issuance of the consideration shares, RAK Petroleum held 438,379,418 shares in DNO, representing 44.94 percent of shares outstanding. Pursuant to the transaction agreement, RAK Petroleum proceeded to distribute its entire DNO shareholding, including the consideration shares, to its shareholders. As a shareholder of RAK Petroleum (5.1 percent), DNO received 26,269,183 own shares to be retained as treasury shares. The total shares outstanding following the completion of the transaction increased to 1,054,376,509, each with a nominal value of NOK 0.25. In December 2022, DNO announced the initiation of a share buyback program through which the Company would repurchase up to 53,107,326 shares, representing approximately five percent of total shares outstanding, for a maximum total consideration of USD 80 million. The buyback program was based upon the authorization to acquire treasury shares granted to the Board of Directors at the 2022 AGM. The Board of Directors plans to propose to the 2023 AGM to cancel repurchased shares under the buyback program as well as the 26,269,183 treasury shares received from RAK Petroleum.

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 22 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.

Board of Directors’ report
12
DNO
Annual Report and Accounts 2022

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 shareholders 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 with an election period until the 2023 AGM. As of 31 December 2022, the Board of Directors consisted of four members, all of whom have relevant and broad experience. 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 board 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 the Company’s 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.

Directors’ and officers’ insurance

The Company has directors’ and officers’ liability insurance which covers the cost of compensation claims made against the Company’s directors and key managers (officers) for alleged wrongful acts.

The Board of Directors’ committees

AUDIT COMMITTEE

The audit committee consists of two members: Mr. Gunnar Hirsti (chair) 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 Ms. Anita Marie Hjerkinn Aarnæs. 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, Mr. Lars Arne Takla 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. It is the Company’s assessment that it is in the interest of DNO and its shareholders that the largest shareholder is represented on the nomination committee. To ensure the independence of the nomination committee, it also consists of two additional members who are both considered independent of the Board of Directors and the Company’s main shareholders.

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).

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.

Board of Directors’ report

Annual Report and Accounts 2022

DNO

13

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 quarterly 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 continuously review our risk profile, 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 18 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. In 2012, the Federal Government of Iraq (FGI) challenged the constitutional validity of the Kurdistan Oil and Gas Law No. 27/2007 (KOGL) and the right of the KRG to export oil independently of the FGI. The Company notes from public reports that on 15 February 2022, the Federal Supreme Court of Iraq (FSCI) ruled on this matter along with another related matter dating back to 2019. Reportedly, the FSCI found amongst other things that the KOGL is unconstitutional, that the KRG is to hand over all oil production from areas located in the KRI to the FGI and that the FGI has the right to pursue the nullity of the oil contracts concluded by the KRG. DNO was not a party to the legal proceedings. DNO has learned via media reports that on 4 July 2022, a commercial court in Baghdad ruled that PSCs signed between the KRG and four international oil companies including DNO should be voided. Likewise, DNO notes from media reports that on 21 August 2022, the KRG filed third party objections to the reported 4 July 2022 Baghdad rulings including those understood to concern DNO. These cases, along with other similar cases against international oil companies, are reported to be still pending. Furthermore and importantly, the KRG has issued repeated reassurances that the PSCs remain valid. The KRG has also initiated legal proceedings against the FGI in Erbil courts and there have been several rulings in Erbil courts affirming the validity of the PSCs.# DNO Notes from Public Reports

DNO notes from public reports that there is increased dialogue between the KRG and the FGI on oil related matters, in particular following the 27 October 2022 federal parliamentary approval of a new federal government led by Prime Minister Mohammed Shia' Sabbar al-Sudani. Since then, DNO notes frequent media reports on regular KRG and FGI engagement to find a way forward, including by way of adopting a new federal oil and gas law. On 13 March 2023, it was announced that the KRG had received a USD 275.5 million payment from the FGI pursuant to an agreement between the parties, notwithstanding an FSCI ruling that deemed such payments by a previous government as “wrong”. It is unclear how and when the KRG and the FGI will permanently address these matters. At present, normal operations are maintained at the Tawke and Baeshiqa licenses.

Due to disagreements between the FGI and the KRG, economic conditions in Kurdistan and limited oil export channels, DNO has historically 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 DNO’s 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 but Board of Directors’ report 14 DNO Annual Report and Accounts 2022 notwithstanding sometimes lengthy delays, payments have ultimately been received by DNO.

At yearend 2020, the Group had accumulated a receivable against the KRG of USD 259 million after certain 2019 and 2020 entitlement and override payments to the Group and other KRI oil exporters were withheld early in 2020 by the KRG in connection with the Covid-19 pandemic. Payment plans were put in place by the KRG by which the outstanding arrears were reduced to USD 2 million at yearend 2022 (from USD 169 million at yearend 2021), not including any interest. The Company continues to work to collect the remaining balances and expects to be paid accordingly.

Over the course of 2022, KRG payments to international oil companies were increasingly delayed. At the time of issuing this report, the invoices related to August and September 2022 oil deliveries were paid in January and March 2023, respectively. The Company is in dialogue with the KRG, seeking timely payments to support timely investments.

Moreover, in September 2022, the KRG proposed a change in the previously agreed pricing formula for oil such that prices should, with effect from 1 September 2022, be based on the purported actual price realized by KRG during the delivery month. The KRG proposal has not been accepted by DNO and the Company continues to invoice the KRG for oil sales based on the previously agreed pricing formula (including the September 2022 invoice) until such time that protocols are put in place to ensure that realised prices are transparent, based on arms-length transactions and subject to third-party audit. The payment for the September oil delivery received after yearend reflects the formula proposed and unilaterally applied by the KRG in September 2022. The payment received was USD 5.2 million (net to DNO) lower than invoiced (see notes 12 and 18). The Company is in continuing dialogue with the KRG to resolve this matter and collect outstanding balances.

DNO also notes the ongoing arbitration case, commenced in 2014, by the FGI against the Turkish Government and its state- owned pipeline operator BOTAS relating to the Iraq-Turkey Pipeline. It is unclear if a ruling, when it comes, may have an impact on future transportation of Kurdish oil in said pipeline.

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.

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.

Climate-related Risk

The most important risks to DNO’s business prospects from concerns about the impact of fossil fuel use on climate derive from the uncertain consequences of environmental action on oil and gas demand and supply, and therefore prices. Increasing concerns about adverse climate impact may affect investor appetite for oil and gas investments both within equity and debt markets, inhibiting the Group’s ability to obtain funding. Such concerns could also reduce the attractiveness of the oil and gas sector (including DNO) as an employer.

In the North Sea, carbon prices have been rising through CO 2 taxes, emissions trading schemes and carbon price floors. Policies requiring electrification of offshore oil and gas production may also increase North Sea operational costs.

In Kurdistan, the Government in 2021 introduced a requirement that oil and gas companies curb gas flaring and thus reduce emissions. While the Group is a pioneer in flaring reduction measures in Kurdistan, having built the first gas capture and injection facilities in the region at the Tawke license, stricter policies or sanctions may increase the Group’s operational cost or preclude development of fields with high gas-oil-ratios.

In preparing these financial statements, management has considered the impact of climate-related risks by assessing the potential effects of stricter climate policies on its oil and gas portfolio. To assess the robustness of its oil and gas assets, the Company has run sensitivities with the oil and gas price assumptions described by scenarios outlined by the International Energy Agency (IEA), namely the Stated Policies Scenario, Announced Pledges Scenario and the Net Zero Emissions by 2050 Scenario (see Note 9).

In addition to the financial aspects mentioned above, climate change may represent a physical risk to personnel and facilities in the form of increased frequency and severity of extreme weather events.

Security Risk

Although some of our operations are in regions with security risks, we continuously work to manage these risks through clearly defined protocols and practices. Nevertheless, we are often dependent on the quality of the security and protection provided by authorities in 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 on the Group’s Code of Conduct to ensure regulatory and company expectations are met. The Company encourages its personnel to raise concerns about unethical or illegal behavior and breaches of DNO’s Code of Conduct or other Company policies. The Company also has a confidential Board of Directors’ report Annual Report and Accounts 2022 DNO 15 channel for those who wish to raise such matters in strict privacy or even anonymously.

Political Risk

Our portfolio is located in some countries where political, social and economic instability may adversely impact our business. Relevant political developments on both the federal and regional level in Iraq is closely observed by the Group. We continue to monitor security conditions although our operations to date have seen minimal impact from regional developments. The Company notes the implications for commodity prices and potential interruptions of supply chains and third-party services from the ongoing Russia-Ukraine conflict. DNO is monitoring international sanctions and trade control legislation to mitigate the potential impact on the Company’s operations.

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 2022:

• Our Total Recordable Injury Frequency (TRIF) was 1.44, compared to 0.48 in 2021.
• There were seven Lost Time Injuries during the year, compared to three in 2021.
• No Serious Vehicle Accident took place despite distances driven of 4.5 million kilometers.# Organization and Personnel

At yearend 2022, DNO had a workforce of 1,449 employees, of which 12 percent were women. A total of 60 individuals were based at the Company’s headquarters in Oslo and 1,391 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 48 nationalities represented. At yearend 2022, the Board of Directors consisted of four members, two of whom are women (50 percent). Executive management and other leading personnel consisted of three women (30 percent) and seven men. The Company is committed to maintain a working environment with equal opportunities for all based on qualifications, irrespective of gender, ethnicity, sexual orientation or disability. The Company has stepped up recruitment and promotion of women. At yearend 2022, women represented 37 percent of employees in managerial, administrative and other non-field operational positions. In the Erbil office, women represented 28 percent of all employees; the comparable figure was 22 percent in the Dubai office and 43 percent in the Oslo and Stavanger offices. There were no incidents of discrimination reported through the internal mechanisms for raising concern in 2022. Sickness absence in the Group in 2022 was 1.2 percent, compared to 1.4 percent in 2021.

Workforce Diversity in DNO Norway

In Norway, DNO had a workforce of 205 employees at yearend 2022, of which 43 percent were women. A total of four employees have worked part time during 2022, of which 50 percent were women. No employees in DNO work part time unless they have initiated or proposed it themselves. A total of 10 employees were on parental leave. Women had an average of 21.4 weeks of parental leave and men had an average of 10.8 weeks of parental leave. Salary mapping of 2022 average women’s salaries and bonuses compared to those of their male colleagues in the same job category is shown below in descending order of seniority for Norway-based employees:

	Base Salary	Bonus
Women's compensation as percentage of those of men's:
Level 1	-	-
Level 2	113%	92%
Level 3	102%	114%
Level 4	91%	91%
Level 5	92%	119%
All employees	72%	71%

Men and women with the same level of jobs, with equal professional experience and who perform equally well receive the same pay in DNO. The complexity of the job, discipline area and work experience affect the pay level of individual employees. Diversity is an important part of our key human resources processes such as recruitment, succession planning, promotions, performance management and employee development. In the first half of 2023, DNO plans to establish Diversity and Inclusion guidelines expressing the principles to be followed, with clear targets and a plan for action.

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 arranged meetings on a regular basis throughout the year. In the Board of Directors’ view, the working environment in DNO during 2022 was good as confirmed through WEC meetings and employee satisfaction surveys.

Leading Personnel Remuneration Policy

The 2022 remuneration of the Company’s executive management was based on the latest approved remuneration guidelines at the 2022 AGM, as published on the Company’s website.

Executive Management as of 15 March 2023

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

Chief Operating Officer
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.

GEIR ARNE SKAU

Director Human Resources and Corporate Services
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.

SAMEH HANNA

General Manager Kurdistan region of Iraq
Mr. Hanna joined DNO in 2022. He previously served as President of MI-SWACO worldwide and in various other operational and managerial roles at Schlumberger. Mr. Hanna holds a Bachelor of Science in Electronics from Ain Shams University, Cairo, and has completed management education programs at MIT Sloan, Lausanne School of Economics and Harvard University.

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.

Board of Directors’ report

Oslo, 15 March 2023

Bijan Mossavar-Rahmani Executive Chairman	Gunnar Hirsti Deputy Chairman	Elin Karfjell Director
Anita Marie Hjerkinn Aarnæs Director	Bjørn Dale Managing Director

Parent Company

The parent company, DNO ASA, reported a net profit of USD 342.5 million, up from USD 222.1 million in 2021. The net profit in 2022 was mainly driven by higher received dividends from subsidiaries. Total assets as of 31 December 2022 stood at USD 1,288.2 million, up from USD 1,224.4 million at yearend 2021. The increase in total assets was mainly due to a higher cash balance, partially offset by write-downs of the book value of shares in subsidiaries. The parent company’s cash balance at yearend 2022 was USD 641 million, up from USD 515 million at yearend 2021. Total liabilities decreased from USD 905.9 million at yearend 2021 to USD 647.4 million at yearend 2022 mainly due to repayments of bonds. Total equity at yearend 2022 was USD 640.8 million, up from USD 318.5 million in 2021. The equity ratio was 49.7 percent (26 percent at yearend 2021). Total dividend of USD 72.8 million was paid in 2022. In addition, a dividend of USD 25.3 million was accrued at yearend 2022 in the parent company accounts following board approval in February 2023. The Board of Directors will recommend that the shareholders approve the transfer of the net profit of USD 342.5 million to retained earnings at the forthcoming AGM.# Board of Directors’ report

Main events since yearend

After yearend 2022, DNO has received a total of USD 114.1 million from the KRG (net to DNO) towards DNO’s entitlement share of the August and September 2022 oil deliveries to the export market from the Tawke license and the Baeshiqa license. The payment received for September oil deliveries reflects a revised oil pricing formula proposed by the KRG in September (see notes 12 and 18) and resulted in a USD 5.2 million (net to DNO) lower payment compared to the invoices issued by DNO for the month.

On 10 January 2023, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 11 exploration licenses, of which one is an operatorship, under Norway's APA 2022 licensing round. Of the 11 new licenses, nine are in the North Sea and two in the Norwegian Sea.

On 9 February 2023, DNO confirmed an oil and gas discovery on the Røver Sør prospect in the Norwegian North Sea license PL923 in which the Company holds a 20 percent interest. The discovery well and a follow-on appraisal sidetrack encountered hydrocarbons in three Jurassic Brent Group sandstone reservoirs (Ness, Etive and Oseberg formations). Preliminary estimates of gross recoverable resources are in the range of 17-47 MMboe. The partners, which in addition to the Company’s wholly-owned subsidiary DNO Norge AS, include Equinor Energy AS (operator), Petoro AS and Wellesley Petroleum AS, consider the discovery to be commercial. Together with a string of recent discoveries in the area, Røver Sør may be tied back to the Equinor-operated Troll field about 10 kilometers to the east.

On 9 February 2023, the Company announced that pursuant to the authorization granted at the 2022 AGM, the Board of Directors has decided to distribute a dividend payment of NOK 0.25 per share. Payment of the dividend was made on 22 February 2023.

On 14 March 2023, DNO confirmed an oil and gas discovery on the Heisenberg prospect in the Norwegian North Sea license PL827S in which the Company holds a 49 percent interest. Preliminary estimates of gross recoverable resources are in the range of 24-84 million barrels of oil equivalent. A part of the discovery may extend into the adjacent PL248F license in which DNO holds a 20 percent interest. The PL827S partnership, which includes operator Equinor Energy AS (51 percent), considers the discovery commercially interesting as a potential tieback to the Troll field.

Board of Directors’ report

Responsibility statement

DNO ASA’s consolidated financial statements for the period 1 January to 31 December 2022 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 2022 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 2022 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, 15 March 2023

Bijan Mossavar-Rahmani
Executive Chairman

Gunnar Hirsti
Deputy Chairman

Elin Karfjell
Director

Anita Marie Hjerkinn Aarnæs
Director

Bjørn Dale
Managing Director

Board of Directors

Board of Directors’ report

Group company accounts

Consolidated statements of comprehensive income

1 January - 31 December USD million

	Note	2022	2021
Revenues	2, 3	1,377.0	1,004.1
Cost of goods sold	4	-460.9	-443.1
Gross profit		916.1	561.0
Share of profit/-loss from Joint Venture	10	6.0	-
Other income/-expenses		2.8	0.5
Administrative expenses	5	-17.9	-16.2
Other operating expenses	5	-7.7	-12.0
Impairment oil and gas assets	9	-371.3	-80.1
Exploration expenses	6	-96.5	-132.3
Operating profit/-loss		431.4	320.9
Financial income	7	13.8	26.0
Financial expenses	7	-98.7	-126.7
Profit/-loss before income tax		346.5	220.1
Tax income/-expense	8	38.4	-16.3
Net profit/-loss		384.9	203.9
Other comprehensive income
Currency translation differences		-31.6	-12.5
Items that may be reclassified to profit or loss in later periods, net of tax		-31.6	-12.5
Net fair value changes from financial instruments	11	14.2	3.6
Items that are not reclassified to profit or loss in later periods, net of tax		14.2	3.6
Total other comprehensive income, net of tax		-17.4	-8.9
Total comprehensive income, net of tax		367.5	195.0
Net profit/-loss attributable to:
Equity holders of the parent		384.9	203.9
Non-controlling interests		-	-
Total comprehensive income attributable to:
Equity holders of the parent		367.5	195.0
Non-controlling interests		-	-
Earnings per share, basic (USD per share)	20	0.39	0.21
Earnings per share, diluted (USD per share)	20	0.39	0.21
Weighted average number of shares outstanding (millions)		986.97	975.43

Consolidated statements of financial position

Years ended 31 December USD million

ASSETS	Note	2022	2021
Non-current assets
Deferred tax assets	8	-	29.3
Goodwill	9	56.1	88.2
Other intangible assets	9	97.2	232.4
Property, plant and equipment	9	1,108.6	1,284.9
Investment in Joint Venture	10	76.1	-
Financial investments	11	-	16.2
Other non-current receivables	12	-	19.4
Total non-current assets		1,338.1	1,670.4
Current assets
Inventories	4	47.0	35.8
Trade and other receivables	12	437.8	483.8
Tax receivables	8	25.8	21.1
Cash and cash equivalents	13	954.3	736.6
Total current assets		1,464.9	1,277.3
TOTAL ASSETS		2,803.0	2,947.8
EQUITY AND LIABILITIES
Equity
Shareholders' equity	14	1,369.4	1,018.8
Total equity		1,369.4	1,018.8
Non-current liabilities
Deferred tax liabilities	8	62.4	267.3
Interest-bearing liabilities	15	546.4	873.4
Provisions for other liabilities and charges	16	379.6	402.4
Total non-current liabilities		988.4	1,543.2
Current liabilities
Trade and other payables	17	244.1	232.6
Income taxes payable	8	125.7	33.1
Current interest-bearing liabilities	15	8.4	-
Provisions for other liabilities and charges	16	67.0	120.2
Total current liabilities		445.3	385.8
Total liabilities		1,433.6	1,929.0
TOTAL EQUITY AND LIABILITIES		2,803.0	2,947.8

