Content
Highlights
3
Key figures
4
Board of Directors
5
Board of Directors’ report
7
Introduction
7
Operations review
8
Business development
9
Financial performance
9
Corporate governance
10
Enterprise risk management
13
HSSE performance
14
Organization and personnel
15
Parent company
18
Main events since yearend
18
Responsibility statement
19
Consolidated accounts
22
Parent company accounts
74
Country-by-Country report
88
Auditor’s report
89
Alternative performance measures
95
Glossary and definitions
98
Annual Report and Accounts 2021
DNO
3
Highlights
On the fiftieth anniversary of its founding, DNO
1
in 2021, up 63 percent from a year earlier on the back of high oil and gas prices and solid
production performance. Annual operating profit climbed to USD 321 million, reversing an
operating loss of USD 315 million in 2020. Strong 2021 free cash flow of USD 362 million drove a
68 percent reduction in net debt to USD 153 million at yearend.
Notwithstanding reduced drilling activity due to the Covid-19 pandemic and related budget cuts,
DNO managed to maintain gross operated production of 108,700 barrels of oil per day (bopd) at its
flagship Tawke license in the Kurdistan region of Iraq (Kurdistan), representing 81,500 bopd net to
DNO. North Sea net production averaged 12,900 barrels of oil equivalent per day (boepd), bringing
the Company’s total 2021 net production to 94,500 boepd.
Starting in the third quarter of 2021, DNO ramped up its drilling activity on the Tawke license,
aiming to keep license production essentially unchanged in 2022. Also contributing to enhanced oil
recovery within the license is the USD 110 million Peshkabir-Tawke gas project commissioned in
mid-2020. During 2021, 7.6 billion cubic feet of otherwise flared gas, equivalent to 461,500 tonnes
of CO2, was captured at the Peshkabir field and injected into the Tawke field for pressure support.
In late December 2021, the DNO-operated Baeshiqa license development was approved by the
Kurdistan Regional Government (KRG). The project represents DNO’s first new field development
in Kurdistan since the start-up of Peshkabir in 2017, and as with Peshkabir, the Company is fast-
tracking production, targeting organic growth in Kurdistan overall.
In the North Sea, DNO is positioned to grow as new production comes on stream. Currently, the
Company is involved in the ongoing Fenja field development as well as holding a stake in four
PDOs (plan for development and operation) projects targeting 2022 sanction, including DNO-
operated Brasse. North Sea exploration continues to be prioritized following two likely commercial
discoveries in 2021. Seven North Sea exploration wells are planned for 2022, all in proven basins
and close to existing infrastructure.
At yearend 2021, DNO held 90 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 offers high quality exploration opportunities. With a record-high operational spend of USD 800
million planned in 2022, 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)
2021
2020
Revenues
1,004.1
614.9
EBITDAX
739.3
378.8
EBITDA
606.9
322.8
Operating profit/-loss
320.9
-314.5
Net profit/-loss
203.9
-285.9
Netback
781.6
559.1
Free cash flow
362.0
150.5
Operational spend
663.8
511.4
Net debt
153.4
472.5
Lifting costs (USD/boe)
5.3
4.9
Netback (USD/boe)
22.7
15.3
Key operational data
2021
2020
Gross operated production (boepd)
108,713
110,282
Net production (boepd)*
94,477
100,063
Sales volume (boepd)
42,171
54,382
Net 2P reserves (MMboe)*
321.4
359.9
* Effective from 2021, the Company reports its net production, reserves and resources based on the percentage ownership
in all of its licenses. Prior to 2021, the Company reported its net figures from licenses governed by PSCs/PSAs on a Company
Working Interest (CWI) basis. Comparison figures are updated accordingly. See Note 23 for further details.
For reconciliation and more information about key figures, see the section on alternative performance measures.
Key figures
Board of Directors
Annual Report and Accounts 2021
DNO
5
Board of Directors
Bijan Mossavar-Rahmani
Executive Chairman
Bijan Mossavar-Rahmani is an experienced oil and gas executive and has served as the
Company’s Executive Chairman of the Board of Directors since 2011.
Mr. Mossavar-Rahmani serves concurrently as Executive Chairman of Oslo-listed RAK Petroleum plc,
the Company’s largest shareholder. He is a Trustee of the New York Metropolitan Museum of Art where
he chairs the audit committee and a member of Harvard University’s Global Advisory Council. He has
published more than ten books on global energy markets and was decorated Commandeur de l’Ordre
National de la Côte d’Ivoire for services to the energy sector of that country. Mr. Mossavar-Rahmani is
a graduate of Princeton (AB) and Harvard Universities (MPA). He is a member of the nomination and
remuneration committees.
Lars Arne Takla
Deputy Chairman
Lars Arne Takla has extensive experience from various managerial, executive and board
positions in the international oil and gas industry.
Mr. Takla has held various managerial positions with ConocoPhillips, including Managing Director and
President of the Scandinavian Division. He was Executive Chairman of the Norwegian Energy
Company ASA between 2005 and 2011. Mr. Takla was appointed Commander of the Royal Norwegian
Order of St. Olav for his strong contribution to the Norwegian petroleum industry.
He holds a Master of
Science degree in chemical engineering from the Norwegian University of Science and Technology. He
was elected to the Company’s Board of Directors in 2012 and is a member of the HSSE committee.
Elin Karfjell
Director
Elin Karfjell is Director of Property Development and Management at Statsbygg and has held
various management positions across a broad range of industries.
Ms. Karfjell has been Managing Partner of Atelika AS and has served as Chief Executive Officer of Fabi
Group, Director of Finance and Administration at Atea AS and partner of Ernst & Young AS and Arthur
Andersen. Other board directorships include Philly Shipyard ASA, North Energy ASA and Contesto AS.
Ms. Karfjell is a state authorized public accountant. She has a Bachelor of Science in Accounting from
Oslo and Akershus University College of Applied Sciences and a Higher Auditing degree from the
Norwegian School of Economics and Business Administration. Ms. Karfjell was elected to the
Company’s Board of Directors in 2015 and is a member of the audit committee.
Board of Directors
6
DNO
Board of Directors
Gunnar Hirsti
Director
Gunnar Hirsti has extensive experience from various managerial, executive and board positions
in the oil and gas industry as well as the information technology industry in Norway.
Mr. Hirsti was Chief Executive Officer of DSND Subsea ASA (now Subsea 7 S.A.) for a period of six
years. He also served as Executive Chairman of the Board of Blom ASA for eight years. Mr. Hirsti holds
a degree in drilling engineering from Tønsberg Maritime Høyskole in Norway. He was elected to the
Company’s Board of Directors in 2007 and is a member of the audit and remuneration committees.
Shelley Watson
Director
Shelley Watson began her career as a reservoir surveillance and facilities engineer with Esso
Australia in its offshore Bass Strait operation.
Ms. Watson has held management positions with Novus Petroleum, Indago Petroleum and RAK
Petroleum PCL where she served as General Manager until 2014. She was appointed as Chief
Operating Officer of RAK Petroleum plc in February 2017 and Chief Financial Officer in May 2017. Ms.
Watson holds a First Class Honours degree in chemical engineering and a Bachelor of Commerce
degree from the University of Melbourne. She has served on the Company’s Board of Directors since
2010 and is a member of the audit and HSSE committees.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
7
Board of Directors’ report
Introduction
2021 full-year results highlights
●
million in 2020;
●
million) and North Sea revenues totaled USD 410 million
(2020: USD 246 million);
●
operating loss of USD 315 million in 2020;
●
million in 2020;
●
million at yearend 2020;
●
containing the Tawke and Peshkabir fields, averaged
108,713 bopd compared to 110,282 bopd in 2020;
●
2
in 2020; and
●
of oil equivalent (MMboe), compared to 360 MMboe at
yearend 2020.
For a detailed financial review, see section on financial
performance.
Our vision and strategic priorities
DNO’s vision is to remain a leading, growth-oriented exploration
and production company with a focus on the Middle East and
the North Sea, with the aim of delivering attractive returns to
shareholders by finding and producing oil and gas at low cost
and at an acceptable level of risk in a socially responsible and
environmentally sensitive manner. To achieve this vision, our
strategic priorities include:
●
existing reserves base;
●
exploration and appraisal drilling;
●
efficient allocation of capital in line with DNO’s full-cycle
business model to deliver growth at a low unit cost;
●
best talent in the industry;
●
●
commitments and managing risks to the business;
●
best practices in our areas of operation; and
●
emissions.
Production strength and capacity
DNO reported gross operated production in 2021 of 108,713
bopd, slightly down from 110,282 boepd in 2020. DNO’s net
production stood at 94,477 boepd in 2021, down from 100,063
boepd in 2020. With net 2P reserves totaling 321 MMboe
across its portfolio, DNO has the asset base to sustain material
levels of production over the long term.
Organic reserves and resource growth
Done in a structured manner, successful exploration can be one
of the most cost-efficient methods of delivering significant
reserves growth and associated value creation. At DNO, we
focus our efforts on areas where we have in-depth knowledge
of the subsurface, playing to our technical and operational
strengths as a fractured carbonate specialist, notably in
Kurdistan. We also benchmark each prospect so that capital
deployed to exploration is only allocated to those opportunities
that meet our technical, financial and strategic requirements.
Looking ahead, we will continue to actively pursue opportunities
in high potential basins across the Middle East and the North
Sea, with the goal of transforming resources into reserves at a
low unit cost.
Operational control and financial flexibility
We operate our most significant oil and gas asset and have the
experienced team and operational capabilities to efficiently
deliver our work programs. To maintain the financial strength
and flexibility to fund growth opportunities, we will look to
internally generated funds and, when necessary, to
international capital markets to strengthen the Company’s
balance sheet. During 2021, DNO had an average lifting cost of
USD 5.3 per boe (2020: USD 4.9 per boe).
Encouraging an entrepreneurial culture
DNO’s growth and success revolve around the quality and
commitment of our people. We are an entrepreneurial company
with a flat organizational structure which means we can make
decisions quickly and execute flexibly. Our employment
practices and policies help our staff realize their full potential.
We are committed to developing local talent in each of our
areas of operations.
Mergers and acquisitions
In addition to organic growth, we continuously evaluate new
assets and take an opportunistic approach to potential
acquisitions.
Corporate governance and managing risk
One of our priorities is to ensure that DNO is a responsible and
transparent enterprise. We are committed to the highest
standards of corporate governance, business conduct and
corporate social responsibility. Recognizing that the success of
an oil and gas company is directly linked to how well risks are
managed, we seek to improve our systems designed to identify
and effectively manage risks. We are also committed to the
health, safety and security of our employees, contractors and
the communities in which we operate, as well as to working
continuously to reduce the environmental impact of our
activities including with respect to greenhouse gas (GHG)
emissions. Please refer to the Country-by-Country Report 2021
in page 88 of this report and the Company’s latest Corporate
Social Responsibility (CSR) Report for more information. The
CSR report is available on the Company’s website.
2
and resources based on the percentage ownership in all of its licenses.
Prior to 2021, the Company reported its net figures from licenses
governed by PSCs/PSAs on a Company Working Interest (CWI) basis.
Comparison figures are updated accordingly. See Note 23 for further
details.
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 carried out an independent assessment of the
Tawke license (containing the Tawke and Peshkabir fields) and
the Baeshiqa license in Kurdistan. International petroleum
consultants Gaffney, Cline & Associates carried out an
independent assessment of DNO's licenses in Norway and the
United Kingdom (UK). The Company internally assessed
Yemen Block 47.
At yearend 2021, DNO’s net proven (1P) reserves stood at
196.1 million barrels of oil equivalent (MMboe), compared to
216.9 MMboe at yearend 2020, after adjusting for production
during the year and upward technical revisions. On a 2P
reserves basis, DNO’s net reserves stood at 321.4 MMboe,
compared to 359.9 MMboe at yearend 2020. On a proven,
probable and possible (3P) reserves basis, DNO’s net reserves
were 420.6 MMboe, compared to 549.6 MMboe at yearend
2020. DNO’s net 2C resources were 189.5 MMboe, compared
to 151.3 MMboe at yearend 2020.
DNO’s net production in 2021 totaled 34.5 MMboe (of which
29.8 million barrels of oil (MMbbls) in Kurdistan, 4.5 MMboe in
Norway and the balance in the UK), compared to 36.6 MMboe
in 2020 (of which 30.3 MMbbls in Kurdistan, 6.0 MMboe in
Norway and the balance in the UK).
The Company’s net yearend 2021 Reserve Life Index (R/P)
stood at 5.7 years on a 1P reserves basis, 9.3 years on a 2P
reserves basis and 12.2 years on a 3P reserves basis.
The ASRR report for 2021 is available on the Company’s
website.
Kurdistan
Tawke license
Gross production from the Tawke license, containing the Tawke
and Peshkabir fields, averaged 108,713 bopd during 2021
(110,282 bopd in 2020). The Tawke field contributed 46,933
bopd (57,570 bopd in 2020) and Peshkabir field contributed
61,780 bopd (52,712 bopd in 2020).
Drilling at the Tawke field resumed in the third quarter of 2021
after an 18-month pause. With few new wells, production
decline has been partially offset by gas injection and workovers.
At yearend, four new Tawke field development wells had been
spudded, in addition to four Peshkabir wells spudded during the
year.
DNO’s USD 110 million Peshkabir-Tawke gas project, which
was commissioned in mid-2020, captured and injected 7.6
billion cubic feet (461,500 tonnes of CO2) of Peshkabir gas that
would otherwise have been flared into the Tawke field in 2021.
DNO holds a 75 percent operated interest in the Tawke and
Peshkabir fields with partner Genel Energy International Limited
(25 percent).
Baeshiqa license
In August 2021, the Kurdistan Regional Government approved
DNO’s acquisition of ExxonMobil Kurdistan Region of Iraq
Limited’s (ExxonMobil) remaining 32 percent interest in the
Baeshiqa license, doubling DNO’s operated stake. In parallel,
commerciality was declared on the license and development
plans submitted. Shortly before yearend, the first phase field
development plan for the license was approved by the
Kurdistan Regional Government, clearing the way for a fast-
track project to deliver early production from previously drilled
but suspended discovery wells. The Baeshiqa development is
DNO’s first new field development in Kurdistan since the startup
of the Peshkabir field in 2017.
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 KRG with a
20 percent carried interest.
RESERVES
On a net basis at yearend 2021, 1P reserves in the Company’s
Kurdistan portfolio totaled 162.2 MMbbls (175.8 MMbbls at
yearend 2020), 2P reserves totaled 267.4 MMbbls (295.4
MMbbls at yearend 2020) and 3P reserves totaled 348.5
MMbbls (453.7 MMbbls at yearend 2020). Net 2C resources
were 71.3 MMbbls, compared to 26.9 MMbbls at yearend 2020.
At the Tawke license containing the Tawke and Peshkabir
fields, at yearend 2021 gross 1P reserves stood at 216.2
MMbbls (162.2 MMbbls on a net basis), compared to 234.4
MMbbls (175.8 MMbbls on a net basis) at yearend 2020. At
yearend 2021 gross 2P reserves stood at 356.6 MMbbls (267.4
MMbbls on a net basis), compared to 393.9 MMbbls (295.4
MMbbls on a net basis) at yearend 2020. At yearend 2021,
gross 3P reserves stood at 464.7 MMbbls (348.5 MMbbls on a
net basis), compared to 604.9 MMbbls (453.7 MMbbls on a net
basis) at yearend 2020. At yearend 2021, gross 2C resources
stood at 47.6 MMbbls (35.7 MMbbls on a net basis), compared
to 17.7 MMbbls (13.3 MMbbls on a net basis) at yearend 2020.
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 the Baeshiqa structure and following a
discovery in 2019, testing and appraisal of the Baeshiqa-2
exploration well was concluded in 2020. The well tested
hydrocarbons to surface from multiple Jurassic and Triassic
zones. The Company performed additional appraisal studies in
2021.
At yearend 2021, gross 2C resources at the Baeshiqa structure
stood at 48.4 MMbbls (31.0 MMbbls on a net basis), compared
to 37.8 MMbbls (12.1 MMbbls on a net basis) at yearend 2020.
At the Zartik structure, the Company completed drilling and
testing of Zartik-1 exploration well in 2020. The well tested
hydrocarbons to surface from several Jurassic zones. The
Company performed additional appraisal studies in 2021.
At yearend 2021, gross 2C resources at the Zartik structure
stood at 7.4 MMbbls (4.7 MMbbls on a net basis), compared to
4.7 MMbbls (1.5 MMbbls on a net basis) at yearend 2020.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
9
At the license level and at yearend 2021, gross 2C resources
stood at 55.7 MMbbls (35.7 MMbbls on a net basis), compared
to 42.5 MMbbls (13.6 MMbbls on a net basis) at yearend 2020.
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 12,942 boepd during 2021 (17,352 boepd
in 2020), of which 12,469 boepd were attributable to Norway
and 473 boepd to the UK (16,465 boepd and 887 boepd in
2020).
In 2021, North Sea production was down compared to 2020
due to natural decline and planned maintenance.
DNO maintained a high activity level drilling seven development
wells and five exploration wells in Norway during the year. This
resulted in four discoveries, of which two likely commercial,
notably Røver Nord and the deeper Åre formation of the
Bergknapp discovery made in 2020.
Also in Norway, the DNO-operated Brasse project as well as
the partner-operated Iris-Hades, Gjøk and Orion discoveries
target 2022 PDO sanction, supporting the Company’s North
Sea growth ambitions.
DNO-operated plugging and abandonment operations on the
Oselvar field in Norway and Ketch field in the UK were
completed during 2021.
In January 2022, the Company’s wholly-owned subsidiary DNO
Norge AS was awarded participation in 10 exploration licenses,
of which three are operatorships, under Norway's Awards in
Predefined Areas (APA) 2021 licensing round.
RESERVES
At yearend 2021, DNO held 73 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
33.2 MMboe, 2P reserves stood at 52.3 MMboe, 3P reserves
totaled 70.2 MMboe and 2C resources stood at 112.2 MMboe.
In 2021, DNO had an active exploration and appraisal program
in Norway resulting in the Røver Nord discovery in License
PL923 and increasing the size of the 2020 Bergknapp discovery
in License PL836 S. Gross 2C resources at these licenses
stood at 40.5 MMboe (8.1 MMboe on a net basis) and 83.5
MMboe (25.1 MMboe on a net basis), respectively.
On a net basis, at yearend 2020 DNO’s portfolio of 76 licenses
in Norway held 1P reserves of 40.0 MMboe, 2P reserves of
63.1 MMboe, 3P reserves of 94.0 MMboe and 2C resources of
118.7 MMboe.
In the UK, DNO held 11 licenses at yearend 2021. On a net
basis, 1P reserves totaled 0.7 MMboe, 2P reserves stood at 1.6
MMboe, 3P reserves totaled 1.9 MMboe and 2C resources
stood at 1.1 MMboe.
At yearend 2020, DNO held 16 licenses in the UK with 1P
reserves of 1.0 MMboe, 2P reserves of 1.4 MMboe, 3P
reserves of 1.9 MMboe and 2C resources of 0.9 MMbbls, all on
a net basis.
Yemen
Production start-up at the Yaalen field at Block 47 in Yemen
remains on hold due to force majeure. At yearend 2021, gross
2C resources at Block 47 stood at 6.2 MMbbls (4.8 MMbbls on
a net basis), unchanged from yearend 2020.
Business development
In August 2021, the KRG approved DNO’s acquisition of
ExxonMobil’s remaining 32 percent interest in the DNO-
operated Baeshiqa license, doubling DNO’s stake. In parallel,
commerciality was declared on the license and development
plans submitted. Shortly before yearend, the first phase field
development plan for the license was approved by the KRG,
clearing the way for a fast-track project to deliver early
production from previously drilled but suspended discovery
wells. The Baeshiqa development is DNO’s first new field
development in Kurdistan since the startup of the Peshkabir
field in 2017.
Following DNO’s re-entry into the North Sea through strategic
2017 and 2019 acquisitions, DNO became a full cycle North
Sea player with a significant portfolio of exploration, production
and development projects and an experienced North Sea oil
and gas team. In 2021, DNO continued to high-grade its North
Sea portfolio through a combination of licensing round awards,
license transactions and relinquishments of licenses considered
not sufficiently attractive.
DNO continues to develop a pipeline of new business
opportunities with a focus on the Middle East and the North
Sea. 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 2021 stood at USD 1,004.1 million, up 63
percent from USD 614.9 million in 2020 on the back of high oil
and gas prices and solid production. Kurdistan revenues stood
at USD 594.3 million (USD 369.1 million in 2020), while the
North Sea generated revenues of USD 409.8 million (USD
245.8 million in 2020).
The Group reported an annual operating profit of USD 320.9
million, reversing operating loss of USD 314.5 million in 2020.
The operating profit in 2021 was mainly driven by improved oil
and gas prices, lower depreciation and impairments, partly
offset by higher expensed exploration.
The Group ended the year with USD 736.6 million in cash and
USD 153.4 million in net debt, compared to USD 477.1 million
and USD 472.5 million at yearend 2020, respectively.
Net cash flows from operating activities for the year was USD
728.8 million, compared to USD 406.2 million in 2020. The
North Sea tax refunds of USD 174.7 million received during the
year contributed to the strong 2021 cash flows from operating
Board of Directors’ report
10
DNO
activities. 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.
Cost of goods sold
In 2021, the total cost of goods sold was USD 443.1 million,
compared to USD 590 million in 2020. The decrease in cost of
goods sold was mainly due to lower depreciation, depletion and
amortization (DD&A), driven by lower DD&A per boe (from USD
17.9 per boe in 2020 to USD 13.4 per boe in 2021) and reduced
production in 2021.
Lifting costs in 2021 totaled USD 184.2 million, compared to
USD 181.1 million in 2020. Lifting costs per barrel in Kurdistan
stood at USD 3.3 in 2021 (USD 3.1 per barrel in 2020). Lifting
costs per boe in the North Sea stood at USD 17.9 in 2021 (USD
13.6 per boe in 2020). The increase in the North Sea lifting cost
per boe was driven by changes in relative production between
the different fields.
Impairment charges
The Group’s total impairment charges stood at USD 80.1 million
in 2021 (USD 276 million in 2020). The 2021 impairments were
mainly driven by revision of reserves and contingent resources
and revision of cost estimates for decommissioning in the North
Sea.
Exploration costs expensed
Total expensed exploration costs for the year were USD 132.3
million, up from USD 55.9 million in 2020, primarily driven by
higher expensing of wells and seismic purchase in the North
Sea.
Capital expenditures
Total capital expenditures for the year were USD 280.6 million
in 2021, up from USD 225 million in 2020 driven by higher
activities at the Tawke license in Kurdistan.
