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
21
Parent company accounts
74
Country-by-Country report
87
Auditor’s report
88
Alternative performance measures
94
Glossary and definitions
97
Annual Report and Accounts 2022
DNO
3
Highlights
Driven by high oil and gas prices and solid operational performance in 2022, DNO
1
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.
Highlights
1
“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.
4
DNO
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),
For reconciliation and more information about key figures, see the section on alternative performance measures.
Key figures
Board of Directors
Annual Report and Accounts 2022
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. She held the position as Director of Human Resources in the
Company from 2012 to 2015, prior to which she had served as Managing Partner at Heidrick & Struggles
and as Management Consultant with PA Consulting Group. Ms. Hjerkinn Aarnæs was a member of the
Board of Directors of Norwegian Finans Holding ASA from its inception. She is a certified EFQM
assessor. She holds a degree in Public Law and is a graduate of the University of Oslo (Cand Mag) and
Harvard University (MPA).
Board of Directors
6
DNO
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
8
DNO
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 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.
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
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
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 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
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.
● Total GHG emissions from operated assets and from all
DNO’s offices and travel stood at 585,481 tonnes of CO
2
equivalent (CO
2
e), compared to 426,109 tonnes in 2021.
● DNO’s total GHG emissions were made up of 580,636 tonnes
of CO
2
e in Scope 1 emissions, 370 tonnes of CO
2
e in Scope
2 emissions, and 4,475 tonnes of CO
2
e in Scope 3 emissions
(category six only).
● Through the operated Peshkabir-to-Tawke gas project a total
of 8.8 billion cubic feet (bcf) of otherwise-flared gas was
captured and injected in 2022 (up from 7.6 bcf in 2021),
delivering a GHG saving of 533,968 tonnes of CO
2
e (up from
463,788 tonnes of CO
2
e in 2021).
● The number of oil spills stood at 3, compared to 6 in 2021;
and
● The total volume spilled was 92 barrels compared to 32
barrels in 2021, most of which was removed and remediated.
The Company is not satisfied with its 2022 safety performance,
which broke a long-term trend of year-on-year reductions in
TRIF. In response, the Company has redoubled efforts with the
aim to bring 2023 TRIF down to the International Association of
Oil and Gas Producers (IOGP) industry average or better. We
continue to work with our employees and third-party contractors
on programs to improve safety performance.
The Scope 1 and Scope 2 GHG intensity from our operated
assets averaged 14.8 kilograms of CO
2
e (kgCO
2
e) per barrel of
oil equivalent (boe) produced in 2022, compared to 10.7
kgCO
2
e/boe in 2021. The year-on-year increase was driven by
early-stage oil production from the Baeshiqa license, which is
accompanied by gas flaring during testing. Nevertheless, our
performance compared favorably to the target set by a group of
12 of the world’s largest oil and gas companies comprising the
Oil and Gas Climate Initiative (OGCI) to reduce the average
intensity of their upstream operations to 17 kgCO
2
e/boe by
2025 from a collective baseline of 23 kgCO
2
e/boe in 2017.
Looking ahead, DNO has set a GHG emissions intensity target
well below the average of the global upstream industry.
In addition to its efforts to reduce CO2 emissions, DNO focuses
on reduction of methane emissions, a potent GHG. In 2022,
DNO joined the Aiming for Zero Methane Emissions Initiative,
an oil and gas industry pledge coordinated by the OGCI, to
reach near zero methane emissions from its operated oil and
gas assets by 2030 and actively work with its partners in its
non-operated assets to achieve the same. DNO has put in
place a Tawke license-wide Leak Detection and Repair (LDAR)
project to discover, measure and mitigate fugitive methane
emissions.
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
2
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
2
defined on the Company’s website.
Board of Directors’ report
16
DNO
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:
Women's compensation as percentage of
those of men's:
Base salary
Bonus
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.
Board of Directors’ report
Annual Report and Accounts 2022
DNO
17
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
18
DNO
Oslo, 15 March 2023
Bijan Mossavar-Rahmani
Gunnar Hirsti
Elin Karfjell
Executive Chairman
Deputy Chairman
Director
Anita Marie Hjerkinn Aarnæs
Bjørn Dale
Director
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.
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
Annual Report and Accounts 2022
DNO
19
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
Gunnar Hirsti
Elin Karfjell
Executive Chairman
Deputy Chairman
Director
Anita Marie Hjerkinn Aarnæs
Bjørn Dale
Director
Managing Director
Board of Directors’ report
20
DNO
Board of Directors’ report
Annual Report and Accounts 2022
DNO
21
Group company accounts
Consolidated statements of comprehensive income
21
Consolidated statements of financial position
22
Consolidated cash flow statements
23
Consolidated statements of changes in equity
24
Note disclosures
Note 1
Summary of IFRS accounting principles
25
Note 2
Segment information
36
Note 3
Revenues
38
Note 4
Cost of goods sold/Inventory
38
Note 5
Administrative/Other operating expenses
39
Note 6
Exploration expenses
41
Note 7
Financial income and financial expenses
41
Note 8
Income taxes
42
Note 9
Property, plant and equipment/Intangible assets
44
Note 10
Joint venture
50
Note 11
Financial investments
51
Note 12
Other non-current receivables/Trade and receivables
52
Note 13
Cash and cash equivalents
52
Note 14
Equity
53
Note 15
Interest-bearing liabilities
55
Note 16
Provisions for other liabilities and charges/Lease liabilities
56
Note 17
Trade and other payables
57
Note 18
Financial instruments
58
Note 19
Commitments and contingencies
63
Note 20
Earnings per share
64
Note 21
Group companies
65
Note 22
Related party disclosure
65
Note 23
Oil and gas reserves (unaudited)
66
Note 24
Oil and gas license portfolio
68
Note 25
Significant events after the reporting date
72
Parent company accounts
Income statement
74
Balance sheet
74
Cash flow statement
76
Note disclosures
77
Auditor’s report
88
Consolidated accounts
22
DNO
Consolidated statements of comprehensive income
1 January - 31 December
USD million
Note
2022
2021
Revenues
2, 3
Cost of goods sold
4
-460.9
-443.1
Gross profit
Share of profit/-loss from Joint Venture
10
Other income/-expenses
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
Financial income
7
Financial expenses
7
-98.7
-126.7