Oslo, 15 March 2023

Bijan Mossavar-Rahmani
Executive Chairman

Gunnar Hirsti
Deputy Chairman

Elin Karfjell
Director

Anita Marie Hjerkinn Aarnæs
Director

Bjørn Dale
Managing Director

Consolidated cash flow statements

1 January - 31 December USD million

	Note	2022	2021
Operating activities
Profit/-loss before income tax		346.5	220.1
Adjustments to add/-deduct non-cash items:
Exploration cost previously capitalized carried to cost	6	52.2	54.1
Depreciation, depletion and amortization	4	216.7	206.0
Impairment oil and gas assets	9	371.3	80.1
Share of profit/-loss in Joint Venture	10	-6.0	-
Amortization of borrowing issue costs		5.2	9.4
Accretion expense on ARO provisions	7,16	15.5	17.7
Interest expense	7	57.5	74.2
Interest income	7	-12.9	-1.7
Other		11.0	1.0
Changes in working capital items and provisions:
- Inventories		-11.2	5.0
- Trade and other receivables	12	59.9	-99.5
- Trade and other payables	17	11.5	55.1
- Provisions for other liabilities and charges		5.9	3.8
Cash generated from operations		1,123.0	625.3
Income taxes paid		-5.1	-
Tax refund received/-repaid		-16.1	174.7
Interest received		12.5	1.7
Interest paid		-58.1	-73.0
Net cash from/-used in operating activities		1,056.3	728.8
Investing activities
Purchases of intangible assets		-74.6	-86.8
Purchases of tangible assets		-300.2	-193.8
Payments for decommissioning		-70.0	-86.2
Acquisition of subsidiary, net of cash acquired	10	21.5	-
Proceeds from license transactions		-	4.7
Proceeds from sale of financial investments		1.0	-
Equity contribution into Joint Venture	10	-4.2	-
Dividends from Joint Venture	10	11.5	-
Net cash from/-used in investing activities		-415.0	-362.0
Financing activities
Proceeds from borrowings	15	-	400.0
Repayment of borrowings	15	-323.7	-459.0
Payment of debt issue costs		-	-15.6
Purchase of treasury shares	14	-11.7	-
Paid dividend	14	-72.8	-22.2
## Annual Report and Accounts 2022

DNO 25

Payments of lease liabilities -10.8 -8.6
Net cash from/-used in financing activities -419.1 -105.4
Net increase/-decrease in cash and cash equivalents 222.3 261.5
Cash and cash equivalents at beginning of the period 736.6 477.1
Exchange gain/-losses on cash and cash equivalents -4.5 -2.0
Cash and cash equivalents at end of the period 13 954.3 736.6
Of which restricted cash 13 22.5 15.8

Consolidated statements of changes in equity

	Share capital	Share premium	Fair value changes equity instruments	Currency translation difference	Retained earnings	Total equity
Total shareholders' equity as of 31 December 2020	32.9	247.7	36.1	-65.0	593.9	845.6
Fair value changes from equity instruments	-	-	3.6	-	-	3.6
Currency translation differences	-	-	-	-12.5	-	-12.5
Other comprehensive income	-	-	3.6	-12.5	-	-8.9
Profit/-loss for the period	-	-	-	-	203.9	203.9
Total comprehensive income	-	-	3.6	-12.5	203.9	195.0
Share capital increase	-	-	-	-	-	-
Purchase of treasury shares	-	-	-	-	-	-
Payment of dividend	-	-	-	-	-21.8	-21.8
Transactions with shareholders	-	-	-	-	-21.8	-21.8
Total shareholders' equity as of 31 December 2021	32.9	247.7	39.7	-77.5	776.0	1,018.8

	Share capital	Share premium	Fair value changes equity instruments	Currency translation difference	Retained earnings	Total equity
Total shareholders' equity as of 31 December 2021	32.9	247.7	39.7	-77.5	776.0	1,018.8
Reallocation of equity*	-	-	-34.3	80.1	-45.8	-
Total shareholders' equity as of 1 January 2022	32.9	247.7	5.4	2.6	730.2	1,018.8
Fair value changes from equity instruments	-	-	14.2	-	-	14.2
Currency translation differences	-	-	-	-31.6	-	-31.6
Other comprehensive income	-	-	14.2	-31.6	-	-17.4
Profit/-loss for the period	-	-	-	-	384.9	384.9
Total comprehensive income	-	-	14.2	-31.6	384.9	367.5
Share capital increase**	1.8	95.9	-	-	-	97.7
Own shares retained as treasury shares from a transaction***	-0.6	-	-19.6	-	-10.2	-30.4
Purchase of treasury shares	-0.3	-	-	-	-12.1	-12.4
Payment of dividend	-	-	-	-	-72.0	-72.0
Transactions with shareholders	1.0	95.9	-19.6	-	-94.2	-17.0
Total shareholders' equity as of 31 December 2022	33.9	343.6	-	-29.0	1,020.9	1,369.4

• Reallocation of equity is related to a change in the presentation of other comprehensive income. Total equity is unchanged.
  ** See Note 10 for information and details.
  *** See Note 11 for details regarding fair value changes from equity instruments.

Consolidated accounts

Note 1 Summary of IFRS accounting principles

DNO 26

Annual Report and Accounts 2022

Consolidated accounts

Note 1 Summary of IFRS accounting principles

Annual Report and Accounts 2022

DNO 27

Principal activities and corporate information

The principal activities of the Group are international oil and gas exploration, development and production operations. 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, the North Sea and West Africa.

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 2022. The consolidated financial statements were approved by the Board of Directors on 15 March 2023.

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

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 covering at least 12 months from the end of the reporting period. 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. Following its review, the Board of Directors confirmed, 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.

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

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. In 2012, the Federal Government of Iraq (FGI) challenged the constitutional validity of the Kurdistan Oil and Gas Law No. 27/2007 (KOGL) and the right of the KRG to export oil independently of the FGI. The Company notes from public reports that on 15 February 2022, the Federal Supreme Court of Iraq (FSCI) ruled on this matter along with another related matter dating back to 2019. Reportedly, the FSCI found amongst other things that the KOGL is unconstitutional, that the KRG is to hand over all oil production from areas located in the KRI to the FGI and that the FGI has the right to pursue the nullity of the oil contracts concluded by the KRG. DNO was not a party to the legal proceedings. DNO has learned via media reports that on 4 July 2022, a commercial court in Baghdad ruled that PSCs signed between the KRG and four international oil companies including DNO should be voided.

Consolidated accounts

Note 1 Summary of IFRS accounting principles

28

DNO Annual Report and Accounts 2022

Likewise, DNO notes from media reports that on 21 August 2022, the KRG filed third party objections to the reported 4 July 2022 Baghdad rulings including those understood to concern DNO. These cases, along with other similar cases against international oil companies, are reported to be still pending. Furthermore and importantly, the KRG has issued repeated reassurances that the PSCs remain valid. The KRG has also initiated legal proceedings against FGI in Erbil courts and there have been several rulings in Erbil courts affirming the validity of the PSCs. DNO notes from public reports that there is increased dialogue between KRG and FGI on oil related matters, in particular following the 27 October 2022 federal parliamentary approval of a new federal government led by Prime Minister Mohammed Shia' Sabbar al-Sudani. Since then, DNO notes frequent media reports on regular KRG and FGI engagement to find a way forward, including by way of adopting a new federal oil and gas law.On 13 March 2023, it was announced that the KRG had received a USD 275.5 million payment from the FGI pursuant to an agreement between the parties, notwithstanding an FSCI ruling that deemed such payments by a previous government as “wrong”. It is unclear how and when the KRG and the FGI will permanently address these matters. At present, normal operations are maintained at the Tawke and Baeshiqa licenses. Due to disagreements between the FGI and the KRG, economic conditions in Kurdistan and limited oil export channels, DNO has historically 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 DNO’s 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 but notwithstanding sometimes lengthy delays, payments have ultimately been received by DNO. See Note 18 for more information. DNO also notes the ongoing arbitration case, commenced in 2014, by the FGI against the Turkish Government and its state- owned pipeline operator BOTAS relating to the Iraq-Turkey Pipeline. It is unclear if a ruling, when it comes, may have an impact on future transportation of Kurdish oil in said pipeline.

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. 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; political development; 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 technology. Decommissioning activities will normally take place in the distant future, and the technology, regulatory requirements and related costs may change. The energy transition may bring forward the decommissioning activities and thereby increasing the present value of associated decommissioning provisions. Based on various scenario analysis performed by the Company, management does not expect any reasonable change in the expected timeframe to have a material effect on the Group’s decommissioning provisions, assuming cost estimates (i.e., cash flows) remain unchanged. 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.

Consolidated accounts

Note 1 Summary of IFRS accounting principles

Annual Report and Accounts 2022 DNO 29

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 cash-generating 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. Goodwill is tested for impairment annually or more frequently when there are impairment indicators. 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 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.

Climate considerations in impairment assessment

Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group’s oil and gas assets, certain climate considerations are factored into the Group’s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in Norway and the UK (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company’s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS. In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Announced Pledges Scenario and the Stated Policies Scenario as published by the IEA.# Consolidated accounts Note 1 Summary of IFRS accounting principles

These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 9.

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 and 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.

A joint venture under IFRS 11, is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Those parties are called joint venturers. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

The Group’s investments in a joint venture are accounted for using the equity method. Under the equity method, the investment is initially recognized at cost. The carrying value of the investment is adjusted to recognize the Group’s share of the net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is neither amortized nor individually tested for impairment. The income statement reflects the Group’s share of the results of operations in the joint venture.

On acquisition of the investment, any difference between the cost of the investment and the Group’s share of the net fair value of the investee’s identifiable assets and liabilities is accounted for as:
* Goodwill relating to a joint venture and is included in the carrying amount of the investment; and any excess of the Group’s share of the net fair value of the joint venture’s profit or loss in the period in which the investment is acquired.

Appropriate adjustments to the Group’s share of the joint venture’s profit or loss after acquisition are made in order to account for, for example, for depreciation of the depreciable assets (and related deferred tax, if any) based on their fair values at the acquisition date. Any change in OCI of those investees is presented as part of the Group’s OCI. In addition, when there has been a change recognized directly in the equity of the joint venture, the Group recognizes its share of any changes, when applicable, in the statement of changes in equity. The aggregate of the Group’s share of profit or loss of a joint venture represents profit or loss after tax and non-controlling interests in the subsidiaries of the joint venture.

The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group (IFRS). The impact of reciprocal interests between the Group and its investees is eliminated before the Group accounts for its share; the Group also reduces its equity and investment balance by its effective interest in its own shares.

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.# Note 1 Summary of IFRS accounting principles

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 relating to 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 current 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 non-current liabilities 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.

Consolidated accounts

Note 1 Summary of IFRS accounting principles

32 DNO Annual Report and Accounts 2022

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. Pre-development 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 period- end 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

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. When DNO, as the operator of a license, is considered to have the primary responsibility for the full lease payments (e.g., a rig lease where the lease agreement is entered into DNO’s name as the operator of a license at the initial signing), the lease liability may be recognized on gross basis, rather than based on DNO’s working interest share. DNO then derecognizes a portion of the RoU asset corresponding to the non-operator’s interests in the license (presented under receivables). In the consolidated statements of comprehensive income, operating lease costs, relating to contracts that 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, rig and equipment. The Group also leases 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.# Consolidated accounts Note 1 Summary of IFRS accounting principles Annual Report and Accounts 2022 DNO 33

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 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. 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 18.

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.

Consolidated accounts Note 1 Summary of IFRS accounting principles 34 DNO Annual Report and Accounts 2022# Consolidated accounts

Note 1 Summary of IFRS accounting principles

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 short-term 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 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. In general, the 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. 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 was 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 for oil quality and transportation fees.

■ Production Sharing Contracts (PSC)
A PSC is an agreement between a contractor and a host government, whereby the contractor bears all of the risks and costs of exploration, and if successful, costs of development and production in return for a stipulated share of production from the discovery. 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 taxes. 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 re-assessed at each reporting date and are recognized to the extent that it has become probable that future taxable profits will allow the deferred tax asset to be recovered. Deferred tax assets and deferred tax liabilities are recognized irrespective of when the differences are reversed. They are recognized at their nominal value and classified as non-current assets/liabilities in the statements of financial position. Deferred tax assets and deferred tax liabilities are offset in the statements of financial position if there is a legal right to settle current tax amounts on a net basis and the deferred tax amounts are levied by the same taxing authority on the same entity or different entities that intend to realize the asset and settle the liability at the same time. Tax payable and deferred tax are recognized directly in the equity to the extent that they relate to items charged directly to equity. For treatment of tax in relation to business combinations, see the Business combinations section. DNO’s PSCs provide that the corporate income tax to which the contractor is subject is deemed to have been paid to the government as part of the payment of profit oil to the government or its representatives. For accounting purposes, if such notional income tax is to be classified as income tax in accordance with IAS 12 Income Taxes, the Group would present this as an income tax expense with a corresponding increase in revenues. Furthermore, it would be assessed whether any deferred tax asset or liability is required to be recognized equal to the difference between book values and the tax values of the qualifying assets and liabilities, multiplied by the applicable tax rate.

■ Business combinations
In accordance with IFRS 3 Business Combinations, an acquisition is considered a business combination, when the acquired asset or groups of assets constitute a business (i.e., an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred. For accounting purposes, the acquisition method is used in connection with the purchase of businesses. Acquisition cost equals the fair value of the assets used as consideration, including contingent consideration, equity instruments issued and liabilities assumed in connection with the transfer of control. Acquisition cost is measured against the fair value of the acquired assets and assumed liabilities. Identifiable intangible assets are included in connection with acquisitions if they can be separated from other assets or meet the legal contractual criteria. If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets (when the acquiring entity achieves control of the transferring entity), goodwill arises.# Consolidated accounts

Note 1 Summary of IFRS accounting principles

Annual Report and Accounts 2022 DNO 37

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. 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 taxes 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 farm- in/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 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, there 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 risk-adjusted 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 2022 but are not considered to have any material impact on the Group’s financial statements.# Consolidated accounts

Note 1 Summary of IFRS accounting principles

The Group identifies and reports its segments based on information provided to the executive management and the Board of Directors who are considered to collectively be the Chief Operating Decision Maker. 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 three operating segments: Kurdistan, the North Sea (which includes the Group’s oil and gas activities in Norway and the UK) and West Africa (which represents the Group’s equity accounted investment in Côte d'Ivoire, see Note 10). 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 can be found in page 87 of this report.

USD million

	Total Un- reporting allocated/ eliminated	Full-Year ending 31 December 2022	Kurdistan	North Sea	West Africa	Other segments	Total Group
COMPREHENSIVE INCOME INFORMATION
Revenues	3	820.1	556.9	-	-	1,377.0	-
Inter-segment sales		-	-	-	-	-	-
Production costs		-124.7	-127.7	-	-	-252.4	0.1
Movement in overlift/underlift		-	8.1	-	-	8.1	-
Depreciation, depletion and amortization		-126.8	-86.5	-	-	-213.3	-3.4
Cost of goods sold	4	-251.5	-206.1	-	-	-457.6	-3.3
Gross profit	568.5	350.8	-	-	919.4	-3.3	916.1
Share of profit/-loss from Joint Venture	10	-	-	6.0	-	6.0	-
Other income		-	2.8	-	-	2.8	-
Administrative expenses	5	-0.1	-6.0	-	-2.3	-8.4	-9.5
Other operating expenses	5	-0.9	-	-	-6.8	-7.7	-
Impairment of oil and gas assets	9	-	-371.3	-	-	-371.3	-
Exploration expenses	6	-	-96.5	-	-	-96.5	-
Operating profit/-loss	567.6	-120.2	6.0	-9.1	444.2	-12.8	431.4
Net financial income/-expense	7	10.4	-32.7	0.1	0.5	-21.6	-64.4
Tax income/-expense	8	-	38.4	-	-	38.4	-
Net profit/-loss	578.0	-114.5	6.1	-8.6	461.1	-77.1	384.9
FINANCIAL POSITION INFORMATION
Non-current assets		750.2	503.5	76.1	-	1,329.8	8.3
Current assets		355.4	418.3	-	11.5	785.3	679.7
Total assets		1,105.5	921.8	76.1	11.5	2,115.0	688.0
Non-current liabilities		68.1	391.8	-	-	459.9	528.4
Current liabilities		97.5	284.3	-	41.6	423.4	21.9
Total liabilities		165.6	676.1	-	41.6	883.3	550.3

Consolidated accounts

Note 1 Summary of IFRS accounting principles

USD million

	Total Un- reporting allocated/ eliminated	Full-Year ending 31 December 2021	Kurdistan	North Sea	West Africa	Other segments	Total Group
COMPREHENSIVE INCOME INFORMATION
Revenues	3	594.3	409.8	-	-	1,004.1	-
Inter-segment sales		-	2.6	-	-	2.6	-2.6
Production costs		-99.6	-119.5	-	-	-219.1	0.3
Movement in overlift/underlift		-	-18.3	-	-	-18.3	-
Depreciation, depletion and amortization		-121.2	-81.7	-	-	-202.9	-3.1
Cost of goods sold	4	-220.9	-219.4	-	-	-440.3	-2.7
Gross profit	373.4	193.0	-	-	566.4	-5.4	561.0
Share of profit/-loss from Joint Venture	10	-	-	-	-	-	-
Other income		-	-	-	-	0.5	-
Administrative expenses	5	-0.3	-8.5	-	-1.8	-10.6	-5.6
Other operating expenses	5	-2.2	-	-	-9.8	-12.0	-
Impairment of oil and gas assets	9	-	-80.1	-	-	-80.1	-
Exploration expenses	6	-2.8	-129.6	-	-	-132.3	-
Operating profit/-loss	368.1	-24.8	-	-11.6	331.8	-11.0	320.9
Net financial income/-expense	7	22.7	-35.7	-	1.0	-12.0	-88.8
Tax income/-expense	8	-	-15.9	-	-0.3	-16.3	-
Net profit/-loss	390.8	-76.4	-	-10.9	303.5	-99.7	203.9
FINANCIAL POSITION INFORMATION
Non-current assets		679.8	964.1	-	-	1,643.9	26.6
Current assets		372.2	367.1	-	11.5	750.8	526.5
Total assets		1,052.0	1,331.2	-	11.5	2,394.7	553.1
Non-current liabilities		63.2	691.2	-	-	754.4	788.8
Current liabilities		78.0	248.5	-	36.3	362.8	23.0
Total liabilities		141.2	939.8	-	36.3	1,117.2	811.7

Consolidated accounts

Note 3 Revenues

1 January - 31 December

USD million	2022	2021	Kurdistan	North Sea	Total
	2022	2021	2022	2021	2022
Sale of oil	820.1	594.3	241.0	233.8	1,061.1
Sale of gas	-	-	281.1	151.3	281.1
Sale of natural gas liquids (NGL)	-	-	29.1	21.3	29.1
Tariff income	-	-	5.8	3.4	5.8
Total revenues from contracts with customers	820.1	594.3	556.9	409.8	1,377.0
Sale of oil (bopd)	25,933	28,091	6,341	8,493	32,273
Sale of gas (boepd)	-	-	4,800	4,344	4,800
Sale of natural gas liquids (NGL) (boepd)	-	-	1,370	1,244	1,370
Total sales volume (boepd)	25,933	28,091	12,511	14,080	38,444

Note 4 Cost of goods sold/Inventory

1 January - 31 December

USD million	2022	2021
Lifting costs	-222.1	-184.2
Tariff and transportation expenses	-30.2	-34.5
Production costs based on produced volumes	-252.3	-218.8
Movement in overlift/underlift	8.1	-18.3
Production costs based on sold volumes	-244.2	-237.0
Depreciation, depletion and amortization	-216.7	-206.0
Total cost of goods sold	-460.9	-443.1

Lifting costs consist of expenses related to the production of oil and gas, including operation and maintenance of installations, well intervention activities and insurances. The lifting costs in 2022 included a provision for obsolete inventory of USD 2.9 million related to North Sea (2021 lifting costs included a reversal of provision for obsolete inventory of USD 1 million related to Kurdistan). 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	2022	2021
Spare parts	47.0	35.8
Total inventory	47.0	35.8

Total inventory of USD 47 million at yearend 2022 was related to Kurdistan (USD 33.7 million) and the North Sea (USD 13.3 million).