Assets, liabilities and equity
At yearend 2021, total assets stood at USD 2,947.8 million,
compared to USD 2,708.7 million at yearend 2020. The
increase in total assets was mainly due to higher trade debtors
following rising oil and gas prices and increase in cash balance,
partly offset by a decrease in the book value of oil and gas
assets including goodwill. Total property, plant and equipment
(PP&E), intangible assets and goodwill decreased from USD
1,644.7 million at yearend 2020 to USD 1,605.5 million at
yearend 2021.
Total liabilities increased from USD 1,863 million at yearend
2020 to USD 1,929 million at yearend 2021, primarily explained
by increase in deferred tax liabilities mainly due to favourable
tax depreciation rules, recorded income tax payable and higher
trade payables and accruals driven by increased license
activities. The increase in liabilities was partly offset by
repayment of borrowings. The equity ratio stood at 34.6 percent
at yearend 2021 (31.2 percent at yearend 2020).
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 reporting date. The Board of Directors’ review
included in particular assessment of the Group’s projected cash
reserves and access to financing arrangements considering its
operational outlook and work programs including its capital-
intensive development projects, while maintaining appropriate
headroom in respect of liquidity and financial covenant
compliance throughout the assessment period.
In making these assessments, the Board of Directors continued
to monitor the uncertainty caused by the Covid-19 pandemic
and its effects on the global economy, while also noting the
gradually loosening of travel restrictions since the reporting
date. The Board of Directors also assessed the February 2022
ruling by the Federal Supreme Court of Iraq (FSCI) on the
KRG’s constitutional rights and powers as regards oil and gas
as further detailed under the section on enterprise risk
management. It is currently not clear how this ruling will be
followed up. To date there has been no effect on operations but
any development will be closely monitored. In assessing the
effect on going concern the Board of Directors considered the
potential effects of any significant interruption in the settlement
of receivables from the KRG. Were such an interruption to
arise, the Board of Directors would reassess the levels of
capital investment at the Tawke and Baeshiqa licenses as was
the case during the initial stages of the Covid-19 pandemic. The
Board of Directors noted the Company’s current cash balance
when reaching its going concern conclusion.
Moreover, the Board of Directors noted the significant
improvement in oil and gas prices, the build-up of the cash
balance and the Group’s reported remaining proven and
probable oil and gas reserves that permit cash flow generation
covering the forecast period.
Stress testing was carried out at lower oil and gas price
scenarios. Sufficient liquidity and covenant compliance can be
maintained through the going concern assessment period in the
base case and the stress test.
Following its review, the Board of Directors 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.
Corporate governance
DNO’s corporate governance policy is based on the
recommendations of the Norwegian Code of Practice for
Corporate Governance. The Company is currently reviewing the
updated October 2021 recommendations and is considering
future implementation.
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.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
11
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 2021, this ratio was 34.6 percent.
The Board of Directors considers this figure to be satisfactory
given the Group’s business objectives, strategy and risk profile.
DIVIDEND POLICY
The Board of Directors assesses on an annual basis whether
dividend payments should be proposed for approval at the
Annual General Meeting (AGM). Assessment is based on
planned capital expenditure, cash flow projections and DNO’s
objective of maintaining a strong credit profile and robust capital
ratios.
At the 2020 AGM, 99.8 percent of the votes cast approved the
resolution to authorize the Board of Directors to approve a
dividend distribution of up to NOK 0.20 per share from the date
of the AGM until 31 December 2020 and a distribution of
dividend of up to NOK 0.20 per share from 1 January 2021 until
the date of the 2021 AGM. Due to continued uncertainty relating
to Covid-19 pandemic, these authorizations were not utilized.
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. In December 2021, the Company’s Board of
Directors approved a dividend payment of NOK 0.20 which was
made on 30 December 2021 to all shareholders of record as of
22 December 2021. In March 2022, the Company’s Board of
Directors approved a dividend payment of NOK 0.20 per share
to be made on or about 21 March 2022 to all shareholders of
record as of 15 March 2022.
OTHER AUTHORIZATIONS TO THE BOARD OF
DIRECTORS
At the 2021 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. The maximum amount to be paid per
share is NOK 100 and the minimum amount is NOK 1.
Purchases of treasury shares are made on the Oslo Stock
Exchange. The authorization is valid until the 2022 AGM, but
not beyond 30 June 2022. As of 31 December 2021, the
Company held no treasury shares.
The Board of Directors was also given the authority to increase
the Company’s share capital by up to NOK 36,578,727, which
corresponds to 146,314,908 new shares. The authorization is
valid until the 2022 AGM, but not beyond 30 June 2022.
In addition, the Board of Directors was given the authority to
raise convertible bonds with an aggregate principal amount of
up to USD 300,000,000. Upon conversion of bonds issued
pursuant to this authorization, the Company’s share capital may
be increased by up to NOK 36,578,727. The authorization is
valid until the 2022 AGM, but not beyond 30 June 2022
.
Equal treatment of shareholders and
transactions with related parties
The Company has one class of shares and each share
represents one vote. We are committed to treating all
shareholders equally.
All transactions between the Company and related parties shall
be on arm’s length terms. Members of the Board of Directors
and executive management are required to notify the board
if they have any direct or indirect material interest in any
transaction entered into by the Company.
For more information about related party transactions, see Note
21 in the consolidated accounts.
Freely negotiable shares
The Company’s shares are listed on the Oslo Stock Exchange
and are freely negotiable.
General meetings
The AGM, usually held by the end of May each year, is the
highest authority of the Company. The minutes of the meetings
are available on the Company’s website.
AGMs are convened by written notice to all shareholders with a
known address and published on the Company’s website
together with all appendices, including the recommendations of
the nomination committee. The notice is sent and published no
later than 21 days prior to the date of the meeting. Any person
who is a shareholder at the time of the AGM can attend and
vote, provided that they have been registered as a shareholder
no later than the fifth working day before the meeting.
Shareholders unable to attend a general meeting may vote
through a proxy.
In accordance with the Norwegian Public Limited Liability
Companies Act, the auditor of DNO, or 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 by the AGM for a
period of two years.
As of 31 December 2021, the Board of Directors consisted of
five members, all of whom have relevant and broad experience.
Three members are independent of the Company’s main
shareholders. There are two women on the board. The majority
of the members are independent of the Company’s executive
management and material business contacts.
The members’ shareholdings are specified in the notes to the
consolidated accounts.
The Board of Directors’ work
The role of the Board of Directors is to supervise the
Company’s executive management and strategic development
in accordance with the long-term interests of the Company’s
shareholders and other stakeholders.
Board of Directors’ report
12
DNO
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 three members: Mr. Gunnar
Hirsti (chair), Ms. Shelley Watson and Ms. Elin Karfjell. Its
mandate includes ensuring the quality and accuracy of the
Company’s financial reporting process and making
recommendations to ensure its integrity. The committee is also
responsible for monitoring internal control, risk management
and internal audit of the Company within its limits as an
independent party and reviewing and monitoring the
appointment, independence and performance of the external
auditor.
HSSE COMMITTEE
The HSSE (health, safety, security and environment) committee
consists of Mr. Lars Arne Takla (chair) and Ms. Shelley Watson.
Its mandate is to review the Company’s management of
operational HSSE risks and performance.
REMUNERATION COMMITTEE
The remuneration committee consists of two members: Mr.
Bijan Mossavar-Rahmani and Mr. Gunnar Hirsti. Its mandate is
to consider matters relating to the compensation of executive
management.
NOMINATION COMMITTEE
The Company’s nomination committee consists of Mr. Bijan
Mossavar-Rahmani and two external members, Ms. Anita Marie
Hjerkinn Aarnæs and Mr. Kåre Tjønneland. Its mandate is to
propose candidates for the Board of Directors and its various
committees to the AGM. It also proposes the level of
remuneration for the Board of Directors.
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.
Information and communication
Our policy is to provide material information to all shareholders
in a timely manner.
DNO’s consolidated financial statements are prepared in
accordance with International Financial Reporting Standards
(IFRS) as adopted by the European Union (EU) and additional
disclosure requirements in the Norwegian Accounting Act.
Interim reports and other relevant information are published on
DNO’s website and through the Oslo Stock Exchange.
We also publish an annual financial calendar setting out key
dates and events, such as regular market presentations. The
DNO investor relations’ policy encourages open communication
with capital markets and shareholders. In addition to scheduled
half-year and full-year presentations, we regularly hold
presentations for investors and analysts.
Takeover
The Board of Directors has a responsibility to ensure that, in the
event of a takeover bid, business activities are not disrupted
unnecessarily. The Board of Directors also has a responsibility
to ensure that shareholders have sufficient information and time
to assess any such bid. Should a takeover situation arise, the
Board of Directors would undertake an evaluation of the
proposed bid terms and provide a recommendation to the
shareholders as to whether or not to accept the proposal. The
recommendation statement would clearly state whether the
Board of Directors’ evaluation is unanimous and the reasons for
any dissent.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
13
Auditor
DNO’s external auditor is elected at the AGM, which also
approves the auditor’s fees for the parent company. The auditor
annually presents an audit plan to the audit committee and
participates in audit committee meetings to review the Group’s
internal control and risk management systems. The auditor also
participates in board meetings when considered appropriate,
with and without executive management present.
Information about the auditor’s fees, including a breakdown of
audit related fees and fees for other services, is included in the
notes to the financial statements in accordance with the
Norwegian Accounting Act.
DNO’s external auditor is Ernst & Young AS.
Enterprise risk management
The objective of DNO’s risk management is to identify potential
exposures that may impact the Group and to manage identified
risks within strict guidelines while pursuing our business
objectives. We review our risk profile on a quarterly basis,
incorporating industry-recognized risk identification and
quantification processes. The Board of Directors and its
committees also regularly monitor the Group’s risk
management systems and internal controls.
Financial risk
Risks related to oil and gas prices, interest rates and currency
exchange rates, liquidity risk, concentration risk and credit risk
constitute financial risks for the Group. In order to minimize any
potentially adverse effects from such risks, financial risk is
managed by the Group finance function under policies
approved by the Board of Directors. For more information about
how we manage financial risk, see Note 9 in the consolidated
accounts.
Entitlement risk
DNO has interests in two licenses in Kurdistan through
Production Sharing Contracts (PSCs) and has based its
entitlement calculations on the terms of these PSCs. 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 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, and it is unclear how the KRG and the FGI will
follow up on the ruling. 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 available export
channels, DNO has historically faced constraints in fully
monetizing the oil it produces in Kurdistan. Following the ruling
and pending follow up by the KRG and FGI, constraints remain.
There is no guarantee that oil and gas can be exported in
sufficient quantities or at prices required to sustain its
operations and investment plans or that the Group will promptly
receive its full entitlement payments for the oil and gas it
delivers for export. Export sales have not always followed the
PSC terms and there has been uncertainty related to receipt of
payments. The Group has accumulated a receivable against
the KRG 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. Entitlement payments were resumed in March
2020 and override payments were resumed in early 2021. In
December 2020, a plan was put in place by the KRG to pay the
international oil companies operating in Kurdistan 50 percent of
incremental revenue in any month in which Brent prices exceed
USD 50 per barrel towards the arrears for 2019 and 2020. In
May 2021, the KRG informed the international oil companies of
revised terms reducing the payment of the arrears to 20 percent
of incremental revenue in any month in which Brent prices
exceed USD 50 per barrel. The KRG also advised that all
international oil company invoices, including towards the
arrears, will be settled within 60 days of receipt. The Company
expects at a minimum to recover the full nominal value of the
withheld receivables, and DNO continues to work to improve
the terms of recovery of the arrears, including but not limited to
interest payments. During 2021, the outstanding arrears were
reduced from USD 259 million at the start of the year to USD
169 million at yearend.
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.
Although Covid-19 and related restrictions continued to affect
the Group’s operations in 2021, the Group managed to avoid
any major business disruptions from the pandemic.
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.
Board of Directors’ report
14
DNO
Climate-related risk
Based on the Company’s assessment, the most important
climate-related risks relate to uncertainty over future oil and gas
demand, future commodity prices and CO2 pricing. Increasing
concerns about climate-related risk may affect investor appetite
for oil and gas investments, inhibiting the Group’s ability to
obtain funding, and also reduce the Company’ attractiveness as
an employer and business partner.
In the North Sea, carbon prices have been rising through CO2
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
for oil companies to put plans in place to 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 add to the Group’s
operational cost.
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) in their World Energy
Outlook (WEO) reports, namely the Stated Policies Scenario
and the Sustainable Development Scenario. Based on this
limited scenario analysis, the Company does not note any
significant impact on its book values of oil and gas assets (see
Note 10) or exploration and development projects.
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, flooding and erosion.
Security risk
Although some of our operations are in regions with security
risks, we continuously work to manage these risks through
clearly defined security protocols and practices. Nevertheless,
we are often dependent on the quality of the security and
protection provided by authorities in our host countries.
Compliance risk
DNO has a policy of zero tolerance for corruption, bribery and
other illegal or inappropriate business conduct. Violations of
compliance laws and contractual obligations can result in fines
and a deterioration in the Group’s ability to effectively execute
its business plans. DNO adheres to a strict and comprehensive
conflict of interest policy, trade sanctions and other policies
focused 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
channel for those who wish to raise such matters in strict
privacy or 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.
In
Kurdistan, we continue to monitor security conditions although
our operations to date have seen minimal impact from regional
developments.
Stakeholder risk
In order to operate effectively, it is necessary for the Company
to maintain productive and proactive relationships with our
stakeholders, host governments, business partners and the
communities in which we operate. Failure to do so can result in
difficulties in progressing initiatives as well as delays to ongoing
operations.
HSSE performance
Our HSSE standards, procedures and protocols are based on
the following principles:
●
●
operations on the environment;
●
and
●
During 2021:
●
to 0.62 in 2020.
●
compared to one in 2020.
●
driven of 2.6 million kilometers.
●
the North Sea and from all DNO’s offices and travel stood at
426,109 tonnes of CO2 equivalent, compared to 422,643
tonnes in 2020.
●
of CO2 in Scope 1 emissions, 342 tonnes of CO2 in Scope 2
emissions, and 1,726 tonnes of CO2 in Scope 3 emissions.
●
2020; and
●
in 2020, most of which was removed and remediated.
We seek to ensure the integrity of our facilities, starting with
design and continuing with robust maintenance focused in
particular on safety critical equipment.
We continue to work with our employees and third-party
contractors on programs to improve safety performance.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
15
Organization and personnel
At yearend 2021, DNO had a workforce of 1,327 employees, of
which 12 percent were women. A total of 59 individuals were
based at the Company’s headquarters in Oslo and 1,268 were
engaged across our international operations, including in
business unit offices in Erbil, Stavanger, Dubai and Aberdeen.
Our workforce is characterized by strong cultural, religious and
national diversity, with some 43 nationalities represented.
At yearend 2021, the Board of Directors consisted of five
members, two of whom are women (40 percent). Executive
management consisted of one woman (13 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.
In 2021, DNO initiated extensive mapping of compensation
levels and promotion practices across the Company, aiming to
identify and mitigate any biases.
The Company has stepped up recruitment and promotion of
women. At yearend 2021, women represented 34 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 21 percent
in the Dubai office and 46 percent in the Oslo and Stavanger
offices.
There were no incidents of discrimination reported through the
internal mechanisms for raising concern in 2021.
Sickness absence in the Group in 2021 was 1.4 percent,
compared to 1.1 percent in 2020.
Covid-19
In mid-March 2020, the Company implemented various
prevention measures, including work from home, testing and
quarantine as appropriate at each location and as guided by
local authorities. This continued throughout 2021.
Workforce diversity in DNO Norway
In Norway, DNO had a workforce of 149 employees at yearend
2021, of which 46 percent were women. A total of four
employees have worked part time during 2021, of which 50
percent were women. No employees in DNO work part time
unless they have initiated or proposed it themselves. A total of
14 employees were on parental leave. Women had an average
of 23.5 weeks of parental leave and men had an average of 13
weeks of parental leave.
Salary mapping of 2021 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
74%
74%
Level 2
106%
106%
Level 3
95%
95%
Level 4
91%
91%
Level 5
-
-
All employees
61%
61%
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 2022, DNO plans to establish a Diversity and
Inclusion Policy 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 2021 was good
as confirmed through WEC meetings and employee satisfaction
surveys.
Executive remuneration policy
The 2021 remuneration of the Company’s executive
management was based on the latest approved remuneration
guidelines and DNO’s remuneration practice detailed below.
Updated guidelines will be presented at the 2022 AGM.
Remuneration policy for 2021
Any remuneration, bonuses or other incentive schemes must
reflect the duties and responsibilities of the employees and add
long-term value for shareholders.
Fixed remuneration
The Board of Directors did not set any upper or lower limit for
the fixed salary of executive management for 2021 beyond the
main principles set out above.
Variable remuneration
In addition to fixed salary, variable remuneration can be used to
recruit, retain and reward employees. For executive
management, such remuneration can include cash bonuses
and share-based compensation. Annual bonuses, when
awarded, are based on corporate results and/or individual
performance. Other types of variable remuneration include
newspaper, mobile phone and broadband communication
subscriptions paid in accordance with established rates.
Pensions
DNO has a defined contribution scheme for its Norway-based
employees which meets the Norwegian legal requirements for
mandatory occupational pensions.
Employee Synthetic Share Program
The Board of Directors continued its employee synthetic share
program in 2021. The purpose of the program was to: (i) align
the interests of executive management and other employees
with those of shareholders; (ii) reward value creation; and (iii)
provide retention incentives. The Board of Directors determines
whether to set allocation criteria, conditions or thresholds for the
scheme.
Board of Directors’ report
16
DNO
Severance agreements
Severance payment agreements may be entered into
selectively.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
17
Executive management
BJØRN DALE
Managing Director
Mr. Dale joined DNO in 2011. Mr. Dale holds a Master of Law
degree from the University of Oslo and an Executive MBA
from the Stockholm School of Economics.
CHRIS SPENCER
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.
NICHOLAS WHITELEY
Chief Commercial Officer
Dr. Whiteley joined DNO in 2015. Dr. Whiteley previously
served as General Manager of Exploration of Cairn India. He
started his career at BP and has a Master of Science degree
in Earth Sciences from the University of Cambridge and a
PhD from the University of Oxford.
TOM ALLAN
General Manager Kurdistan region of Iraq
Mr. Allan joined DNO in 2019. Mr. Allan previously served as
COO of Oilserv and in various operational and managerial
roles at Schlumberger. Mr. Allan holds a Bachelor of Science
degree in Engineering from the Royal Military College of
Canada.
ØRJAN GJERDE
General Manager DNO North Sea
Mr. Gjerde joined DNO in 2017. Mr Gjerde previously served
as CFO of Noreco and in management roles at various oil
services companies. Mr. Gjerde is a state authorized public
accountant and obtained his Master level degree in Accounting
and Auditing from the Norwegian School of Economics.
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.
TONJE PARELI GORMLEY
General Counsel - Middle East
Ms. Gormley joined DNO in 2018 upon secondment as a
partner from the law firm Arntzen de Besche and has since
permanently joined DNO. Ms. Gormley holds a Master level
degree in law from the University of Oslo and a diploma in law
from the London Metropolitan University.
Board of Directors’ report
18
DNO
Parent company
The parent company, DNO ASA, reported annual net profit of
USD 222.1 million, reversing the net loss of USD 319.1 million
in 2020. The net profit in 2021 was mainly driven by higher
received dividends from subsidiaries and lower write-downs of
the book value of shares in subsidiaries. Total assets as of 31
December 2021 stood at USD 1,224.4 million, up from USD
1,091.6 million at yearend 2020. The increase in total assets
was mainly due to a higher cash balance following the
dividends received, partially offset by write-downs of the book
value of shares in subsidiaries. The parent company’s cash
balance at yearend 2021 was USD 515 million, up from
USD 299.7 million at yearend 2020. Total liabilities decreased
from USD 951.3 million at yearend 2020 to USD 905.9 million at
yearend 2021 mainly due to a reduction in long-term
intercompany liabilities. Total equity at yearend 2021 was
USD 318.5 million, up from USD 140.3 million in 2020. The
equity ratio was 26 percent (12.8 percent at yearend 2020).
A dividend of USD 21.8 million was distributed and paid in
2021. In addition, a dividend of USD 22.1 million was accrued
at yearend 2021 in the parent company accounts (see Note 22).
The Board of Directors will recommend that the shareholders
approve the transfer of the net profit of USD 222.1 million to
retained earnings at the forthcoming AGM.
Main events since yearend
On 18 January 2022, the Company announced that its wholly-
owned subsidiary DNO Norge AS has been awarded
participation in 10 exploration licenses, of which three are
operatorships, under Norway's Awards in Predefined Areas
(APA) 2021 licensing round. Of the 10 new licenses, six are in
the North Sea and four in the Norwegian Sea.
Following yearend 2021, DNO has received USD 153.3 million
for the months October and November 2021 towards the
respective month’s entitlement share of oil deliveries to the
export market from the Tawke license, override payments
equivalent to three percent of gross revenues under the August
2017 Receivables Settlement Agreement and arrears relating to
withheld payment of 2019 and 2020 entitlement and override
invoices.
The Company notes from public reports that on 15 February
2022, the FSCI ruled amongst other things that the Kurdistan
Oil and Gas Law 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, and it is unclear how the KRG and the FGI
will follow up on the ruling. At present, normal operations are
maintained at the Tawke and Baeshiqa licenses. The Company
continues to monitor the situation. Any future impacts of this
ruling and subsequent actions by the FGI and the KRG cannot
currently be estimated but may impact the operations and
financial performance of the Group.
On 9 March 2022, the Company announced that pursuant to
the authorization granted at the 2021 AGM, the Board of
Directors has decided to distribute a dividend payment of NOK
0.20 per share to be made on or about 21 March 2022 to all
shareholders of record as of 15 March 2022.
The Company notes the implications for commodity prices and
potential interruptions of supply chains and third-party services
from the ongoing Russia-Ukraine armed conflict. DNO is
monitoring international sanctions and trade control legislation
in order to mitigate the potential impact on the Company’s
operations.