Profit/-loss before income tax
Tax income/-expense
8
-16.3
Net profit/-loss
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
Items that are not reclassified to profit or loss in later periods, net of tax
Total other comprehensive income, net of tax
-17.4
-8.9
Total comprehensive income, net of tax
Net profit/-loss attributable to:
Equity holders of the parent
Non-controlling interests
Total comprehensive income attributable to:
Equity holders of the parent
Non-controlling interests
Earnings per share, basic (USD per share)
20
Earnings per share, diluted (USD per share)
20
Weighted average number of shares outstanding (millions)
Consolidated accounts
Annual Report and Accounts 2022
DNO
23
Consolidated statements of financial position
Years ended 31 December
USD million
Note
2022
2021
ASSETS
Non-current assets
Deferred tax assets
8
Goodwill
9
Other intangible assets
9
Property, plant and equipment
9
Investment in Joint Venture
10
Financial investments
11
Other non-current receivables
12
Total non-current assets
Current assets
Inventories
4
Trade and other receivables
12
Tax receivables
8
Cash and cash equivalents
13
Total current assets
TOTAL ASSETS
EQUITY AND LIABILITIES
Equity
Shareholders' equity
14
Total equity
Non-current liabilities
Deferred tax liabilities
8
Interest-bearing liabilities
15
Provisions for other liabilities and charges
16
Total non-current liabilities
Current liabilities
Trade and other payables
17
Income taxes payable
8
Current interest-bearing liabilities
15
Provisions for other liabilities and charges
16
Total current liabilities
Total liabilities
TOTAL EQUITY AND LIABILITIES
Oslo,
15
Bijan Mossavar-Rahmani
Gunnar Hirsti
Elin Karfjell
Watson
Executive Chairman
Deputy Chairman
Director
Anita Marie Hjerkinn Aarnæs
Bjørn Dale
Director
Managing Director
Consolidated accounts
24
DNO
Consolidated cash flow statements
1 January - 31 December
USD million
Note
2022
2021
Operating activities
Profit/-loss before income tax
Adjustments to add/-deduct non-cash items:
Exploration cost previously capitalized carried to cost
6
Depreciation, depletion and amortization
4
Impairment oil and gas assets
9
Share of profit/-loss in Joint Venture
10
-6.0
Amortization of borrowing issue costs
Accretion expense on ARO provisions
7,16
Interest expense
7
Interest income
7
-12.9
-1.7
Other
Changes in working capital items and provisions:
- Inventories
-11.2
- Trade and other receivables
12
-99.5
- Trade and other payables
17
- Provisions for other liabilities and charges
Cash generated from operations
Income taxes paid
-5.1
Tax refund received/-repaid
-16.1
Interest received
Interest paid
-58.1
-73.0
Net cash from/-used in operating activities
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
Proceeds from license transactions
Proceeds from sale of financial investments
Equity contribution into Joint Venture
10
-4.2
Dividends from Joint Venture
10
Net cash from/-used in investing activities
-415.0
-362.0
Financing activities
Proceeds from borrowings
15
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
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
Cash and cash equivalents at beginning of the period
Exchange gain/-losses on cash and cash equivalents
-4.5
-2.0
Cash and cash equivalents at end of the period
13
Of which restricted cash
13
Consolidated accounts
Annual Report and Accounts 2022
DNO
25
Consolidated statements of changes in equity
Other comprehensive income
Fair value
Currency
Share
Share
changes equity
translation
Retained
Total
USD million
capital
premium
instruments
difference
earnings
equity
Total shareholders' equity as of 31 December 2020
-65.0
Fair value changes from equity instruments
Currency translation differences
-12.5
-12.5
Other comprehensive income
-12.5
-8.9
Profit/-loss for the period
Total comprehensive income
-12.5
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
-77.5
Other comprehensive income
Fair value
Currency
Share
Share
changes equity
translation
Retained
Total
USD million
capital
premium
instruments
difference
earnings
equity
Total shareholders' equity as of 31 December 2021
-77.5
Reallocation of equity*
-34.3
-45.8
Total shareholders' equity as of 1 January 2022
Fair value changes from equity instruments
Currency translation differences
-31.6
-31.6
Other comprehensive income
-31.6
-17.4
Profit/-loss for the period
Total comprehensive income
-31.6
Share capital increase**
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
-19.6
-94.2
-17.0
Total shareholders' equity as of 31 December 2022
-29.0
* 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
26
DNO
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
organized and existing under the laws of
Norwegian
(“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
1981, currently under the ticker "DNO". The Company's registered
office is located at
. DNO’s
activities are mainly undertaken in the Middle East, the North Sea
and West Africa.
■
Statement of compliance
The consolidated financial statements of
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
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
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:
•
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
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. 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
Consolidated accounts
Note 1
Summary of IFRS accounting principles
30
DNO
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.
Consolidated accounts
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2022
DNO
31
For those licenses that are not deemed to be joint arrangements
pursuant to the definition in IFRS 11, either because unanimous
consent is not required among the parties involved, or no single
group of parties has joint control over the activity, DNO
recognizes its share of related expenses, assets, liabilities and
cash flows under the respective items in the Group’s financial
statements in accordance with applicable IFRS standards. In
determining whether each separate arrangement related to
DNO’s joint operations is within or outside the scope of IFRS 11,
DNO considers the terms of relevant license agreements,
governmental concessions and other legal arrangements
impacting how and by whom each arrangement is controlled.
■
Foreign currency translation and transactions
Functional currency
The consolidated financial statements are presented in USD,
which is also DNO ASA’s functional currency and presentation
currency.
Items included in the financial statements of each subsidiary are
initially recorded in the subsidiary’s functional currency, i.e., the
currency that best reflects the economic substance of the
underlying events and circumstances relevant to that subsidiary.
Transactions and balances
Foreign currency transactions are translated into functional
currency of the Company or subsidiaries using the exchange
rates prevailing at the dates of the transactions. Financial assets
and financial liabilities in foreign currencies are translated into
functional currency at the balance sheet date exchange rates.