Consolidated accounts

Note 5 Administrative/Other expenses

1 January - 31 December

USD million	2022	2021
Salaries, bonuses, etc.	-55.2	-56.2
Employer's payroll tax expenses	-5.1	-5.4
Pensions	-4.1	-3.8
Other personnel costs	-5.8	-4.2
General and administration expenses	-32.5	-42.3
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets	84.8	95.5
Total administrative expenses	-17.9	-16.2
Other expenses	-7.7	-12.0
Total other operating expenses	-7.7	-12.0

Salaries and social expenses directly attributable to license activities are reclassified to lifting costs and exploration costs, or tangible assets and capitalized exploration. Other expenses in 2022 were mainly related to provisions in Yemen, see Note 19. DNO has a defined contribution scheme for its Norway-based employees, with USD 4.1 million expensed in 2022 (USD 3.8 million in 2021). The Group’s obligations are limited to the annual pension contributions. DNO meets the Norwegian legal requirements for mandatory occupational pension (“obligatorisk tjenestepensjon”). At yearend 2022, the Company’s liability for synthetic shares as part of other variable remuneration amounted to USD 5.4 million (USD 2.2 million at yearend 2021). 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	2022	2021
Outstanding as of 1 January	3,178,536	2,837,151
Granted during the year	9,471,309	1,321,431
Forfeited/reversed during the year	37,099	71,374
Settled during the year	1,159,108	908,672
Outstanding as of 31 December	11,453,638	3,178,536
Unrestricted as of 31 December	834,872	462,214
Weighted average remaining contractual life for the synthetic shares (years)	2.43	2.78
Weighted average settlement price for synthetic shares settled during the year (NOK)	12.56	10.83
Settlement price for synthetic shares at the end of the year (NOK)	11.81	10.46

Remuneration to Board of Directors and executive management

1 January - 31 December

USD million	2022	2021
Managing Director
Salary	-0.64	-0.69
Bonus	-0.26	-0.08
Pension	-0.02	-0.02
Other remuneration	-0.17	-0.07
Remuneration to Managing Director	-1.09	-0.85
Other executive management
Salary	-1.99	-3.24
Bonus	-0.15	-0.70
Pension	-0.08	-0.13
Other remuneration	-0.59	-0.55
Remuneration to other executive management	-2.81	-4.63
Total remuneration to executive management	-3.90	-5.48
Number of managers included	6	8
Total remuneration to Board of Directors	-1.17	-1.10
Total remuneration to Board of Directors and executive management	-5.07	-6.58

Total remuneration of USD 2.4 million (not included in the above table) was paid in 2022 to Nicholas Whiteley and Tom Allan, former members of the executive management. For further details on remuneration to the executive management, see Note 3 in the parent company accounts.Shares and options held by Board of Directors and executive management
Years ended 31 December 2022 2021
Directors and executive management | Shares | Options | Shares | Options
---|---|---|---|---
Bijan Mossavar-Rahmani, Executive Chairman* | 125,683,241 | - | - | -
Gunnar Hirsti, Deputy Chairman (Hirsti Invest AS) | 350,000 | - | 350,000 | -
Elin Karfjell, Director (Elika AS) | 33,000 | - | 33,000 | -
Anita Marie Hjerkinn Aarnæs, Director | - | - | - | -
Bjørn Dale, Managing Director | - | - | - | -
Chris Spencer, Chief Operating Officer (Chris's Corporation AS) | 32,000 | - | 32,000 | -
Haakon Sandborg, Chief Financial Officer | - | - | - | -
Geir Arne Skau, Chief Human Resources and Corporate Services Officer | 35,750 | - | 25,750 | -
Sameh Hanna, General Manager Kurdistan region of Iraq | - | - | - | -
Ørjan Gjerde, General Manager DNO North Sea (Kvile Invest AS) | 15,000 | - | 15,000 | -

• At yearend 2022, Bijan Mossavar-Rahmani held interests in the Company through a nominee account held by Goldman Sachs & Co. LLC. At yearend 2021, Mr. Mossavar- Rahmani held indirect interest in the Company through his shareholdings in RAK Petroleum plc (see also Note 11 for more details). 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)
| | 2022 | 2021 |
---|---|---|
| Auditor fees | -0.71 | -0.84 |
| Other financial auditing | -0.04 | -0.04 |
| Tax advisory services | -0.08 | -0.10 |
| Other advisory services | - | - |
| Total auditor fees | -0.82 | -0.98 |

Consolidated accounts

Note 6 Exploration expenses

Annual Report and Accounts 2022 DNO 43
1 January - 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Exploration expenses (G&G and field surveys) | -10.2 | -19.1 |
| Seismic costs | -18.5 | -37.6 |
| Exploration expenses capitalized in previous years carried to cost | -3.9 | -13.4 |
| Exploration expenses capitalized during the year carried to cost | -48.3 | -40.7 |
| Other exploration expenses | -15.6 | -21.5 |
| Total exploration expenses | -96.5 | -132.3 |

Exploration expenses in 2022 were related to exploration activities in the North Sea, including expensing of exploration wells (Edinburgh, Overly and Uer wells) and seismic purchase. Exploration expenses in 2021 were related to exploration activities in the North Sea, including expensing of exploration wells (Black Vulture, Gomez and Mugnetind wells) and seismic purchase.

Note 7 Financial income and financial expenses

1 January - 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Interest income | 12.9 | 1.7 |
| Other financial income | 1.0 | 24.3 |
| Currency exchange gains recognized in the income statement (net) | - | - |
| Financial income | 13.9 | 26.0 |
| Interest expenses | -57.5 | -74.2 |
| Currency exchange loss recognized in the income statement (net) | -6.6 | -5.8 |
| Other financial expenses | -34.8 | -46.8 |
| Financial expenses | -98.9 | -126.7 |
| Net financial income/-expenses | -85.0 | -100.7 |

Other financial expenses in 2022 were mainly related to the accretion expenses (i.e., unwinding of discount related to the ARO provisions and lease liabilities, see Note 16), amortization of borrowing issue costs and incurred put option premium. Other financial expenses and other financial income in 2021 also included accounting effects from IFRS 9 assessments related to the Tawke license arrears from 2020 and 2021 entitlement and override invoices (presented gross).

Consolidated accounts

Note 8 Income taxes

44 DNO Annual Report and Accounts 2022
1 January - 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Changes in deferred taxes | 162.9 | -115.2 |
| Income taxes receivable/-payable | -124.5 | 98.9 |
| Total tax income/-expense | 38.4 | -16.3 |

Income tax receivable/-payable
Years ended 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Tax receivables | 25.8 | 21.1 |
| Income taxes payable | -125.7 | -33.1 |
| Net tax receivable/-payable | -99.9 | -11.9 |

The tax balances relate to the activity on the Norwegian Continental Shelf (NCS) and the UK Continental Shelf (UKCS). The current tax receivable relates to tax refunds of decommissioning spend on the UKCS expected to be received during the third quarter of 2023. The current income taxes payable relates to taxable profits in 2022 on the NCS and will be paid during first half of 2023. In June 2022, the Norwegian Parliament approved certain changes to the taxation of oil and gas companies operating on the NCS, effective from 1 January 2022. The companies can expense investments immediately in the special tax basis and receive a cash refund of the tax value of losses in the special tax basis. The uplift on investments is discontinued but will apply to the investments covered by the temporary changes, as approved by the parliament in June 2020. The ordinary corporate tax is deductible in the special tax basis and to maintain a combined marginal tax rate of 78 percent, the special tax rate is increased to 71.8 percent. Losses in the corporate tax basis are not eligible for refund but can be carried forward. The tax value of unused uplift and carried forward losses as of yearend 2021 will be paid out in connection with the 2022 tax assessment in November 2023 or offset tax installments on 2022 taxable profits. In December 2022, the Norwegian Parliament approved a change to the uplift under the temporary tax rules applying to PDOs delivered by the end of 2022, from 17.69 percent to 12.4 percent, effective from 1 January 2023. The change to the uplift adversely impacts the economics of development projects under the temporary rules. During 2022, DNO received tax refunds of USD 17.7 million in the UK in relation to decommissioning spend for 2021. In Norway, DNO paid net USD 38.9 million which consisted of repayment of refunds received during the second half of 2021 and the first three tax installments on 2022 taxable profits.

Reconciliation of tax income/-expense
1 January - 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Profit/-loss before income tax | 346.5 | 220.1 |
| Expected income tax according to nominal tax rate in Norway, 22 percent | -108.1 | -52.4 |
| Expected income tax according to nominal petroleum tax rate in Norway, 78 percent | 43.3 | 24.3 |
| Expected income tax according to nominal tax outside Norway | 33.5 | 7.4 |
| Foreign exchange variations between functional and tax currency | 2.5 | -4.5 |
| Adjustment of previous years | 0.7 | 0.2 |
| Adjustment of deferred tax assets not recognized | -62.3 | -31.0 |
| Other items including other permanent differences | 116.2 | 35.3 |
| Change in tax rate | 12.4 | 4.6 |
| Tax income/-expense | 38.4 | -16.3 |
| Effective income tax rate | -11.1% | -7.4% |

Taxes charged to equity
| | 2022 | 2021 |
---|---|---|
| | - | - |

Consolidated accounts

Note 8 Income taxes

Annual Report and Accounts 2022 DNO 45
Expected income tax related to activities on the NCS and outside Norway is positive as the petroleum activities in Norway and the UK generated a loss before tax. Other items above consist mainly of permanent differences on impairments which are 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.

Tax effects on temporary differences
Years ended 31 December USD million
| | 2022 | 2021 |
---|---|---|
| Tangible assets | -195.8 | -351.5 |
| Intangible assets (including capitalized exploration expenses) | -76.9 | -168.0 |
| ARO provisions | 226.2 | 266.6 |
| Losses carried forward | 167.6 | 155.5 |
| Non-deductible interests carried forward | 26.5 | 29.4 |
| Other temporary differences | -0.9 | -8.1 |
| Net deferred tax assets/-liabilities | 146.8 | -76.0 |
| Valuation allowance | -209.1 | -162.0 |
| Net deferred tax assets/-liabilities | -62.4 | -238.0 |
| Recognized deferred tax assets | - | 29.3 |
| Recognized deferred tax liabilities | -62.4 | -267.3 |

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. 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. 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). In the UK, the tax rate in the ordinary tax regime will increase to 25 percent from April 2023. Additionally, in May 2022 the Energy Profits Levy (EPL) was introduced which is a new 25 percent temporary levy on oil and gas ring fence profits, adjusted for decommissioning spend. The rate will increase to 35 percent from 1 January 2023. EPL did not affect the 2022 results as the UK companies were loss-making. The changes in tax rates have not had any impact as deferred tax asset has not been recognized on carried forward losses and temporary differences in the UK.## Consolidated accounts Note 9 Property, plant and equipment

Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December USD million
| | 2022 | 2021 |
|---|---|---|
| Net deferred tax assets/-liabilities at 1 January | -238.0 | -131.4 |
| Change in deferred taxes in the income statement | 162.9 | -115.2 |
| Reclassification from/-to tax receivable | -15.3 | - |
| Currency and other movements | 28.0 | 8.6 |
| Net deferred tax assets/-liabilities at 31 December | -62.4 | -238.0 |

Reconciliation of change in tax receivable/-payable
Years ended 31 December USD million
| | 2022 | 2021 |
|---|---|---|
| Net tax receivable/-payable at 1 January | -11.9 | 63.1 |
| Tax receivable/-payable related to transactions posted directly to balance sheet | 0.9 | 3.7 |
| Tax receivable/-payable in the income statement | -124.5 | 98.9 |
| Tax payment/-refund | 21.2 | -174.7 |
| Prior period adjustment | -0.5 | - |
| Reclassification to/-from deferred tax asset | 15.3 | - |
| Currency and other movements | -0.4 | -3.0 |
| Net tax receivable/-payable at 31 December | -99.9 | -11.9 |

Consolidated accounts Note 9 Property, plant and equipment

PROPERTY, PLANT AND EQUIPMENT

2022 - USD million	Total assets	Development assets	Production oil & gas assets	Other PP&E assets	RoU assets	Total
As of 1 January 2022
Acquisition costs	290.3	2,785.1	3,075.4	13.9	34.6	3,123.9
Accumulated impairments	-42.1	-89.6	-131.7	-0.1	-	-131.8
Accumulated depreciation	-	-1,680.4	-1,680.4	-12.8	-14.1	-1,707.2
Net book amount	248.2	1,015.1	1,263.3	1.0	20.5	1,284.9
Period ended 31 December 2022
Opening net book amount	248.2	1,015.1	1,263.3	1.0	20.5	1,284.9
Translation differences	-19.0	-47.0	-66.0	-0.1	-1.2	-67.2
Additions*	49.4	275.8	325.2	0.9	1.8	327.9
Transfers**	38.1	94.5	132.6	-	-	132.6
Disposals acquisition costs	-	4.6	4.6	-	0.4	5.0
Disposals depreciation/impairments	-	-4.6	-4.6	-	-0.2	-4.8
Depreciation of RoU recognized against ARO	-	-	-	-	-6.7	-6.7
Impairments (net)	-99.0	-250.1	-349.1	-	-	-349.1
Depreciation	-	-209.3	-209.3	-0.7	-3.7	-213.8
Closing net book amount	217.7	879.1	1,096.8	1.1	10.6	1,108.6
As of 31 December 2022
Acquisition costs	358.3	3,072.1	3,430.5	14.3	34.2	3,479.0
Accumulated impairments	-140.6	-332.0	-472.7	-0.1	-	-472.7
Accumulated depreciation	-	-1,861.0	-1,861.0	-13.1	-23.3	-1,897.4
Net book amount	217.7	879.1	1,096.8	1.1	10.6	1,108.6

Depreciation method UoP Linear (2-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Brasse license from exploration phase (intangible assets) to development phase (tangible assets) and reclassification of the book value of Baeshiqa license from development phase to production phase.
Depreciation, depletion and amortization (DD&A) is charged to cost of goods sold in the statements of comprehensive income.

INTANGIBLE ASSETS

2022 - USD million	Total Goodwill	License interest	Exploration assets	Other intangible assets	Total
As of 1 January 2022
Acquisition costs	456.8	98.1	368.4	14.6	481.1
Accumulated impairments	-368.6	-8.7	-161.3	-	-170.0
Accumulated depreciation	-	-68.2	-	-10.5	-78.7
Net book amount	88.2	21.2	207.1	4.1	232.4
Period ended 31 December 2022
Opening net book amount	88.2	21.2	207.1	4.1	232.4
Translation differences	-10.4	-1.0	-21.0	-	-22.0
Additions	-	0.4	73.5	0.7	74.6
Transfers*	-	-	-132.6	-	-132.6
Disposals cost price	-	-	-	-	-
Disposals impairments/depreciation	-	-	-	-	-
Exploration cost previously capitalized carried to cost	-	-	-52.2	-	-52.2
Impairments	-21.5	0.0	-0.0	-	0.0
Depreciation	-	-1.9	-	-1.1	-3.0
Closing net book amount	56.1	18.8	74.8	3.8	97.2
As of 31 December 2022
Acquisition costs	407.2	97.5	335.2	15.4	448.1
Accumulated impairments/exploration write-offs	-351.1	-8.8	-260.5	-	-269.3
Accumulated depreciation	-	-70.1	-	-11.6	-81.6
Net book amount	56.1	18.7	74.8	3.8	97.2

Depreciation method UoP Linear (3-7 years)
* Transfers was related to reclassification of the book value of Brasse license from exploration phase (intangible assets) to development phase (tangible assets).

PROPERTY, PLANT AND EQUIPMENT

2021 - USD million	Total assets	Development assets	Production oil & gas assets	Other PP&E assets	RoU assets	Total
As of 1 January 2021
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	-	-1,632.3	-1,632.3	-11.7	-6.7	-1,650.6
Net book amount	109.9	1,046.1	1,155.9	2.0	16.2	1,174.1
Period ended 31 December 2021
Opening net book amount	109.9	1,046.1	1,155.9	2.0	16.2	1,174.1
Translation differences	-3.0	-15.8	-18.8	-	-1.7	-20.6
Additions*	15.5	190.6	206.2	0.2	14.6	221.0
Transfers**	125.7	4.0	129.7	-	-	129.7
Disposal cost price	-	-440.4	-440.4	-	-2.6	-443.0
Disposal impairments/depreciations	-	440.4	440.4	-	2.6	443.0
Depreciation of RoU recognized against ARO	-	-	-	-	-4.6	-4.6
Impairments	-	-11.6	-11.6	-	-	-11.6
Depreciation	-	-198.2	-198.2	-1.1	-3.9	-203.2
Closing net book amount	248.2	1,015.2	1,263.3	1.0	20.6	1,284.9
As of 31 December 2021
Acquisition costs	290.3	2,785.1	3,075.4	13.9	34.6	3,123.9
Accumulated impairments	-42.1	-89.6	-131.7	-0.1	-	-131.8
Accumulated depreciation	-	-1,680.4	-1,680.4	-12.8	-14.1	-1,707.2
Net book amount	248.2	1,015.2	1,263.3	1.0	20.6	1,284.9

Depreciation method UoP Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers was related to reclassification of the book value of Baeshiqa license from exploration phase (intangible assets) to development phase (tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).