Board of Directors’ report
Annual Report and Accounts 2021
DNO
19
Responsibility statement
DNO ASA’s consolidated financial statements for the period 1 January to 31 December 2021 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 2021 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 2021 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, 16 March 2022
Bijan Mossavar-Rahmani
Lars Arne Takla
Shelley Watson
Executive Chairman
Deputy Chairman
Director
Elin Karfjell
Gunnar Hirsti
Bjørn Dale
Director
Director
Managing Director
Board of Directors’ report
20
DNO
Board of Directors’ report
Annual Report and Accounts 2021
DNO
21
Consolidated statements of comprehensive income
22
Consolidated statements of financial position
23
Consolidated cash flow statements
24
Consolidated statements of changes in equity
25
Note disclosures
Note 1
Summary of IFRS accounting principles
26
Note 2
Segment information
37
Note 3
Revenues
39
Note 4
Cost of goods sold/Inventory
39
Note 5
Administrative/Other operating expenses
40
Note 6
Exploration expenses
42
Note 7
Financial income and financial expenses
42
Note 8
Income taxes
43
Note 9
Financial instruments
##ToC_Note9
Note 10
Property, plant and equipment/Intangible assets
50
Note 11
Financial investments
56
Note 12
Other non-current receivables/Trade and receivables
57
Note 13
Cash and cash equivalents
57
Note 14
Equity
58
Note 15
Interest-bearing liabilities
60
Note 16
Provisions for other liabilities and charges/Lease liabilities
61
Note 17
Commitments and contingencies
63
Note 18
Trade and other payables
64
Note 19
Earnings per share
64
Note 20
Group companies
65
Note 21
Related party disclosure
65
Note 22
Significant events after the reporting date
66
Note 23
Oil and gas reserves (unaudited)
67
Note 24
Oil and gas license portfolio
69
Parent company accounts
Income statement
74
Balance sheet
74
Cash flow statement
76
Note disclosures
77
Auditor’s report
89
Consolidated accounts
22
DNO
Consolidated statements of comprehensive income
1 January - 31 December
USD million
Note
2021
2020
Revenues
2, 3
Cost of goods sold
-443.1
-590.0
Gross profit
Other income/-expenses
Administrative expenses
-16.2
-4.8
Other operating expenses
-12.0
-2.7
Impairment oil and gas assets
-80.1
-276.0
Exploration expenses
-132.3
-55.9
Operating profit/-loss
-314.5
Financial income
Financial expenses
-126.7
-131.0
Profit/-loss before income tax
-425.8
Tax income/-expense
8
-16.3
Net profit/-loss
-285.9
Other comprehensive income
Currency translation differences
-12.5
-3.6
Items that may be reclassified to profit or loss in later periods
-12.5
-3.6
Net fair value changes from financial instruments
11
-8.4
Items that are not reclassified to profit or loss in later periods
-8.4
Total other comprehensive income, net of tax
-8.9
-12.0
Total comprehensive income, net of tax
-298.0
Net profit/-loss attributable to:
Equity holders of the parent
-285.9
Non-controlling interests
Total comprehensive income attributable to:
Equity holders of the parent
-298.0
Non-controlling interests
Earnings per share, basic (USD per share)
19
-0.29
Earnings per share, diluted (USD per share)
19
-0.29
Weighted average number of shares outstanding (millions)
Consolidated accounts
Annual Report and Accounts 2021
DNO
23
Consolidated statements of financial position
Years ended 31 December
USD million
Note
2021
2020
ASSETS
Non-current assets
Deferred tax assets
Goodwill
Other intangible assets
Property, plant and equipment
Financial investments
Other non-current receivables
Total non-current assets
Current assets
Inventories
Trade and other receivables
Tax receivables
Cash and cash equivalents
Total current assets
TOTAL ASSETS
EQUITY AND LIABILITIES
Equity
Shareholders' equity
14
Total equity
Non-current liabilities
Deferred tax liabilities
Interest-bearing liabilities
Lease liabilities
Provisions for other liabilities and charges
16
Total non-current liabilities
Current liabilities
Trade and other payables
Income taxes payable
Current lease liabilities
Provisions for other liabilities and charges
16
Total current liabilities
Total liabilities
TOTAL EQUITY AND LIABILITIES
Oslo,
16
Bijan Mossavar-Rahmani
Lars Arne Takla
Shelley Watson
Executive Chairman
Deputy Chairman
Director
Elin Karfjell
Gunnar Hirsti
Bjørn Dale
Director
Director
Managing Director
Consolidated accounts
24
DNO
Consolidated cash flow statements
1 January - 31 December
USD million
Note
2021
2020
Operating activities
Profit/-loss before income tax
-425.8
Adjustments to add/-deduct non-cash items:
Exploration cost previously capitalized carried to cost
Depreciation, depletion and amortization
Impairment oil and gas assets
Amortization of borrowing issue costs
Accretion
7,16
Interest expense
7
Interest income
7
-1.7
-5.3
Other
Changes in working capital items and provisions:
- Inventories
-13.7
- Trade and other receivables
-99.5
- Trade and other payables
-108.5
- Provisions for other liabilities and charges
-2.7
Cash generated from operations
Tax refund received
Interest received
Interest paid
-73.0
-85.7
Net cash from/-used in operating activities
Investing activities
Purchases of intangible assets
-86.8
-62.8
Purchases of tangible assets
-193.8
-162.2
Payments for decommissioning
-86.2
-30.7
Proceeds from license transactions
Net cash from/-used in investing activities
-362.0
-255.7
Financing activities
Proceeds from borrowings
Repayment of borrowings
-459.0
-290.3
Purchase of treasury shares
-17.8
Payment of debt issue costs
-15.6
Paid dividend
-22.2
Payments of lease liabilities
-8.6
-3.4
Net cash from/-used in financing activities
-105.4
-159.1
Net increase/-decrease in cash and cash equivalents
-8.6
Cash and cash equivalents at beginning of the period
Exchange gain/-losses on cash and cash equivalents
-2.0
-0.0
Cash and cash equivalents at end of the period
13
Of which restricted cash
In prior years adjustments for interest income, interest expense, accretion expense and amortization of borrowing issue costs were
included in Other. Effective from 2021, these are shown in separate lines. Comparable figures are updated accordingly.
Purchases of intangible assets that were related to capitalized exploration costs were previously shown net of exploration write-downs.
Effective from 2021, these are shown gross (before exploration write-downs), while the exploration write-downs are shown separately in
the line Exploration cost previously capitalized carried to cost. Comparable figures are updated accordingly.
Consolidated accounts
Annual Report and Accounts 2021
DNO
25
Consolidated statements of changes in equity
Other comprehensive income
Other paid-in
Fair value
Currency
Share
Share
capital/Other
changes equity
translation
Retained
Total
USD million
capital
premium
reserves
instruments
difference
earnings
equity
Total shareholders' equity as of 31 December 2019
-30.2
-61.4
Fair value changes from equity instruments
-8.4
-8.4
Currency translation differences
-3.6
-3.6
Other comprehensive income
-8.4
-3.6
-12.0
Profit/-loss for the period
-285.9
-285.9
Total comprehensive income
-8.4
-3.6
-285.9
-298.0
Purchase of treasury shares
-0.4
-17.3
-17.7
Payment of dividend
Transactions with shareholders
-0.4
-17.3
-17.7
Transfers
-47.5
Total shareholders' equity as of 31 December 2020
-65.0
Other comprehensive income
Other paid-in
Fair value
Currency
Share
Share
capital/Other
changes equity
translation
Retained
Total
USD million
capital
premium
reserves
instruments
difference
earnings
equity
Total shareholders' equity as of 31 December 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
Payment of dividend
-21.8
-21.8
Transactions with shareholders
-21.8
-21.8
Transfers
Total shareholders' equity as of 31 December 2021
-77.5
See Note 11 for details regarding fair value changes from equity instruments.
Note 1
Summary of IFRS accounting principles
26
DNO
■
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 and the North
Sea. DNO is included in the consolidated accounts of RAK
Petroleum plc (RAK Petroleum).
■
Statement of compliance
The consolidated financial statements of
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 2021. The consolidated financial
statements were approved by the Board of Directors on 16 March
2022.
■
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 reporting date. The
Board of Directors’ review included in particular assessment of
the Group’s projected cash reserves and access to financing
arrangements considering its operational outlook and work
programs including its capital-intensive development projects,
while maintaining appropriate headroom in respect of liquidity and
financial covenant compliance throughout the assessment period.
In making these assessments, the Board of Directors continued to
monitor the uncertainty caused by the Covid-19 pandemic and its
effects on the global economy, while also noting the gradually
loosening of travel restrictions since the reporting date. The Board
of Directors also assessed the February 2022 ruling by the
Federal Supreme Court of Iraq (FSCI) on the KRG’s constitutional
rights and powers as regards oil and gas as further detailed under
the section on enterprise risk management. It is currently not clear
how this ruling will be followed up. To date there has been no
effect on operations but any development will be closely
monitored. In assessing the effect on going concern the Board of
Directors considered the potential effects of any significant
interruption in the settlement of receivables from the KRG. Were
such an interruption to arise, the Board of Directors would
reassess the levels of capital investment at the Tawke and
Baeshiqa licenses as was the case during the initial stages of the
Covid-19 pandemic. The Board of Directors noted the Company’s
current cash balance when reaching its going concern conclusion.
Moreover, the Board of Directors noted the significant
improvement in oil and gas prices, build-up of the cash balance
and the Group’s reported remaining proven and probable oil and
gas reserves that permit cash flow generation covering the
forecast period.
Stress testing was carried out at lower oil and gas price
scenarios. Sufficient liquidity and covenant compliance can be
maintained through the going concern assessment period in the
base case and the stress test.
Following its review, the Board of Directors 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.
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2021
DNO
27
Estimates and assumptions
The key assumptions and key sources of estimation uncertainty
for the Group are:
•
Risks associated with operating in Kurdistan;
•
Reserves and resources estimates;
•
Contingencies, provisions and litigations;
•
Impairment/reversal of impairment of oil and gas assets;
•
Impairment of technical goodwill;
•
Measurement of fair values;
•
Acquisition accounting;
•
Accounting for exploration costs; and
•
Notional corporate income tax/deferred taxation in Kurdistan.
Risks associated with operating in Kurdistan
DNO has interests in two licenses in Kurdistan through Production
Sharing Contracts (PSCs) and has based its entitlement
calculations on the terms of these PSCs. In 2012, the Federal
Government of Iraq (FGI) challenged the constitutional validity of
the Kurdistan Oil and Gas Law No. 27/2007 (KOGL) and the right
of the KRG to export oil independently of the FGI. The Company
notes from public reports that on 15 February 2022, the 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, and it is unclear how the KRG and the FGI will
follow up on the ruling. 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 available export channels,
DNO has historically faced constraints in fully monetizing the oil it
produces in Kurdistan. Following the ruling and pending follow up
by the KRG and FGI, constraints remain. There is no guarantee
that oil and gas can be exported in sufficient quantities or at
prices required to sustain its operations and investment plans or
that the Group will promptly receive its full entitlement payments
for the oil and gas it delivers for export. Export sales have not
always followed the PSC terms and there has been uncertainty
related to receipt of payments.
The Group has accumulated a receivable against the KRG 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. Entitlement
payments were resumed in March 2020 and override payments
were resumed in early 2021. In December 2020, a plan was put in
place by the KRG to pay the international oil companies operating
in Kurdistan 50 percent of incremental revenue in any month in
which Brent prices exceed USD 50 per barrel towards the arrears
for 2019 and 2020. In May 2021, the KRG informed the
international oil companies of revised terms reducing the payment
of the arrears to 20 percent of incremental revenue in any month
in which Brent prices exceed USD 50 per barrel. The KRG also
advised that all international oil company invoices, including
towards the arrears, will be settled within 60 days of receipt. The
Company expects at a minimum to recover the full nominal value
of the withheld receivables, and DNO continues to work to
improve the terms of recovery of the arrears, including but not
limited to interest payments. During 2021, the outstanding arrears
were reduced from USD 259 million at the start of the year to
USD 169 million at yearend. See Note 9 for further details on
estimates and judgement on recoverability. Management monitors
development and continuously ensures that revenue recognition
criteria in IFRS 15 are met.
Reserves and resources estimate
DNO’s reserves and contingent resources are estimated and
classified by the Company in accordance with the rules and
guidelines of the Society of Petroleum Engineers (SPE) and are in
conformity with requirements from the Oslo Stock Exchange for
the reporting of reserves and resources.
All estimates of reserves and resources involve uncertainty.
International petroleum consultants DeGolyer and MacNaughton
(D&M) carried out an independent assessment of the Tawke
license (containing the Tawke and Peshkabir fields) and the
Baeshiqa license (containing the Baeshiqa and Zartik structures)
in the Kurdistan region of Iraq. International petroleum consultants
Gaffney, Cline & Associates (GCA) carried out an independent
assessment of DNO's licenses in Norway and the United Kingdom
(UK). The Group’s estimates are based on internal assessment
for contingent resources on Yemen Block 47.
Figures reported in Note 23 are the estimated proven (1P),
proven and probable (2P) and proven, probable and possible (3P)
quantities of oil and gas that can be recovered from a field or
reservoir given the information available at yearend.
Important factors that could cause actual results to differ from the
estimates include, but are not limited to: technical, geological and
geotechnical conditions; economic and market conditions; oil and
gas prices; changes in government regulations; 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.
Note 1
Summary of IFRS accounting principles
28
DNO
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.
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 Stated Policies Scenario and
Sustainable Development Scenario as published by the IEA as
part of the World Energy Outlook (WEO) reports. 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 10.
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
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2021
DNO
29
pricing the asset or liability, including assumptions about risk,
assuming that market participants act in their economic best
interest. There are situations when the Group is required to
measure fair values of non-financial assets and liabilities, for
example when investing in equity instruments, in a business
combination including allocation of purchase price or when the
Group measures the recoverable amount of an asset at fair value
less costs to sell in an impairment testing situation.
Fair value measurement of a non-financial asset takes into
account a market participant’s ability to generate economic
benefits by using the asset in its highest and best use or by
selling it to another market participant that would use the asset in
its highest and best use.
The Group uses valuation techniques that are appropriate in the
circumstances and for which sufficient data are available to
measure fair value. The fair value of oil and gas assets is
normally based on discounted cash flow models (income
approach), where the determination of different inputs in the
model requires significant judgment from management, as
described in the section above regarding impairment.
Acquisition accounting
The Group applies the acquisition method for transactions
involving business combinations and applies the principles of the
acquisition method when an interest or an additional interest is
acquired in a joint operation which constitutes a business.
Application of the acquisition method may require significant
judgement in, among other matters, determining and measuring
the fair value of the transaction consideration including contingent
consideration elements, identifying all assets acquired and
liabilities assumed, establishing their fair values, determining
deferred taxes, and allocating the purchase price accordingly,
including measurement and allocation of goodwill. The
judgements applied in acquisition accounting may materially
affect the financial statements both in the transaction period and
in future periods.
The assets acquired through business combinations are
recognized at fair values and, as such, are sensitive to adverse
changes in a number of often volatile economic factors, including
future oil and gas prices and the underlying performance of the
assets.
Accounting for exploration costs
The Group’s accounting policy is to temporarily capitalize drilling
expenditures related to exploration wells, pending an evaluation
of potential oil and gas discoveries. If resources are not
discovered, or if recovery of the resources is not considered
technically or commercially viable, the costs of the exploration
wells are expensed in the income statement. Decisions as to
whether an exploration well should remain capitalized or
expensed during the period may have a material effect on the
financial results for the period.
Notional corporate income tax/deferred taxation in Kurdistan
Under the terms of its PSCs in Kurdistan, DNO is not required to
pay any corporate income taxes. The share of profit oil which the
government is entitled to is deemed to include a portion
representing the notional corporate income tax paid by the
government on behalf of DNO. Current and deferred taxation for
accounting purposes arising from such notional corporate income
tax is not recognized for Kurdistan as it has not been possible to
measure reliably such notional corporate income tax paid on
behalf of DNO. This is an accounting presentational matter and
there is no corporate income tax required to be paid, see also
section Income taxes and Note 8.
■
Group accounting and consolidation principles
Basis for consolidation
The consolidated financial statements include the financial
statements of DNO ASA and its subsidiaries. The Company
currently holds a 100 percent interest in all of its subsidiaries.
The financial results of subsidiaries acquired or sold during the
year are included in the consolidated financial statements from
the date when the Company obtains control of the subsidiary and
up to the date when the Company loses control of the subsidiary.
The financial statements of the subsidiaries are prepared for the
same reporting period as the parent company using consistent
accounting policies. Where necessary, the accounting policies of
the subsidiaries have been adjusted to ensure consistency with
the policies adopted by DNO. All intercompany balances and
transactions have been eliminated upon consolidation.
Interest in jointly controlled operations (assets)
A joint arrangement is present when DNO holds a long-term
interest which is jointly controlled by DNO and one or more other
parties under a contractual arrangement in which decisions about
the relevant activities require the unanimous consent of the
parties sharing control. Such joint arrangements are classified as
either joint operations or joint ventures.
Under IFRS 11
Joint Arrangements
, a joint operation is a joint
arrangement whereby the parties that have joint control of the
arrangement have rights to the assets and obligations for the
liabilities. Oil and gas licenses held by the Group which are within
the scope of IFRS 11 have been classified as joint operations.
DNO recognizes its investments in joint operations by reporting its
share of related revenues, expenses, assets, liabilities and cash
flows under the respective items in the Group's financial
statements.
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.
Note 1
Summary of IFRS accounting principles
30
DNO
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.
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
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2021
DNO
31
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
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.
Note 1
Summary of IFRS accounting principles
32
DNO
■
Impairment/reversal of impairment
At the end of each reporting period, the Group assesses whether
there is any indication that an asset may be impaired. If an
impairment indicator is concluded to exist, an impairment test is
performed.
Indications of impairment may include a decline in the long-term
oil and gas price (or short-term oil and gas price for late-life oil
and gas fields), changes in future investments or significant
downward revision of reserve and resource estimates. For the
purposes of impairment assessment, assets are grouped at the
lowest levels for which there are separable identifiable cash
inflows. For oil and gas assets, a CGU may be individual oil and
gas fields, or a group of oil and gas fields that are connected to
the same infrastructure/production facilities, or a license.
An impairment loss is recognized when the carrying amount
exceeds the recoverable amount of an asset. The recoverable
amount is the higher of the asset’s fair value less costs to sell and
its value in use. Fair value less costs to sell determined through
either the discounted cash flow method (income approach) or the
market transactions method (market approach). The value in use
can only be determined through the discounted cash flow method.
A previously recognized impairment loss is reversed through the
income statement if the circumstances that gave rise to the
impairment no longer exist. It is not reversed to an amount that
would be higher than if no impairment loss had been recognized.
After such a reversal, the depreciation charge is adjusted in future
periods to allocate the asset’s revised carrying amount, less any
residual value, on a systematic basis over its remaining useful life.
Technical goodwill
Technical goodwill is tested for impairment annually or more
frequently when there are impairment indicators. Those indicators
may be specific to an individual CGU or groups of CGUs to which
the technical goodwill is related. When performing the impairment
test for technical goodwill, deferred tax recognized in relation to
the acquired licenses reduces the net carrying value prior to the
impairment charges.
Impairment is recognized if the recoverable amount of the CGU
(or groups of CGUs) to which the technical goodwill is related is
less than the carrying amount.
Impairment of goodwill cannot be reversed in future periods.
■
Financial instruments
A financial instrument is any contract that gives rise to a financial
asset of one entity and a financial liability or equity instrument of
another entity. Financial instruments are initially recognized at fair
value. After initial recognition the measurement and accounting
treatment depend on the type of instrument and classification.
Financial assets
Financial assets are classified at initial recognition and
subsequently measured at:
•
Amortized cost;
•
Fair value through other comprehensive income (FVTOCI); and
•
Fair value through profit or loss (FVTPL).
Financial assets at amortized cost
Financial assets are measured at amortized cost if both of the
following conditions are met:
•
The financial asset is held within a business model with the
objective to hold financial assets in order to collect contractual
cash flows; and
•
The contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of
principal and interest on the principal amount outstanding.
Financial assets at amortized cost are subsequently measured
using the effective interest rate (EIR) method and are subject to
impairment. Gains and losses are recognized in profit or loss
when the asset is derecognized, modified or impaired. The
Group’s financial assets at amortized cost include trade and other
receivables.
Financial assets designated at FVTOCI
Upon initial recognition, equity investments can be irrevocably
classified as equity instruments designated at FVTOCI. Gains and
losses on these financial assets are not recycled to profit or loss
at later periods. Equity instruments designated at FVTOCI are not
subject to an impairment assessment.
Financial assets at FVTPL
Financial assets at FVTPL include financial assets held for
trading, financial assets designated upon initial recognition at
FVTPL or financial assets mandatorily required to be measured at
fair value. Financial assets at FVTPL are carried in the statements
of financial position at fair value with net changes in fair value
recognized in profit or loss. Dividends on listed equity investments
are also recognized as other income in profit or loss when the
right of payment has been established. The Group does not have
significant assets designated at FVTPL.
Derecognition of financial assets
A financial asset is derecognized when the Group:
•
No longer has the right to receive cash flows from the asset;
•
Retains the right to receive cash flows from the asset but has
assumed an obligation to pay them in full without material
delay to a third party under a pass-through arrangement; or
•
Has transferred its rights to receive cash flows from the asset
and either has transferred substantially all the risks and
rewards of the asset or has neither transferred nor retained
substantially all the risks and rewards of the asset but has
transferred the control of the asset.
Impairment of financial assets
An allowance is recognized for expected credit losses (ECLs) for
all debt instruments not held at FVTPL. ECLs are based on the
difference between the contractual cash flows due in accordance
with the contract and all the cash flows that are expected to be
received, discounted at an approximation of the original effective
interest rate.
ECLs are recognized in two stages. For credit exposures with no
significant increase in credit risk since initial recognition, ECLs are
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2021
DNO
33
provided for credit losses that result from default events that are
possible within the next 12 months. For credit exposures with
significant increase in credit risk since initial recognition, a loss
allowance is provided for credit losses expected over the
remaining life of the exposure, irrespective of the timing of the
default.
For trade receivables, a simplified approach is applied in
calculating ECLs. Changes in credit risk are not tracked but
instead a loss allowance based on lifetime ECLs at each reporting
date is recognized. Expected credit losses are based on a
multifactor and holistic analysis and depend on historical
experience with the customers adjusted for forward-looking
factors specific to the customers and the economic environment.
Financial assets are assessed with regards to default when
contractual payments are past the established payment due date
and there is internal or external information indicating that the
Group is unlikely to receive the outstanding contractual amounts
in full. A financial asset is written off when there is no reasonable
expectation of recovering the contractual cash flows.
Further disclosures on impairment of financial assets are provided
in Note 9.
Financial liabilities
Financial liabilities are classified at initial recognition as financial
liabilities at FVTPL, loans and borrowings or payables.