Foreign exchange gains and losses resulting from the settlement
of such transactions and from the translation of monetary assets
and liabilities denominated in foreign currencies are recognized in
profit or loss. Those arising in respect of financial assets and
liabilities are recorded on a net basis as a financial item.
Foreign exchange gains or losses 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
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. 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
Consolidated accounts
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2022
DNO
33
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.
Consolidated accounts
Note 1
Summary of IFRS accounting principles
34
DNO
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. 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.
Consolidated accounts
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2022
DNO
35
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
Consolidated accounts
Note 1
Summary of IFRS accounting principles
36
DNO
or its representatives. For accounting purposes, if such notional
income tax is to be classified as income tax in accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any deferred tax
asset or liability is required to be recognized equal to the
difference between book values and the tax values of the
qualifying assets and liabilities, multiplied by the applicable tax
rate.
■
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired asset or
groups of assets constitute a business (i.e., an integrated set of
operations and assets conducted and managed for the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements from
the transaction date. The transaction date is defined as the date
on which the Group achieves control over the financial and
operating assets. This date may differ from the actual date on
which the assets are transferred.
For accounting purposes, the acquisition method is used in
connection with the purchase of businesses. Acquisition cost
equals the fair value of the assets used as consideration,
including contingent consideration, equity instruments issued and
liabilities assumed in connection with the transfer of control.
Acquisition cost is measured against the fair value of the acquired
assets and assumed liabilities. Identifiable intangible assets are
included in connection with acquisitions if they can be separated
from other assets or meet the legal contractual criteria. If the
acquisition cost at the time of the acquisition exceeds the fair
value of the acquired net assets (when the acquiring entity
achieves control of the transferring entity), goodwill arises.
If the fair value of the acquired net assets exceeds the acquisition
cost on the acquisition date, the excess amount is taken to profit
or loss immediately.
Goodwill is allocated to the CGUs or groups of CGUs that are
expected to benefit from synergy effects of the acquisition. The
allocation of goodwill may vary depending on the basis of its initial
recognition.
The goodwill that is recognized by the Group is related to
technical goodwill and is recognized due to the requirement to
recognize deferred tax for the difference between the assigned
fair values and the related tax base. The fair values of the Group’s
licenses in the North Sea are based on cash flows after tax. This
is because these licenses are sold only on an after-tax basis. The
purchaser is therefore not entitled to a tax deduction for the
consideration paid above the seller’s tax values. In accordance
with IAS 12, a provision is made for deferred tax corresponding to
the tax rate multiplied by the difference between the fair values of
the acquired assets and the transferred tax depreciation basis.
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.
Consolidated accounts
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2022
DNO
37
■
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
38
DNO
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-
Full-Year ending
West
reporting
allocated/
Total
31 December 2022
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
820.1
556.9
-
-
1,377.0
-
1,377.0
Inter-segment sales
-
-
-
-
-
-
-
Production costs
-124.7
-127.7
-
-
-252.4
0.1
-252.3
Movement in overlift/underlift
-
8.1
-
-
8.1
-
8.1
Depreciation, depletion and amortization
-126.8
-86.5
-
-
-213.3
-3.4
-216.7
Cost of goods sold
4
-251.5
-206.1
-
-
-457.6
-3.3
-460.9
Gross profit
568.5
350.8
-
-
919.4
-3.3
916.1
Share of profit/-loss from Joint Venture
10
-
-
6.0
-
6.0
-
6.0
Other income
-
2.8
-
-
2.8
-
2.8
Administrative expenses
5
-0.1
-6.0
-
-2.3
-8.4
-9.5
-17.9
Other operating expenses
5
-0.9
-
-
-6.8
-7.7
-
-7.7
Impairment of oil and gas assets
9
-
-371.3
-
-
-371.3
-
-371.3
Exploration expenses
6
-
-96.5
-
-
-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
-85.0
Tax income/-expense
8
-
38.4
-
-
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
1,338.1
Current assets
355.4
418.3
-
11.5
785.3
679.7
1,464.9
Total assets
1,105.5
921.8
76.1
11.5
2,115.0
688.0
2,803.0
Non-current liabilities
68.1
391.8
-
-
459.9
528.4
988.4
Current liabilities
97.5
284.3
-
41.6
423.4
21.9
445.3
Total liabilities
165.6
676.1
-
41.6
883.3
550.3
1,433.6
Consolidated accounts
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2022
DNO
39
USD million
Total
Un-
Full-Year ending
West
reporting
allocated/
Total
31 December 2021
Note
Kurdistan
North Sea
Africa
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
594.3
409.8
-
-
1,004.1
-
1,004.1
Inter-segment sales
-
2.6
-
-
2.6
-2.6
-
Production costs
-99.6
-119.5
-
-
-219.1
0.3
-218.8
Movement in overlift/underlift
-
-18.3
-
-
-18.3
-
-18.3
Depreciation, depletion and amortization
-121.2
-81.7
-
-
-202.9
-3.1
-206.0
Cost of goods sold
4
-220.9
-219.4
-
-
-440.3
-2.7
-443.1
Gross profit
373.4
193.0
-
-
566.4
-5.4
561.0
Share of profit/-loss from Joint Venture
10
-
-
-
-
-
-
-
Other income
-
-
-
-
0.5
-
0.5
Administrative expenses
5
-0.3
-8.5
-
-1.8
-10.6
-5.6
-16.2
Other operating expenses
5
-2.2
-
-
-9.8
-12.0
-
-12.0
Impairment of oil and gas assets
9
-
-80.1
-
-
-80.1
-
-80.1
Exploration expenses
6
-2.8
-129.6
-
-
-132.3
-
-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
-100.7
Tax income/-expense
8
-
-15.9
-
-0.3
-16.3
-
-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
1,670.5
Current assets
372.2
367.1
-
11.5
750.8
526.5
1,277.3
Total assets
1,052.0
1,331.2
-
11.5
2,394.7
553.1
2,947.8
Non-current liabilities
63.2
691.2
-
-
754.4
788.8
1,543.2
Current liabilities
78.0
248.5
-
36.3
362.8
23.0
385.8
Total liabilities
141.2
939.8
-
36.3
1,117.2
811.7
1,929.0
Consolidated accounts
Note 3
Revenues
40
DNO
1 January - 31 December
Total
USD million
2022
2021
2022
2021
2022
2021
Sale of oil
820.1
594.3
241.0
233.8
1,061.1
828.1
Sale of gas
-
-
281.1
151.3
281.1
151.3
Sale of natural gas liquids (NGL)
-
-
29.1
21.3
29.1
21.3
Tariff income
-
-
5.8
3.4
5.8
3.4
Total revenues from contracts with customers
820.1
594.3
556.9
409.8
1,377.0
1,004.1
Sale of oil (bopd)
25,933
28,091
6,341
8,493
32,273
36,583
Sale of gas (boepd)
-
-
4,800
4,344
4,800
4,344
Sale of natural gas liquids (NGL) (boepd)
-
-
1,370
1,244
1,370
1,244
Total sales volume (boepd)
25,933
28,091
12,511
14,080
38,444
42,171
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
Annual Report and Accounts 2022
DNO
41
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
Consolidated accounts
Note 5
Administrative/Other expenses
42
DNO
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
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
Tax income/-expense
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
-
-
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.