INTANGIBLE ASSETS

2021 - USD million	Total Goodwill	License interest	Exploration assets	Other intangible assets	Total
As of 1 January 2021
Acquisition costs	474.3	97.1	389.2	14.3	500.5
Accumulated impairments/exploration write-offs	-312.3	-7.7	-108.3	-	-116.0
Accumulated depreciation	-	-66.4	-	-9.5	-75.9
Net book amount	162.0	23.0	280.9	4.7	308.6
Period ended 31 December 2021
Opening net book amount	162.0	23.0	280.9	4.7	308.6
Translation differences	-5.3	-	-9.6	0.2	-9.4
Additions	-	1.0	85.3	0.4	86.7
Additions through license acquisition*	-	35.2	-	-	35.2
Transfers**	-	-	-125.7	-	-125.7
Disposal cost price	-	-	-6.0	-0.3	-6.3
Disposal impairments/depreciations	-	-	-	-	-
Exploration cost previously capitalized carried to cost	-	-1.1	-53.0	-	-54.1
Impairments	-68.5	-	-	-	-
Depreciation	-	-1.8	-	-1.0	-2.8
Closing net book amount	88.2	21.1	207.1	4.0	232.3
As of 31 December 2021
Acquisition costs	456.8	98.1	368.4	14.6	481.2
Accumulated impairments/exploration write-offs	-368.6	-8.7	-161.3	-	-170.0
Accumulated depreciation	-	-68.2	-	-10.5	-78.7
Net book amount	88.2	21.2	207.1	4.0	232.4

Depreciation method UoP Linear (3-7 years)
* Addition through license acquisition was related to DNO's acquisition of ExxonMobil's remaining 32 percent interest in the Baeshiqa license, approved by the KRG in August 2021.
** Transfers was related to reclassification of the book value of Baeshiqa license from exploration phase (intangible assets) to development phase (tangible assets) and reclassification of the book value of Berling (previously named Iris/Hades).

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 Petroleum Plc, the impairment assessment is 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 2022.

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.# Consolidated accounts

Note 9 Property, plant and equipment

The nominal oil and gas price assumptions applied for impairment assessments at yearend 2022 were as follows (yearend 2021 in brackets):

	2023	2024	2025	2026
Brent (USD/bbl)	86.6 (76.9)	88.5 (70.4)	85.0 (68.3)	78.4 (70.0)
NBP (pence/therm)	289.0 (158.3)	179.4 (77.4)	126.4 (65.5)	102.9 (57.6)

For periods after year 2026, the long-term oil and gas price assumptions applied were USD 65 per barrel and 72 pence sterling per therm, respectively (in real terms, basis year 2022).

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.
• 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 2022 was 16.1 percent (13.6 percent at yearend 2021) for the Kurdistan assets. For the fair value calculations, the relevant post-tax nominal discount rates at yearend 2022 was 8.4 percent for the North Sea assets (7.7 percent at yearend 2021).

Inflation and currency rates

The long-term inflation rate is assumed to be 2 percent independent of the underlying country or currency (unchanged from yearend 2021). DNO has applied the forward curve and observable broker and analyst consensus as basis for assessment of currency rates. The USD/NOK applied for impairment testing at yearend 2022, was USD/NOK 9.5 for the years 2023 and 2024 and thereafter kept constant at USD/NOK 9.0 from the year 2025 onwards.

Impairment charge and reversal

The following table shows the recoverable amounts and net impairment charges or reversal for the CGUs which were impaired in 2022 and 2021, and how it was recognized in the income statement and the balance sheet.

Full-Year ended 31 December 2022

Income statement: (in USD million)	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax -charge/ -expense (post-tax)	Other Property, plant and equipment	Balance sheet: Impairment -charge/ reversal (post-tax)	Deferred tax asset/ -liability	Currency effects
CGU, segment				Goodwill	Intangible assets
Brasse, North Sea	-	-147.0	108.1	-38.9	-8.5	-	-138.5
Berling, North Sea	28.0	39.4	-30.7	8.7	-	-	39.4
Ula area, North Sea	-	-252.5	182.1	-70.4	-13.0	-	-238.8
Schooner and Ketch, North Sea	-	-13.5	-	-13.5	-	-	-13.4
Other CGUs, North Sea	-	2.2	-1.4	0.8	-	-	2.2
Total	-	-371.3	258.2	-113.1	-21.5	-	-349.1

Full-Year ended 31 December 2021

Income statement: (in USD million)	Recoverable amount (post-tax)	Impairment -charge/ reversal (pre-tax)	Tax -charge/ -expense (post-tax)	Other Property, plant and equipment	Balance sheet: Impairment -charge/ reversal (post-tax)	Deferred tax asset/ -liability	Currency effects
CGU, segment				Goodwill	Intangible assets
Fenja, North Sea	54.0	-9.7	-9.7	-9.7	-	-	-
Trym area, North Sea	9.0	-7.7	-7.7	-7.7	-	-	-
Ula area, North Sea	158.0	-51.1	-51.1	-51.1	-	-	-
Oselvar, North Sea	-	1.5	-1.2	0.3	-	-	1.5
Schooner and Ketch, North Sea	-	-11.2	4.1	-7.1	-	-	-11.2
Other CGUs, North Sea	-	-1.9	-	-1.9	-	-	-1.9
Total	-	-80.1	2.9	-77.2	-68.5	-	-11.6

During 2022, a total impairment charge of USD 371.3 million (USD 113.1 million post-tax) was recognized, mainly driven by:

• Decision not to submit a PDO by yearend 2022 (Brasse pre-development asset);
• Revised reserves and resource estimates, and cost profiles (Ula area CGU);
• Revision in the cost estimate for decommissioning (Schooner and Ketch fields and other CGUs); and
• Partially offset by a reversal of previously recognized impairments following decision to submit a PDO and revised long-term gas price assumption (Berling development asset).

During 2021, a total impairment charge of USD 80.1 million (USD 77.2 million post-tax) was recognized, mainly driven by:

• Revised reserves and resource estimates (Fenja development);
• Revised reserves and resource estimates, and cost profiles (Ula area CGU, Trym area CGU); and
• Revision in the cost estimate for decommissioning (Schooner and Ketch fields, Oselvar field, and other CGUs).

Sensitivities

The table below illustrates how the net profit/-loss in 2022 would have been affected by changes in the various assumptions, holding the remaining assumptions unchanged. The estimated recoverable amounts related to the Tawke license in Kurdistan is substantially higher than the carrying amounts and the same sensitivity tests would not imply any impairment charges.

Assumption	Change	Reported net profit/-loss (net) (USD million)
Oil and gas price (2P)	+/- 15%	-
Reserves (2P) and resources (2C)	+/- 5%	-
Discount rate (WACC)	+/- 1%	-
Currency rate (USD/NOK)	+/- 1.0 NOK	-

Change

• Increase in assumption: -
• Decrease in assumption:

Climate considerations in impairment assessment

Certain climate considerations are factored into the Group’s estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. For DNO’s oil and gas assets on the NCS, carbon pricing is in line with current legislation and reflects the operator’s forecasts for individual assets. As proposed in the Norwegian Government’s Climate Plan for 2021-2030, a steady increase in the total carbon price (quota plus CO 2 tax) to NOK 2,000 per tonne (in 2020 real terms) is expected by 2030. In Kurdistan, the KRG introduced in 2021 a requirement for oil companies to put plans in place to curb gas flaring to reduce emissions. The Company has run sensitivities for its Kurdistan oil assets with the CO2 tax assumptions as described in the scenarios described by the International Energy Agency (IEA). An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company’s oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would only lead to limited impairment reversals as most of the impairments recognized by the Group were related to impairment of goodwill which cannot be reversed under IFRS. To assess the robustness of the Group’s oil and gas assets, the Company has run sensitivities with the oil and gas price assumptions described by scenarios outlined by the IEA, namely the Net Zero Emissions Scenario by 2050, Announced Pledges Scenario and the Stated Policies Scenario. These scenarios are commonly applied by peer companies and the Company believes that these are useful for investors and other stakeholders in assessing portfolio resilience across companies in the industry. The oil and gas price assumptions in the scenarios have been provided by the IEA for the years 2030 and 2050 (in 2021 real terms), and for the sensitivity calculation a linear development between average actual 2022 and 2030, as well as between 2030 and 2050 have been applied.

The table below summarizes how the reported net profit would be impacted by an increase (+) or decrease (-) in impairment charge using the oil and gas price assumptions in the following scenarios:

IEA scenario	Oil price USD/bbl (assumption)	Gas price USD/MMBTU (assumption)	Change in reported net profit/-loss (net) (USD million)
	2030	2050	2030
Announced Pledges	64	60	7.9
Net Zero Emissions by 2050	35	24	4.6

These illustrative impairment sensitivities assume no changes to assumptions other than oil and gas prices. The illustrative sensitivities on climate change are not considered to represent a best estimate of an expected impairment impact.# Consolidated accounts

Note 10 Joint Venture

52 DNO Annual Report and Accounts 2022

Acquisition of Mondoil Enterprises LLC

On 11 October 2022, the Company completed the transaction with RAK Petroleum plc (RAK Petroleum) for transferring shares in Mondoil Enterprises LLC (Mondoil Enterprises) to DNO ASA (see also Note 11). The transaction was entered on 22 August 2022 with effective date 1 January 2022 and the Company issued 78.94 million new shares to RAK Petroleum as consideration (consideration shares).

Following transaction completion, the Company holds 100 percent of the shares in Mondoil Enterprises. Mondoil Enterprises owns 50 percent of Mondoil Côte d’Ivoire LLC (Mondoil Côte d’Ivoire), which, in turn, owns 66.66 percent in the privately-held Foxtrot International LDC (Foxtrot International), resulting in the Company’s indirect 33.33 percent interest in Foxtrot International. Foxtrot International holds a 27.27 percent interest in and operatorship of Block CI-27 offshore Côte d’Ivoire, which contains the Foxtrot gas field, the Mahi gas field, the Marlin oil and gas field and the Manta gas field. Foxtrot International also operates an exploration license offshore Côte d’Ivoire, Block CI-12, in which it holds a 24 percent interest.

The acquisition date for accounting purposes corresponds to the completion of the transaction on 11 October 2022. A purchase price allocation (PPA) has been performed to allocate the value of consideration shares to fair value of assets acquired and liabilities assumed. The PPA was performed as of the completion date, 11 October 2022. The 11 October closing share price at Oslo Stock Exchange (NOK 13.27/USD 1.24) and the closing currency exchange rate (USD/NOK 10.7205) were used as a basis for measuring the value of the consideration shares, as set forth below.

The following table summarizes the PPA and acquisition cost as recorded as at transaction completion date:

Purchase price allocation (PPA)	As at transaction completion date	USD million
Consideration shares	78,943,763
Share price at closing date (USD/share)	1.24
Consideraton in the form of equity instruments issued at fair value		97.7
Transaction fees		1.3
Total consideration		99.0
Carrying amount of proportional net assets acquired (of Foxtrot International)		63.8
Fair value uplift of proportional net assets acquired (of Foxtrot International)		12.9
Cash and cash equivalents (of Mondoil Enterprises)		21.5
Total proportional identifiable net assets at fair value		98.2
Goodwill		0.8

The provisional fair values from the table above are based on currently available information about fair values as of the completion date. If new information becomes available within 12 months from this date (measurement period), the Group may change the fair value assessment in the PPA. Eventual changes in fair values will be recorded retrospectively from the completion date.

Financial information of Foxtrot International as of yearend 2022

The Company’s indirect 33.33 percent interest in Foxtrot International is treated in accordance with IFRS 11 and IAS 28 Investments in Associates and Joint Ventures (i.e., the Group’s interest in Mondoil Côte d’Ivoire/Foxtrot International is accounted for using the equity method) and disclose in the table below the summarised financial information of Foxtrot International as an associate/joint venture (IAS 28) in terms of summarised financial information.

Foxtrot International's summarized statement of financial position

	Year ended 31 December	USD million
	2022
Non-current assets		216.5
Current assets		67.3
Total assets		283.7
Non-current liabilities		67.1
Current liabilities		30.0
Total liabilities		97.2
Equity		186.6
Group's share of net assets (33.33 percent)		62.2
Goodwill		0.8
Fair value uplift on PP&E and ARO (net of related deferred tax)		13.0
Carrying amount Investment in Joint Venture		76.1

Annual Report and Accounts 2022 DNO 53

Foxtrot International's summarized statement of comprehensive income

	1 January - 31 December	USD million
	2022
Revenues		28.8
Expenses		-4.2
Depreciation		-8.0
Other income/finance income		3.5
Tax income/-expense		-
Net profit/-loss		20.1
Group's share of net profit (33.33 percent)		6.7
Depletion of fair value uplift of PP&E and ARO (net of related deferred tax)		-0.7
Share of profit/-loss from Joint Venture		6.0

	As at transaction completion date	Year ended 31 December	Movement in the carrying amount of Investment in Joint Venture	USD million
		2022
Opening balance	-	77.5
Acquired share of Joint Venture's carrying amount	63.8	-
Acquired fair value uplift of PP&E and ARO (net of related deferred tax)	12.9	-
Goodwill	0.8	-
Share of profit/-loss from Joint Venture	-	6.0
Equity contribution into Joint Venture	-	-4.2
Dividends from Joint Venture	-	-11.5
Carrying amount Investment in Joint Venture	77.5	76.1

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
	2022	2021
Book value as of 1 January	16.2	12.6
Fair value changes through other comprehensive income (FVTOCI)	14.2	3.6
Disposal	-30.4	-
Book value as of 31 December	-	16.2

Financial investments include the following:

USD million
	2022	2021
Listed shares:
RAK Petroleum plc	-	16.2
Total financial investments	-	16.2

Prior to the completion of the agreement entered between DNO and RAK Petroleum in October 2022 (see Note 10), the Company held a total of 15,849,737 (5.1 percent) shares in RAK Petroleum. RAK Petroleum was listed on the Oslo Stock Exchange and was the largest shareholder in DNO ASA with 44.94 percent of the total issued shares.

As part of the all-share transaction with RAK Petroleum, on 19 October 2022, RAK Petroleum distributed by way of a capital repayment the entirety of its DNO ASA shareholding, including the transaction consideration shares, to its shareholders, which also included DNO ASA. Following the distribution, the Company had 26,269,183 own shares which were retained as treasury shares and the Company’s investment in RAK Petroleum was simultaneously derecognized from the balance sheet.

Change in fair value prior to transaction completion was recognized in other comprehensive income with USD 14.2 million in 2022 (USD 3.6 million in 2021).

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

54 DNO Annual Report and Accounts 2022

Years ended 31 December	USD million
	2022	2021
Trade debtors (non-current portion)	-	18.2
Other long-term receivables	-	1.3
Total other non-current receivables	-	19.4
Trade debtors	311.8	344.4
Underlift	14.0	17.2
Other short-term receivables	111.9	122.2
Total trade and other receivables	437.8	483.8

Total book value of trade debtors of USD 311.8 million at yearend 2022 relate mainly to outstanding invoices for Kurdistan oil deliveries for the months August through December 2022 (USD 295.9 million).

In September 2022, the KRG proposed a change in the previously agreed pricing formula for oil such that prices should, with effect from 1 September 2022, be based on the purported actual price realized by KRG during the delivery month. The KRG proposal has not been accepted by DNO and the Company continues to invoice the KRG for oil sales based on the previously agreed pricing formula (including the September 2022 invoice) until such time that protocols are put in place to ensure that realized prices are transparent, based on arms-length transactions and subject to third-party audit.

See Note 18 regarding trade debtors from oil sales in Kurdistan. See also Note 25 regarding payments received from the KRG after yearend.# Consolidated accounts

Note 13 Cash and cash equivalents

Years ended 31 December
USD million | 2022 | 2021
---|---|---
Cash and cash equivalents, restricted | 22.5 | 15.8
Cash and cash equivalents, non-restricted | 931.8 | 720.8
Total cash and cash equivalents | 954.3 | 736.6

Restricted cash consists of deposits on escrow account, employees’ tax withholdings and deposits for rent. Non-restricted cash is mainly related to bank deposits in USD, NOK, GBP and EUR as of 31 December 2022. Included in the non-restricted cash and cash equivalents as of 31 December 2022 is USD 408.7 million held on fixed interest time deposit contracts with different duration and maturity dates up to 23 January 2023.

Note 14 Equity

Annual Report and Accounts 2022	DNO	55
	Share capital	Number of Ordinary shares (1,000)
As of 1 January 2021	975,433	32.9
Treasury shares sold/-purchased	-	-
As of 31 December 2021	975,433	32.9

| | Number of Ordinary shares (1,000) | Treasury shares | USD million | Total
As of 1 January 2022 | 975,433 | 32.9 | 0.0 | 32.9
Treasury shares sold/-purchased | -36,369 | - | -0.9 | -0.9
Share capital increase* | 78,944 | 1.8 | - | 1.8
As of 31 December 2022 | 1,018,008 | 34.8 | -0.9 | 33.9

• See Note 10 for information and details

At the 2022 Annual General Meeting (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 which corresponds to 97,543,373 new shares. 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 was time-limited until the 2023 AGM, and not beyond 30 June 2023. The Board of Directors was also given the authority to increase the Company’s share capital by up to NOK 24,385,818 which corresponds to 97,543,373 new shares. The authorization was time-limited until the 2023 AGM, and not beyond 30 June 2023. 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 24,385,818. The authorization is valid until the 2023 AGM, but not beyond 30 June 2023. The Board of Directors was given the authority to approve total dividend distributions of up to NOK 1 per share from the date of the 2022 AGM until the date of the 2023 AGM. Following this, the Board of Directors decided to distribute quarterly dividends of NOK 0.25 in August and November 2022, as well as in February 2023. At an Extraordinary General Meeting (EGM) in September 2022, a proposal to increase the Company’s share capital received support of over 99 percent of the votes cast. In accordance with the EGM approval and a transaction agreement, DNO in October 2022 issued 78,943,763 new shares to RAK Petroleum, its then largest shareholder, as consideration for the transfer of West Africa assets between the companies. Pursuant to the transaction agreement, RAK Petroleum proceeded to distribute its entire DNO shareholding, including the consideration shares, to its shareholders. As a shareholder of RAK Petroleum (5.1 percent), DNO received 26,269,183 own shares to be retained as treasury shares. The total shares outstanding following the completion of the transaction increased to 1,054,376,509, each with a nominal value of NOK 0.25. In December 2022, DNO announced the initiation of a share buyback program through which the Company would repurchase up to 53,107,326 shares, representing approximately five percent of total shares outstanding, for a maximum total consideration of USD 80 million. The buyback program was based upon the authorization to acquire treasury shares granted to the Board of Directors at the 2022 AGM.