All financial liabilities are recognized initially at fair value and in
the case of loans/borrowings and payables, net of directly
attributable transaction costs.
The Group’s financial liabilities include trade and other payables
and loans.
The subsequent measurement of financial liabilities depends on
the classification. No financial liabilities have been designated at
FVTPL. Interest-bearing loans are after initial recognition
measured at amortized cost using the effective interest rate
method. Gains and losses are recognized in profit or loss when
the liabilities are derecognized as well as through the amortization
process. Amortized cost is calculated by taking into account any
discount or premium on acquisition and fees or costs that are an
integral part of the effective interest rate. The amortization cost is
included as finance expense in the statements of comprehensive
income. This applies mainly to bond loans, see Note 15.
A financial liability is derecognized when the obligation under the
liability is discharged, cancelled or expires. When an existing
financial liability is replaced by another from the same lender on
substantially different terms, or the terms of an existing liability are
substantially modified, such a modification is treated as a
derecognition of the original liability and a recognition of a new
liability. The difference in the respective carrying amounts is
recognized in the statements of comprehensive income.
Cash and cash equivalents
Cash and short-term deposits in the statements of financial
position comprise cash held in banks, cash in hand and short-
term deposits with an original maturity of three months or less.
■
Equity
Ordinary shares
Ordinary shares are classified as equity. Costs directly
attributable to the issue of ordinary shares and share options are
recognized as a reduction of equity, net of any tax effects.
Repurchase of share capital (treasury shares)
When share capital recognized as equity is repurchased, the
amount of the consideration paid, which includes directly
attributable costs, is net of any tax effects and is recognized as a
deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction from total
equity. When treasury shares are subsequently sold or reissued,
the amount received is recognized as an increase in equity and
the resulting surplus or deficit of the transaction is transferred
to/from retained earnings.
Dividend
Liability to pay a dividend is recognized when the distribution is
authorized by the shareholders. A corresponding amount is
recognized directly in equity.
■
Financial income and expenses
Financial income comprises: interest income; dividend income;
gains on the disposal of financial investments; foreign exchange
gains; changes in the fair value of financial assets through profit
or loss; and other financial income. Interest income is recognized
as it accrues in profit or loss using the effective interest method.
Dividend income is recognized in the profit or loss on the date that
the Group’s right to receive payment is established, which in the
case of quoted securities is the ex-dividend date.
Financial expenses comprise: interest expenses on loans;
unwinding of the discount on provisions; changes in the fair value
of financial assets measured at FVTPL; impairment losses
recognized on financial assets; foreign exchange losses; losses
on financial assets recognized in the profit or loss; and other
financial expenses.
Foreign exchange gains or losses from financial instruments are
reported as financial income or financial expenses.
■
Inventories
Inventories are valued at the lower of cost and net realizable
value. Cost is determined by the first-in, first-out (FIFO) method.
Net realizable value is the estimated selling price in the ordinary
course of business, less the estimated costs of completion and
estimated selling expenses.
■
Revenue recognition
Revenues presented in the consolidated statements of
comprehensive income consist of
Revenue from contracts with
customers
(see Note 3).
Revenue from contracts with customers is recognized when the
customer obtains control of the oil and gas, which normally will be
when title passes at the point of delivery.
Note 1
Summary of IFRS accounting principles
34
DNO
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.
Revenues from the sale of services are recognized when services
are performed.
Other revenues are recognized when the goods or services are
delivered and risk and control are transferred.
Revenue recognition in Kurdistan
DNO generates revenues in Kurdistan through the sale of oil
produced from the Tawke license which is exported by pipeline
through Turkey. The title is considered to have passed on delivery
of oil to the export pipeline at Fish Khabur. In addition, pursuant to
a receivables settlement agreement with the KRG in August 2017,
DNO is entitled to production overrides (override) representing
three percent of gross Tawke license revenues until 31 July 2022.
The Group recognizes revenues in Kurdistan in line with the
invoiced oil sales and overrides following monthly deliveries to the
KRG. The PSCs held by the Group are considered to be within
the scope of the standard and sale of oil and gas to customers is
recognized as
Revenue from contracts with customers
. Based on
business practice, the KRG is responsible for exporting the oil
produced in Kurdistan and it is assessed that DNO has a
customer relationship with the KRG. It is considered that the
contracts with customers contain a single performance obligation
which is considered to be delivery of produced oil and gas to the
customer.
The price for oil deliveries to the KRG is based on Brent prices
with adjustments for oil quality and transportation fees.
■
Production Sharing Contracts
A PSC is an agreement between a contractor and a host
government, whereby the contractor bears all of the risks and
costs for exploration, development and production in return for a
stipulated share of production.
The contractor recovers the sum of its investment and operating
costs from a percentage of production (cost oil). In addition, the
contractor is entitled to receive a share of production in excess of
cost oil (profit oil). The sum of cost oil attributable to the
contractor’s share of costs and the share of profit oil represents
the contractor’s entitlement under a PSC. The sum of royalties
and the government’s share of profit oil, including that of a
government-controlled enterprise, represents the government
take under a PSC.
DNO presents its operations governed by PSCs according to the
sales method and only recognizes its sales as revenue after
deduction of government take.
■
Income taxes
Tax income/expense consists of taxes receivable/payable and
changes in deferred taxes. Taxes receivable/payable are based
on the amounts receivable from or payable to the tax authorities.
Deferred tax liability is calculated on all taxable temporary
differences unless there is a recognition exception. A deferred tax
asset is recognized only to the extent that it is probable that the
future taxable income will be available against which the asset
can be utilized. Unrecognized deferred tax assets are re-
assessed at each reporting date and are recognized to the extent
that it has become probable that future taxable profits will allow
the deferred tax asset to be recovered.
Deferred tax assets and deferred tax liabilities are recognized
irrespective of when the differences are reversed. They are
recognized at their nominal value and classified as non-current
assets/liabilities in the statements of financial position. Deferred
tax assets and deferred tax liabilities are offset in the statements
of financial position if there is a legal right to settle current tax
amounts on a net basis and the deferred tax amounts are levied
by the same taxing authority on the same entity or different
entities that intend to realize the asset and settle the liability at the
same time.
Tax payable and deferred tax are recognized directly in the equity
to the extent that they relate to items charged directly to equity.
For treatment of tax in relation to business combinations, see the
Business combinations section.
DNO’s PSCs provide that the corporate income tax to which the
contractor is subject is deemed to have been paid to the
government as part of the payment of profit oil to the government
or its representatives. For accounting purposes, if such notional
income tax is to be classified as income tax in accordance with
IAS 12
Income Taxes
, the Group would present this as an income
tax expense with a corresponding increase in revenues.
Furthermore, it would be assessed whether any deferred tax
asset or liability is required to be recognized equal to the
difference between book values and the tax values of the
qualifying assets and liabilities, multiplied by the applicable tax
rate.
■
Business combinations
In accordance with IFRS 3
Business Combinations
, an acquisition
is considered a business combination, when the acquired asset or
groups of assets constitute a business (i.e., an integrated set of
operations and assets conducted and managed for the purpose of
providing a return to the investors).
Acquired businesses are included in the financial statements from
the transaction date. The transaction date is defined as the date
on which the Group achieves control over the financial and
operating assets. This date may differ from the actual date on
which the assets are transferred.
Note 1
Summary of IFRS accounting principles
Annual Report and Accounts 2021
DNO
35
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.
■
Employee benefits
Pensions
The Group’s pension obligations in Norway are limited to certain
defined contribution plans which are paid to pension insurance
plans and charged to profit or loss in the period in which they are
incurred. Once the contributions are paid there are no further
obligations.
Share-based payments
Cash-settled share-based payments are recognized in the income
statement as expenses during the vesting period and as a liability.
The liability is measured at fair value and revaluated using the
Black & Scholes pricing model at each balance sheet date and at
the date of settlement, with any change in the fair value
recognized in the income statement for the period.
■
Provisions and contingent liabilities
A provision is recognized when the Group has a present
obligation (legal or constructive) as a result of a past event, it is
likely that an outflow of resources will be required to settle the
obligation and a reliable estimate can be made of the obligation
amount. When the Group expects some or all of a provision to be
reimbursed, for example under an insurance contract, the
reimbursement is recognized as a separate asset, but only if the
reimbursement is certain. The expense related to any provision is
presented in profit or loss, net of any reimbursement. Provisions
Note 1
Summary of IFRS accounting principles
36
DNO
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 2021 but are not considered to have any material impact on the
Group’s financial statements.
Consolidated accounts
Annual Report and Accounts 2021
DNO
37
Note 2
Segment information
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 two operating segments: Kurdistan and the North Sea (which includes the Group’s oil and gas activities
in Norway and the UK). The operating segments correspond to the reportable segments. Remaining operating segments are included in
the Other category based on a materiality assessment.
The country-by-country reporting for companies in extractive industries in line with the Norwegian Accounting Act can be found in page
88 of this report.
USD million
Total
Un-
Full-Year ending
reporting
allocated/
Total
31 December 2021
Note
Kurdistan
North Sea
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
Other income
-
0.5
-
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
10
-
-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
38
DNO
Note 2
Segment information
USD million
Total
Un-
Full-Year ending
reporting
allocated/
Total
31 December 2020
Note
Kurdistan
North Sea
Other
segments
eliminated
Group
COMPREHENSIVE INCOME INFORMATION
Revenues
3
369.1
245.8
-
614.9
-
614.9
Inter-segment sales
-
1.4
-
1.4
-1.4
-
Production costs
-94.5
-123.2
-
-217.6
0.4
-217.3
Movement in overlift/underlift
-
-11.3
-
-11.3
-
-11.3
Depreciation, depletion and amortization
-239.5
-118.9
-
-358.4
-3.0
-361.4
Cost of goods sold
4
-334.0
-253.4
-
-587.3
-2.7
-590.0
Gross profit
35.2
-6.2
-
29.0
-4.1
24.9
Other income
-
-
-
-
-
-
Administrative expenses
5
-0.6
-2.1
-4.2
-6.9
2.1
-4.8
Other operating expenses
5
-1.4
-
-1.3
-2.7
-
-2.7
Impairment of oil and gas assets
10
-
-276.0
-
-276.0
-
-276.0
Exploration expenses
6
-1.6
-60.1
-
-61.7
5.7
-55.9
Operating profit/-loss
31.6
-344.4
-5.4
-318.3
3.7
-314.5
Net financial income/-expense
7
-15.9
-26.3
1.3
-40.9
-70.3
-111.2
Tax income/-expense
8
-
141.7
0.5
142.2
-2.4
139.8
Net profit/-loss
15.7
-229.0
-3.7
-217.0
-68.9
-285.9
FINANCIAL POSITION INFORMATION
Non-current assets
830.5
1,031.6
-
1,862.1
25.0
1,887.1
Current assets
173.1
335.9
3.9
512.8
308.8
821.6
Total assets
1,003.6
1,367.4
3.9
2,374.9
333.8
2,708.7
Non-current liabilities
60.6
710.1
-
770.7
796.2
1,566.9
Current liabilities
73.9
178.8
28.9
281.6
14.5
296.1
Total liabilities
134.5
888.9
28.9
1,052.3
810.8
1,863.0
Consolidated accounts
Annual Report and Accounts 2021
DNO
39
Note 3
Revenues
1 January - 31 December
USD million
2021
2020
Sale of oil
828.1
566.6
Sale of gas
151.3
27.5
Sale of natural gas liquids (NGL)
21.3
14.8
Tariff income
3.4
6.0
Total revenues from contracts with customers
1,004.1
614.9
Sale of oil (bopd)
36,583
48,139
Sale of gas (boepd)
4,344
4,548
Sale of natural gas liquids (NGL) (boepd)
1,244
1,695
Total sales volume (boepd)
42,171
54,382
In 2021, sale of oil from Kurdistan was USD 594.3 million and in the North Sea USD 233.8 million. Sale of gas was USD 151.3 million,
sale of NGL was USD 21.3 million and tariff income was USD 3.4 million, all entirely from the North Sea.
In 2020, sale of oil from Kurdistan was USD 369.1 million and in the North Sea USD 197.5 million. Sale of gas was USD 27.5 million,
sale of NGL was USD 14.8 million and tariff income was USD 6 million, all entirely from the North Sea.
Note 4
Cost of goods sold/Inventory
1 January - 31 December
USD million
2021
2020
Lifting costs
-184.2
-181.1
Tariff and transportation expenses
-34.5
-36.2
Production costs based on produced volumes
-218.8
-217.3
Movement in overlift/underlift
-18.3
-11.3
Production costs based on sold volumes
-237.0
-228.6
Depreciation, depletion and amortization
-206.0
-361.4
Total cost of goods sold
-443.1
-590.0
Lifting costs consist of expenses related to the production of oil and gas, including operation and maintenance of installations, well
intervention activities and insurances. Tariff and transportation expenses consist of charges incurred by the Group in the North Sea for
the use of infrastructure owned by other companies.
Years ended 31 December
USD million
2021
2020
Spare parts
35.8
41.9
Total inventory
35.8
41.9
Total inventory of USD 35.8 million at yearend 2021 was related to Kurdistan (USD 18.8 million) and the North Sea (USD 17.0 million).
Consolidated accounts
40
DNO
Note 5
Administrative/Other operating expenses
1 January - 31 December
USD million
2021
2020
Salaries, bonuses, etc.
-56.2
-42.0
Employer's payroll tax expenses
-5.4
-5.2
Pensions
-3.8
-3.7
Other personnel costs
-4.2
-1.1
General and administration expenses
-42.3
-38.9
Reallocation of salaries and social expenses to lifting costs and exploration costs/PP&E and intangible assets
95.5
86.0
Total administrative expenses
-16.2
-4.8
Other expenses
-12.0
-2.7
Total other operating expenses
-12.0
-2.7
This note should be read in conjunction with Note 21 on related parties. Salaries and social expenses directly attributable to license
activities are reclassified to lifting costs and exploration costs, or tangible assets and capitalized exploration. Other expenses in 2021
were mainly related to provisions in Oman and Yemen, see Note 17.
DNO has a defined contribution scheme for its Norway-based employees, with USD 3.8 million expensed in 2021 (USD 3.7 million in
2020). The Group’s obligations are limited to the annual pension contributions. DNO meets the Norwegian legal requirements for
mandatory occupational pension
(“obligatorisk tjenestepensjon”).
Certain members of the executive management and staff have been awarded synthetic shares during the year as part of their variable
remuneration. At yearend 2021, the Company’s liability for synthetic shares as part of other variable remuneration amounted to USD 2.2
million (USD 1.3 million at yearend 2020). 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
2021
2020
Outstanding as of 1 January
2,837,151
3,191,605
Granted during the year
1,321,431
1,561,975
Forfeited/reversed during the year
71,374
551,116
Settled during the year
908,672
1,365,313
Expired during the year
-
-
Outstanding as of 31 December
3,178,536
2,837,151
Unrestricted as of 31 December
462,214
626,951
Weighted average remaining contractual life for the synthetic shares (years)
2.78
3.85
Weighted average settlement price for synthetic shares settled during the year (NOK)
10.83
6.11
Settlement price for synthetic shares at the end of the year (NOK)
10.46
6.87
Consolidated accounts
Annual Report and Accounts 2021
DNO
41
Note 5
Administrative/Other operating expenses
Remuneration to Board of Directors and executive management
1 January - 31 December
USD million
2021
2020
Managing Director
Salary
-0.69
-0.63
Bonus
-0.08
-0.20
Pension
-0.02
-0.02
Other remuneration
-0.07
-0.07
Remuneration to Managing Director
-0.85
-0.92
Other executive management
Salary
-3.24
-3.71
Bonus
-0.70
-0.89
Pension
-0.13
-0.15
Other remuneration
-0.55
-0.71
Remuneration to other executive management
-4.63
-5.46
Total remuneration to executive management
-5.48
-6.38
Number of managers included
8
10
Total remuneration to Board of Directors
-1.10
-1.00
Total remuneration to Board of Directors and executive management
-6.58
-7.38
Total remuneration of USD 1.3 million (not included in the above table) was in 2021 paid to Ute Quinn and Aernout van der Gaag,
former members of the executive management. For further details on remuneration to the executive management, see Note 3 in the
parent company accounts.
Members of the executive management, Bjørn Dale, Chris Spencer, Haakon Sandborg and Nicholas Whiteley have severance payment
agreements ranging from six months to 12 months of their respective annual base salaries.
Shares and options held by Board of Directors and executive management
Years ended 31 December
Directors and executive management
Shares
Options
Shares
Options
Bijan Mossavar-Rahmani, Executive Chairman*
-
-
-
-
Lars Arne Takla, Deputy Chairman
30,000
-
30,000
-
Elin Karfjell, Director (Elika AS)
33,000
-
33,000
-
Gunnar Hirsti, Director (Hirsti Invest AS)
350,000
-
350,000
-
Shelley Watson, Director*
-
-
-
-
Bjørn Dale, Managing Director
-
-
-
-
Chris Spencer, Chief Operating Officer (Chris's Corporation AS)
32,000
-
32,000
-
Haakon Sandborg, Chief Financial Officer
-
-
-
-
Nicholas Whiteley, Chief Commercial Officer
-
-
-
-
Ørjan Gjerde, General Manager DNO North Sea (Kvile Invest AS)
15,000
-
15,000
-
Tom Allan, General Manager Kurdistan region of Iraq
-
-
-
-
Geir Arne Skau, Director of Human Resources and Corporate Services
25,750
-
10,750
-
Tonje Pareli Gormley, General Counsel - Middle East
-
-
-
-
* Bijan Mossavar-Rahmani and Shelley Watson hold indirect interests in the Company through their shareholdings in RAK Petroleum plc (see Note 11).
Executive management have been awarded synthetic shares during the year as part of their variable remuneration, see Note 3
in the parent company accounts.
Auditor fees
1 January - 31 December
USD million (excluding VAT)
2021
2020
Auditor fees
-0.84
-0.74
Other financial auditing
-0.04
-0.01
Tax advisory services
-0.10
-0.05
Other advisory services
-
-0.01
Total auditor fees
-0.98
-0.81
Consolidated accounts
42
DNO
Note 6
Exploration expenses
1 January - 31 December
USD million
2021
2020
Exploration expenses (G&G and field surveys)
-19.1
-16.1
Seismic costs
-37.6
-2.9
Exploration expenses capitalized in previous years carried to cost
-13.4
-0.4
Exploration expenses capitalized during the year carried to cost
-40.7
-17.1
Other exploration expenses
-21.5
-19.5
Total exploration expenses
-132.3
-55.9
Exploration expenses in 2021 and 2020 were related to exploration activities in the North Sea, including expensing of exploration wells
and seismic purchase.
Note 7
Financial income and financial expenses
1 January - 31 December
USD million
2021
2020
Interest income
1.7
5.4
Other financial income
24.3
-
Currency exchange gains recognized in the income statement (net)
-
14.4
Financial income
26.0
19.8
Interest expenses
-74.2
-87.3
Currency exchange loss recognized in the income statement (net)
-5.8
-
Other financial expenses
-46.8
-43.7
Financial expenses
-126.7
-131.1
Net financial income/-expenses
-100.7
-111.3
Other financial expenses in 2021 relate mainly 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 accounting effects from IFRS 9 assessments during the year
(presented gross) (see Note 9 and 12). Other financial income relates mainly to accounting effects from IFRS 9 assessments during the
year (presented gross) entirely reversing the financial expense recognized in 2020 (see Note 9 and 12).
Consolidated accounts
Annual Report and Accounts 2021
DNO
43
Note 8
Income taxes
Tax income/-expense
1 January - 31 December
USD million
2021
2020
Changes in deferred taxes
-115.2
11.1
Income taxes receivable/-payable
98.9
128.8
Total tax income/-expense
-16.3
139.8
Income tax receivable/-payable
Years ended 31 December
USD million
2021
2020
Tax receivables
21.1
63.1
Income taxes payable
-33.1
-
Net tax receivable/-payable
-11.9
63.1
During 2020, the Norwegian Parliament approved certain time limited changes to the taxation of oil and gas companies operating on the
Norwegian Continental Shelf (NCS) with effect from the income year 2020. The changes comprised of immediate expensing of
investments in the special petroleum tax regime, increased uplift on capital investments from 20.8 percent over four years to 24 percent
in the first year and cash refund of tax value of losses incurred in the income years 2020 and 2021. The temporary changes, other than
the cash refund of tax losses, will also apply to investments where the Plan for Development and Operation (PDO) is delivered by 31
December 2022 and approved by 31 December 2023.
During 2021, the Norwegian Government proposed certain changes to the taxation of oil and gas companies operating on the NCS with
effect from 2022. The companies will be able to expense the investments immediately in the special tax basis and receive cash refund
of tax value of all losses in the special tax basis. The uplift on investments is proposed discontinued. The ordinary corporate tax will be
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 will not be eligible for refund but can be carried forward. Moreover, tax value of unused uplift
and carried forward losses as of yearend 2021 will be paid out. Provisions under the temporary changes extending beyond 2021 will not
be impacted. As of the date of issuing this report, the proposal has not been approved by the Norwegian Parliament and may be subject
to adjustments. If the proposal is approved, limited impact is estimated on DNO’s asset values.
The tax income/-expense, tax receivable/-payable and recognized deferred tax assets/-liabilities relate to activity on the NCS and the
UKCS. Current tax receivable of USD 21.1 million relate to tax refund of decommissioning spend on the UKCS for 2021. Current income
tax payable of USD 33.1 million relate to repayment of tax refunds in Norway that exceeded the tax value of actual losses for 2021.
During 2021, DNO received total tax refunds of USD 159.4 million in Norway in relation to tax losses incurred in 2020 and estimated tax
losses for 2021 and USD 15.3 million in the UK in relation to decommissioning spend for 2020. The refund of tax losses on the NCS
incurred in 2021 is paid out in six instalments every two months with the first three instalments received during the second half of 2021.
As the tax value of actual tax loss incurred for 2021 is lower than what has already been received in tax refunds during 2021, DNO will
repay the difference over the remaining three instalments during the first half of 2022. The decommissioning tax refund on the UKCS for
2021 of USD 21.1 million is expected during the third quarter of 2022.