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
46
DNO
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2022 - USD million
assets
assets
assets
PP&E
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
Depreciation, depletion and amortization (DD&A) is charged to cost of goods sold in the statements of comprehensive income.
Consolidated accounts
Note 9
Property, plant and equipment
Annual Report and Accounts 2022
DNO
47
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2022 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2022
Acquisition costs
456.8
98.1
368.4
14.6
481.1
938.0
Accumulated impairments
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Period ended 31 December 2022
Opening net book amount
88.2
21.2
207.1
4.1
232.4
320.6
Translation differences
-10.4
-1.0
-21.0
-
-22.0
-32.4
Additions
-
0.4
73.5
0.7
74.6
74.6
Transfers*
-
-
-132.6
-
-132.6
-132.6
Disposals cost price
-
-
-
-
-
-
Disposals impairments/depreciation
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-
-52.2
-
-52.2
-52.2
Impairments
-21.5
0.0
-0.0
-
0.0
-21.5
Depreciation
-
-1.9
-
-1.1
-3.0
-3.0
Closing net book amount
56.1
18.8
74.8
3.8
97.2
153.3
As of 31 December 2022
Acquisition costs
407.2
97.5
335.2
15.4
448.1
855.3
Accumulated impairments/exploration write-offs
-351.1
-8.8
-260.5
-
-269.3
-620.3
Accumulated depreciation
-
-70.1
-
-11.6
-81.6
-81.6
Net book amount
56.1
18.7
74.8
3.8
97.2
153.3
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).
Consolidated accounts
Note 9
Property, plant and equipment
48
DNO
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2021 - USD million
assets
assets
assets
PP&E
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
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2021 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2021
Acquisition costs
474.3
97.1
389.2
14.3
500.5
974.9
Accumulated impairments/exploration write-offs
-312.3
-7.7
-108.3
-
-116.0
-428.3
Accumulated depreciation
-
-66.4
-
-9.5
-75.9
-75.9
Net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Period ended 31 December 2021
Opening net book amount
162.0
23.0
280.9
4.7
308.6
470.6
Translation differences
-5.3
-
-9.6
0.2
-9.4
-14.7
Additions
-
1.0
85.3
0.4
86.7
86.8
Additions through license acquisition*
-
35.2
35.2
35.2
Transfers**
-
-
-125.7
-
-125.7
-125.7
Disposal cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposal impairments/depreciations
-
-
-
-
-
-
Exploration cost previously capitalized carried to cost
-
-1.1
-53.0
-54.1
-54.1
Impairments
-68.5
-
-
-
-
-68.5
Depreciation
-
-1.8
-
-1.0
-2.8
-2.8
Closing net book amount
88.2
21.1
207.1
4.0
232.3
320.6
As of 31 December 2021
Acquisition costs
456.8
98.1
368.4
14.6
481.2
938.0
Accumulated impairments/exploration write-offs
-368.6
-8.7
-161.3
-
-170.0
-538.6
Accumulated depreciation
-
-68.2
-
-10.5
-78.7
-78.7
Net book amount
88.2
21.2
207.1
4.0
232.4
320.6
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
** Transfers was related to reclassification of the book value of Baeshiqa license from exploration phase (intangible assets) to development phase
Consolidated accounts
Note 9
Property, plant and equipment
Annual Report and Accounts 2022
DNO
49
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.
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).
Consolidated accounts
Note 9
Property, plant and equipment
50
DNO
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:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Brasse, North Sea
-
-147.0
108.1
-38.9
-8.5
-
-138.5
108.1
-
Berling, North Sea
28.0
39.4
-30.7
8.7
-
-
39.4
-30.7
-
Ula area, North Sea
-
-252.5
182.1
-70.4
-13.0
-
-238.8
180.6
-0.7
Schooner and Ketch, North Sea
-
-13.5
-
-13.5
-
-
-13.4
-
-0.1
Other CGUs, North Sea
-
2.2
-1.4
0.8
-
-
2.2
-1.4
-
Total
-371.3
258.2
-113.1
-21.5
-
-349.1
256.6
-0.8
Full-Year ended 31 December 2021
Income statement:
Balance sheet:
(in USD million)
Impairment
Impairment
Recoverable
Tax
Other
Property,
Deferred
amount
reversal
income
reversal
intangible
plant and
tax asset/
Currency
CGU, segment
(post-tax)
(pre-tax)
(post-tax)
Goodwill
assets
equipment
effects
Fenja, North Sea
54.0
-9.7
-9.7
-9.7
-
-
-
-0.1
Trym area, North Sea
9.0
-7.7
-7.7
-7.7
-
-
-
-0.3
Ula area, North Sea
158.0
-51.1
-51.1
-51.1
-
-
-
0.4
Oselvar, North Sea
-
1.5
-1.2
0.3
-
-
1.5
-1.2
-
Schooner and Ketch, North Sea
-
-11.2
4.1
-7.1
-
-
-11.2
4.1
-
Other CGUs, North Sea
-
-1.9
-
-1.9
-
-
-1.9
-
-
Total
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
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.