Consolidated accounts	Note 14 Equity	56	DNO Annual Report and Accounts 2022
The Company's shareholders as of 31 December 2022	Shares (percent)
Goldman Sachs & Co. LLC	131,926,545	12.51
Euroclear Bank S.A./N.V.	93,818,919	8.90
Folketrygdfondet	44,490,590	4.22
RAK Gas LLC	34,311,403	3.25
State Street Bank and Trust Comp	28,018,325	2.66
The Bank of New York Mellon	25,336,833	2.40
BNP Paribas	24,188,187	2.29
The Bank of New York Mellon SA/NV	15,017,836	1.42
Clearstream Banking S.A	14,083,236	1.34
CACEIS Bank	14,054,243	1.33
HSBC Bank Plc	13,888,921	1.32
JPMorgan Chase Bank	10,886,384	1.03
Citibank	10,275,813	0.97
The Bank of New York Mellon	9,285,363	0.88
State Street Bank and Trust Comp	9,059,036	0.86
Saxo Bank A/S	8,611,705	0.82
Salt Value AS	8,495,200	0.81
The Northern Trust Comp	8,193,045	0.78
Citibank	7,263,451	0.69
Morgan Stanley & Co. International	7,093,637	0.67
Other shareholders	499,708,654	47.39
Total number of shares excluding treasury shares	1,018,007,326	96.55
Treasury shares as of 31 December 2022 (DNO ASA)	36,369,183	3.45
Total number of outstanding shares	1,054,376,509	100.00

Dividends of USD 72 million were distributed in 2022 (USD 21.8 million in 2021). See Note 25 for dividend approved on 9 February 2023. See also Note 5 for shares held by Board of Directors and executive management.

Note 15 Interest-bearing liabilities

Consolidated accounts	Annual Report and Accounts 2022	DNO	57
	Effective interest rate (percent)	Fair value (percent)	Carrying amount
	Ticker	Facility	Interest rate
Non-current
Bond loan (ISIN NO0010852643)	DNO03	USD 150.7	8.375
Bond loan (ISIN NO0011088593)	DNO04	USD 400.0	7.875
Capitalized borrowing issue costs
Reserve based lending facility	USD 350.0	see below	see below
Total non-current interest-bearing liabilities
Current
Reserve based lending facility (current)	NOK 350.0	see below	see below
Total current interest-bearing liabilities
Total interest-bearing liabilities

During 2022, DNO ASA acquired USD 263.7 million of DNO03 bonds at a price range of 99 to 103.35 percent of par plus accrued interest. Facility and carrying amount for the bonds is shown net of bonds held by the Company. The financial covenants of the bonds issued by DNO ASA require a minimum USD 40 million of liquidity and the maintenance by the Group of 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 a reserve-based lending (RBL) facility for its Norway and UK production licenses with a total facility limit of USD 350 million which is available for both debt and issuance of letters of credit. In addition, there is an uncommitted accordion option of USD 350 million. Interest charged on utilizations is based on LIBOR 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 3.50. 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 borrowing base amount of the facility from 1 January 2023 is USD 74.2 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD 31.8 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.

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

USD million	At 1 Jan 2022	Cash flows	Non-cash changes	Amortization	Currency	Acquisition	At 31 Dec 2022
Bond loans	794.9	-263.7	-	-	-	-	531.2
Borrowing issue costs	-16.5	-	5.2	-	-	-	-11.3
Reserve based lending facility	95.0	-60.0	-	-8.4	-	26.6	-
Reserve based lending facility (current)	-	-	-	-	-	8.4	8.4
Total	873.4	-323.7	5.2	-	-	-	554.8

USD million	At 1 Jan 2021	Cash flows	Non-cash changes	Amortization	Currency	Acquisition	At 31 Dec 2021
Bond loans	800.0	-5.1	-	-	-	-	794.9
Borrowing issue costs	-15.4	-10.5	9.4	-	-	-	-16.5
Reserve based lending facility	149.6	-53.9	-	-0.7	-	-	95.0
Total	934.2	-69.5	9.4	-0.7	-	-	873.4

Note 16 Provisions for other liabilities and charges/Lease liabilities

Consolidated accounts	Annual Report and Accounts 2022	DNO	58
USD million	2022	2021
Non-current
Asset retirement obligations (ARO)	368.2	386.3
Other long-term obligations	4.9	3.6
Total non-current provisions for other liabilities and charges	373.1	389.9
Lease liabilities
Total non-current lease liabilities	6.5	12.5
Current
Asset retirement obligations (ARO)	20.5	69.7
Other provisions and charges	39.8	34.8
Total current provisions for other liabilities and charges	60.2	104.4
Current lease liabilities	6.8	15.7
Total current lease liabilities	6.8	15.7
Total provisions for other liabilities and charges and lease liabilities	446.6	522.6

Asset retirement obligations (ARO)
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 2022 were between 4.5 percent and 4.8 percent (yearend 2021: between 3.2 percent and 3.7 percent). The credit margin included in the discount rates at yearend 2022 was 0.8 percent (yearend 2021: 2.3 percent).

Consolidated accounts Note 16 Provisions for other liabilities and charges/Lease liabilities

Annual Report and Accounts 2022 DNO 59

Asset	Other retirement obligations	non-current	Provisions as of 1 January 2021	USD million
Decommissioning spend	-86.8	-
Increase/-decrease in existing provisions	0.9	0.2
Amounts charged against provisions	-	-
Effects of change in the discount rate	0.9	-
Accretion expenses (unwinding of discount)	17.7	-
Reclassification and transfer	-	-
Provisions as of 31 December 2021	456.0	3.6
Decommissioning spend	-70.5	-
Increase/-decrease in existing provisions	25.0	1.3
Amounts charged against provisions	-	-
Effects of change in the discount rate	-37.0	-
Accretion expenses (unwinding of discount)	15.2	-
Reclassification and transfer	-	-
Provisions as of 31 December 2022	388.7	4.9

Lease liabilities

The recognized lease liabilities in the balance sheet are mainly related to rig lease and office rent. In 2021, DNO entered into a rig lease agreement to perform decommissioning, plugging and abandonment at the Schooner and Ketch fields in the UK part of the North Sea. The rig lease was entered into with DNO as the operator of the licenses at the initial signing and subsequently partly allocated to the license partners (presented under non-current and current receivables). The rig lease was recognized on a gross basis, rather than based on DNO’s working interest share (60 percent). 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 low-value assets are recognized under lifting costs and exploration costs, or tangible assets and capitalized exploration. Total lease payments related to short-term leases and low-value assets were USD 56 million (2021: USD 56.6 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	2022	2021
Within one year	7.0	16.6
Two to five years	6.5	13.1
After five years	-	-
Total undiscounted lease liabilities end of the period	13.5	29.7

Note 17 Trade and other payables

Years ended 31 December USD million	2022	2021
Trade payables	62.7	85.7
Public duties payable	4.1	6.1
Prepayments from customers	12.7	-
Overlift	9.0	17.3
Other accrued expenses	155.7	123.4
Total trade and other payables	244.1	232.6

Trade payables are non-interest bearing and are normally settled within 30 days. Trade payables and other accrued expenses include items of working capital related to participation in licenses in Kurdistan and the North Sea, and prepayment from customers related to oil sales in the North Sea. The overlift payable relates to North Sea overlifted volumes, valued at production cost including depreciation.

Consolidated accounts Note 18 Financial instruments

60 DNO Annual Report and Accounts 2022

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. 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. No hedge accounting is applied.

Market risk

The Group is exposed to market risks driven by fluctuations in oil and gas prices, foreign currency exchange rates and interest rates.

Oil and gas price risk

DNO’s revenues are generated from the sale of oil and gas. In 2022, the Group had gas price put options in place with strike prices of GBP 79 -110 pence per therm, securing approximately 75 percent of after-tax profit from estimated 2022 gas production. The Group had no oil and gas price hedging arrangements at yearend 2022.

The following table illustrates the impact on reported 2021 and 2022 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 9 for a sensitivity analysis related to the impairment assessment of oil and gas assets.

Change in yearend oil and gas price (percent)	Effect on profit before tax (USD mill)
2022 +/- 15.0	+/- 170.9
2021 +/- 15.0	+/- 129.0

Foreign currency exchange rate risk

Revenues from oil and gas production are primarily in USD and EUR, while operating expenses, capital and abandonment expenditures are primarily denominated in USD, NOK and GBP. Dividend distributions from the Company are in NOK. The Group had no currency hedging instruments at yearend 2022 although it monitors its foreign currency risk exposure on a continuous basis and evaluates hedging alternatives.

Consolidated accounts Note 18 Financial instruments

Annual Report and Accounts 2022 DNO 61

The following tables illustrate the impact on DNO’s reported profit/-loss before income tax in 2021 and 2022 from foreign currency exchange rate fluctuations deemed reasonable and possible in NOK, EUR and GBP exchange rates, with all other variables held constant. The other currencies (e.g., AED, IQD) are not included as the exposure is deemed immaterial.

Change in NOK (percent)	Effect on profit before tax (USD mill)
2022 + 10.0	-3.5
2022 - 10.0	3.5
2021 + 10.0	-5.9
2021 - 10.0	5.9

Change in GBP (percent)	Effect on profit before tax (USD mill)
2022 + 10.0	-19.0
2022 - 10.0	19.0
2021 + 10.0	1.4
2021 - 10.0	-1.4

Change in EUR (percent)	Effect on profit before tax (USD mill)
2022 + 10.0	-4.8
2022 - 10.0	4.8
2021 + 10.0	-3.6
2021 - 10.0	3.6

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 RBL is considered limited and no hedging arrangement was in place during 2022. 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 reported profit/-loss before income tax in 2021 and 2022 from a change in interest rates on that portion of interest-bearing liabilities and cash deposits deemed reasonable and possible, with all other variables held constant.

Increase/decrease in basis points	Effect on profit before tax (USD mill)
2022 +/- 200	+/-7.7
2021 +/- 200	+/-14.8

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 requires 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 by the Company’s Board of Directors and the executive management.

Investment in joint venture Foxtrot International issues cash calls to Mondoil Enterprises (see Note 10) to fund capital and operating requirements for Côte d’Ivoire Block CI-27 and Block CI-12, which are made on a regular basis pursuant to an approved budget and work program. The cash distributions anticipated to be received from Foxtrot International will be sufficient to enable the Company to meet all of its scheduled and anticipated obligations.

Consolidated accounts Note 18 Financial instruments

62 DNO Annual Report and Accounts 2022

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 in 2022 derived primarily 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 asset acquisitions aimed at further diversifying its revenue sources. See also Note 10 regarding the Company’s entry in West Africa.

The tables below summarize the maturity profile of the Group’s financial liabilities based on contractual undiscounted cash flows.## Consolidated accounts Note 18 Financial instruments Annual Report and Accounts 2022 DNO 63

Credit risk

Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or 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
	2022	2021
Trade debtors (non-current portion) (Note 12)	-	18.2
Trade debtors (Note 12)	311.8	344.4
Other receivables (Note 12)	126.0	139.4
Tax receivables	25.8	21.1
Cash and cash equivalents	954.3	736.6
Total	1,417.9	1,259.7

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 debtors from oil sales invoices in Kurdistan Normal payment terms apply to amounts owed to DNO by the KRG for oil sales and override invoices from the Tawke and the Baeshiqa 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 early 2020. At yearend 2020, the Group had accumulated a receivable against the KRG of USD 259 million after certain 2019 and 2020 entitlement and override payments to the Group and other Kurdistan oil exporters were withheld early in 2020 by the KRG in connection with the hardships and uncertainties brought about by the Covid-19 pandemic. Entitlement payments resumed in March 2020 and override payments in early 2021. A payment plan was put in place by the KRG in December 2020 and subsequently revised in May 2021 to pay the outstanding arrears. As a part of the May 2021 revision, the KRG also informed the international oil companies that all invoices, including towards the arrears, will be settled within 60 days of the end of the respective production month. During 2022, the outstanding arrears were reduced from USD 169 million at the start of the year to USD 2 million at yearend, not including any interest. The Company continues to work to collect the remaining balances and expects to be paid accordingly. Over the course of 2022, KRG payments to international oil companies were increasingly delayed. At the time of issuing this report, the invoices related to August and September 2022 oil deliveries were paid in January and March 2023, respectively. The Company is in dialogue with the KRG, seeking timely payments to support timely investments. Moreover, in September 2022, the KRG proposed a change in the previously agreed pricing formula for oil such that prices should, with effect from 1 September 2022, be based on the purported price realized by KRG during the delivery month. The KRG proposal has not been accepted by DNO and the Company continues to invoice the KRG for oil sales based on the previously agreed pricing formula (including the September 2022 invoice) until such time that protocols are put in place to ensure that realized prices are transparent, based on arms-length transactions and subject to third-party audit. The payment for the September oil delivery received after yearend reflects the formula proposed and unilaterally applied by the KRG in September 2022 resulting in an approximately USD 11/bbl reduction in realized price compared to current pricing formula based on Dated Brent. The payment received was USD 5.2 million (net to DNO) lower than invoiced. The Company is in continuing dialogue with the KRG to resolve this matter and collect outstanding balances. The Company estimates that using the KRG proposed prices, the impact of the change in pricing would have resulted in approximately USD 23 million lower revenues compared to the reported September through December 2022 Kurdistan revenues. The table below shows the aging of trade debtors and information about credit risk exposure using a provision matrix.

Contract Days past due (trade debtors) USD million assets	Current	< 30 days	30-60 days	61-90 days	> 90 days	Total
As of 31 December 2022
Trade debtors (nominal value) (Note 12)	-	132.7	58.1	55.9	63.1	2.0
Expected credit loss rate (percent)	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-
As of 31 December 2021
Trade debtors (nominal value) (Note 12)	-	131.6	61.9	-	-	169.1
Expected credit loss rate (percent)	-	-	-	-	-	-
Expected credit loss rate (USD million)	-	-	-	-	-	-

Total trade debtors of USD 311.8 million at yearend 2022 relate mainly to the Tawke license, see Note 12 for details.

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 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 improved primarily due to a net profit in 2022. The table below shows the book equity ratio at yearend. No changes were made in the objectives, policies or processes for managing capital during 2022 and 2021.

Years ended 31 December	USD million
	2022	2021
Total equity	1,369.4	1,018.8
Total assets	2,803.0	2,947.8
Equity ratio	48.9%	34.6%

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 Financial	Fair value hierarchy assets liabilities	designated at amortized	2022 - 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	-	-	-	31 December 2022	-	-	-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)			-	15	546.4	546.4		31 December 2022	507.3	-	26.6
Interest-bearing liabilities (current)			-	15	8.4	8.4			-	8.4

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

Consolidated accounts Note 18 Financial instruments 64 DNO Annual Report and Accounts 2022

Maturity analysis of financial liabilities

USD million
On Less than 3 to 12 1 to 3 Over 3 At
demand 3 months months years years Interest-bearing liabilities* - 11.3 33.8 203.8 460.7
Other provisions and charges - 18.4 22.2 - -
Taxes payable - 125.7 - - -
Trade and other payables - 233.0 2.0 - -
Total liabilities - 388.4 58.0 203.8 460.7

USD million
On Less than 3 to 12 1 to 3 Over 3 At
demand 3 months months years years Interest-bearing liabilities* - 16.9 60.8 510.4 545.3
Other provisions and charges - 18.6 16.2 - -
Taxes payable - 12.6 20.5 - -
Trade and other payables 1.9 210.4 3.0 - -
Total liabilities 1.9 258.5 100.5 510.4 545.3

• Face value of the bonds was USD 531.2 million at yearend 2022 (USD 794.9 million at yearend 2021). For changes in liabilities arising from financing activities, see Note 15.## Consolidated accounts

Note 19 Commitments and contingencies

Annual Report and Accounts 2022 DNO 65

Contingent liabilities and contingent assets

Disputes with Ministry of Oil and Minerals of Yemen (MOM) – 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). The Contractor (including DNO Yemen AS), filed for annulment proceedings in the Paris Court d’Appel which was dismissed in 2022 but is currently on appeal at the Supreme Court. A provision of USD 22.2 million was recognized at yearend 2022 related to this arbitration award (USD 14 million at yearend 2021).

DNO Yemen AS (DNO Yemen) was involved in a dispute with MOM with respect to DNO Yemen’s relinquishment of Block 32 in 2016. An arbitral award was rendered on 7 April 2021 in the Ministry’s favor in the amount of USD 8.1 million (out of a USD 151 million counterclaim) while the Contractor of the license was awarded USD 5 million (out of a USD 14 million claim). A provision for liability of USD 1.4 million (net to DNO Yemen AS) was recognized in 2021 related to this arbitration award (unchanged at yearend 2022).

DNO Yemen was involved in a dispute with MOM with respect to DNO Yemen’ relinquishment of Block 43 in 2016. An arbitral award was rendered on 18 February 2020 in DNO Yemen’ favor in the amount of USD 6.8 million (almost entirely dismissing the USD 131 million counterclaim of the MOM). In accordance with IAS 37, the asset related to this arbitration award was not recognized in the balance sheet as of 31 December 2022.

As part of the Block 43 arbitral award in 2020 (above), a cost recovery audit was mandated for the years 2014 and 2015. In 2021, MOM filed an arbitration claim against DNO Yemen AS for allegedly over-recovered costs of USD 17.2 million from the Ministry in 2014 and 2015. 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 for a liability was made at yearend 2022 related to this dispute.

On 8 December 2022, the Oslo District Court ruled that previously rendered arbitration awards regarding Blocks 53 and 32 are enforceable against DNO Yemen in Norway. DNO Yemen has appealed this decision. The Oslo District Court also ruled that the previously rendered arbitration award regarding Block 43 in favor of DNO Yemen is enforceable against the MOM in Norway. The MOM has not contested this decision. A parallel enforcement case regarding the same subject matter but filed against DNO ASA remains suspended pending a final ruling in the DNO Yemen case.