Reconciliation of tax income/-expense
1 January - 31 December
USD million
2021
2020
Profit/-loss before income tax
220.1
-425.8
Expected income tax according to nominal tax rate in Norway, 22 percent
-52.4
83.6
Expected income tax according to nominal tax rate in Norway, 56 percent
24.3
182.5
Expected income tax according to nominal tax outside Norway
7.4
19.0
Foreign exchange variations between functional and tax currency
-4.5
-19.9
Adjustment of previous years
0.2
0.8
Adjustment of deferred tax assets not recognized
-31.0
-17.2
Change in previous years
-
0.4
Other items including other permanent differences
35.3
-110.5
Change in tax rate
4.6
0.4
Tax loss carried forward utilized
-
0.7
Tax income/-expense
-16.3
139.8
Effective income tax rate
7.4%
-32.8%
Taxes charged to equity
-
-
Consolidated accounts
44
DNO
Note 8
Income taxes
Expected income tax in the 56 percent basis and the expected income tax related to activities 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
impairment of goodwill which is not tax deductible, and permanent differences on tax exempted profits/losses from upstream activities
outside of Norway carried out by the Company’s Norwegian subsidiaries.
Tax effects on temporary differences
Years ended 31 December
USD million
2021
2020
Tangible assets
-351.5
-267.4
Intangible assets (including capitalized exploration expenses)
-168.0
-197.9
ARO provisions
266.6
313.2
Losses carried forward
155.5
170.3
Non-deductible interests carried forward
29.4
11.5
Other temporary differences
-8.1
-5.2
Net deferred tax assets/-liabilities
-76.0
24.4
Valuation allowance
-162.0
-155.8
Net deferred tax assets/-liabilities
-238.0
-131.4
Recognized deferred tax assets
29.3
47.4
Recognized deferred tax liabilities
-267.3
-178.8
Under the terms of the PSCs in Kurdistan, the Company’s subsidiary DNO Iraq AS is not required to pay any corporate income taxes.
The share of profit oil which the government is entitled to is deemed to include a portion representing the notional corporate income tax
paid by the government on behalf of DNO Iraq AS. Current and deferred taxation arising from such notional corporate income tax is not
calculated for Kurdistan, as there is uncertainty related to the tax laws of the KRG and there is currently no well-established tax regime
for international oil companies. As such, it has not been possible to reliably measure such notional corporate income taxes deemed to
have been paid on behalf of DNO Iraq AS. This is an accounting presentational issue and there is no outstanding tax required to be paid
by DNO Iraq AS. See also Note 1.
Profits/-losses by Norwegian companies from upstream activities outside of Norway are not taxable/deductible in Norway in accordance
with the General Tax Act, section 2-39. Under these rules, only certain financial income and expenses are taxable in Norway. A deferred
tax asset has been recognized on petroleum activities in Norway and the UK in relation to carry forward losses and temporary
differences as it has been considered probable that taxable profits or tax refunds will be available to utilize these deferred tax assets. A
valuation allowance was recognized relating to carried forward losses in Norway (ordinary tax regime) and the UK due to the uncertainty
regarding future taxable profits.
There are no tax consequences attached to items recorded in other comprehensive income.
The following nominal tax rates apply in the jurisdictions where the subsidiaries of the Group are taxable: Ordinary tax regime in Norway
(22 percent), the NCS (78 percent), ordinary tax regime in the UK (19 percent) and the UKCS (40 percent). In the UK, the tax rate in the
ordinary tax regime will increase to 25 percent from April 2023. This has not had any impact on deferred taxes as deferred tax asset has
not been recognized on carried forward losses in the ordinary tax regime in the UK.
Reconciliation of change in deferred tax assets/-liabilities
Years ended 31 December
USD million
2021
2020
Net deferred tax assets/-liabilities at 1 January
-131.4
-153.9
Change in deferred taxes in the income statement
-115.2
11.1
Deferred taxes related to business combinations and other transactions
-
-
Prior period adjustment
-
0.8
Reclassification from tax receivable
-
1.6
Currency and other movements
8.6
9.0
Net deferred tax assets/-liabilities at 31 December
-238.0
-131.4
Reconciliation of change in tax receivable/-payable
Years ended 31 December
USD million
2021
2020
Net tax receivable/-payable at 1 January
63.1
164.5
Tax receivable/-payable related to transactions posted directly to balance sheet
3.7
-
Tax receivable/-payable in the income statement
98.9
128.8
Tax payment/-refund
-174.7
-236.3
Prior period adjustment
-
-2.4
Reclassification to deferred tax asset
-
-1.6
Currency and other movements
-3.0
10.0
Net tax receivable/-payable at 31 December
-11.9
63.1
Consolidated accounts
Annual Report and Accounts 2021
DNO
45
Financial risk management, objectives and policies
Overview
The Group’s principal financial liabilities are comprised of interest-bearing liabilities and trade and other payables. The main purpose of
these financial liabilities is to finance DNO’s operations. The Group’s principal financial assets include trade and other receivables, tax
receivables and cash and cash equivalents. The Group also holds investments in equity instruments.
DNO is exposed to a range of risks affecting its financial performance including market risk, liquidity risk and credit risk. The Group
seeks to minimize potential adverse effects of such risks through sound business practices and risk management programs. 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, interest rates and the
value of equity instruments held by the Company.
Oil and gas price risk
DNO’s revenues are generated from the sale of oil and gas. Various hedging opportunities were evaluated and assessed in 2021 as
part of a prudent financial risk management process. At yearend 2021, the Company had gas price put options in place with an average
strike price of GBP 0.935 per therm, securing approximately 75 percent of after-tax profit from the estimated 2022 gas production.
The following table illustrates the impact on 2020 and 2021 profit/-loss before income tax from oil and gas price fluctuations deemed
reasonable and possible, with all other variables held constant. In addition to driving revenues, price fluctuations or the expectations of
price fluctuations could impact DNO’s capital expenditure levels and impairment assessments. See Note 10 for a sensitivity analysis
related to the impairment assessment of oil and gas assets.
Change in yearend
Effect on profit
oil and gas price
before tax
2021
+/- 15.0
2020
+/- 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. The Group had no currency hedging instruments at yearend 2021 although it
monitors its foreign currency risk exposure on a continuous basis and evaluates hedging alternatives.
The following tables illustrate the impact on DNO’s profit/-loss before income tax and other comprehensive income in 2020 and 2021
from foreign currency exchange rate fluctuations deemed reasonable and possible in NOK and GBP exchange rates, with all other
variables held constant. The other currencies (e.g., AED, IQD) are not included as the exposure is deemed immaterial.
Change in
Effect on profit
Effect on OCI
NOK (percent)
before tax (USD mill)
(USD mill)
2021
+ 10.0
-5.9
-30.0
2021
- 10.0
5.9
8.8
2020
+ 10.0
-7.8
-65.4
2020
- 10.0
7.8
74.4
Change in
Effect on profit
Effect on OCI
GBP (percent)
before tax (USD mill)
(USD mill)
2021
+ 10.0
1.4
-75.6
2021
- 10.0
-1.4
50.8
2020
+ 10.0
1.0
-31.4
2020
- 10.0
-1.0
30.0
Change in
Effect on profit
Effect on OCI
EUR (percent)
before tax (USD mill)
(USD mill)
2021
+ 10.0
-3.6
-
2021
- 10.0
3.6
-
2020
+ 10.0
-0.9
-
2020
- 10.0
0.9
-
Note 9
Financial instruments
46
DNO
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 reserve based lending facility (RBL) is considered limited and no hedging
arrangement was in place during 2021. The Group is also exposed to interest rate risk on its cash deposits held at floating interest rates.
The following table illustrates the impact on DNO’s profit/-loss before income tax in 2020 and 2021 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)
2021
+/- 100
+/-3.9
2020
+/- 100
+/-2.4
Equity price risk
The Group’s listed equity investments are recorded at fair value at the end of each period and are exposed to market price risk arising
from uncertainties about future values of the equity instruments. Fair value changes are included in other comprehensive income, see
Note 1 and Note 11 for more information.
As of 31 December 2021, the exposure to equity investments at fair value was USD 16.2 million (USD 12.6 million at yearend 2020).
The following table illustrates the impact on DNO’s profit/-loss before income tax and other comprehensive income from a change in the
equity price deemed reasonable and possible, with all other variables held constant.
Increase/decrease
in share price
Effect on profit
Effect on OCI
before tax (USD mill)
(USD mill)
2021
+/- 10.0
-
2020
+/- 10.0
-
Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group’s business activities may not be available. Prudent liquidity risk
management implies maintaining sufficient cash balances, credit facilities and other financial resources to maintain financial flexibility
under dynamic market conditions. The Group’s principal sources of liquidity are operating cash flows from its producing assets in
Kurdistan and the North Sea. In addition to its operating cash flows, the Group relies on the debt capital markets for both short- and
long-term funding, see Note 15. The Group’s finance function prepares projections on a regular basis in order to plan the Group’s
liquidity requirements. These plans are updated regularly for various scenarios and form part of the basis for decision making for the
Company’s Board of Directors and executive management.
Excessive risk concentration
Concentrations arise when a number of counterparties are engaged in similar business activities, or activities in the same geographical
region, or have economic features that would cause their ability to meet contractual obligations to be similarly affected by changes in
economic, political or other conditions. DNO’s revenues currently derive from production in the Tawke license in Kurdistan and from
several licenses in the North Sea. The Group actively seeks to reduce such risk through organic growth and business and asset
acquisitions aimed at further diversifying its revenue sources.
Note 9
Financial instruments
Annual Report and Accounts 2021
DNO
47
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 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
USD million
On
Less than
3 to 12
1 to 3
Over 3
At 31 December 2020
demand
3 months
months
years
years
Interest-bearing liabilities*
-
17.1
51.4
516.6
564.0
Other provisions and charges
-
11.3
14.0
-
-
Taxes payable
-
-
-
-
-
Trade and other payables
2.0
169.8
8.5
-
-
Total liabilities
2.0
198.2
73.9
516.6
564.0
* Face value of the bond loans are USD 794.9 million at yearend 2021 (USD 800 million at yearend 2020).
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
2021
2020
Trade debtors (non-current portion) (Note 12)
18.2
182.0
Trade debtors (Note 12)
344.4
96.2
Other receivables (Note 12)
139.4
143.3
Tax receivables
21.1
63.1
Cash and cash equivalents
736.6
477.1
Total
1,259.7
961.7
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.
Note 9
Financial instruments
48
DNO
Trade receivables from oil sales and override invoices in Kurdistan
Normal payment terms apply to amounts owed to DNO by the KRG for oil sales and override invoices from the Tawke license in
Kurdistan. Since late 2015, DNO received the payment due to it from oil sales and overrides on a monthly basis from the KRG until early
2020. At yearend 2020, the Group had accumulated a receivable against the KRG after certain 2019 and 2020 entitlement and override
payments to the Group (USD 259 million DNO share) and other KRI oil exporters were withheld early in 2020 by the KRG in connection
with the Covid-19 pandemic. Entitlement payments were resumed in March 2020 and override payments were resumed in early 2021.
In December 2020, the KRG informed the international oil companies operating in Kurdistan of a payment plan whereby the KRG stated
it would pay 50 percent of incremental revenue in any month in which Brent prices exceed USD 50 per barrel towards the arrears for
2019 and 2020. At yearend 2020, due to the IFRS 9 requirement to incorporate the time value of money, the Company reduced the
book value of the Tawke license arrears by USD 16 million (recognized as other financial expense) when comparing the book value of
the arrears to the estimated present value.
In May 2021, the KRG informed the international oil companies of revised terms reducing the payment of the arrears to 20 percent of
incremental revenue in any month in which Brent prices exceed USD 50 per barrel. The KRG also advised that all international oil
company invoices, including towards the arrears, will be settled within 60 days of receipt. The Company expects at a minimum to
recover the full nominal value of the withheld receivables, and DNO continues to work to improve the terms of recovery of the arrears,
including but not limited to interest payments. During 2021, the outstanding arrears were reduced from USD 259 million at the start of
the year to USD 169.1 million at yearend. At yearend 2021, in line with IFRS 9, the Company made a re-run of the estimated present
value, updated the Brent price assumptions resulting in a net increase in the book value of the arrears by USD 16 million, entirely
reversing the financial expense recognized in 2020. Moreover, the classification of the receivables (current/non-current portion) was
updated accordingly. The calculation of present value in accordance with IFRS 9, takes into account the most recent production
forecasts for the Tawke license and the Company’s Brent price assumptions to determine the expected timing of payments towards the
arrears plus contractual interests under IFRS 9, and reflects the probability-weighted amount for a range of possible scenarios including
probability-weighted Brent price scenarios with a probability assigned to each. The discount rate applied reflects the Company’s cost of
debt.
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 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)
-
-
-
-
-
-
-
As of 31 December 2020
Trade debtors (nominal value) (Note 12)
-
42.0
2.7
2.8
3.3
243.4
294.2
Expected credit loss rate (percent)
-
-
-
-
-
-
-
Expected credit loss rate (USD million)
-
-
-
-
-
-
-
Total trade debtors of USD 362.6 million at yearend 2021 relate mainly to the Tawke license, see Note 12 for further 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 a variety of other
measures.
The Group monitors capital on the basis of the equity ratio, which is calculated as total equity divided by total assets. It is DNO’s policy
that this ratio should be 30 percent or higher. The financial covenants of the bond loans require a minimum of USD 40 million of liquidity
and that the Group maintains either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million.
There is also a restriction from declaring or making any dividend payments if the liquidity of the Company is less than USD 80 million
immediately after such distribution is made, see Note 15. The equity ratio has improved primarily due to a net profit in 2021. The table
below shows the book equity ratio at yearend.
Note 9
Financial instruments
Annual Report and Accounts 2021
DNO
49
No changes were made in the objectives, policies or processes for managing capital during 2021 and 2020.
Years ended 31 December
USD million
2021
2020
Total equity
1,018.8
845.6
Total assets
2,947.8
2,708.7
Equity ratio
34.6%
31.2%
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
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
-
-
-
-
-
-
* 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
2020 - USD million
Note
at FVTOCI
cost
Total
Date of valuation
Level 1
Level 2
Level 3
Financial assets measured or disclosed at fair value
Financial investments
11
12.6
-
12.6
31 December 2020
12.6
-
-
Financial liabilities measured or disclosed at fair value
Interest-bearing liabilities (non-current)
15
-
934.2
934.2
31 December 2020
746.5
-
149.6
Interest-bearing liabilities (current)
15
-
-
-
-
-
-
50
DNO
Note 10
Property, plant and equipment/Intangible assets
Depreciation, depletion and amortization (DD&A) is charged to cost of goods sold in the statements of comprehensive income.
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
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
Disposals acquisition costs
-
-440.4
-440.4
-
-2.6
-443.0
Disposals depreciation/impairments
-
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 (2-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
** Transfers relate to reclassification of the book value of Baeshiqa license from exploration phase (intangible assets) to development phase (tangible assets)
following KRG approval of the first phase development plan and reclassification of the book value of Iris/Hades (PL644) license following concept select.
Annual Report and Accounts 2021
DNO
51
Note 10
Property, plant and equipment/Intangible assets
DD&A is charged to cost of goods sold in the statements of comprehensive income.
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
-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
Disposals cost price
-
-
-6.0
-0.3
-6.3
-6.3
Disposals impairments/depreciation
-
-
-
-
-
-
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
21.2
207.1
4.0
232.4
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)
* Additions through license acquisition relate to DNO's acquisition of ExxonMobil’s remaining 32 percent interest in the Baeshiqa license, approved by
the KRG in August 2021. As consideration, DNO has covered ExxonMobil’s share of exploration costs since January 2019 up to KRG’s approval of the
acquisition in August 2021 and the seller will receive a payment of USD 15 million. Following KRG’s approval of the acquisition, DNO’s payments for
ExxonMobil’s share of exploration costs was transferred to intangible assets, previously presented under Trade and other receivables.
** Transfers relate to reclassification of the book value of Baeshiqa license from exploration phase (intangible assets) to development phase (tangible assets)
following KRG approval of the first phase development plan, and reclassification of the book value of Iris/Hades (PL644) license following concept select.
For pledges over the North Sea oil and gas assets, see Note 15.
52
DNO
Note 10
Property, plant and equipment/Intangible assets
PROPERTY, PLANT AND EQUIPMENT
Total
Development
Production
oil & gas
Other
RoU
2020 - USD million
assets
assets
assets
PP&E
assets
Total
As of 1 January 2020
Acquisition costs
120.4
2,871.6
2,992.0
18.0
17.5
3,027.5
Accumulated impairments
-42.1
-334.6
-376.7
-0.1
-
-376.8
Accumulated depreciation
-
-1,279.9
-1,279.9
-17.8
-3.6
-1,301.3
Net book amount
78.3
1,257.1
1,335.4
0.1
14.0
1,349.5
Period ended 31 December 2020
Opening net book amount
78.3
1,257.1
1,335.4
0.1
14.0
1,349.5
Translation differences
8.8
-3.6
5.2
0.6
-
5.8
Additions*
22.8
169.0
191.8
0.4
7.0
199.2
Transfers
-
-
-
-
-
-
Disposal cost price
-
-
-
-5.0
-1.9
-6.9
Disposal impairments/depreciations
-
-
-
7.0
1.1
8.1
Impairments
-
-24.0
-24.0
-
-
-24.0
Depreciation
-
-352.4
-352.4
-1.2
-4.0
-357.6
Closing net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
As of 31 December 2020
Acquisition costs
152.0
3,037.0
3,189.0
13.7
22.9
3,225.6
Accumulated impairments
-42.1
-358.6
-400.7
-0.1
-
-400.8
Accumulated depreciation
0.0
-1,632.3
-1,632.3
-11.7
-6.7
-1,650.8
Net book amount
109.9
1,046.1
1,155.9
2.0
16.2
1,174.1
Depreciation method
UoP
Linear (3-7 years)
* Includes changes in estimate of asset retirement, see Note 16.
INTANGIBLE ASSETS
Total Other
License
Exploration
intangible
2020 - USD million
Goodwill
interest
assets
Other
assets
Total
As of 1 January 2020
Acquisition costs
462.6
95.7
339.4
13.8
448.9
911.5
Accumulated impairments/exploration write-offs
-128.8
-12.0
-18.3
-
-30.2
-159.0
Accumulated depreciation
-
-63.6
-
-8.6
-72.1
-72.0
Net book amount
333.9
20.3
321.1
5.2
346.6
680.5
Period ended 31 December 2020
Opening net book amount
333.9
20.3
321.1
5.2
346.6
680.5
Translation differences
-10.8
-
5.9
-
5.9
-4.7
Additions
-
-
62.3
0.5
62.8
62.8
Transfers
-
-
-
-
-
-
Disposal cost price
-
-0.4
-0.9
-
-1.3
-1.3
Disposal impairments/depreciations
-
5.8
0.9
-
6.7
6.7
Exploration cost previously capitalized carried to cost
-
-17.5
-17.5
-17.5
Impairments
-161.1
-
-90.9
-
-90.9
-252.0
Depreciation
-
-2.8
-
-1.0
-3.8
-3.8
Closing net book amount
162.0
23.0
280.9
4.7
308.6
470.6
As of 31 December 2020
Acquisition costs
474.3
97.1
389.2
14.3
500.5
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
Depreciation method
UoP
Linear (3-7 years)
Annual Report and Accounts 2021
DNO
53
Note 10
Property, plant and equipment/Intangible assets
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 2021.
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 2021 were as follows (yearend 2020 in
brackets):
2022
2023
2024
2025
Brent (USD/bbl)
76.9 (59.1)
70.4 (59.1)
68.3 (64.7)
70.0 (70.4)
NBP (pence/therm)
158.3 (37.8)
77.4 (41.4)
65.5 (45.1)
57.6 (48.7)
For periods after year 2025, the long-term oil and gas price assumptions applied were USD 65 per barrel and 45 pence sterling per
therm, respectively (in real terms, basis year 2021).
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 2021 was 13.6 percent (13 percent at yearend
2020) for the Kurdistan assets. For the fair value calculations, the relevant post-tax nominal discount rates at yearend 2021 were 7.7
percent for the Norway assets (7.6 percent at yearend 2020) and 7 percent for the UK assets (7.8 percent at yearend 2020).
54
DNO
Note 10
Property, plant and equipment/Intangible assets
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
2020). DNO has applied the forward curve as basis for assessment of currency rates. The USD/NOK applied for impairment testing at
yearend 2021, was USD/NOK 8.5 (unchanged from yearend 2020) and kept it constant thereafter.
Impairment charge and reversal
The following table shows the recoverable amounts and impairment charges or reversal for the CGUs which were impaired in 2021 and
2020, and how it was recognized in the income statement and balance sheet.
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
221.0
-80.1
2.9
-77.2
-68.5
-
-11.6
2.9
-
Full-Year ended 31 December 2020
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
SE Tor, North Sea
-
-66.4
28.5
-37.9
-28.6
-37.9
-
28.7
1.6
Agar, North Sea
-
-14.7
7.0
-7.7
-4.2
-10.5
-
6.9
3.5
Iris and Hades, North Sea
11.7
-82.7
33.2
-49.5
-40.2
-42.5
-
33.1
3.5
Fenja, North Sea
66.1
-18.6
-
-18.6
-18.6
-
-
-
1.4
Ringhorne East, North Sea
13.3
-27.1
-
-27.1
-27.1
-
-
-
1.3
Ula area, North Sea
247.8
-19.3
-
-19.3
-19.3
-
-
-
2.2
Brage, North Sea
25.6
-6.7
-
-6.7
-6.7
-
-
-
0.1
Marulk, North Sea
15.1
-4.3
1.1
-3.2
-2.8
-
-1.4
1.1
0.6
Vilje, North Sea
32.9
-8.4
-
-8.4
-8.4
-
-
-
1.6
Trym area, North Sea
13.6
-5.2
-
-5.2
-5.2
-
-
-
0.1
Oselvar, North Sea
-
-19.8
15.5
-4.3
-
-
-19.8
15.5
0.3
Schooner and Ketch, North Sea
-
2.1
-1.0
1.1
-
-
2.1
-1.0
-
Other CGUs, North Sea
-
-4.9
2.2
-2.7
-
-
-4.9
2.2
0.4
Total
426.1
-276.0
86.5
-189.5
-161.1
-90.9
-24.0
86.5
16.6
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).
During 2020, a total impairment charge of USD 276 million (USD 189.5 million post-tax) was recognized, mainly driven by:
•
Relinquishment of DNO’s participation in a license (Agar discovery);
•
Reduction in resource estimates following appraisal and evaluation of potential (SE Tor discovery and Iris and Hades discoveries);
•
Revised reserves estimates (Fenja development and Ringhorne East);
•
Revised oil and gas price assumptions (Ula area CGU, Marulk, Vilje and Trym area CGU);
•
Revised oil and gas price assumptions and update in cost profiles (Brage);
•
Upward revision in the cost estimate for decommissioning (Oselvar field); and
•
Partially offset by a downward revision in the cost estimate for decommissioning (Schooner and Ketch fields).