Change in reported net profit/-loss (net)
Assumption (USD million)
Change
Increase in assumption:
Decrease in assumption:
Oil and gas price
-
-12
Reserves (2P) and resources (2C)
-
-1
Discount rate (WACC)
-
-
Currency rate (USD/NOK)
-
-3
Consolidated accounts
Note 9
Property, plant and equipment
Annual Report and Accounts 2022
DNO
51
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
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:
Oil price USD/bbl (assumption)
Gas price USD/MMBTU (assumption)
Change in reported
IEA scenario (USD million)
2030
2050
2030
2050
net profit/-loss (net):
Stated Policies
82
95
8.5
-
Announced Pledges
64
60
7.9
-
Net Zero Emissions by 2050
35
24
4.6
-44
A significant reduction in the oil and gas price assumptions could also affect the estimated economic cut-off of the projects.
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. Moreover, a significant and
prolonged reduction in oil and gas prices would likely result in mitigating actions by DNO and its license partners; for example it could
have an impact on drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered
impracticable, as it requires detailed evaluations based on hypothetical scenarios and not based on existing business or development
plans.
License expiry and economic cut-off dates for development and production assets
In Kurdistan, the Tawke license expires in 2026 but DNO has the right to one automatic five-year extension (i.e., to 2031) and, if
commercial production is still possible at the end of this extended period, DNO is entitled to, upon request to the KRG, a further five-
year extension (i.e., to 2036). Based on DNO’s current assessments, the production from Tawke license will be commercial for the
duration of its contractual term and through subsequent extensions. On the Baeshiqa license, commerciality was declared by the
contractor on 1 August 2021, terminating the exploration period and moving into the PSC development period, which has as a 20-year
duration. If commercial production is still possible at the end of the 20-year period, DNO is entitled to a five-year extension.
In the North Sea, the following relevant license expiry and economic cut-off (in brackets) dates were applied in relation to yearend 2022
impairment assessments; the Ula area CGU have license expiry dates that ranges between 2027 and 2036 (economic cut-off assumed
to be at the end of 2026); the Ringhorne East license expires in 2030 (2046); the Brage license expires in 2030 (2028); the Trym license
expires in 2027 (2026); the Alve license expires in 2029 (2029); an application for extension of the Marulk license from 2025 to 2026 has
been submitted and is pending approval (2026); the Vilje license expires in 2032 (2040); the Fenja license expires in 2039 (2037); and
the Berling license expires in 2023 (2033, application for license extension was included in the PDO submission, subject to approval).
Consolidated accounts
Note 10
Joint Venture
52
DNO
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
USD million
completion date
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
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
Consolidated accounts
Note 10
Joint Venture
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
Year ended 31
Movement in the carrying amount of Investment in Joint Venture
completion date
USD million
2022
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).
Consolidated accounts
Note 12
Other non-current receivables/Trade and other receivables
54
DNO
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.
The underlift receivable of USD 14 million as of 31 December 2022 relates to North Sea underlifted volumes. Other short-term
receivables mainly relate to items of working capital in licenses in Kurdistan and the North Sea and accrual for earned income not
invoiced in the North Sea.
Note 13
Cash and cash equivalents
Years ended 31 December
USD million
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.
Consolidated accounts
Note 14
Equity
Annual Report and Accounts 2022
DNO
55
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2021
975,433
32.9
-
32.9
Treasury shares sold/-purchased
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
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
Interest
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.
Consolidated accounts
Note 15
Interest-bearing liabilities
Annual Report and Accounts 2022
DNO
57
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150.7
8.375
29.05.24
9.0
131.5
410.2
131.2
394.9
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
375.8
414.0
400.0
400.0
Capitalized borrowing issue costs
-11.3
-16.5
Reserve based lending facility
-
USD
350.0
see below
see below
-
26.6
95.0
26.6
95.0
Total non-current interest-bearing liabilities
533.9
919.2
546.4
873.4
Current
Reserve based lending facility (current)
-
NOK
350.0
see below
see below
-
8.4
-
8.4
-
Total current interest-bearing liabilities
8.4
-
8.4
-
Total interest-bearing liabilities
542.3
919.2
554.8
873.4
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2022
flows
Amortization
Currency
Acquisition
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
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2021
flows
Amortization
Currency
Acquisition
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
Consolidated accounts
Note 16
Provisions for other liabilities and charges/Lease liabilities
58
DNO
Years ended 31 December
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
6.5
12.5
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
non-
USD million
obligations
current
Provisions as of 1 January 2021
523.3
3.4
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
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
Effect on profit
oil and gas price
before tax
2022
+/- 15.0
2021
+/- 15.0
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
Effect on profit
NOK (percent)
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
Effect on profit
GBP (percent)
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
Effect on profit
EUR (percent)
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
Effect on profit
in basis points
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
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.
USD million
On
Less than
3 to 12
1 to 3
Over 3
At 31 December 2022
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 31 December 2021
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.
Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing
financial loss to the Group. The Group’s exposure to credit risk is mainly related to its outstanding trade debtors. Other counterparty
credit risk exposure to DNO is related to its cash deposits with banks and financial institutions. The table below provides an overview of
financial assets exposed to credit risk at yearend.
Years ended 31 December
USD million
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.
Consolidated accounts
Note 18
Financial instruments
Annual Report and Accounts 2022
DNO
63
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
311.8
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
362.6
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.
Consolidated accounts
Note 18
Financial instruments
64
DNO
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).
Carrying amount
Financial
Financial
Fair value hierarchy
assets
liabilities
designated
at amortized
2021 - 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
16.2
-
16.2
31 December 2021
16.2
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
873.4
873.4
31 December 2021
824.2
-
95.0
Interest-bearing liabilities (current)
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.
Consolidated accounts
Note 20
Earnings per share
66
DNO
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.