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 2022 and contingent on future market conditions including development in the oil price, the Group’s projected operational spend comprising of capital and exploration expenditures, abandonment expenditures and operational expenditures at yearend 2022 amounted to USD 640 million. The projected operational spend reflects the Group’s share of planned drilling and facility investments and decommissioning plan in its licenses for 2022. Execution of these work plans is subject to revisions.

Guarantees related to assets in operation at yearend 2022

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.

Liability for damages/insurance

Installations and operations are covered by various insurance policies.

Note 20 Earnings per share

66 DNO Annual Report and Accounts 2022

	1 January - 31 December 2022	2021
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)	384.9	203.9
Weighted average number of ordinary shares excluding treasury shares (millions)	986.97	975.43
Earnings per share, basic (USD per share)	0.39	0.21
Earnings per share, diluted (USD per share)	0.39	0.21

Basic earnings per share are calculated by dividing the net profit/-loss attributable to equity holders by the weighted average number of outstanding ordinary shares during the period, excluding ordinary shares purchased and held as treasury shares. The Company did not have any potential dilutive shares at yearend 2022.

Note 21 Group companies and other companies

Annual Report and Accounts 2022 DNO 67

Ownership and voting interest (percent)	USD million
Shares in the Company's subsidiaries
DNO Iraq AS	Norway
DNO UK Limited	United Kingdom
DNO Mena AS	Norway
DNO Technical Services AS	Norway
DNO Exploration UK Limited	United Kingdom
DNO Yemen AS	Norway
DNO North Sea plc	United Kingdom
Mondoil Enterprises LLC	United States
Shares in subsidiaries owned through subsidiaries
DNO Mena AS
DNO Oman Limited	Bermuda
DNO Oman Block 8 Limited	Guernsey
DNO Oman Block 30 Limited	Guernsey
North Limited	Guernsey
DNO Tunisia Limited	Guernsey
DNO North Sea plc
DNO Norge AS	Norway
DNO North Sea (UK) Limited	United Kingdom
DNO North Sea (ROGB) Limited	United Kingdom
DNO North Sea (Energy) Limited	United Kingdom
DNO North Sea SIP EBT Limited	United Kingdom
Shares in other entities, indirectly (equity accounted)
Mondoil Côte d’Ivoire LLC	United States
Foxtrot International LDC	Cayman Islands

The Group’s operations in Kurdistan are carried out through its subsidiary DNO Iraq AS, while activities on the NCS are carried out through DNO Norge AS and UKCS activities are carried out through DNO North Sea (UK) Limited and DNO North Sea (ROGB) Limited. Activities in Côte d'Ivoire are carried out by Foxtrot International LDC, in which the Company’s indirect of 33.33 percent is accounted for using the equity method. DNO ASA, 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. Northstar Norge AS (DNO North Sea (Norge) AS) was liquidated during 2022 and DNO Technical Services Limited was renamed to Northstar Limited.

Note 22 Related party disclosure

The following table provides details of the Group’s related party transactions in 2022. See also Note 5 on remuneration.

Related party	Transaction	2022	2021
RAK Petroleum plc	Service agreement	-1.1	-0.1
Total related party transactions		-1.1	-0.1

Prior to the completion of the agreement entered between DNO and RAK Petroleum in October 2022 (see Note 10), RAK Petroleum, through its subsidiary RAK Petroleum Holdings B.V., was the Company’s largest shareholder and the Company’s Executive Chairman Bijan Mossavar-Rahmani also served as Executive Chairman of RAK Petroleum. The Company had an agreement with RAK Petroleum for services including administrative and commercial support, travel and other expenses. See also Note 3 in the parent company accounts relating to reimbursement of expenses to the members of the Board of Directors. There are additional transactions between Group companies, see Note 20 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 23 Oil and gas reserves (unaudited)

68 DNO Annual Report and Accounts 2022

	Proven (1P)	Proven and probable (2P)	Proven, probable and possible (3P)
MMboe	Oil	NGL	Gas
By region/field
Tawke	126.1	-	-
Peshkabir	64.8	-	-
Total Kurdistan	190.9	-	-
Blane	0.3	-	-
UK	0.1	-	-
Total UK	0.4	-	-
Alve	0.3	0.3	1.6
Andvare	0.1	0.5	2.6
Berling	1.0	0.7	3.5
Brage	0.9	0.1	0.2
Fenja	1.7	0.1	0.6
Marulk	-	0.2	0.6
Oda	1.3	-	0.1
Ringhorne East	1.3	-	-
Tambar	1.4	0.1	0.3
Tambar East	0.2	-	-
Trym	0.2	-	1.0
Ula

Note 23 Oil and gas reserves (unaudited)

Reserves development by segment (net to DNO)	Kurdistan	North Sea	Subtotal	West Africa	Total Group
MMboe	1P 2P 3P	1P 2P 3P	1P 2P 3P	1P 2P 3P	1P 2P 3P
As of 1 January 2021	175.8 295.4 453.7	41.1 64.4 96.0	216.9 359.9 549.6	- - -	216.9 359.9 549.6
Production	-29.8 -29.8 -29.8	-4.7 -4.7 -4.7	-34.5 -34.5 -34.5	- - -	-34.5 -34.5 -34.5
Acquisitions	- - -	- - -	- - -	- - -	- - -
Divestments	- - -	- - -	- - -	- - -	- - -
Extensions and discoveries	- - -	- - -	- - -	- - -	- - -
New developments	- - -	- - -	- - -	- - -	- - -
Revision of previous estimates	16.1 1.8 -75.4	-2.4 -5.8 -19.1	13.7 -4.0 -94.4	- - -	13.7 -4.0 -94.4
As of 31 December 2021	162.2 267.4 348.5	33.9 54.0 72.1	196.1 321.4 420.6	- - -	196.1 321.4 420.6
Production	-29.3 -29.3 -29.3	-4.9 -4.9 -4.9	-34.2 -34.2 -34.2	-1.2 -1.2 -1.2	-35.4 -35.4 -35.4
Acquisitions	- - -	- - -	- - -	5.6 11.5 22.5	5.6 11.5 22.5
Divestments	- - -	- - -	- - -	- - -	- - -
Extensions and discoveries	- - -	- - -	- - -	- - -	- - -
New developments	- - -	8.4 12.1 16.5	8.4 12.1 16.5	- - -	8.4 12.1 16.5
Revision of previous estimates	58.1 7.2 -3.2	-12.5 -24.8 -34.3	45.6 -17.6 -37.6	- - -	45.6 -17.6 -37.6
As of 31 December 2022	190.9 245.3 316.0	25.0 36.5 49.3	215.9 281.8 365.4	4.4 10.3 21.3	220.3 292.1 386.7

Net Entitlement (NE) reserves by segment	Kurdistan	North Sea	Subtotal	West Africa	Total Group
MMboe	1P 2P 3P	1P 2P 3P	1P 2P 3P	1P 2P 3P	1P 2P 3P
As of 31 December 2021	56.5 77.7 88.8	33.9 54.0 72.1	90.4 131.7 160.9	- - -	90.4 131.7 160.9
As of 31 December 2022	63.8 74.3 84.7	25.0 36.5 49.4	88.8 110.8 134.1	2.7 6.3 12.0	91.5 117.1 146.1

The reserves and contingent resources are according to the Annual Statement of Reserves and Resources (ASRR) dated 15 March 2023. The reported reserves fall within class 1-3 of the Norwegian Petroleum Directorate (NPD) classification and 2C resources fall within classes 4, 5 and 7 of the NPD classification. 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 (containing the Baeshiqa and Zartik structures) in the Kurdistan region of Iraq. International petroleum consultants RPS Energy Consultants carried out an independent assessment of DNO's licenses in Norway and the UK. The Company used reserves and resources numbers reported by the operating entity of its licenses in Côte d’Ivoire. For the producing Block CI-27 in Côte d’Ivoire, the numbers were based on an independent assessment carried out by international petroleum consultant Gaffney, Cline & Associates at yearend 2016, adjusted for production and technical revisions to reflect yearend 2022 values. 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, 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 2022, DNO’s net 1P reserves stood at 220.3 MMboe, compared to 196.1 MMboe at yearend 2021, after adjusting for production during the year, upward technical revisions and addition of assets in Côte d’Ivoire. On a 2P reserves basis, DNO’s net reserves stood at 292.1 MMboe, compared to 321.4 MMboe at yearend 2021. On a 3P reserves basis, DNO’s net reserves were 386.7 MMboe, compared to 420.6 MMboe at yearend 2021. DNO’s net 2C resources were 152.5 MMboe, compared to 189.5 MMboe at yearend 2021. DNO’s net production in 2022 totaled 35.4 MMboe (of which 29.3 million barrels of oil (MMbbls) were from the Tawke license in Kurdistan, 4.8 MMboe in Norway, 1.2 MMboe in Côte d’Ivoire and the balance in the UK), compared to 34.5 MMboe in 2021 (of which 29.8 MMbbls in Kurdistan, 4.5 MMboe in Norway and the balance in the UK). The Company’s net yearend 2022 Reserve Life Index (R/P) stood at 6.2 years on a 1P reserves basis, 8.3 years on a 2P reserves basis and 10.9 years on a 3P reserves basis. Net reserves in DNO’s licenses governed by PSCs (Kurdistan and Côte d’Ivoire) are based on the participation interest. NE reserves 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). Net reserves reflect pre-tax shares while Net Entitlement (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 net volumes. Net and NE reserves in DNO’s licenses not governed by PSCs (Norway and the UK) are equivalent and reflect pre-tax shares.

Note 24 Oil and gas license portfolio

Kurdistan licenses

At yearend 2022, DNO held interests in two licenses in Kurdistan, both of which are PSCs. The Tawke license contains the producing Tawke and Peshkabir fields. The Baeshiqa license contains two large structures with multiple independent stacked target reservoirs, including in the Cretaceous, Jurassic and Triassic formations. The structures at Baeshiqa and Zartik have the potential to be part of a single accumulation of hydrocarbons at one or more of the geological formation intervals.

North Sea (Norway and the UK, and other)

At yearend 2022, DNO held 68 offshore licenses in Norway, seven offshore licenses in the UK and two offshore licenses in Netherlands.

West Africa (Côte d’Ivoire)

At yearend 2022, DNO held two licenses in Côte d’Ivoire through its indirect 33.33 percent in Foxtrot International, both of which are PSCs. Foxtrot International holds a 27.27 percent interest in and operatorship of the producing Block CI-27, which contains the Foxtrot gas field, the Mahi gas field, the Marlin oil and gas field and the Manta gas field. Foxtrot International also operates the exploration Block CI-12, in which it holds a 24 percent interest. In accordance with IFRS, DNO’s indirect interest in Foxtrot Mondoil Côte d’Ivoire/Foxtrot International is accounted for using the equity method (see Note 10).

Other

At yearend 2022, DNO held 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 2022	Held through DNO as a subsidiary:	Participating interest (percent)	Operator	Partner(s)
Region/license
Kurdistan
Tawke PSC	DNO Iraq AS	75.0	DNO Iraq AS	Genel Energy International Limited
Baeshiqa PSC	DNO Iraq AS	64.0	DNO Iraq AS	Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL006 C (SE Tor)	DNO Norge AS	65.0	DNO Norge AS	Aker BP ASA
PL018 ES	DNO Norge AS	45.0	A/S Norske Shell	DNO Norge AS, Spirit Energy Norway AS
PL019 (Ula)	DNO Norge AS	20.0	Aker BP ASA	DNO Norge AS
PL019 E (Ula)	DNO Norge AS	20.0	Aker BP ASA	DNO Norge AS
PL019 F (Ula)	DNO Norge AS	45.0	Aker BP ASA	DNO Norge AS
PL036 D (Vilje)	DNO Norge AS	28.9	Aker BP ASA	DNO Norge AS, PGNiG Upstream Norway AS
PL048 D (Enoch)	DNO Norge AS	9.3	Equinor Energy AS	DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B (Brage)	DNO Norge AS	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 (Brage)	DNO Norge AS	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 B (Brage)	DNO Norge AS	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 D (Brage)	DNO Norge AS	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 E (Brage)	DNO Norge AS	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL065 (Tambar)	DNO Norge AS	45.0	Aker BP ASA	DNO Norge AS
PL065 B (Tambar)	DNO Norge AS	45.0	Aker BP ASA	DNO Norge AS
PL1048	DNO Norge AS	50.0	Lundin Energy Norway AS	DNO Norge AS
PL1076	DNO Norge AS	50.0	Equinor Energy AS	DNO Norge AS
PL1083	DNO Norge AS	30.0	Lundin Energy Norway AS	DNO Norge AS, Petoro AS
PL1084	DNO Norge AS	40.0	Lundin Energy Norway AS	DNO Norge AS
PL1085	DNO Norge AS	25.0	Aker BP ASA	DNO Norge AS, Petoro AS
PL1086	DNO Norge AS	50.0	DNO Norge AS	Source Energy AS, Petoro AS
PL1102	DNO Norge AS	30.0	Lundin Norway AS	DNO Norge AS
PL1106	DNO Norge AS	40.0	DNO Norge AS	Petoro AS, Petrolia NOCO AS, Lundin Energy Norway AS
PL1108	DNO Norge AS	40.0	DNO Norge AS	Pandion Energy AS, OKEA ASA
PL1109	DNO Norge AS	30.0	OMV (Norge) AS	DNO Norge AS, ONE-Dyas Norge AS
PL1112	DNO Norge AS	20.0	A/S Norske Shell	DNO Norge AS, Neptune Energy Norge AS, Spirit Energy Norway AS
PL1120	DNO Norge AS	40.0	DNO Norge AS	Equinor Energy AS, Vår Energi AS, Wintershall Dea Norge AS
PL1145	DNO Norge AS	60.0	DNO Norge AS	DNO Norge AS, Aker BP ASA
PL1146	ConocoPhilips Skandinavia AS	25.0	ConocoPhilips Skandinavia AS	ConocoPhilips Skandinavia AS; DNO Norge AS
PL1147	Lundin Norway AS	20.0	Lundin Norway AS	Spirit Energy Norway AS; Lundin Energy Norway AS; DNO Norge AS; Equinor Energy AS
PL1148	Wellesley Petroleum AS	30.0	Wellesley Petroleum AS	Wellesley Petroleum AS; DNO Norge AS; Aker BP ASA; Equinor Energy AS
PL1151	Wintershall Dea Norge AS	20.0	Wintershall Dea Norge AS	Wintershall Dea Norge AS; DNO Norge AS; Aker BP ASA; ONE-Dyas Norge AS
PL1158	Lundin Norway	40.0	Lundin Norway AS
## Note 24 Oil and gas license portfolio
### Annual Report and Accounts 2022

Region/license	interest (percent)	Operator	Partner(s)
Norway
PL1160	60.0	DNO Norge AS	DNO Norge AS; Spirit Energy Norway AS
PL122 (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL147 (Trym)	50.0	DNO Norge AS	Spirit Energy Norway AS
PL159 B (Alve)	32.0	Equinor Energy AS	DNO Norge AS, PGNiG Upstream Norway AS
PL159 G (Alve)	32.0	Equinor Energy AS	DNO Norge AS, PGNiG Upstream Norway AS
PL169 E (Ringhorne Øst)	87.0	DNO Norge AS	Vår Energi AS
PL185 (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum 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
PL274 (Oselvar)	55.0	DNO Norge AS	CapeOmega AS
PL293 B	29.0	Equinor Energy AS	DNO Norge AS, Idemitsu Petroleum Norge AS, Longboat Energy Norway AS
PL300 (Tambar Øst)	45.0	Aker BP ASA	DNO Norge AS
PL405 (Oda)	15.0	Spirit Energy Norway AS	DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL586 (Fenja)	7.5	Neptune Energy Norge AS	DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL586B (Fenja)	7.5	Neptune Energy Norge AS	DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL644 (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740 (Brasse)	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
PL836 SB	30.0	Wintershall Dea Norge AS	DNO Norge AS, Spirit Energy Norway AS
PL906	30.0	Aker BP ASA	DNO Norge AS, Longboat Energy Norge AS
PL923	20.0	Equinor Energy AS	DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL923B	20.0	Equinor Energy AS	DNO Norge AS, Wellesley Petroleum AS, Petoro 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
PL968	50.0	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
PL969B	45.0	A/S Norske Shell	DNO Norge AS, Spirit Energy Norway AS
PL984	30.0	DNO Norge AS	Vår Energi AS, Source Energy AS
PL984 BS	30.0	DNO Norge AS	Vår Energi AS, Source Energy 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.
P219	18.2	Repsol Sinopec North Sea Ltd	DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK Ltd
P2401	45.0	Shell U.K. Ltd	DNO North Sea (U.K), Spirit Energy Resources Ltd
P255	45.0	Shell U.K. Ltd	DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
P558	10.0	Britoil Ltd	DNO North Sea (U.K.) Ltd, Rockrose Energy
P803	10.0	BP Exploration Operating Company Ltd	DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P2537	30.0	Chrysaor Production (U.K.) Limited	DNO North Sea (U.K.) Ltd, Neo Energy (ZEX) Limited
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
Held through equity-accounted investment Mondoil Côte d’Ivoire/Foxtrot International as a joint venture (Note 10):
Côte d’Ivoire
Block CI-27	27.3	Foxtrot International LDC	SECI SA, Petroci*
Block CI-12	24.0	Foxtrot International LDC	SECI SA, Petroci *
*Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire
As of 31 December 2021
Held through DNO as a subsidiary:
Participating

Consolidated accounts

Note 24 Oil and gas license portfolio

DNO

Annual Report and Accounts 2022

Region/license	interest (percent)	Operator	Partner(s)
Kurdistan
Tawke PSC	75.0	DNO Iraq AS	Genel Energy International Limited
Baeshiqa PSC	64.0	DNO Iraq AS	Turkish Energy Company Limited, Kurdistan Regional Government
Norway
PL006 C (SE Tor)	65.0	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	45.0	A/S Norske Shell	DNO Norge AS, Spirit Energy Norway AS
PL019 (Ula)	20.0	Aker BP ASA	DNO Norge AS
PL019 E (Ula)	20.0	Aker BP ASA	DNO Norge AS
PL019 F (Ula)	45.0	Aker BP ASA	DNO Norge AS
PL036 D (Vilje)	28.9	Aker BP ASA	DNO Norge AS, PGNiG Upstream Norway AS
PL048 D (Enoch)	9.3	Equinor Energy AS	DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norge AS
PL055 (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norge AS
PL055 B (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norge AS
PL055 D (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norge AS
PL055 E (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norge AS
PL065 (Tambar)	45.0	Aker BP ASA	DNO Norge AS
PL065 B (Tambar)	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
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
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
PL1084	40.0	Lundin Energy Norway AS	DNO Norge AS
PL1085	25.0	Aker BP ASA	DNO Norge AS, Petoro AS
PL1086	50.0	DNO Norge AS	Source Energy AS, Petoro AS
PL1102	40.0	Lundin Norway AS	DNO Norge AS
PL1106	40.0	DNO Norge AS	Petoro AS, Petrolia NOCO AS, Lundin Energy Norway AS
PL1108	40.0	DNO Norge AS	Pandion Energy AS, OKEA ASA
PL1109	30.0	OMV (Norge) AS	DNO Norge AS, ONE-Dyas Norge AS
PL1112	20.0	A/S Norske Shell	DNO Norge AS, Neptune Energy Norge AS, Spirit Energy Norway AS
PL1120	40.0	DNO Norge AS	Equinor Energy AS, Vår Energi AS, Wintershall Dea Norge AS
PL1127	20.0	Equinor Energy AS	DNO Norge AS, TotalEnergies EP Norge AS
PL122 (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D (Marulk)	17.0	Vår Energi AS	DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL147 (Trym)	50.0	DNO Norge AS	Spirit Energy Norway AS
PL159 B (Alve)	32.0	Equinor Energy AS	DNO Norge AS, PGNiG Upstream Norway AS
PL159 G (Alve)	32.0	Equinor Energy AS	DNO Norge AS, PGNiG Upstream Norway AS
PL169 E (Ringhorne Øst)	87.0	DNO Norge AS	Vår Energi AS
PL185 (Brage)	14.3	Wintershall Dea Norge AS	DNO Norge AS, Lime Petroleum 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 (Oselvar)	55.0	DNO Norge AS	CapeOmega AS
PL293 B	29.0	Equinor Energy AS	DNO Norge AS, Idemitsu Petroleum Norge AS, Longboat Energy Norway AS
PL300 (Tambar Øst)	45.0	Aker BP ASA	DNO Norge AS
PL405 (Oda)	15.0	Spirit Energy Norway AS	DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL586 (Fenja)	7.5	Neptune Energy Norge AS	DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL644 (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C (Berling)	20.0	OMV (Norge) AS	DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740 (Brasse)	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
PL836 SB	30.0	Wintershall Dea Norge AS	DNO Norge AS, Spirit Energy Norway AS
PL906	30.0	Aker BP ASA	DNO Norge AS, Longboat Energy Norge 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
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
PL983	20.0	Equinor Energy AS	DNO Norge AS, TotalEnergies EP 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
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.
P219	18.2	Repsol Sinopec North Sea Ltd	DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK Ltd
P2401	45.0	Shell U.K.