Annual Report and Accounts 2021
DNO
55
Note 10
Property, plant and equipment/Intangible assets
Sensitivities
The table below illustrates how the net profit/-loss in 2021 would have been affected by changes in the various assumptions, holding the
remaining assumptions unchanged. The estimated recoverable amounts related to the Kurdistan licenses are substantially higher than
the carrying amounts and the same sensitivity tests would not imply any impairment charges.
Net profit/-loss effects:
Assumption (USD million)
Change
Increase in assumption:
Decrease in assumption:
Oil and gas price
42
-52
Reserves (2P) and resources (2C)
21
-12
Discount rate (WACC)
-7
17
Currency rate (USD/NOK)
28
-28
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 CO2 tax) to NOK 2,000 per tonne (in 2020 real terms) is expected by 2030. In Kurdistan, the KRG introduced in 2021 a
requirement for oil companies to put plans in place to curb gas flaring to reduce emissions. The Company has run sensitivities for its
Kurdistan oil assets with the CO2 tax assumptions as described in the scenarios outlined by the International Energy Agency (IEA) in
their World Energy Outlook (WEO) reports, namely the Stated Policies Scenario and the Sustainable Development Scenario.
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, as shown above, would result in impairments on
certain production and development assets in the North Sea portfolio 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 North Sea impairments recognized 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 Stated Policies Scenario and the Sustainable Development 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 2020 real terms), and for the sensitivity calculation a linear development
between average actual 2021 and 2030, as well as between 2030 and 2050 have been applied. A calculation of a possible effect of
using the oil and gas prices in the Sustainable Development Scenario (oil price: USD 56 per barrel in 2030 and USD 50 per barrel in
2050, gas price: USD 4.2 per MMBtu and USD 4.5 per MMBtu, in real terms 2020) indicates a potential impairment of around USD 28
million post-tax. No impairments are expected related to the Company’s Kurdistan assets at these price levels. As the oil and gas price
assumptions in the Stated Policies Scenario are at higher levels (oil price: USD 77 per barrel in 2030 and USD 88 per barrel in 2050,
gas price: USD 7.7 per MMBtu and USD 8.3 per MMBtu, in real terms 2020) compared to the Group’s long-term price assumption of
USD 65 per barrel, no impairments or significant reversals are expected, but the estimated headroom in the impairment testing would
increase.
A significant reduction in the oil and gas price assumptions could also have effect on the estimated economic cut-off of the projects.
Based on the Group’s scenario analysis, no significant impact was identified with regards to estimated economic cut-off dates.
These illustrative impairment sensitivities assume no changes to assumptions other than oil and gas prices. However, significant
reduction in the oil and gas prices, offset by foreign currency effects, would likely impact the Group’s investment levels as occurred
following significant changes in oil and gas prices during the Covid-19 pandemic in 2020. 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.
56
DNO
Note 10
Property, plant and equipment/Intangible assets
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 2021
impairment assessments; the Ula area CGU have license expiry dates that ranges between 2027 and 2036 (economic cut-off dates
range between 2031 and 2032); the Ringhorne East license expires in 2030 (2045); the Brage license expires in 2030 (2030); the Trym
license expires in 2027 (2025); the Alve license expires in 2029 (2030); the Marulk license expires in 2025 (2026); the Vilje license
expires in 2032 (2040); the Fenja license expires in 2039 (2039); the Brasse license expires in 2022 (2044, subject to extension when
PDO is submitted and approved); and the Iris and Hades license expires in 2023 (2031, subject to extension when PDO is submitted
and approved).
Note 11
Financial investments
Financial investments are comprised of equity instruments and are recorded at fair value (market price, where available) at the end of
the reporting period. Fair value changes are included in other comprehensive income (FVTOCI), see Note 1 for details.
Years ended 31 December
USD million
2021
2020
Book value as of 1 January
12.6
21.0
Fair value changes through other comprehensive income (FVTOCI)
3.6
-8.4
Book value as of 31 December
16.2
12.6
Financial investments include the following:
USD million
2021
2020
Listed shares:
RAK Petroleum plc
16.2
12.6
Total financial investments
16.2
12.6
At yearend 2021, the Company held a total of 15,849,737 shares (5.1 percent of total issued Class A shares) in RAK Petroleum. RAK
Petroleum is listed on the Oslo Stock Exchange. Through its subsidiary, RAK Petroleum Holdings B.V., RAK Petroleum is the largest
shareholder in DNO ASA with 44.94 percent of the total issued shares, see Note 14. The Company’s Executive Chairman Bijan
Mossavar-Rahmani, the largest shareholder in RAK Petroleum, also serves as Executive Chairman of RAK Petroleum. Change in fair
value is recognized in other comprehensive income with USD 3.6 million in 2021 (USD -8.4 million in 2020).
Annual Report and Accounts 2021
DNO
57
Note 12
Other non-current receivables/Trade and other receivables
Years ended 31 December
USD million
2021
2020
Trade debtors (non-current portion)
18.2
182.0
Other long-term receivables
1.3
0.4
Total other non-current receivables
19.4
182.4
Trade debtors
344.4
96.2
Underlift
17.2
27.4
Other short-term receivables
122.2
116.0
Total trade and other receivables
483.8
239.6
Total book value of trade debtors of USD 362.6 million (current and non-current portion) at yearend 2021 relate mainly to the Tawke
license arrears for 2019 and 2020 entitlement and override invoices (USD 169.1 million), and outstanding invoices for Tawke license
crude oil deliveries for the months October through December 2021 (USD 180.3 million). See also Note 22 regarding subsequent events
after yearend 2021.
At yearend 2020, due to the IFRS 9 requirement to incorporate the time value of money, the Company reduced the book value of the
Tawke license arrears by USD 16 million when comparing the book value of the arrears to the estimated present value.
As of 31 December 2021, in line with IFRS 9, the Company made a re-run of the estimated present value, updated the Brent price
assumptions resulting in a net increase in the book value of the arrears by USD 16 million, entirely reversing the financial expense
recognized in 2020. Moreover, the classification of the receivables (current/non-current portion) was updated accordingly. The
calculation of present value in accordance with IFRS 9, takes into account the most recent production forecasts for the Tawke license
and the Company’s Brent price assumptions to determine the expected timing of payments towards the arrears plus contractual
interests under IFRS 9, and reflects the probability-weighted amount for a range of possible scenarios including probability-weighted
Brent price scenarios with a probability assigned to each. The discount rate applied reflects the Company’s cost of debt, see Note 9.
The underlift receivable of USD 17.2 million as of 31 December 2021 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
2021
2020
Cash and cash equivalents, restricted
15.8
13.6
Cash and cash equivalents, non-restricted
720.8
463.5
Total cash and cash equivalents
736.6
477.1
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, EUR and DKK as of 31 December 2021.
58
DNO
Note 14
Equity
Share capital
Number of
Ordinary
Treasury
USD million
shares (1,000)
shares
shares
Total
As of 1 January 2020
990,114
36.0
-2.6
33.4
Treasury shares sold/-purchased
-14,681.3
-
-0.4
-0.4
Cancellation of treasury shares
-3.1
3.1
-
As of 31 December 2020
975,433
32.9
-
32.9
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
-
-
-
-
Cancellation of treasury shares
-
-
-
-
As of 31 December 2021
975,433
32.9
-
32.9
At the 2021 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. The maximum amount to be paid per share is NOK 100 and the minimum amount is NOK 1. Purchases of treasury shares
are made on the Oslo Stock Exchange. The authorization is valid until the 2022 AGM, but not beyond 30 June 2022. As of 31 December
2021, the Company held no treasury shares.
The Board of Directors was also given the authority to increase the Company’s share capital by up to NOK 36,578,727, which
corresponds to 146,314,908 new shares. The authorization is valid until the 2022 AGM, but not beyond 30 June 2022.
In addition, the Board of Directors was given the authority to raise convertible bonds with an aggregate principal amount of up to USD
300,000,000. Upon conversion of bonds issued pursuant to this authorization, the Company’s share capital may be increased by up to
NOK 36,578,727. The authorization is valid until the 2022 AGM, but not beyond 30 June 2022.
The Board of Directors was given the authority to approve a dividend distribution of up to NOK 0.20 per share (but no exceed NOK
224.35 million) from the date of the AGM until 31 December 2021 and a distribution of dividend of up to NOK 0.20 per share (but no
exceed NOK 224.35 million) from 1 January 2022 until the date of the 2022 AGM. In December 2021, the Company’s Board of Directors
approved a dividend payment of NOK 0.20 which was made on 30 December 2021 to all shareholders of record as of 22 December
2021.
Annual Report and Accounts 2021
DNO
59
Note 14
Equity
Interest
The Company's shareholders as of 31 December 2021
Shares
(percent)
RAK Petroleum Holdings B.V.
438,379,418
44.94
Folketrygdfondet
39,668,897
4.07
State Street Bank and Trust Comp (Nominee)
18,088,459
1.85
JPMorgan Chase Bank, N.A., London (Nominee)
10,502,178
1.08
JP.P. Morgan Sercurities Plc
9,757,656
1.00
The Bank of New York Mellom SA/NV (Nominee)
7,643,385
0.78
Nordnet Bank AB (Nominee)
6,923,475
0.71
State Street Bank and Trust Comp (Nominee)
6,917,097
0.71
Salt Value AS
6,480,188
0.66
The Bank of New York Mellon SA/NV (Nominee)
6,207,101
0.64
State Street Bank and Trust Comp (Nominee)
6,006,625
0.62
Avanza Bank AB (Nominee)
5,902,386
0.61
Euroclear Bank S.A./N.V. (Nominee)
4,515,502
0.46
BNP Paribas Securities Services (Nominee)
4,200,000
0.43
Verdipapirfondet Storebrand Norge
4,174,554
0.43
Goldman Sachs & Co. LLC (Nominee)
4,036,915
0.41
JPMorgan Chase Bank, N.A., London (Nominee)
3,609,970
0.37
Nordea Bank Abp (Nominee)
3,522,990
0.36
The Bank of New York Mellon SA/NV (Nominee)
3,387,412
0.35
UBS AG London Branch
3,384,355
0.35
Other shareholders
382,124,183
39.17
Total number of shares excluding treasury shares
975,432,746
100.00
Treasury shares as of 31 December 2021 (DNO ASA)
0.00
0.00
Total number of outstanding shares
975,432,746
100.00
A dividend of USD 21.8 million was distributed in 2021 (nil in 2020). See Note 22 for dividend approved on 9 March 2022.
60
DNO
Note 15
Interest-bearing liabilities
Effective
interest
Fair value
Carrying amount
Ticker
Facility
Facility
Interest
rate
USD million
OSE
currency
amount
(percent)
Maturity
(percent)
2021
2020
2021
2020
Non-current
Bond loan (ISIN NO0010823347)
DNO02
USD
-
-
-
-
-
376.5
-
400.0
Bond loan (ISIN NO0010852643)
DNO03
USD
394.9
8.375
29.05.24
9.0
410.2
370.0
394.9
400.0
Bond loan (ISIN NO0011088593)
DNO04
USD
400.0
7.875
09.09.26
8.8
414.0
-
400.0
-
Capitalized borrowing issue costs
-16.5
-15.4
Reserve based lending facility
-
USD
350.0
see below
see below
-
95.0
149.6
95.0
149.6
Total non-current interest-bearing liabilities
919.2
896.1
873.4
934.2
On 1 September 2021, DNO ASA completed the placement of USD 400 million of a new, five-year senior unsecured bond (DNO04)
issued at 100 percent at par with a coupon rate of 7.875 percent. In connection with the bond placement, the Company agreed to buy
back USD 154 million in nominal value of DNO02 at 103.7 percent of par plus accrued interest. The remaining DNO02 bonds were
called and settled after completion of the new bond at 103.5 percent of par plus accrued interest.
During 2021, DNO ASA has acquired USD 5.1 million of DNO03 bonds at a price range of 103.9 to 104 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 minimum USD 40 million of liquidity, and that the Group maintains
either an equity ratio of 30 percent or a total equity of a minimum of USD 600 million. There is also a restriction on declaring or making
any dividend payments if the liquidity of the Company is less than USD 80 million immediately following such distribution.
The Group has available a revolving exploration financing facility (EFF) in an aggregate amount of NOK 250 million with an
uncommitted accordion option of NOK 750 million. The interest rate equals NIBOR plus a margin of 1.70 percent. Utilizations can be
made until 31 December 2022. Due to temporary changes to the taxation of oil and gas companies in Norway, the Group has chosen to
not utilize the EFF in relation to exploration spend in 2021.
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 3.75 until end of 2021 and 3.50
thereafter. The security under the RBL includes, without limitation, a pledge over the shares in DNO North Sea plc and its subsidiaries,
assignment of claims under shareholder loans, intra-group loans and insurances, a pledge of certain bank accounts and mortgages over
the license interests. There are also restrictions on loans and dividend payments to DNO ASA. The borrowing base amount of the
facility from 1 January 2022 is USD 106 million. Amount utilized as of the reporting date is disclosed in the table above. In addition, USD
88 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
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
Exploration financing facility
-
-
-
-
-
-
Total
934.2
-69.5
9.4
-0.7
-
873.4
At 1 Jan
Cash
Non-cash changes
At 31 Dec
USD million
2020
flows
Amortization
Currency
Acquisition
2020
Bond loans
821.2
-21.2
-
-
-
800.0
Bond loans (current)
140.0
-139.8
-0.2
-
-
-
Borrowing issue costs
-23.0
-
7.6
-
-
-15.4
Reserve based lending facility
37.8
109.2
-
2.6
-
149.6
Exploration financing facility
85.6
-86.1
-
0.5
-
-
Total
1,061.6
-137.9
7.4
3.1
-
934.2
Annual Report and Accounts 2021
DNO
61
Note 16
Provisions for other liabilities and charges/Lease liabilities
Years ended 31 December
USD million
2021
2020
Non-current
Asset retirement obligations (ARO)
386.3
436.6
Other long-term obligations
3.6
3.4
Total non-current provisions for other liabilities and charges
389.9
440.1
Lease liabilities
12.5
13.9
Total non-current lease liabilities
12.5
13.9
Current
Asset retirement obligations (ARO)
69.7
86.7
Other provisions and charges
34.8
25.3
Total current provisions for other liabilities and charges
104.4
112.0
Current lease liabilities
15.7
3.8
Total current lease liabilities
15.7
3.8
Total provisions for other liabilities and charges and lease liabilities
522.6
569.7
Asset retirement obligations
The provisions for ARO are based on the present value of estimated future cost of decommissioning oil and gas assets in Kurdistan and
the North Sea. The discount rates before tax applied at yearend 2021 were between 3.2 percent and 3.7 percent (yearend 2020:
between 3.2 percent and 3.7 percent). The credit margin included in the discount rates at yearend 2021 was 2.3 percent (yearend 2020:
2.8 percent).
62
DNO
Note 16
Provisions for other liabilities and charges/Lease liabilities
Asset
Other
retirement
non-
USD million
obligations
current
Provisions as of 1 January 2020
492.8
7.1
Decommissioning spend
-30.7
-
Increase/-decrease in existing provisions
38.3
-3.6
Amounts charged against provisions
-
-0.1
Effects of change in the discount rate
2.9
-
Accretion expenses (unwinding of discount)
17.0
-
Reclassification and transfer
3.0
-
Provisions as of 31 December 2020
523.3
3.4
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
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 56.6 million (2020: USD 31.2 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
2021
2020
Within one year
16.6
4.7
Two to five years
13.1
13.8
After five years
-
1.1
Total undiscounted lease liabilities end of the period
29.7
19.6
Annual Report and Accounts 2021
DNO
63
Note 17
Commitments and contingencies
Contingent liabilities and contingent assets
Disputes with Ministry of Oil and Minerals of Yemen (MOM) – Block 43 and Block 32
DNO Yemen AS (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 2021.
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 2021 related to this dispute.
DNO Yemen AS 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) was recognized in 2021 related to this arbitration award.
Disputes with Ministry of Energy and Minerals (MEM) of Oman – Block 8
On 3 January 2019, the Company announced that its subsidiary DNO Oman Block 8 Limited (DNO Oman Block 8) had relinquished
operatorship and participation in Block 8 to Oman's Ministry of Energy and Minerals (MEM) as a result of the expiry of the Exploration
and Production Sharing Agreement (EPSA). DNO Oman Block 8 held a 50 percent interest in the license alongside LX International
Corp. (LXI), which held the remaining 50 percent interest. The relinquishment gave rise to certain contested issues between MEM and
the Contractor (DNO Oman Block 8 and LXI) which resulted in arbitration proceedings. A final settlement agreement was signed
between the parties in Q4 2021 in MEM’s favor in the amount of USD 17.7 million. The provision for liability related to this settlement
agreement at yearend 2021 was USD 8.9 million (net to DNO Oman Block 8).
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 2021 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 2021 amounted to USD 800 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 as of 31 December 2021
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.
64
DNO
Note 18
Trade and other payables
Years ended 31 December
USD million
2021
2020
Trade payables
85.7
58.3
Public duties payable
6.1
4.1
Prepayments from customers
-
9.2
Overlift
17.3
6.4
Other accrued expenses
123.4
102.4
Total trade and other payables
232.6
180.3
Trade payables are non-interest bearing and are normally settled within 30 days.
Trade payables and other accrued expenses at yearend 2021 include items of working capital related to participation in licenses in
Kurdistan and the North Sea and prepayment from customers in the North Sea.
The overlift payable of USD 17.3 million at yearend 2021 relates to North Sea overlifted volumes, valued at production cost including
depreciation.
Note 19
Earnings per share
1 January - 31 December
2021
2020
Net profit/-loss attributable to ordinary equity holders of the parent (USD million)
203.9
-285.9
Weighted average number of ordinary shares excluding treasury shares (millions)
975.43
975.73
Earnings per share, basic (USD per share)
0.21
-0.29
Earnings per share, diluted (USD per share)
0.21
-0.29
Basic earnings per share are calculated by dividing the net profit/-loss attributable to equity holders by the weighted average number of
ordinary shares in issue during the period, excluding ordinary shares purchased and held as treasury shares.
The Company did not have any potential dilutive shares at yearend 2021.
Annual Report and Accounts 2021
DNO
65
Note 20
Group companies
Ownership and voting
USD million
Office
interest (percent)
Shares in the Company's subsidiaries
DNO Iraq AS
Norway
100
DNO UK Limited
UK
100
DNO Mena AS
Norway
100
DNO Technical Services AS
Norway
100
DNO Exploration UK Limited
UK
100
DNO Yemen AS
Norway
100
DNO North Sea plc
UK
100
Shares in subsidiaries owned through subsidiaries
DNO Mena AS
DNO Oman Limited
Bermuda
100
DNO Oman Block 8 Limited
Guernsey
100
DNO Oman Block 30 Limited
Guernsey
100
DNO Technical Services Limited
Guernsey
100
DNO Tunisia Limited
Guernsey
100
DNO North Sea plc
DNO North Sea (Norge) AS
Norway
100
DNO Norge AS
Norway
100
DNO North Sea (UK) Limited
UK
100
DNO North Sea (ROGB) Limited
UK
100
DNO North Sea (Energy) Limited
UK
100
DNO North Sea SIP EBT Limited
UK
100
The Company’s subsidiary DNO Iraq AS has operations in Kurdistan. Activities on the NCS are carried out through DNO Norge AS,
while activities on the UKCS are carried out through DNO North Sea (UK) Limited and DNO North Sea (ROGB) Limited. DNO 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 Oman AS and Føroya Kolvetni P/F were
liquidated during 2021.
Note 21
Related party disclosure
The following table provides details of the Group’s related party transactions in 2021. See also Note 5 on remuneration.
1 January - 31 December
Related party (USD million)
Transaction
2021
2020
RAK Petroleum plc
Service agreement
-0.1
-0.5
Total related party transactions
-0.1
-0.5
RAK Petroleum, through its subsidiary RAK Petroleum Holdings B.V., is the Company’s largest shareholder and the Company’s
Executive Chairman Bijan Mossavar-Rahmani also serves as Executive Chairman of RAK Petroleum. The Company has an agreement
with RAK Petroleum for services including administrative and commercial support and other expenses.
There are additional transactions between Group companies, see Note 19 in the parent company accounts.
A portion of the overhead expenses in the Company are charged to the subsidiaries through the hourly rate for services provided by the
Company.
66
DNO
Note 22
Significant events after the reporting date
DNO receives 10 awards in Norway's APA licensing round
On 18 January 2022, the Company announced that its wholly-owned subsidiary DNO Norge AS has been awarded participation in 10
exploration licenses, of which three are operatorships, under Norway's Awards in Predefined Areas (APA) 2021 licensing round. Of the
10 new licenses, six are in the North Sea and four in the Norwegian Sea.
Payments from Kurdistan
Following yearend 2021, DNO has received USD 153.3 million for the months October and November 2021 towards the respective
month’s entitlement share of oil deliveries to the export market from the Tawke license, override payments equivalent to three percent of
gross revenues under the August 2017 Receivables Settlement Agreement and arrears relating to withheld payment of 2019 and 2020
entitlement and override invoices.
Federal Supreme Court of Iraq (FSCI) ruling
The Company notes from public reports that on 15 February 2022, the FSCI ruled amongst other things that the Kurdistan Oil and Gas
Law 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, and it is unclear how
the KRG and the FGI will follow up on the ruling. At present, normal operations are maintained at the Tawke and Baeshiqa licenses. The
Company continues to monitor the situation. Any future impacts of this ruling and subsequent actions by the FGI and the KRG cannot
currently be estimated but may impact the operations and financial performance of the Group.
The Company’s Board of Directors approve dividend payment
On 9 March 2022, the Company announced that pursuant to the authorization granted at the 2021 AGM, the Board of Directors has
decided to distribute a dividend payment of NOK 0.20 per share to be made on or about 21 March 2022 to all shareholders of record as
of 15 March 2022.
Potential implications of the Russia-Ukraine conflict
The Company notes the implications for commodity prices and potential interruptions of supply chains and third-party services from the
ongoing Russia-Ukraine armed conflict. DNO is monitoring international sanctions and trade control legislation in order to mitigate the
potential impact on the Company’s operations.