Consolidated accounts
Note 21
Group companies and other companies
Annual Report and Accounts 2022
DNO
67
Ownership and voting
USD million
Office
interest (percent)
Shares in the Company's subsidiaries
DNO Iraq AS
Norway
100
DNO UK Limited
United Kingdom
100
DNO Mena AS
Norway
100
DNO Technical Services AS
Norway
100
DNO Exploration UK Limited
United Kingdom
100
DNO Yemen AS
Norway
100
DNO North Sea plc
United Kingdom
100
Mondoil Enterprises LLC
United States
100
Shares in subsidiaries owned through subsidiaries
DNO Mena AS
DNO Oman Limited
Bermuda
100
DNO Oman Block 8 Limited
Guernsey
100
DNO Oman Block 30 Limited
Guernsey
100
North Limited
Guernsey
100
DNO Tunisia Limited
Guernsey
100
DNO North Sea plc
DNO Norge AS
Norway
100
DNO North Sea (UK) Limited
United Kingdom
100
DNO North Sea (ROGB) Limited
United Kingdom
100
DNO North Sea (Energy) Limited
United Kingdom
100
DNO North Sea SIP EBT Limited
United Kingdom
100
Shares in other entities, indirectly (equity accounted)
Mondoil Côte d’Ivoire LLC
United States
50
Foxtrot International LDC
Cayman Islands
33.33
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.
1 January - 31 December
Related party (USD million)
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.
Consolidated accounts
Note 23
Oil and gas reserves (unaudited)
68
DNO
Net reserves by region/field as of 31 December 2022
Proven (1P)
Proven and probable (2P)
Proven, probable and possible (3P)
MMboe
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Oil
NGL
Gas
Total
Tawke
126.1
-
-
126.1
157.3
-
-
157.3
208.0
-
-
208.0
Peshkabir
64.8
-
-
64.8
88.0
-
-
88.0
108.0
-
-
108.0
Total Kurdistan
190.9
-
-
190.9
245.3
-
-
245.3
316.0
-
-
316.0
Blane
0.3
-
-
0.3
0.8
-
-
0.8
1.2
-
-
1.2
UK
0.1
-
-
0.1
0.1
-
-
0.1
0.1
-
-
0.1
Total UK
0.4
-
-
0.4
0.9
-
-
0.9
1.3
-
-
1.3
Alve
0.3
0.3
1.6
2.3
0.6
0.9
3.0
4.5
0.8
1.4
4.7
6.9
Andvare
0.1
0.5
2.6
3.2
0.2
0.8
3.7
4.7
0.3
1.2
5.1
6.7
Berling
1.0
0.7
3.5
5.2
1.5
1.1
4.9
7.4
2.1
1.5
6.3
9.9
Brage
0.9
0.1
0.2
1.2
1.3
0.2
0.4
1.9
2.1
0.3
0.7
3.1
Fenja
1.7
0.1
0.6
2.4
2.7
0.1
0.8
3.5
4.0
0.1
1.1
5.1
Marulk
-
0.2
0.6
0.8
-
0.2
0.8
1.0
-
0.2
0.9
1.1
Oda
1.3
-
0.1
1.4
1.5
0.1
0.1
1.7
1.7
0.1
0.1
1.9
Ringhorne East
1.3
-
-
1.3
1.8
-
-
1.8
2.3
-
-
2.3
Tambar
1.4
0.1
0.3
1.7
2.0
0.1
0.4
2.5
2.4
0.1
0.5
3.0
Tambar East
0.2
-
-
0.3
0.7
0.1
0.1
0.9
1.3
0.2
0.2
1.6
Trym
0.2
-
1.0
1.2
0.3
-
1.0
1.3
0.4
-
1.5
1.9
Ula
1.2
0.1
-
1.3
1.7
0.2
-
1.9
1.8
0.2
-
2.0
Vilje
2.3
-
-
2.3
2.5
-
-
2.5
2.7
-
-
2.7
Total Norway
11.9
2.1
10.5
24.6
16.8
3.8
15.2
35.6
21.9
5.3
21.1
48.1
Subtotal Consolidated reserves
215.9
281.8
365.4
Côte d'Ivoire
0.2
-
4.2
4.4
0.4
-
9.9
10.3
0.7
-
20.6
21.3
Total West Africa
0.2
-
4.2
4.4
0.4
-
9.9
10.3
0.7
-
20.6
21.3
Subtotal Equity accounted reserves
4.4
10.3
21.3
Total Group
220.3
292.1
386.7
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
Consolidated accounts
Note 23
Oil and gas reserves (unaudited)
Annual Report and Accounts 2022
DNO
69
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.
Consolidated accounts
Note 24
Oil and gas license portfolio
70
DNO
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
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
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 Norway AS
PL055 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 B (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 D (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 E (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL065 (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL065 B (Tambar)
45.0
Aker BP ASA
DNO Norge AS
PL1048
50.0
Lundin Energy Norway AS
DNO Norge AS
PL1076
50.0
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
30.0
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
PL1145
60.0
DNO Norge AS
DNO Norge AS, Aker BP ASA
PL1146
25.0
ConocoPhilips Skandinavia AS
ConocoPhilips Skandinavia AS; DNO Norge AS
PL1147
20.0
Lundin Norway AS
Spirit Energy Norway AS; Lundin Energy Norway AS; DNO Norge AS; Equinor
Energy AS
PL1148
30.0
Wellesley Petroleum AS
Wellesley Petroleum AS; DNO Norge AS; Aker BP ASA; Equinor Energy AS
PL1151
20.0
Wintershall Dea Norge AS
Wintershall Dea Norge AS; DNO Norge AS; Aker BP ASA; ONE-Dyas Norge AS
PL1158
40.0
Lundin Norway AS
Aker BP ASA; DNO Norge AS; Spirit Energy Norway AS
Consolidated accounts
Note 24
Oil and gas license portfolio
Annual Report and Accounts 2022
DNO
71
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
*Soci
é
t
é
Nationale d’Op
é
rations P
é
troli
è
res de la C
ô
te d’Ivoire
As of 31 December 2021
Held through DNO as a subsidiary:
Participating
Consolidated accounts
Note 24
Oil and gas license portfolio
72
DNO
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 Norway AS
PL055 (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 B (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 D (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 E (Brage)
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway 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
Consolidated accounts
Note 24
Oil and gas license portfolio
Annual Report and Accounts 2022
DNO
73
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. Ltd
DNO North Sea (U.K), Spirit Energy Resources Ltd
P2472
70.0
DNO North Sea (U.K.) Ltd
One-Dyas E&P Ltd
P255
45.0
Shell U.K. Ltd
DNO North Sea (U.K.) Ltd, Spirit Energy Resources Ltd
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
P2551
100.0
DNO North Sea (U.K.) Ltd
P2537
30.0
Chrysaor Production (U.K.) Limited
DNO North Sea (U.K.) Ltd, Neo Energy (ZEX) Limited
P2548
100.0
DNO North Sea (U.K.) Ltd
P2533
50.0
NEO Energy (ZEX) Limited
DNO North Sea (U.K.) Ltd
Ireland
FEL3/19
20.0
CNOOC Petroleum Europe Ltd
DNO North Sea (U.K.) Ltd
Netherlands
D15
5.0
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
D18a
2.5
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
Yemen
Block 47
64.0
DNO Yemen AS
The Yemen Company, Geopetrol Hadramaut Incorporated
Consolidated accounts
Note 25
Significant events after the reporting date
74
DNO
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.