Consolidated accounts

Note 25 Significant events after the reporting date

74 DNO Annual Report and Accounts 2022

Payments from Kurdistan

After yearend 2022, DNO has received a total of USD 114.1 million from the KRG (net to DNO) representing DNO’s entitlement share of the August and September 2022 oil deliveries to the export market from the Tawke license and the Baeshiqa license. The payment received for September oil deliveries reflects changed oil pricing as proposed by the KRG in September 2022 (see notes 12 and 18) resulting in USD 5.2 million (net to DNO) lower payment compared to the invoices issued by DNO for the respective month.

DNO receives 11 awards in Norway's APA licensing round

On 10 January 2023, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 11 exploration licenses, of which one is an operatorship, under Norway's APA 2022 licensing round. Of the 11 new licenses, nine are in the North Sea and two in the Norwegian Sea.

Discovery at the Røver Sør prospect

On 9 February 2023, DNO confirmed an oil and gas discovery on the Røver Sør prospect in the Norwegian North Sea license PL923 in which the Company holds a 20 percent interest. The discovery well and a follow-on appraisal sidetrack encountered hydrocarbons in three Jurassic Brent Group sandstone reservoirs (Ness, Etive and Oseberg formations). Preliminary estimates of gross recoverable resources are in the range of 17-47 MMboe. The partners, which in addition to the Company’s wholly-owned subsidiary DNO Norge AS, include Equinor Energy AS (operator), Petoro AS and Wellesley Petroleum AS, consider the discovery to be commercial. Together with a string of recent discoveries in the area, Røver Sør may be tied back to the Equinor-operated Troll field about 10 kilometers to the east.

The Company’s Board of Directors approve dividend payment

On 9 February 2023, the Company announced that pursuant to the authorization granted at the 2022 AGM, the Board of Directors has decided to distribute a dividend payment of NOK 0.25 per share. Payment of the dividend was made on 22 February 2023.

Discovery at the Heisenberg prospect

On 14 March 2023, DNO confirmed an oil and gas discovery on the Heisenberg prospect in the Norwegian North Sea license PL827S in which the Company holds a 49 percent interest. Preliminary estimates of gross recoverable resources are in the range of 24-84 million barrels of oil equivalent. A part of the discovery may extend into the adjacent PL248F license in which DNO holds a 20 percent interest. The PL827S partnership, which includes operator Equinor Energy AS (51 percent), considers the discovery commercially interesting as a potential tieback to the Troll field.

Parent company accounts

Annual Report and Accounts 2022 DNO 75

Income statement

1 January - 31 December USD thousand	Note	2022	2021
Operating revenues	2, 19	27,448	24,190
Total operating revenues		27,448	24,190
Depreciation	7	-1,353	-1,110
Payroll and other social expenses	3	-20,514	-19,404
Other operating expenses	4	-18,414	-15,231
Total operating expenses		-40,281	-35,745
Operating profit/-loss		-12,833	-11,555
Net financial income/-expense	5	355,341	233,695
Profit/-loss before income tax		342,508	222,140
Tax income/-expense	6	-	-
Net profit/-loss		342,508	222,140
Earnings per share, basic (USD per share)	18	0.35	0.23
Earnings per share, diluted (USD per share)	18	0.35	0.23
Weighted average number of shares outstanding (millions)		986.97	975.43

Balance sheet

ASSETS Years ended 31 December USD thousand	Note	2022	2021
Fixed assets
Intangible assets	7	3,801	4,131
Property, plant and equipment	7	398	323
Total intangible and tangible assets		4,199	4,454
Financial assets
Shares in subsidiaries	8	543,597	591,083
Intercompany receivables	19	86,081	86,895
Other long-term receivables		-	23
Investment in shares	8	-	16,174
Total financial assets		629,678	694,175
Total non-current assets		633,877	698,629
Current assets
Intercompany receivables	19	9,773	7,500
Other receivables	9	3,511	3,238
Cash and cash equivalents	10	641,007	515,018
Total current assets		654,291	525,756
TOTAL ASSETS		1,288,168	1,224,385

Parent company accounts Annual Report and Accounts 2022 DNO 77

EQUITY AND LIABILITIES

Years ended 31 December USD thousand	Note	2022	2021
Paid-in capital
Share capital		34,777	32,936
Treasury shares		-869	-
Share premium		343,620	247,743
Total paid-in capital	11	377,528	280,679
Retained earnings
Retained earnings		263,269	37,808
Total retained earnings	11	263,269	37,808
Total equity	11	640,797	318,487
Non-current liabilities
Intercompany liabilities	19	80,967	83,256
Interest-bearing liabilities	13	521,401	780,692
Other non-current liabilities		1,283	295
Total non-current liabilities		603,651	864,243
Current liabilities
Trade payables and provisions for other liabilities and charges	14	18,461	19,515
Intercompany liabilities	19	-	20
Dividend	11	25,259	22,120
Total current liabilities		43,720	41,655
Total liabilities		647,371	905,898
TOTAL EQUITY AND LIABILITIES		1,288,168	1,224,385

Oslo, 15 March 2023

Bijan Mossavar-Rahmani Executive Chairman
Gunnar Hirsti Deputy Chairman
Elin Karfjell Watson Director
Anita Marie Hjerkinn Aarnæs Director
Bjørn Dale Managing Director

Parent company accounts 78 DNO Annual Report and Accounts 2022

Cash flow statement

1 January - 31 December USD thousand	Note	2022	2021
Operating activities
Profit/-loss before income tax		342,508	222,140
Adjustments to add (deduct) non-cash items:
Depreciation and impairment of tangible and intangible assets	7	1,353	1,110
Impairment/-reversal of impairment of financial assets	5	152,601	95,661
Change in fair value of financial investments	5	-14,211	-3,580
Amortization of borrowing issue costs	5,13	4,454	8,927
Interest expense	5	52,153	65,414
Interest income	5	-9,429	-1,353
Other		-728	3,171
Changes in working capital and provisions:
- Trade and other receivables		-2,523	-3,901
- Trade and other payables		-1,054	5,993
- Provisions for other liabilities and charges		968	20
Cash generated from operations		526,092	393,602
Income taxes paid	6
Interest received		9,504	1,353
Interest paid		-53,636	-65,429
Dividend received	5	-	-
Net cash from/-used in operating activities		481,961	329,526
Investing activities
Purchases of intangible and tangible assets	7	-1,098	-533
Loans to subsidiaries	19	-5,325	-3,880
Proceeds from sale of financial investments		1,017	-
Net cash from/-used in investing activities		-5,406	-4,413
Financing activities
Repayment of borrowings	13	-263,745	-5,093
Payment debt issue costs	13	-	-15,609
Loans from subsidiaries	19	-2,289	-66,881
Purchase of treasury shares	11	-11,713	-
Paid dividend	11	-72,819	-22,177
Net cash from/-used in financing activities		-350,565	-109,760
Net increase/-decrease in cash and cash equivalents		125,989	215,353
Cash and cash equivalents at the beginning of the period		515,018	299,665
Cash and cash equivalents at end of the period	10	641,007	515,018
Of which restricted cash		2,153	2,851

Parent company accounts Annual Report and Accounts 2022 DNO 79

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

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.

Parent company accounts

Note 2 Operating revenues

1 January - 31 December
USD thousand	2022	2021
Operating revenues	27,448	24,190
Total operating revenues	27,448	24,190

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	2022	2021
Payroll and other social expenses
Salaries, bonuses and other salary expenses	-15,088	-14,050
Employer's payroll tax expense	-2,487	-2,384
Pensions	-2,164	-1,969
Other personnel costs	-775	-1,001
Total payroll and other social expenses	-20,514	-19,404
Average number of man-labor years	56	56

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)

	2022	2021
Bijan Mossavar-Rahmani, Executive Chairman, member of the nomination and remuneration committees	919.8	832.8
Gunnar Hirsti, Deputy Chairmen (from June 2022), chairs the audit committee and is a member of the remuneration committee	72.1	65.6
Lars Arne Takla, former Deputy Chairman and member of the HSSE committee (until May 2022)	26.0	69.7
Elin Karfjell, Director, member of the audit committee	59.1	59.2
Anita Marie Hjerkinn Aarnæs, Director, member of the HSSE committee (from June 2022)	38.2	-
Shelley Watson, former Director and member of the audit and HSSE committees (until November 2022)	59.6	65.6
Total	1,174.8	1,092.8

Total remuneration to the Board of Directors consists of regular fees (USD 1,126,870) and fees for participation in the board committees (USD 47,961). Separately, a fee of USD 3,194 was paid to Kåre Tjønneland for service on the nomination committee. The Company may reimburse travel expenses and other relevant expenses incurred by the members of the Board of Directors in connection with the performance of their duties.

Remuneration to Managing Director and executive management (USD thousand)

	Salary	Bonus	shares*	Other	Total	Pension
Bjørn Dale, Managing Director	638.8	258.2	84.0	82.0	1,063.1	19.7
Chris Spencer, Chief Operating Officer	579.4	68.3	152.3	82.7	882.7	19.7
Haakon Sandborg, Chief Financial Officer	426.2	33.1	67.2	44.3	570.9	19.7
Geir Arne Skau, Chief Human Resources and Corporate Services Officer	378.3	37.5	67.7	67.9	551.4	19.7
Sameh Hanna, General Manager Kurdistan region of Iraq (from August 2022)	193.5	-	-	67.0	260.5	-
Ørjan Gjerde, General Manager DNO North Sea	416.8	16.1	-	35.8	468.7	19.7

• Synthetic share awards that vested during the year.
  ** Total remuneration of USD 2.4 million (not included in the above table) was in 2022 paid to the following former members of the executive management: Nicholas Whiteley (former Chief Commercial Officer) and Tom Allan (former General Manager Kurdistan region of Iraq).

The following members of the executive management are employed in subsidiaries of DNO ASA: Ørjan Gjerde and Sameh Hanna. 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.

	Opening balance (1 Jan)	Movemements (full-year)	Settled*	Closing balance (31 Dec)	Weight. average price at 31 Dec	Unresrict. average	Number of shares
Bjørn Dale, Managing Director	73,992	36,094	73,992	36,094	-	10.92	-
Chris Spencer, Chief Operating Officer	586,813	1,095,215	232,862	1,449,166	379,265	11.81	-
Haakon Sandborg, Chief Financial Officer	205,547	774,786	30,188	950,145	30,409	10.92	-
Geir Arne Skau, Chief Human Resources and Corporate Services Officer	59,597	768,600	60,601	767,596	-	14.89	-
Sameh Hanna, General Manager Kurdistan Region of Iraq*	-	-	-	-	-	-	-
Ørjan Gjerde, General Manager DNO North Sea	-	11,696	-	11,696	-	-	-

• Synthetic shares settled in cash. The weighted average settlement price for synthetic shares settled during 2022 was NOK 12.40. The weighted average remaining contractual life of the synthetic shares was 2.4 years. The synthetic share awards and vesting period is between one and five years and require continued employment in the Company accordingly. Following vesting, the employee is free to settle the shares in cash. For an overview of synthetic shares at yearend 2022, see Note 5 in the consolidated accounts. For more information regarding determination of salary and other remuneration to the executive management and other leading personnel please refer to the separate remuneration report published on the Company’s website.

Auditor fees

1 January - 31 December
All figures are exclusive of VAT (USD thousand)	2022	2021
Auditor fees	-296	-306
Other financial audit services	-26	-16
Total auditing fees	-322	-322
Tax assistance	-54	-82
Other assistance	-	-
Total auditor fees	-376	-404

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

Note 4 Other operating expenses

1 January - 31 December
USD thousand	2022	2021
Lease expense on buildings and equipment	-2,492	-2,557
Other office expenses	-203	-14
IT expenses	-9,760	-8,871
Travel expenses	-1,146	-164
Legal expenses	-281	-582
Consultant fees	-3,418	-2,051
Other general and administrative costs	-1,113	-992
Total other operating expenses	-18,414	-15,231

Note 5 Net financial income/-expenses

1 January - 31 December
USD thousand	2022	2021
Dividend and group contribution received from group companies	556,648	414,019
Interest received	9,429	1,353
Interest received from group companies	6,050	4,074
Gain on foreign exchange	4,925	4,214
Change in fair value of financial investments	14,211	3,580
Total financial income	592,138	427,240
Interest expenses	-52,153	-65,414
Interest expenses group companies	-13,106	-9,862
Loss on foreign exchange	-7,204	-4,655
Impairment of financial assets	-152,601	-95,661
Other financial expenses	-11,733	-17,952
Total financial	### Note 5 Financial income/-expenses

	2022 (USD thousand)	2021 (USD thousand)
Interest income	-112,434	-100,462
Interest expense	355,341	233,695
Impairment financial assets	-152,611	-95,720
Change in fair value of financial investments	-15,907	-3,600
Other financial expenses	-11,270	-17,789
Net financial income/-expenses	355,341	233,695

In 2022, the impairment of financial assets of USD 152.6 million was mainly related to DNO North Sea plc (USD 146.4 million), DNO Yemen AS (USD 3.6 million) and DNO Oman Ltd (USD 1.1 million). Change in fair value of financial investments was related to the Company’s shareholding in RAK Petroleum until transaction completion with RAK Petroleum (see note 10 in the consolidated accounts). Other financial expenses in 2022 were mainly related to amortization of bond issue costs (USD 4.5 million) and expensing of bond premium and fees related to repurchase of bonds (USD 6.8 million). In 2021, the impairment of financial assets of USD 95.7 million was mainly related to DNO North Sea plc (USD 91.3 million), DNO Mena AS (USD 2.9 million) and DNO Yemen AS (USD 2 million). The change in fair value of financial investments of USD 3.6 million recognized in 2021 was due to the increase in fair value related to the Company’s shares in RAK Petroleum. Other financial expenses in 2021 were mainly related to amortization of bond issue costs (USD 8.9 million) and expensing of bond premium and fees related to repurchase and cancellation of bonds (USD 8.9 million).

Parent company accounts

Annual Report and Accounts 2022

DNO 83

Note 6 Taxes

	2022 (USD thousand)	2021 (USD thousand)
Change in deferred taxes	-	-
Income tax receivable/-payable	-	-
Tax income/-expense	-	-

Reconciliation of tax income/-expense

	2022 (USD thousand)	2021 (USD thousand)
Profit/-loss before income tax	342,508	222,140
Expected income tax according to nominal tax rate of 22 percent	-75,352	-48,892
Foreign exchange variations between functional and tax currency	4,063	-607
Adjustment of deferred tax assets not recognized	-18,113	-20,757
Impairment financial assets	-30,233	-17,684
Tax-free dividend from subsidiaries	119,125	88,490
Other items	510	-549
Tax income/-expense	-	-
Effective income tax rate	0%	0%

Tax effects of temporary differences and losses carried forward

	2022 (USD thousand)	2021 (USD thousand)
Intangible assets	-38	-63
Losses carried forward	83,750	86,637
Non-deductible interests carried forward	26,358	28,003
Other temporary differences	-816	-2,762
Deferred tax assets/-liabilities	109,254	111,815
Valuation allowance	-109,254	-111,815
Net deferred tax assets/-liabilities	-	-
Recognized deferred tax assets	-	-
Recognized deferred tax liabilities	-	-

The corporate tax rate in Norway is 22 percent. The carry forward period for unused losses in Norway is indefinite. Non-deductible interest expense can be carried forward for a period of up to 10 years and will expire in the period 2026 to 2031. A deferred tax asset has not been recognized for these losses as there is uncertainty regarding future taxable profits. The losses cannot be used towards petroleum activities on the NCS. The petroleum activities carried out abroad by Norwegian subsidiaries are tax exempt in Norway and under the exemption method dividends from subsidiaries are not taxable in Norway.