Annual Report and Accounts 2021
DNO
67
Note 23
Oil and gas reserves (unaudited)
Net reserves by region/field as of 31 December 2021
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
113.9
-
-
113.9
176.4
-
-
176.4
215.8
-
-
215.8
Peshkabir
48.2
-
-
48.2
91.0
-
-
91.0
132.7
-
-
132.7
Total Kurdistan
162.2
-
-
162.2
267.4
-
-
267.4
348.5
-
-
348.5
Blane
0.5
0.1
-
0.6
1.3
0.2
-
1.4
1.4
0.2
-
1.6
Enoch
0.1
-
-
0.1
0.2
-
-
0.2
0.3
-
-
0.3
Total UK
0.6
0.1
-
0.7
1.5
0.2
-
1.6
1.8
0.2
-
1.9
Alve
0.6
1.0
3.6
5.2
1.0
1.5
5.5
8.0
1.4
2.2
8.0
11.7
Brage
1.1
0.1
0.2
1.4
1.9
0.2
0.3
2.4
2.4
0.3
0.4
3.0
Brasse
8.8
1.4
3.2
13.4
11.4
1.7
4.0
17.1
14.4
2.1
4.8
21.2
Fenja
2.6
0.3
0.8
3.7
3.2
0.3
1.0
4.6
3.7
0.4
1.2
5.2
Marulk
0.1
0.1
0.7
0.9
0.1
0.2
1.3
1.6
0.1
0.4
2.0
2.5
Oda
1.0
-
0.0
1.0
2.0
0.0
0.0
2.0
2.6
0.0
0.3
2.9
Ringhorne East
0.5
-
-
0.5
0.6
-
-
0.6
0.7
-
-
0.7
Tambar
1.2
0.1
0.3
1.5
2.9
0.2
0.7
3.8
4.1
0.2
1.1
5.4
Tambar East
-
-
-
-
0.2
0.0
0.0
0.2
0.2
0.0
0.0
0.3
Trym
0.3
-
1.7
1.9
0.4
-
2.8
3.2
0.6
-
4.2
4.8
Ula
1.3
0.0
-
1.4
5.1
0.1
-
5.2
6.2
0.2
-
6.3
Vilje
2.2
-
-
2.2
3.7
-
-
3.7
6.1
-
-
6.1
Total Norway
19.7
3.0
10.5
33.2
32.3
4.3
15.6
52.3
42.4
5.8
22.0
70.2
Total Group
196.1
321.4
420.6
Reserves development by segment (net to DNO)
Kurdistan
North Sea
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 1 January 2020
170.7
300.0
480.5
48.6
70.1
102.0
219.3
370.2
582.5
Production
-30.3
-30.3
-30.3
-6.4
-6.4
-6.4
-36.6
-36.6
-36.6
Acquisitions
-
-
-
-
-
-
-
-
-
Divestments
-
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
-
New developments
-
-
-
-
-
-
-
-
-
Revision of previous estimates
35.4
25.7
3.4
-1.2
0.7
0.2
34.2
26.3
3.7
As of 31 December 2020
175.8
295.4
453.7
41.1
64.4
96.0
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
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
As of 31 December 2021
162.2
267.4
348.5
33.9
54.0
72.1
196.1
321.4
420.6
Net Entitlement (NE) reserves by segment
Kurdistan
North Sea
Total Group
MMboe
1P
2P
3P
1P
2P
3P
1P
2P
3P
As of 31 December 2020
69.4
96.7
120.1
41.1
64.4
96.0
110.5
161.2
216.0
As of 31 December 2021
56.5
77.7
88.8
33.9
54.0
72.1
90.4
131.7
160.9
68
DNO
Note 23
Oil and gas reserves (unaudited)
The reserves and contingent resources are according to the Annual Statement of Reserves and Resources (ASRR) dated 21 February
2022. 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 (D&M) carried out an independent assessment of the Tawke license
(containing the Tawke and Peshkabir fields) and the Baeshiqa license (containing the Baeshiqa and Zartik structures) in the Kurdistan
region of Iraq. International petroleum consultants Gaffney, Cline & Associates (GCA) carried out an independent assessment of DNO's
licenses in Norway and the United Kingdom (UK). The Company internally assessed Yemen Block 47.
The estimation of oil and gas reserves involves uncertainty. The figures above represent management’s best judgment of the most likely
quantity of economically recoverable oil and gas estimated at yearend 2021, 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 2021, DNO’s net 1P reserves stood at 196.1 MMboe, compared to 216.9 MMboe at yearend 2020, after adjusting for
production during the year and upward technical revisions. On a 2P reserves basis, DNO’s net reserves stood at 321.4 MMboe,
compared to 359.9 MMboe at yearend 2020. On a 3P reserves basis, DNO’s net reserves were 420.6 MMboe, compared to 549.6
MMboe at yearend 2020. DNO’s net 2C resources were 189.5 MMboe, compared to 151.3 MMboe at yearend 2020.
DNO’s net production in 2021 totaled 34.5 MMboe (of which 29.8 million barrels of oil (MMbbls) in Kurdistan, 4.5 MMboe in Norway and
the balance in the UK), compared to 36.6 MMboe in 2020 (of which 30.3 MMbbls in Kurdistan, 6.0 MMboe in Norway and the balance in
the UK).
The Company’s net yearend 2021 Reserve Life Index (R/P) stood at 5.7 years on a 1P reserves basis, 9.3 years on a 2P reserves basis
and 12.2 years on a 3P reserves basis.
Effective from 2021, the Company reports its net production, reserves and resources based on the participating interest in all of its licenses.
Prior to 2021 and for the licenses governed by PSCs, the Company reported its net figures after royalty and included DNO’s additional
share of cost oil covering its advances towards the government carried interest (if any) as well as volumes attributed to the three percent
of gross Tawke license production under the August 2017 Receivables Settlement Agreement. The main reason for the change is to
improve comparability with peer companies and to show the Company’s share of production before the government take. All 2020 figures
in this note are updated accordingly.
The Net Entitlement (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) as well as volumes attributed to the three percent of gross Tawke license production
under the August 2017 Receivables Settlement Agreement. Net reserves reflect pre-tax shares while NE reserves reflect post-tax shares.
NE reserves are based on economic evaluation of the license agreements, incorporating projections of future production, costs and oil
and gas prices. NE reserves may therefore fluctuate over time, even if there are no changes in the underlying gross and net volumes.
Net and NE reserves in DNO’s licenses not governed by PSCs (Norway and the UK) are equivalent and reflect pre-tax shares.
Note 24
Oil and gas license portfolio
Annual Report and Accounts 2021
DNO
69
At yearend 2021, 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.
At yearend 2021, DNO also held 73 offshore licenses in Norway, 11 offshore licenses in the UK, two offshore licenses in Netherlands,
one offshore license in Ireland and one onshore license in Yemen.
As is customary in the oil and gas industry, most of the Group's assets are held in partnership with other companies. Below is an
overview of the Group's licenses, which are held through several wholly-owned subsidiary companies.
As of 31 December 2021:
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
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
20.0
Aker BP ASA
DNO Norge AS
PL019 E
20.0
Aker BP ASA
DNO Norge AS
PL019 F
45.0
Aker BP ASA
DNO Norge AS
PL036 D
28.9
Aker BP ASA
DNO Norge AS, PGNiG Upstream Norway AS
PL048 D
9.3
Equinor Energy AS
DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 B
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 D
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL055 E
14.3
Wintershall Dea Norge AS
DNO Norge AS, Lime Petroleum AS, Vår Energi AS, Neptune Energy Norway AS
PL065
45.0
Aker BP ASA
DNO Norge AS
PL065 B
45.0
Aker BP ASA
DNO Norge AS
PL1006
30.0
Equinor Energy AS
DNO Norge AS
PL1007
40.0
DNO Norge AS
OMV (Norge) AS, Spirit Energy Norway AS, Equinor Energy AS
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
17.0
Vår Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 B
17.0
Vår Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 C
17.0
Vår Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL122 D
17.0
Vår Energi AS
DNO Norge AS, Equinor Energy AS, PGNiG Upstream Norway AS
PL147
50.0
DNO Norge AS
Spirit Energy Norway AS
PL159 B
32.0
Equinor Energy AS
DNO Norge AS, PGNiG Upstream Norway AS
PL159 G
32.0
Equinor Energy AS
DNO Norge AS, PGNiG Upstream Norway AS
PL169 E
87.0
DNO Norge AS
Vår Energi AS
PL185
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
Note 24
Oil and gas license portfolio
70
DNO
PL274
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
45.0
Aker BP ASA
DNO Norge AS
PL405
15.0
Spirit Energy Norway AS
DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL586
7.5
Neptune Energy Norge AS
DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL644
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740
50.0
DNO Norge AS
Vår Energi AS
PL827 S
49.0
Equinor Energy AS
DNO Norge AS
PL836 S
30.0
Wintershall Dea Norge AS
DNO Norge AS, Spirit Energy Norway AS
PL836 SB
30.0
Wintershall Dea Norge AS
DNO Norge AS, Spirit Energy Norway AS
PL906
30.0
Aker BP ASA
DNO Norge AS, Longboat Energy Norge AS
PL923
20.0
Equinor Energy AS
DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL924
15.0
Wellesley Petroleum AS
DNO Norge AS, Equinor Energy AS, Lundin Energy Norway AS
PL929
10.0
Neptune Energy Norge AS
DNO Norge AS, Pandion Energy AS, Wintershall Dea Norge AS, Lundin Norway
AS
PL943
30.0
Equinor Energy AS
DNO Norge AS, Sval Energi AS
PL967
60.0
DNO Norge AS
Equinor Energy AS
PL968
40.0
DNO Norge AS
Petoro AS, MOL Norge AS, Aker BP ASA
PL969
45.0
A/S Norske Shell
DNO Norge AS, Spirit Energy Norway AS
PL983
20.0
Equinor Energy AS
DNO Norge AS, TotalEnergies EP Norge AS, Petoro AS
PL984
40.0
DNO Norge AS
Vår Energi AS, Source Energy AS
PL984 BS
40.0
DNO Norge AS
Vår Energi AS, Source Energy AS
PL986
20.0
Aker BP ASA
DNO Norge AS, Petoro AS
PL994
30.0
Neptune Energy Norge AS
DNO Norge AS, Petrolia NOCO AS
UK
P111
54.3
Repsol Sinopec Resources UK Ltd
DNO North Sea (U.K.) Ltd, DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK)
Ltd.
P219
18.2
Repsol Sinopec North Sea Ltd
DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK
Ltd
P2401
45.0
Shell U.K. 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
Note 24
Oil and gas license portfolio
Annual Report and Accounts 2021
DNO
71
As of 31 December 2020:
Participating
Region/license
interest (percent)
Operator
Partner(s)
Kurdistan
Tawke PSC
75.0
DNO Iraq AS
Genel Energy International Limited
Baeshiqa PSC
32.0
DNO Iraq AS
ExxonMobil Kurdistan Region of Iraq Limited, Turkish Energy Company Limited,
Kurdistan Regional Government
Norway
PL006 C
85.0
DNO Norge AS
Aker BP ASA
PL006 E
85.0
DNO Norge AS
Aker BP ASA
PL006 F
85.0
DNO Norge AS
Aker BP ASA
PL018 ES
100.0
DNO Norge AS
PL019
20.0
Aker BP ASA
DNO Norge AS
PL019 E
20.0
Aker BP ASA
DNO Norge AS
PL019 F
45.0
Aker BP ASA
DNO Norge AS
PL036 D
28.9
Aker BP ASA
DNO Norge AS, PGNiG Upstream Norway AS
PL048 D
9.3
Equinor Energy AS
DNO Norge AS, Petrolia NOCO AS, Aker BP ASA
PL053 B
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055 B
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055 D
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL055 E
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL065
45.0
Aker BP ASA
DNO Norge AS
PL065 B
45.0
Aker BP ASA
DNO Norge AS
PL1006
30.0
Equinor Energy AS
DNO Norge AS
PL1007
40.0
DNO Norge AS
OMV (Norge) AS, Spirit Energy Norway AS, Equinor Energy AS
PL1021
50.0
Wintershall Dea Norge AS
DNO Norge AS
PL1022
30.0
Aker BP ASA
DNO Norge AS, Concedo ASA
PL1027
20.0
Lundin Norway AS
DNO Norge AS, Wintershall Dea Norge AS, INPEX Norge AS
PL1029
40.0
Lundin Norway AS
DNO Norge AS, Spirit Energy Norway AS
PL1036
60.0
DNO Norge AS
Source Energy AS
PL1048
50.0
Lundin Energy Norway AS
DNO Norge AS
PL1056
20.0
A/S Norske Shell
DNO Norge AS, Petoro AS, Wintershall Dea Norge AS, Aker BP ASA
PL1070
30.0
Total E&P Norge AS
DNO Norge AS, Vår Energi As
PL1076
50.0
Equinor Energy AS
DNO Norge AS
PL1077
40.0
Equinor Energy AS
DNO Norge AS
PL1083
30.0
Lundin Energy Norway AS
DNO Norge AS, Petoro AS
PL122
17.0
Vår Energi AS
DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 B
17.0
Vår Energi AS
DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 C
17.0
Vår Energi AS
DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL122 D
17.0
Vår Energi AS
DNO Norge AS, INEOS E&P Norge AS, Equinor Energy AS
PL147
50.0
DNO Norge AS
Spirit Energy Norway AS
PL159 B
32.0
Equinor Energy AS
DNO Norge AS, INEOS E&P Norge AS
PL159 G
32.0
Equinor Energy AS
DNO Norge AS, INEOS E&P Norge AS
PL169 E
87.0
DNO Norge AS
Vår Energi AS
PL185
14.3
Wintershall Dea Norge AS
DNO Norge AS, Repsol Norge AS, Vår Energi AS, Neptune Energy Norge AS
PL248 F
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL248 GS
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL248 HS
20.0
Wintershall Dea Norge AS
DNO Norge AS, Petoro AS
PL274
55.0
DNO Norge AS
CapeOmega AS
PL274 CS
55.0
DNO Norge AS
CapeOmega AS
PL293 B
29.0
Equinor Energy AS
DNO Norge AS, Idemitsu Petroleum Norge AS
PL300
45.0
Aker BP ASA
DNO Norge AS
PL405
15.0
Spirit Energy Norway AS
DNO Norge AS, Aker BP ASA, Suncor Energy Norge AS
PL433
15.0
Spirit Energy Norway AS
DNO Norge AS, ONE-Dyas Norge AS, PGNiG Upstream Norway AS
PL586
7.5
Neptune Energy Norge AS
DNO Norge AS, Vår Energi AS, Suncor Energy Norge AS
PL644
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 B
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL644 C
20.0
OMV (Norge) AS
DNO Norge AS, Equinor Energy AS, Spirit Energy Norway AS
PL740
50.0
DNO Norge AS
Vår Energi AS
PL827 S
49.0
Equinor Energy AS
DNO Norge AS
PL836 S
30.0
Wintershall Dea Norge AS
DNO Norge AS, Spirit Energy Norway AS
PL888
40.0
DNO Norge AS
Wellesley Petroleum AS, ConocoPhillips Skandinavia AS
PL902
10.0
Lundin Norway AS
DNO Norge AS, Petoro AS, Aker BP ASA
PL902 B
10.0
Lundin Norway AS
DNO Norge AS, Petoro AS, Aker BP ASA
PL906
20.0
Aker BP ASA
DNO Norge AS, Equinor Energy AS
Note 24
Oil and gas license portfolio
72
DNO
PL923
20.0
Equinor Energy AS
DNO Norge AS, Wellesley Petroleum AS, Petoro AS
PL924
15.0
Wellesley Petroleum AS
DNO Norge AS, Equinor Energy AS, Lundin Energy Norway AS
PL926
60.0
DNO Norge AS
Concedo ASA, Lundin Norway AS
PL929
10.0
Neptune Energy Norge AS
DNO Norge AS, Pandion Energy AS, Wintershall Dea Norge AS, Lundin Norway
AS
PL943
30.0
Equinor Energy AS
DNO Norge AS, Sval Energi AS
PL967
60.0
DNO Norge AS
Equinor Energy AS
PL968
40.0
DNO Norge AS
Petoro AS, MOL Norge AS, Aker BP ASA
PL969
45.0
A/S Norske Shell
DNO Norge AS, Spirit Energy Norway AS
PL975
60.0
DNO Norge AS
Source Energy AS
PL983
20.0
Equinor Energy AS
DNO Norge AS, Total E&P Norge AS, Petoro AS
PL984
40.0
DNO Norge AS
Vår Energi AS, Source Energy AS
PL984 BS
40.0
DNO Norge AS
Vår Energi AS, Source Energy AS
PL986
20.0
Aker BP ASA
DNO Norge AS, Petoro AS
PL987
20.0
Suncor Energy Norge AS
DNO Norge AS, Lundin Norway AS, Vår Energi AS
PL987 B
20.0
Suncor Energy Norge AS
DNO Norge AS, Lundin Norway AS, Vår Energi AS
PL988
30.0
Lundin Norway AS
DNO Norge AS, Vår Energi AS
PL991
60.0
DNO Norge AS
Lundin Norway AS
PL994
30.0
Neptune Energy Norge AS
DNO Norge AS, Petrolia NOCO AS
UK
P111
54.3
Repsol Sinopec Resources UK Ltd
DNO North Sea (U.K.) Ltd, DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK)
Ltd.
P1763
12.5
Apace Beryl I Ltd
DNO North Sea (U.K.) Ltd , Azinor Catalyst Ltd, Nautical Petroleum Ltd
P2074
25.0
Chrysaor CNS Ltd
DNO Exploration UK Ltd, Chrysaor Ltd, Ineos UK SNS Ltd
P219
18.2
Repsol Sinopec North Sea Ltd
DNO North Sea (ROGB) Ltd, Dana Petroleum (BVUK) Ltd, Waldorf Production UK
Ltd
P2312
15.0
Nautical Petroleum Ltd
DNO North Sea (U.K.) Ltd, Suncor Energy 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
P454
5.9
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
P558
10.0
Britoil Ltd
DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P611
5.9
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
P803
10.0
BP Exploration Operating Company
Ltd
DNO North Sea (U.K.) Ltd, Rockrose UKCS 10 Ltd
P2551
100.0
DNO North Sea (U.K.) Ltd
P2537
30.0
Chrysaor Production (U.K.) Limited
DNO North Sea (U.K.) Ltd
P2548
100.0
DNO North Sea (U.K.) Ltd
P2533
50.0
Zennor Exploration Ltd
DNO North Sea (U.K.) Ltd
Ireland
FEL3/19
20.0
CNOOC Petroleum Europe Ltd
DNO North Sea (U.K.) Ltd
Netherlands
D15
5.0
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
D18a
2.5
Neptune E&P UKCS Ltd
DNO North Sea (U.K.) Ltd, Ineos UK SNS Ltd, Premier Oil E&P UK Ltd
Yemen
Block 47
64.0
DNO Yemen AS
The Yemen Company, Geopetrol Hadramaut Incorporated
Annual Report and Accounts 2021
DNO
73
Parent company accounts
Income statement
74
Balance sheet
74
Cash flow statement
76
Note disclosures
Note 1
Accounting principles
77
Note 2
Operating revenues
78
Note 3
Salaries, pensions, remuneration, shares, options and severance
78
Note 4
Other operating expenses
81
Note 5
Net financial income/-expenses
81
Note 6
Taxes
82
Note 7
Property, plant and equipment/Intangible assets
83
Note 8
Investment in shares/Other investments
83
Note 9
Other receivables
84
Note 10
Cash and cash equivalents
84
Note 11
Equity
84
Note 12
Guarantees, leasing liabilities and commitments
85
Note 13
Interest-bearing liabilities
85
Note 14
Current liabilities
85
Note 15
Financial instruments
85
Note 16
Related party disclosure
86
Note 17
Significant events after the reporting date
86
Note 18
Earnings per share
86
Note 19
Intercompany
86
Parent company accounts
74
DNO
Income statement
1 January - 31 December
USD thousand
Note
2021
2020
Operating revenues
2, 19
24,190
22,888
Total operating revenues
24,190
22,888
Depreciation
-1,110
-1,071
Payroll and other social expenses
-19,404
-15,037
Other operating expenses
-15,231
-9,315
Total operating expenses
-35,745
-25,423
Operating profit/-loss
-11,555
-2,535
Net financial income/-expense
233,695
-316,539
Profit/-loss before income tax
222,140
-319,074
Tax income/-expense
-
-
Net profit/-loss
222,140
-319,074
Earnings per share, basic (USD per share)
18
0.23
-0.33
Earnings per share, diluted (USD per share)
18
0.23
-0.33
Weighted average number of shares outstanding (millions)
975.43
975.73
Balance sheet
ASSETS
Years ended 31 December
USD thousand
Note
2021
2020
Fixed assets
Intangible assets
4,131
4,704
Property, plant and equipment
323
327
Total intangible and tangible assets
4,454
5,031
Financial assets
Shares in subsidiaries
591,083
684,412
Intercompany receivables
86,895
83,015
Other long-term receivables
23
42
Investment in shares
16,174
12,594
Total financial assets
694,175
780,063
Total non-current assets
698,629
785,094
Current assets
Intercompany receivables
7,500
4,743
Other receivables
3,238
2,075
Cash and cash equivalents
515,018
299,665
Total current assets
525,756
306,483
TOTAL ASSETS
1,224,385
1,091,577
Parent company accounts
Annual Report and Accounts 2021
DNO
75
EQUITY AND LIABILITIES
Years ended 31 December
USD thousand
Note
2021
2020
Paid-in capital
Share capital
32,936
32,936
Share premium
247,743
247,743
Total paid-in capital
11
280,679
280,679
Retained earnings
Retained earnings
37,808
-140,415
Total retained earnings
11
37,808
-140,415
Total equity
11
318,487
140,264
Non-current liabilities
Intercompany liabilities
83,256
150,137
Interest-bearing liabilities
780,692
787,359
Other non-current liabilities
295
301
Total non-current liabilities
864,243
937,797
Current liabilities
Trade payables and provisions for other liabilities and charges
19,515
13,516
Intercompany liabilities
20
-
Dividend
22,120
-
Total current liabilities
41,655
13,516
Total liabilities
905,898
951,313
TOTAL EQUITY AND LIABILITIES
1,224,385
1,091,577
Bijan Mossavar-Rahmani
Lars Arne Takla
Shelley Watson
Executive Chairman
Deputy Chairman
Director
Elin Karfjell
Gunnar Hirsti
Bjørn Dale
Director
Director
Managing Director
Parent company accounts
76
DNO
Cash flow statement
1 January - 31 December
USD thousand
Note
2021
2020
Operating activities
Profit/-loss before income tax
222,140
-319,074
Adjustments to add (deduct) non-cash items:
Depreciation and impairment of tangible and intangible assets
1,110
1,071
Impairment/reversal of impairment of financial assets
95,661
245,203
Change in fair value of financial investments
-3,580
8,436
Amortization of borrowing issue costs fees
5,13
8,927
6,433
Interest income
-1,353
-7,539
Interest expense
65,414
74,286
Other
3,171
16,113
Changes in working capital and provisions:
-3,901
11,079
20
-161
5,993
-6,402
Cash generated from operations
393,602
29,445
Taxes paid
-
-
Interest received
1,353
7,539
Interest paid
-65,429
-74,657
Dividend received
-
261
Net cash flow from/-used in operating activities
329,526
-37,412
Investing activities
Payments made for intangible and tangible assets
-533
-876
Loans to subsidiaries
-3,880
26,693
Purchase of bonds
-
-15,001
Net cash flow from/-used in investing activities
-4,413
10,816
Financing activities
Payment debt issue costs
-15,609
-
Repayment of interest-bearing liabilities (bonds)
13
-5,093
-140,000
Loans from subsidiaries
19
-66,881
94,975
Purchase of treasury shares and options
-
-17,741
Paid dividend
-22,177
-
Net cash flow from/-used in financing activities
-109,760
-62,766
Cash and cash equivalents at the beginning of the period
299,665
389,028
Net increase/-decrease in cash and cash equivalents
215,353
-89,363
Cash and cash equivalents at the end of the period
10
515,018
299,665
Of which restricted cash
2,851
2,203
Parent company accounts
Annual Report and Accounts 2021
DNO
77
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
78
DNO
Note 2
Operating revenues
1 January - 31 December
USD thousand
2021
2020
Operating revenues
24,190
22,888
Total operating revenues
24,190
22,888
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
2021
2020
Payroll and other social expenses
Salaries, bonuses and other salary expenses
-14,050
-10,490
Employer's payroll tax expense
-2,384
-2,415
Pensions
-1,969
-2,093
Other personnel costs
-1,001
-39
Total payroll and other social expenses
-19,404
-15,037
Average number of man-labor years
56
66
Pensions
DNO has a defined contribution scheme for its Norway-based employees. DNO meets the Norwegian requirements for mandatory
occupational pensions
(“obligatorisk tjenestepensjon”).