Annual Report and Accounts 2022
DNO
75
Parent company accounts
Income statement
74
Balance sheet
74
Cash flow statement
76
Note disclosures
Note 1
Accounting principles
77
Note 2
Operating revenues
78
Note 3
Salaries, pensions, remuneration, shares, options and severance
78
Note 4
Other operating expenses
80
Note 5
Net financial income/-expenses
80
Note 6
Taxes
81
Note 7
Property, plant and equipment/Intangible assets
82
Note 8
Investment in shares/Other investments
82
Note 9
Other receivables
83
Note 10
Cash and cash equivalents
83
Note 11
Equity
83
Note 12
Guarantees, leasing liabilities and commitments
84
Note 13
Interest-bearing liabilities
84
Note 14
Current liabilities
84
Note 15
Financial instruments
84
Note 16
Related party disclosure
85
Note 17
Significant events after the reporting date
85
Note 18
Earnings per share
85
Note 19
Intercompany
85
Parent company accounts
76
DNO
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
-1,353
-1,110
Payroll and other social expenses
-20,514
-19,404
Other operating expenses
-18,414
-15,231
Total operating expenses
-40,281
-35,745
Operating profit/-loss
-12,833
-11,555
Net financial income/-expense
355,341
233,695
Profit/-loss before income tax
342,508
222,140
Tax income/-expense
-
-
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
3,801
4,131
Property, plant and equipment
398
323
Total intangible and tangible assets
4,199
4,454
Financial assets
Shares in subsidiaries
543,597
591,083
Intercompany receivables
86,081
86,895
Other long-term receivables
-
23
Investment in shares
-
16,174
Total financial assets
629,678
694,175
Total non-current assets
633,877
698,629
Current assets
Intercompany receivables
9,773
7,500
Other receivables
3,511
3,238
Cash and cash equivalents
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
80,967
83,256
Interest-bearing liabilities
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
18,461
19,515
Intercompany liabilities
-
20
Dividend
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
Bijan Mossavar-Rahmani
Gunnar Hirsti
Elin Karfjell
Watson
Executive Chairman
Deputy Chairman
Director
Anita Marie Hjerkinn Aarnæs
Bjørn Dale
Director
Managing Director
Parent company accounts
78
DNO
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
1,353
1,110
Impairment/-reversal of impairment of financial assets
152,601
95,661
Change in fair value of financial investments
-14,211
-3,580
Amortization of borrowing issue costs
5,13
4,454
8,927
Interest expense
52,153
65,414
Interest income
-9,429
-1,353
Other
-728
3,171
Changes in working capital and provisions:
-2,523
-3,901
-1,054
5,993
968
20
Cash generated from operations
526,092
393,602
Income taxes paid
Interest received
9,504
1,353
Interest paid
-53,636
-65,429
Dividend received
-
-
Net cash from/-used in operating activities
481,961
329,526
Investing activities
Purchases of intangible and tangible assets
-1,098
-533
Loans to subsidiaries
-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
-263,745
-5,093
Payment debt issue costs
13
-
-15,609
Loans from subsidiaries
19
-2,289
-66,881
Purchase of treasury shares
-11,713
-
Paid dividend
-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
80
DNO
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.
Synthetic
Remuneration to Managing Director and executive management (USD thousand)
Salary
Bonus
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).
Parent company accounts
Annual Report and Accounts 2022
DNO
81
Note 3
Salaries, pensions, remuneration, shares, options and severance
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
.
Movement in synthetic Company shares during 2022
Opening
Closing
Weight.
balance
Movemements (full-year)
balance
Unresrict.
average
Number of shares
at 1 Jan
Granted
Settled*
at 31 Dec
at 31 Dec
price
Bjørn Dale, Managing Director
73,992
36,094
73,992
36,094
Chris Spencer, Chief Operating Officer
586,813
1,095,215
232,862
1,449,166
Haakon Sandborg, Chief Financial Officer
205,547
774,786
30,188
950,145
Geir Arne Skau, Chief Human Resources and Corporate Services Officer
59,597
768,600
60,601
767,596
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.