Parent company accounts

DNO 84

Annual Report and Accounts 2022

Note 7 Property, plant and equipment/Intangible assets

	Intangible assets (USD thousand)	PP&E (USD thousand)	Total (USD thousand)
Costs as of 1 January 2022	14,778	3,322	18,100
Additions	742	356	1,098
Costs as of 31 December 2022	15,520	3,678	19,198
Accumulated depreciation as of 1 January 2022	-10,647	-2,999	-13,646
Depreciation	-1,072	-281	-1,353
Accumulated depreciation and impairments as of 31 December 2022	-11,719	-3,280	-14,999
Book value as of 31 December 2022	3,801	398	4,199
Book value as of 31 December 2021	4,131	323	4,454

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

Subsidiaries owned by the Company	Office	Ownership (percent)	Share capital (1,000 USD)	Book net profit/ (loss) in equity (1,000 USD)	Book value in (1,000 USD)
DNO Yemen AS*	Norway	100	NOK 291,000	-62,618	-9,886
DNO UK Limited	UK	100	GBP 100	-120	-7
DNO Iraq AS	Norway	100	NOK 1,200	1,006,814	578,000
DNO Mena AS**	Norway	100	NOK 2,000	4,603	1,356
DNO Technical Services AS	Norway	100	NOK 200	5,285	-37
DNO Exploration UK Limited	UK	100	GBP 30,912	-1,238	132
DNO North Sea plc**	UK	100	GBP 37,289	157,585	-114,581
Mondoil Enterprices LLC**	United States	100	USD 1	105,120	6,144
Total				1,215,431	461,121

• Production start-up at the Block 47 in Yemen remains on hold due to force majeure.
  ** See Note 21 in the consolidated accounts.

The figures above include the respective subgroup's equity and any excess values recognized by the Group. In 2022, the book value of shares in subsidiaries was partially written off by USD 146.5 million mainly related to DNO North Sea plc. In 2021, the book value of shares in subsidiaries was partially written off by USD 93.4 million related to DNO North Sea plc (USD 91.3 million) and DNO Mena AS (USD 2 million). Northstar Oman AS and Føroya Kolvetni P/F were liquidated in 2021. See Note 5 for further details. 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.

Parent company accounts

DNO 85

Annual Report and Accounts 2022

Note 9 Other receivables

	2022 (USD thousand)	2021 (USD thousand)
Prepayments and accrued income	2,549	2,169
Other short-term receivables	962	1,069
Other receivables	3,511	3,238

Note 10 Cash and cash equivalents

	2022 (USD thousand)	2021 (USD thousand)
Cash and cash equivalents, restricted	2,153	2,851
Cash and cash equivalents, non-restricted	638,854	512,167
Total cash and cash equivalents	641,007	515,018

Restricted cash relates to employees' tax withholdings and deposits for rent. Non-restricted cash is entirely related to bank deposits in USD, NOK, EUR and GBP as of 31 December 2022.

Note 11 Equity

	Total capital registered shares (USD thousand)	Treasury share capital (USD thousand)	Share premium (USD thousand)	Retained earnings (USD thousand)	Total equity (USD thousand)
Shareholders' equity as of 1 January 2021	32,936	-	32,936	247,743	-140,415
Purchase of treasury shares	-	-	-	-	-
Dividend	-	-	-	-	-21,797
Additional dividend provision	-	-	-	-	-22,120
Profit/-loss for the year	-	-	-	-	222,140
Shareholders' equity as of 31 December 2021	32,936	-	32,936	247,743	37,808
	-	-	-	-	-
Shareholders' equity as of 1 January 2022	32,936	-	32,936	247,743	37,808
Purchase of treasury shares	-	-869	-869	-	-41,837
Share capital increase	1,841	-	1,841	95,877	-
Dividend	-	-	-	-	-49,951
Additional dividend	-	-	-	-	-25,259
Profit/-loss	-	-	-	-	342,508
Shareholders' equity as of 31 December 2022	34,777	-869	33,908	343,620	263,270

See Note 14 in the consolidated accounts for further information regarding the Company’s equity and shareholders. During 2022, the Board of Directors approved two dividend payments of NOK 0.25 per share. The dividends were paid on 23 August and 16 November 2022. On 9 February 2023, the Company announced that pursuant to the authorization granted at the 2022 AGM, the Board of Directors decided to distribute a dividend payment of NOK 0.25 per share on 22 February 2023.

Parent company accounts

DNO 86

Annual Report and Accounts 2022

Note 12 Guarantees, leasing liabilities and commitments

See Note 19 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 million.

Note 13 Interest-bearing liabilities

Ticker	Facility	Facility currency	Interest rate (percent)	Maturity	Fair value (percent)	Carrying amount (USD thousand) 2022	Carrying amount (USD thousand) 2021
DNO03	Bond loan	USD	8.375	29.05.24	9.0	131,507	410,202
DNO04	Bond loan	USD	7.875	09.09.26	8.8	375,816	414,000
						-9,761	-14,215
Total non-current interest-bearing liabilities						507,323	824,202

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

Note 14 Current liabilities

	2022 (USD thousand)	2021 (USD thousand)
Trade payables	3,255	4,398
Public duties payable	1,794	2,524
Accrued expenses and other current liabilities	13,412	12,593
Trade payables and provisions for other liabilities and charges	18,461	19,515

Accrued expenses and other current liabilities include accrued interest for bond loans of USD 2.8 million (USD 4.8 million in 2021) and accruals for incurred costs of USD 10.5 million (USD 3.4 million in 2021).

Note 15 Financial instruments

See Note 18 in the consolidated accounts for information on financial instruments.

Parent company accounts

Annual Report and Accounts 2022

DNO 87

Note 16 Related party disclosure

Overhead expenses and IT-services in the parent company are allocated to the subsidiaries based on their proportional use of the services provided by the parent company. See Note 22 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 Significant events after the reporting date

See Note 19 and Note 25 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	2022	2021
Net profit/-loss attributable to ordinary equity holders of the parent		342,508	222,140
Weighted average number of ordinary shares (excluding treasury shares) (millions)		986.97	975.43
Earnings per share, basic (USD per share)		0.35	0.23
Earnings per share, diluted (USD per share)		0.35	0.23

Note 19 Intercompany

Long-term intercompany receivables/liabilities

Functional Receivables	Liabilities	USD thousand	currency	2022	2021	2022	2021
DNO Iraq AS		USD		-	-	76,115	79,195
DNO Mena AS		USD		2,503	1,486	-	-
DNO North Sea (Norge) AS		NOK		-	2,524	-	-
DNO North Sea plc		USD		83,580	81,322	-	-
DNO Oman Block 8 Limited		USD		-	-	4,852	4,061
DNO Oman Block 30 Limited		USD		-	556	-	-
DNO Oman Limited		USD		-	1,008	-	-
Total long-term intercompany receivables and liabilities				86,081	86,895	80,967	83,256

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 set at arm's length.

Parent company accounts

88 DNO Annual Report and Accounts 2022

Note 19 Intercompany

Short-term intercompany receivables/liabilities

Functional Receivables	Liabilities	USD thousand	currency	2022	2021	2022	2021
DNO Iraq AS		USD		3,658	3,079	-	-
DNO Mena AS		USD		73	-	-	-
DNO Norge AS		USD / NOK		2,461	3,178	-	-
DNO North Sea (Norge) AS		NOK		-	66	-	-
DNO North Sea Plc		GBP		1,967	1,128	-	-
DNO North Sea (U.K.) Limited		GBP		3	17	-	-
DNO North Sea (ROGB) Limited		GBP		-	29	-	-
DNO Technical Services AS		USD		1,423	-	-	20
DNO Oman Block 8 Limited		USD		188	-	-	-
Other		USD		4	-	-	-
Total Short-term intercompany receivables and liabilities				9,773	7,500	-	20

Intercompany sales/purchases

Functional Sales	Purchases	USD thousand	currency	2022	2021	2022	2021
DNO Iraq AS		USD		8,659	17,646	-91	-
DNO Norge AS		USD		3,235	4,567	-1,616	-2,754
DNO North Sea plc		USD		501	447	-	-
DNO North Sea (U.K.) Limited		USD		25	83	-	-
DNO North Sea (ROGB) Limited		USD		70	143	-	-
DNO Oman Limited		USD		26	21	-	-
DNO Oman Block 8 Limited		USD		42	112	-	-
DNO Technical Services AS		USD		14,741	1,018	-3,033	-2,481
DNO Yemen AS		USD		107	111	-	-
Other		USD		43	44	-8	-
Intercompany sales/purchases				27,448	24,190	-4,741	-5,244

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

Functional Interest income, dividend	Interest expense and group contribution	USD thousand	currency	2022	2021	2022	2021
DNO Iraq AS		USD		555,590	410,000	-12,595	-8,889
DNO Mena AS		USD		1,058	1,441	-	-
DNO North Sea (Norge) AS		USD		107	2,650	-	-
DNO North Sea Plc		USD		5,943	4,001	-	-
DNO Oman Block 8 Limited		USD		-	-	-511	-974
Intercompany interest income/-expense				562,698	418,092	-13,106	-9,863

See Note 5 for more details on financial items.

Parent company accounts

89 Annual Report and Accounts 2022 DNO

Country-by-Country report 2022

In line with the Norwegian Accounting Act and Norwegian Securities Trading Act, the Company has prepared a country-by-country report for its activities in the extractive industries, including information on investments, revenue, production, cost and the number of employees in each country of operation by subsidiary. Among other requirements, total payments to governmental bodies during the financial year must be broken down by country and by payment type. Additional information regarding the Group's performance in each geographic area can be found in Note 2 of the DNO ASA’s Annual Report and Accounts 2022. A complete list of the Group's oil and gas license portfolio is disclosed in Note 24.

License, legal entity level and country/region of operation	Country of incorporation	Royalty	Net production	Corporate income tax	Special tax	Area fee	Contractual bonuses	Investments	Revenue	Expenditure	Net intercompany interest	Profit/-loss before tax	Tax income/-expense	Equity	Number of employees
Tawke		-333.5	80,326	-	-1,538.1	-	-	-	-	-	-	-	-	-	-
Baeshiqa		-1.6	343	-	-3.8	-	-	-	-	-	-	-	-	-	-
DNO Iraq AS	Norway	-	-	-	-	-	-	214.4	820.1	-252.5	-	578.0	-	1,006.8	1,140
Total Kurdistan region of Iraq		-335.1	80,669	-	-1,541.9	-	-	214.4	820.1	-252.5	-	578.0	-	1,006.8	1,140
DNO Norge AS	Norway	-	13,035	-13.1	-25.5	-0.7	-0.4	151.7	552.5	-273.8	-1.2	12.6	-7.1	202.6	145
Total Norway (NCS)		-	13,035	-13.1	-25.5	-0.7	-0.4	151.7	552.5	-273.8	-1.2	12.6	-7.1	202.6	145
DNO North Sea (U.K.) Limited	UK	-	159	-	-	-0.1	1.8	35.0	0.8	-27.0	-	-42.0	-18.0	-234.9	-
DNO North Sea (ROGB) Limited	UK	-	120	10.7	7.1	-0.1	-	1.3	3.7	-1.4	-	-3.1	-	-80.1	-
DNO Exploration UK Limited	UK	-	-	-	-	-	-	-	0.1	-	-	0.1	-	-1.2	-
Total United Kingdom (UKCS)		-	279	10.7	7.1	-0.2	1.8	36.3	4.5	-28.3	-	-45.0	-18.0	-316.2	-
Block 47		-	-	-	-	-	-	-	-	-	-	-	-	-	-
DNO Yemen AS	Norway	-	-	-	-	-	-	-	-	-	-9.9	-9.9	-	-62.6	2
Total Yemen		-	-	-	-	-	-	-	-	-	-9.9	-9.9	-	-62.6	2
DNO Mena AS	Norway	-	-	-	-	-	-	-	-	-	0.1	-	-	0.9	-
DNO ASA	Norway	-	-	-	-	-	-	27.4	-	-40.0	1.8	342.9	-	666.1	60
DNO Technical Services AS	Norway	-	-	-	-	-	-	-	40.9	-40.9	-	-	-	5.3	85
DNO North Sea plc	UK	-	-	-	-	-	-	-	-	-0.5	-4.6	-119.3	-	425.1	17
Other *		-	3,327	-	-	-	-	-	0.8	0.5	7.3	-3.1	-	-	-
Other *		-	3,327	-	-	-	-	68.3	-80.6	-2.4	231.0	-	-	1,100.4	162
Eliminations/ Intercompany		-	-	-	-	-	-	-68.3	64.9	-0.1	-420.2	63.6	-671.0	-	-
GRAND TOTAL		-335.1	97,310	-2.4	-1,560.4	-0.8	1.4	402.5	1,377.0	-580.2	-	346.5	38.4	1,369.4	1,449

• Other includes subsidiaries of DNO ASA that did not hold oil and gas licenses during the year and equity accounted investments.

• Country/region of operation is the country where the company carries out its main activity.

• Country of incorporation is the jurisdiction in which the legal entity is registered.
• Royalty is a fee payable to the Kurdistan Regional Government (KRG) before distribution of cost oil and profit oil.
• Net production in barrels of oil equivalent per day (boepd).
• Corporate tax received/-paid during the year. In Norway, corporate income tax relates to a tax refund of exploration costs and tax losses. In the UK, corporate income tax received relate to carry back of decommissioning loss.
• Special tax received/-paid during the year. In Kurdistan, special tax represents Group's share of government take. In Norway, the special tax is an additional tax on petroleum activities. In the UK, special tax relates to carry back of decommissioning loss.
• Area fee in Kurdistan and Norway.
• Contractual bonuses include environment funds, training funds and rental fees in Kurdistan. In Norway, the amount is related to environmental fund (NOx fund).
• Investments as presented in the consolidated financial statements and include estimate changes in asset retirement obligations.
• Revenues, expenditure, profit/-loss before tax and equity at entity level in accordance with the accounting principles in the consolidated financial statements and include intercompany transactions. Audit of statutory financial statements has not been completed at the time of issuing this report.
• Expenditure as presented in accordance with the accounting principles in the consolidated financial statements and includes cost of goods sold, administrative expenses, other operating expenses and exploration costs expensed including intercompany transactions.
• Net intercompany interest income /-expense to/from Group companies incorporated in another jurisdiction.
• Tax income/-expense for the year.
• Number of employees at yearend.

Auditor’s report

90 DNO Annual Report and Accounts 2022

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Annual Report and Accounts 2022

DNO 91

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Auditor’s report

92 DNO Annual Report and Accounts 2022

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Auditor’s report

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DNO 93

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94 DNO Annual Report and Accounts 2022

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Auditor’s report

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DNO 95

Auditor’s report 2022

Auditor’s report

96 DNO Annual Report and Accounts 2022

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
	2022
Revenues	1,377.0
Lifting costs	-222.1
Tariffs and transportation	-30.2
Movement in overlift/underlift	8.1
Share of profit/-loss from Joint Venture	6.0
Exploration expenses	-96.5
Administrative expenses	-17.9
Other operating income/expenses	-5.0
EBITDA	1,019.5

EBITDAX

	USD million
	2022
EBITDA	1,019.5
Exploration expenses	96.5
EBITDAX	1,116.0

Lifting costs

	2022	2021
Lifting costs (USD million)	-222.1	-184.2
Net production (MMboe)*	34.3	34.5
Lifting costs (USD/boe)	6.5	5.3

• For accounting purposes, the net production from equity accounted investments is not included.

Capital expenditures

	USD million
	2022
Purchases of intangible assets	-74.6
Purchases of tangible assets	-300.2
Capital expenditures*	-374.8

• Exclude estimate changes on asset retirement obligations.# DNO Annual Report and Accounts 2022

Alternative performance measures

Operational spend USD million

	2022	2021
Lifting costs	-222.1	-184.2
Tariff and transportation expenses	-30.2	-34.5
Exploration expenses	-96.5	-132.3
Exploration cost previously capitalized carried to cost (Note 6 in the consolidated accounts)	52.2	54.1
Capital expenditures	-374.8	-280.6
Payments for decommissioning	-70.0	-86.2
Operational spend	-741.4	-663.8

Alternative performance measures

Equity ratio USD million

	2022	2021
Equity	1,369.4	1,018.8
Total assets	2,803.0	2,947.8
Equity ratio	48.9%	34.6%

Free cash flow USD million

	2022	2021
Net cash from/-used in operating activities*	1,056.3	728.8
Capital expenditures	-374.8	-280.6
Payments for decommissioning	-70.0	-86.2
Equity contribution into Joint Venture (Note 10)	-4.2	-
Dividends from Joint Venture (Note 10)	11.5	-
Free cash flow	618.8	362.0

Net debt USD million

	2022	2021
Cash and cash equivalents	954.3	736.6
Bond loans and reserve based lending	566.2	889.9
Net cash/-debt	388.2	-153.4

Reserve Life Index (R/P)*

	2022	2021
Net production (MMboe)	35.5	34.5
1P reserves	220.3	196.1
2P reserves	292.1	321.4
3P reserves	386.7	420.6
1P Reserve Life Index (R/P in years)	6.2	5.7
2P Reserve Life Index (R/P in years)	8.3	9.3
3P Reserve Life Index (R/P in years)	10.9	12.2

• Net production in 2022 and net reserves as of yearend 2022 includes West Africa segment (equity accounted investment). The net production and reserves from West Africa is accounted for effective from 1 January 2022.

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

Alternative performance measures

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.

Capital expenditures

Capital expenditures 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, capital expenditures 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 net cash from/-used in operating activities less capital expenditures, payments for decommissioning and net cash received/-paid from equity accounted investments. 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.

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 Resources
• bbls: Barrels of oil
• bcf: billion cubic feet
• Board of Directors: The Board of Directors of the Company
• boe: Barrels of oil equivalent
• bopd or boepd: Barrels of oil per day or barrels of oil equivalent per day
• CAPM: Capital Asset Pricing Model
• Company: DNO ASA
• Contingent resources: Quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations but not currently considered to be commercially recoverable or where a field development plan has not yet been submitted
• Contractor: A company or companies operating in a country under a PSC on behalf of the host government for which it receives either a share of production or a fee
• Cost oil: Share of oil produced which is applied to the recovery of costs under a Production Sharing Contract
• Crude oil, crude or oil: A mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated
• DKK: Danish kroner
• 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
• Net production: Production based on the participation interest in the license
• Net reserves and resources: Reserves and resources based on the participation interest in the license
• 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 rocks.
• PP&E: Property, plant and equipment
• 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
• RPS: RPS Energy Consultants
• SPE: Society of Petroleum Engineers
• UAE: The United Arab Emirates
• UK: The United Kingdom
• UKCS: The United Kingdom Continental Shelf
• USD: United States dollar
• WACC: Weighted Average Cost of Capital

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