Parent company accounts
82
DNO
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 expenses
-236,797
-193,544
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
Tax income/-expense
1 January - 31 December
USD thousand
2022
2021
Change in deferred taxes
-
-
Income tax receivable/-payable
-
-
Tax income/-expense
-
-
Reconciliation of tax income/-expense
1 January - 31 December
USD thousand
2022
2021
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
Years ended 31 December
USD thousand
2022
2021
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
84
DNO
Note 7
Property, plant and equipment/Intangible assets
Intangible
USD thousand
assets
PP&E
Total
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
Ownership
Share
Book
Net profit/
Book
interest
capital in
equity in
-loss in
value in
Subsidiaries owned by the Company
Office
(percent)
1,000
USD 1,000
USD 1,000
USD 1,000
DNO Yemen AS*
Norway
100
-62,618
-9,886
-
DNO UK Limited
UK
100
-120
-7
-
DNO Iraq AS
Norway
100
1,006,814
578,000
279,848
DNO Mena AS**
Norway
100
4,603
1,356
1,904
DNO Technical Services AS
Norway
100
5,285
-37
5,285
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
157,585
Mondoil Enterprices LLC**
United
States
100
USD 1
105,120
6,144
98,976
Total
1,215,431
461,121
543,597
* 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
Annual Report and Accounts 2022
DNO
85
Note 9
Other receivables
Years ended 31 December
USD thousand
2022
2021
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
Years ended 31 December
USD thousand
2022
2021
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
Share
Total
capital
Treasury
share
Share
Retained
Total equity
USD thousand
registered
shares
capital
premium
earnings
Shareholders' equity as of 1 January 2021
32,936
-
32,936
247,743
-140,415
140,264
Purchase of treasury shares
-
-
-
-
-
-
Dividend
-
-
-
-
-21,797
-21,797
Additional dividend provision
-
-
-
-
-22,120
-22,120
Profit/-loss for the year
-
-
-
222,140
222,140
Shareholders' equity as of 31 December 2021
32,936
-
32,936
247,743
37,808
318,487
-
Shareholders' equity as of 1 January 2022
32,936
-
32,936
247,743
37,808
318,487
Purchase of treasury shares
-
-869
-869
-
-41,837
-42,706
Share capital increase
1,841
-
1,841
95,877
-
97,718
Dividend
-
-
-
-
-49,951
-49,951
Additional dividend
-
-
-
-
-25,259
-25,259
Profit/-loss
-
-
-
-
342,508
342,508
Shareholders' equity as of 31 December 2022
34,777
-869
33,908
343,620
263,270
640,797
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
86
DNO
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
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
USD thousand
OSE
currency
amount
(percent)
Maturity
(percent)
2022
2021
2022
2021
Non-current
Bond loan (ISIN NO0010852643)
DNO03
USD
150,700
8.375
29.05.24
9.0
131,507
410,202
131,162
394,907
Bond loan (ISIN NO0011088593)
DNO04
USD
400,000
7.875
09.09.26
8.8
375,816
414,000
400,000
400,000
Capitalized borrowing issue costs
-9,761
-14,215
Total non-current interest-bearing liabilities
507,323
824,202
521,401
780,692
See Note 15 in the consolidated accounts for further information on interest-bearing liabilities.
Note 14
Current liabilities
Years ended 31 December
USD thousand
2022
2021
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
Years ended 31 December
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
Note 19
Intercompany
Short-term intercompany receivables/liabilities
Years ended 31 December
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
1 January - 31 December
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
1 January - 31 December
Interest income, dividend
Interest expense
Functional
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
Annual Report and Accounts 2022
DNO
89
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.
(USD million)
License, legal entity level and
country/region of operation
1
Country
of
incorpor-
ation
2
Royalty
3
Net
produc-
tion
4
Corporat
e income
tax
5
Special
tax
6
Area
fee
7
Contract-
ual
bonuses
8
Invest-
ments
9
Revenue
1
0
Expend-
iture
11
Net inter-
comp-
any
interest
12
Profit/
-loss
before
tax
10
Tax
income/-
expense
1
3
Equity
10
Number
of
employees
14
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
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
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
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.
1 Country/region of operation is the country where the company carries out its main activity.
2 Country of incorporation is the jurisdiction in which the legal entity is registered.
3 Royalty is a fee payable to the Kurdistan Regional Government (KRG) before distribution of cost oil and profit oil.
4 Net production in barrels of oil equivalent per day (boepd).
5 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.
6 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.
7 Area fee in Kurdistan and Norway.
8 Contractual bonuses include environment funds, training funds and rental fees in Kurdistan. In Norway, the amount is related to
environmental fund (NOx fund).
9 Investments as presented in the consolidated financial statements and include estimate changes in asset retirement obligations.
10 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.
11 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.
12 Net intercompany interest income /-expense to/from Group companies incorporated in another jurisdiction.
13 Tax income/-expense for the year.
14 Number of employees at yearend.
Auditor’s report
90
DNO
Auditor’s report 2022
Auditor’s report
Annual Report and Accounts 2022
DNO
91
Auditor’s report 2022
Auditor’s report
92
DNO
Auditor’s report 2022
Auditor’s report
Annual Report and Accounts 2022
DNO
93
Auditor’s report 2022
Auditor’s report
94
DNO
Auditor’s report 2022
Auditor’s report
Annual Report and Accounts 2022
DNO
95
Auditor’s report 2022
Alternative performance measures
Alternative performance measures
96
DNO
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
2021
Revenues
1,377.0
1,004.1
Lifting costs
-222.1
-184.2
Tariffs and transportation
-30.2
-34.5
Movement in overlift/underlift
8.1
-18.3
Share of profit/-loss from Joint Venture
6.0
-
Exploration expenses
-96.5
-132.3
Administrative expenses
-17.9
-16.2
Other operating income/expenses
-5.0
-11.5
EBITDA
1,019.5
606.9
EBITDAX
USD million
2022
2021
EBITDA
1,019.5
606.9
Exploration expenses
96.5
132.3
EBITDAX
1,116.0
739.3
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
2021
Purchases of intangible assets
-74.6
-86.8
Purchases of tangible assets
-300.2
-193.8
Capital expenditures*
-374.8
-280.6
* Exclude estimate changes on asset retirement obligations.
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
Alternative performance measures
Annual Report and Accounts 2022
DNO
97
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).
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
Alternative performance measures
98
DNO
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.
Annual Report and Accounts 2022
DNO
99
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.
100
DNO
Glossary and definitions
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
Annual Report and Accounts 2022
DNO
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DNO ASA
DOKKVEIEN 1 / AKER BRYGGE / 0250 OSLO / NORWAY / PHONE + 47 23 23 84 80 / FAX +47 23 23 84 81/ www.dno.no