Remuneration to the Board of Directors and executive management
Remuneration to the Board of Directors (USD thousand)
2021
2020
Bijan Mossavar-Rahmani, Executive Chairman, member of the nomination and remuneration committees
832.8
760.6
Lars Arne Takla, Deputy Chairman, member of the HSSE committee
69.7
63.7
Elin Karfjell, Director, member of the audit committee
59.2
54.0
Gunnar Hirsti, Director, member of the audit and remuneration committees
65.6
59.9
Shelley Watson, Director, member of the audit and HSSE committees
65.6
54.0
Total
1,092.8
992.3
Total remuneration to the Board of Directors consist of regular fees (USD 1,044,790) and fees for participation in the board committees
(USD 47,970). Separately, a fee of USD 3,198 was paid to each of Anita Marie Hjerkinn Aarnæs and Kåre Tjønneland for service on
the nomination committee.
Synthetic
Remuneration to Managing Director and executive management (USD thousand)
Salary
Bonus
Other
Total
Pension
Bjørn Dale, Managing Director
688.7
75.5
-
68.6
832.8
21.0
Chris Spencer, Chief Operating Officer
577.2
66.0
29.3
52.6
725.1
21.0
Haakon Sandborg, Chief Financial Officer
460.8
50.3
22.0
38.3
571.4
21.0
Nicholas Whiteley, Chief Commercial Officer
457.1
50.3
22.0
90.1
619.6
21.0
Tom Allan, General Manager Kurdistan region of Iraq
584.4
68.4
150.2
283.3
1,086.3
-
Ørjan Gjerde, General Manager DNO North Sea
439.4
48.9
15.7
36.8
540.8
21.0
Geir Arne Skau, Director of Human Resources and Corporate Services
346.0
38.0
-
24.5
408.5
21.0
Tonje Pareli Gormley, General Counsel - Middle East
374.6
40.9
98.2
29.2
542.8
21.0
* Synthetic share awards that vested during the year.
**Total remuneration of USD 1.3 million was paid to the following former members of the executive management: Ute Quinn and Aernout van der Gaag.
Parent company accounts
Annual Report and Accounts 2021
DNO
79
Note 3
Salaries, pensions, remuneration, shares, options and severance
The following members of the executive management are employed in subsidiaries of DNO ASA: Tom Allan and Ørjan Gjerde.
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 2021
Out-
Movements 1 January - 31 December
Out-
Unrest
Weighted
standing
Forfeited/
standing
ricted
average
Number of shares
at 1 Jan
Granted
Reversed
Settled
Expired
at 31 Dec
at 31 Dec
price*
Bjørn Dale, Managing Director
72,513
1,479
-
-
73,992
Chris Spencer, Chief Operating Officer
589,965
11,723
14,875
-
586,813
108,061
7.80
Haakon Sandborg, Chief Financial Officer
82,265
147,537
24,255
-
205,547
7.80
Nicholas Whiteley, Chief Commercial Officer
178,424
827
137,738
-
41,513
2,052
11.79
Tom Allan, General Manager Kurdistan region of Iraq
447,492
9,126
-
-
456,618
Ørjan Gjerde, General Manager DNO North Sea
17,305
-
17,305
-
-
7.80
Geir Arne Skau, Director of Human Resources and Corporate Services
103,804
1,191
45,398
-
59,597
-
7.74
Tonje Pareli Gormley, General Counsel - Middle East
171,781
1,978
74,785
-
98,974
11.16
The weighted average settlement price for synthetic shares settled during 2021 was NOK 10.34. The weighted average remaining
contractual life of the synthetic shares was three years.
The synthetic share awards are subject to a two-year vesting period and require continued employment in the Company for a period
of two years after the grant date. Some of the shares granted to Haakon Sandborg in 2021 have a three-year vesting period.
Following vesting, the employee is free to settle the shares in cash.
For an overview of synthetic shares at yearend 2021, see Note 5 in the consolidated accounts.
Severance agreements
Members of the executive management, Bjørn Dale, Chris Spencer, Haakon Sandborg and Nicholas Whiteley have severance payment
agreements ranging from six months to 12 months of their respective annual base salaries.
Auditor fees
1 January - 31 December
All figures are exclusive of VAT (USD thousand)
2021
2020
Auditor fees
-306
-266
Other financial audit services
-16
-4
Total auditing fees
-322
-270
Other assistance
-
-
Tax assistance
-
-
Total auditor fees
-322
-270
Determination of salary and other remuneration to the Managing Director and the rest of the 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.
Any remuneration, bonuses and other incentive schemes must reflect the duties and responsibilities of the employees and add long-
term value for shareholders.
Fixed salary
The Board of Directors did not set any upper or lower limit for the fixed salary of executive management for 2021 beyond the main
principles set out above.
Parent company accounts
80
DNO
Note 3
Salaries, pensions, remuneration, shares, options and severance
Variable elements
In addition to fixed salary, variable remuneration can be used to recruit, retain and reward employees. For executive management, such
remuneration can include cash bonuses and share-based compensation. Annual bonuses, when awarded, are based on corporate
results and/or individual performance. Other types of variable remuneration include newspaper, mobile phone and broadband
communication subscriptions paid in accordance with established rates.
Pensions
The Company has a contribution-based pension system under which Norway-based employees are entitled to a pension contribution of
12.5 percent of their annual salary. Any excess of the maximum legally allowable pension contribution is paid out to the employees as
additional salary.
Employee Synthetic Share Program
The Board of Directors continued its employee synthetic share program in 2021. The purpose of the program was to: (i) align the
interests of executive management and other employees with those of shareholders’; (ii) reward value creation; and (iii) provide
retention incentives. The Board of Directors determines whether to set allocation criteria, conditions or thresholds for the scheme.
Severance agreements
Severance payment agreements may be entered into selectively if the Board of Directors finds this to be useful in recruitment.
Remuneration committee
The Board of Directors has established a remuneration committee composed of two members, the current members are Bijan
Mossavar-Rahmani and Gunnar Hirsti. Its mandate is to consider matters relating to compensation of executive management and to
make related recommendations to the Board of Directors.
See Note 5 in the consolidated accounts for further information on administrative expenses.
Parent company accounts
Annual Report and Accounts 2021
DNO
81
Note 4
Other operating expenses
1 January - 31 December
USD thousand
2021
2020
Lease expense on buildings and equipment
-2,557
-2,008
Other office expenses
-14
-54
IT expenses
-8,871
-4,381
Travel expenses
-164
-230
Legal expenses
-582
-
Consultant fees
-2,051
-1,589
Other general and administrative costs
-992
-1,052
Total other operating expenses
-15,231
-9,315
Note 5
Net financial income/-expenses
1 January - 31 December
USD thousand
2021
2020
Dividend and group contribution received from group companies
414,019
13,625
Interest received
1,353
7,539
Interest received from group companies
4,074
1,387
Gain on foreign exchange
4,214
8,427
Change in fair value of financial investments
3,580
-
Total financial income
427,240
30,978
Interest expenses
-65,414
-74,286
Interest expenses group companies
-9,862
-4,029
Loss on foreign exchange
-4,655
-5,993
Impairment of financial assets
-95,661
-245,203
Other financial expenses
-17,952
-9,570
Change in fair value of financial investments
-
-8,436
Total financial expenses
-193,544
-347,516
Net financial income/-expenses
233,695
-316,539
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 8.8 million) and expensing of bond premium and fees related to
repurchase and cancellation of bonds (USD 8.9 million).
In 2020, the impairment of financial assets of USD 245.2 million was mainly related to DNO North Sea plc (USD 249.7 million), DNO
Yemen AS (USD 2.9 million), DNO Mena AS (USD 2.3 million) and DNO Exploration UK Limited (USD 0.5 million), partially offset by
received liquidation settlement related to the liquidation of DNO Somaliland AS, Northstar Exploration Holding AS and DNO Invest AS in
2020 (USD 10.2 million). The change in fair value of financial investments of USD 8.4 million recognized in 2020 was due to the
decrease in fair value related to the Company’s shares in RAK Petroleum. Other financial expenses in 2020 were mainly related to
amortization of bond issue costs (USD 6.4 million) and a loss related to the FAPE01 redemption (USD 3.1 million).
Parent company accounts
82
DNO
Note 6
Taxes
Tax income/-expense
1 January - 31 December
USD thousand
2021
2020
Change in deferred taxes
-
-
Income tax receivable/-payable
-
-
Tax income/-expense
-
-
Reconciliation of tax income/-expense
1 January - 31 December
USD thousand
2021
2020
Profit/-loss before income tax
222,140
-319,074
Expected income tax according to nominal tax rate of 22 percent
-48,892
70,196
Foreign exchange variations between functional and tax currency
-607
-7,581
Adjustment of deferred tax assets not recognized
-20,757
1,676
Impairment financial assets
-17,684
-48,425
Tax-free dividend from subsidiaries
88,490
-
Other items
-549
-17,141
Tax loss carried forward (utilized)
-
1,275
Tax income/-expense
-
-
Effective income tax rate
0%
0%
Tax effects of temporary differences and losses carried forward
Years ended 31 December
USD thousand
2021
2020
Intangible assets
-63
-51
Losses carried forward
86,637
87,705
Non-deductible interests carried forward
28,003
11,278
Other temporary differences
-2,762
-1,223
Deferred tax assets/-liabilities
111,815
97,709
Valuation allowance
-111,815
-97,709
Net deferred tax assets/-liabilities
-
-
Recognized deferred tax assets
-
-
Recognized deferred tax liabilities
-
-
The corporate tax rate in Norway is 22 percent and has been used to calculate the deferred taxes.
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 activity on the NCS, the petroleum activities
carried out abroad by Norwegian subsidiaries are tax exempt in Norway and the dividends from subsidiaries are not taxable.
Parent company accounts
Annual Report and Accounts 2021
DNO
83
Note 7
Property, plant and equipment/Intangible assets
Intangible
USD thousand
assets
PP&E
Total
Costs as of 1 January 2021
14,371
3,196
17,567
Additions
407
126
533
Costs as of 31 December 2021
14,778
3,322
18,100
Accumulated depreciation as of 1 January 2021
-9,667
-2,869
-12,536
Depreciation
-980
-130
-1,110
Accumulated depreciation and impairments as of 31 December 2021
-10,647
-2,999
-13,646
Book value as of 31 December 2021
4,131
323
4,454
Book value as of 31 December 2020
4,704
327
5,031
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
-52,732
-4,342
-
DNO UK Limited
UK
100
-
-
-
DNO Iraq AS
Norway
100
985,020
390,844
279,848
DNO Mena AS**
Norway
100
1,904
-6,568
1,904
Northstar Oman AS
Norway
100
-
-10
-
DNO Technical Services AS
Norway
100
5,324
5
5,359
DNO Exploration UK Limited
UK
100
GBP 30,912
-1,487
-66
-
DNO North Sea plc**
UK
100
GBP 37,289
303,972
-76,247
303,972
Total
1,242,001
303,616
591,083
* Production start-up at the Block 47 in Yemen remains on hold due to force majeure.
** DNO Mena AS and DNO North Sea plc own shares in other subsidiaries, see Note 20 in the consolidated accounts. The figures in the table above
include the respective subgroup's equity and any excess values recognized at the Group level.
In 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.
In 2020, the book value of shares in subsidiaries was partially written off by USD 252 million related to DNO North Sea plc (USD 249.7
million) and DNO Mena AS (USD 2.3 million). Northstar Somaliland AS (previously DNO Somaliland AS), Northstar Exploration Holding
AS and Northstar Invest AS (previously DNO Invest AS) were liquidated in 2020. 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
84
DNO
Note 9
Other receivables
Years ended 31 December
USD thousand
2021
2020
Prepayments and accrued income
2,169
1,599
Other short-term receivables
1,069
476
Other receivables
3,238
2,075
Note 10
Cash and cash equivalents
Years ended 31 December
USD thousand
2021
2020
Cash and cash equivalents, restricted
2,851
2,203
Cash and cash equivalents, non-restricted
512,167
297,462
Total cash and cash equivalents
515,018
299,665
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 2021.
Note 11
Equity
Treasury
Other
Share
shares
Treasury
Share
paid-in
Retained
Total equity
USD thousand
capital
(numbers)
shares
premium
capital
earnings
Shareholders' equity as of 1 January 2020
35,991
93,700,000
-2,641
247,743
-
195,986
477,079
Purchase of treasury shares
-
14,681,415
-414
-
-
-17,327
-17,741
Dividend
-
-
-
-
-
-
-
Profit/-loss for the year
-
-
-
-319,074
-319,074
Cancellation of treasury shares
-3,055
-108,381,415
3,055
-
-
-
Shareholders' equity as of 31 December 2020
32,936
-
-
247,743
-
-140,415
140,264
Shareholders' equity as of 1 January 2021
32,936
-
-
247,743
-
-140,415
140,264
Purchase of treasury shares
-
-
-
-
-
-
-
Dividend
-
-
-
-
-
-21,797
-21,797
Additional dividend
-
-
-
-
-
-22,120
-22,120
Profit/-loss
-
-
-
-
-
222,140
222,140
Shareholders' equity as of 31 December 2021
32,936
-
-
247,743
-
37,808
318,487
See Note 14 in the consolidated accounts for further information on the Company’s equity and shareholders.
In December 2021, the Board of Directors approved a dividend payment of NOK 0.20 per share. The dividend was paid
on 30 December 2021. On 9 March 2022, the Company announced that pursuant to the authorization granted at the
2021 AGM, the Board of Directors has decided to distribute a dividend payment of NOK 0.20 per share to be made
on or about 21 March 2022 to all shareholders of record as of 15 March 2022.
Parent company accounts
Annual Report and Accounts 2021
DNO
85
Note 12
Guarantees, leasing liabilities and commitments
See Note 17 in the consolidated accounts for information regarding other guarantees and commitments.
The Company’s future minimum lease payments under non-cancellable operating leases are related to office rent. The lease period
expires on 30 September 2024 and the yearly rent is USD 2 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)
2021
2020
2021
2020
Non-current
Bond loan (ISIN NO0010823347)
DNO02
USD
-
-
-
-
-
376,500
-
400,000
Bond loan (ISIN NO0010852643)
DNO03
USD
394,900
8.375
29.05.24
9.0
410,202
370,000
394,907
400,000
Bond loan (ISIN NO0011088593)
DNO04
USD
400,000
7.875
09.09.26
8.8
414,000
-
400,000
-
Capitalized borrowing issue costs
(14,215)
(12,641)
Total non-current interest-bearing liabilities
824,202
746,500
780,692
787,359
See Note 15 in the consolidated accounts for further information on interest-bearing liabilities.
Note 14
Current liabilities
Years ended 31 December
USD thousand
2021
2020
Trade payables
4,398
2,225
Public duties payable
2,524
1,665
Accrued expenses and other current liabilities
12,593
9,626
Trade payables and provisions for other liabilities and charges
19,515
13,516
Accrued expenses and other current liabilities include accrued interest for bond loans of USD 4.8 million (USD 5.9 million
in 2020) and accruals for incurred costs of USD 3.4 million (USD 1.2 million in 2020).
Note 15
Financial instruments
See Note 9 in the consolidated accounts for information on financial instruments.
Parent company accounts
86
DNO
Note 16
Related party disclosure
Overhead expenses in the parent company are allocated to the subsidiaries based on their proportional use of the services provided by
the parent company.
See Note 21 in the consolidated accounts for further information on transactions with related parties and Note 19 in parent company
accounts for intercompany transactions and balances at yearend.
Note 17
Significant events after the reporting date
See Note 17 and Note 22 in the consolidated accounts for information on contingencies and events after the balance sheet date.
Note 18
Earnings per share
1 January - 31 December
USD thousand
2021
2020
Net profit/-loss attributable to ordinary equity holders of the parent
222,140
-319,074
Weighted average number of ordinary shares (excluding treasury shares) (millions)
975.43
975.73
Earnings per share, basic (USD per share)
0.23
-0.33
Earnings per share, diluted (USD per share)
0.23
-0.33
Note 19
Intercompany
Long-term intercompany receivables/liabilities
Years ended 31 December
Functional
Receivables
Liabilities
USD thousand
currency
2021
2020
2021
2020
DNO Iraq AS
USD
-
-
79,195
137,216
DNO Mena AS
USD
1,486
881
-
-
DNO North Sea (Norge) AS
NOK
2,524
-
-
-
DNO North Sea plc
USD
81,322
81,322
-
-
DNO Oman Block 8 Limited
USD
-
-
4,061
12,921
DNO Oman Block 30 Limited
USD
556
536
-
-
DNO Oman Limited
USD
1,008
277
-
-
Total long-term intercompany receivables and liabilities
86,895
83,015
83,256
150,137
Except for loans to companies with exploration activities, the intercompany receivables and liabilities are interest bearing.
The intercompany interest rates used by DNO ASA and its subsidiaries are arm's length.
Parent company accounts
Annual Report and Accounts 2021
DNO
87
Note 19
Intercompany
Short-term intercompany receivables/liabilities
Years ended 31 December
Functional
Receivables
Liabilities
USD thousand
currency
2021
2020
2021
2020
DNO Iraq AS
USD
3,079
2,052
-
-
DNO Norge AS
USD / NOK
3,178
1,689
-
-
DNO North Sea (Norge) AS
NOK
66
-
-
-
DNO North Sea Plc
GBP
1,128
504
-
-
DNO North Sea (U.K.) Limited
GBP
17
26
-
-
DNO North Sea (ROGB) Limited
GBP
29
15
-
-
DNO Technical Services AS
USD
-
427
20
-
DNO Yemen AS
USD
-
-
-
-
Other
USD
4
30
-
Total Short-term intercompany receivables and liabilities
7,500
4,743
20
-
Intercompany sales/purchases
1 January - 31 December
Functional
Sales
Purchases
USD thousand
currency
2021
2020
2021
2020
DNO Iraq AS
USD
17,646
18,191
-
-
DNO Norge AS
USD
4,567
3,328
-2,754
-575
DNO North Sea plc
USD
447
673
-
-
DNO North Sea (U.K.) Limited
USD
83
29
-
-
DNO North Sea (ROGB) Limited
USD
143
18
-
-
DNO Oman Limited
USD
21
17
-
-
DNO Oman Block 8 Limited
USD
112
80
-
-
DNO Technical Services AS
USD
1,018
348
-2,481
-1,360
DNO Yemen AS
USD
111
107
-
-
Other
USD
44
95
-8
-
Intercompany sales/purchases
24,190
22,888
-5,244
-1,935
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
2021
2020
2021
2020
DNO Iraq AS
USD
410,000
12,772
-8,889
-2,452
DNO Mena AS
USD
1,441
853
-
-
DNO North Sea (Norge) AS
NOK
2,650
-
-
-
DNO North Sea Plc
USD
4,001
1,387
-
-
DNO Oman Block 8 Limited
USD
-
-
-974
-1,242
Northstar Exploration Holding AS
NOK
-
-
-
-335
Intercompany interest income/-expense
418,092
15,012
-9,863
-4,029
See Note 5 for more details on financial items.
Country-by-Country report
88
DNO
Country-by-Country report 2021
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 2021. 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
incorpora-
tion
2
Royalty
3
Net
product-
ion
4
Corporate
income
tax
5
Special
tax
6
Area fee
7
Contract-
ual
bonuses
8
Invest-
ments
9
Rev-
enue
10
Expendi-
ture
11
Net inter-
company
interest
12
Profit/-
loss
before
tax
10
Tax
income/-
expense
13
Number
employees
14
Equity
10
Tawke
-226.4
81,535
-
-1,002.2
-
-1.5
-
-
-
-
-
-
-
Baeshiqa
-
-
-
-
-
-0.6
-
-
-
-
-
-
-
DNO Iraq AS
Norway
-
-
-
-
-
-
95.9
594.3
-226.2
0.0
390.8
-
985.0
Total Kurdistan region of Iraq
-226.4
81,535
-
-1,002.2
-
-2.1
95.9
594.3
-226.2
0.0
390.8
-
985.0
1,042
DNO Norge AS
Norway
-
12,469
30.6
128.8
-2.2
-0.2
182.0
395.0
-323.1
-11.6
32.8
-23.3
259.6
Total Norway (NCS)
-
12,469
30.6
128.8
-2.2
-0.2
182.0
395.0
-323.1
-11.6
32.8
-23.3
259.6
125
DNO North Sea (U.K.) Limited
UK
-
348
-
-
-0.1
-
4.9
15.8
-21.8
-
-8.5
1.9
-197.5
DNO North Sea (ROGB) Limited
UK
-
126
9.1
6.2
-0.1
-
23.8
2.9
-0.6
-
-17.0
1.0
-87.4
DNO Exploration UK Limited
UK
-
-
-
-
-
-
-
-
-0.0
-
-0.1
-
-1.5
Total United Kingdom (UKCS)
-
473
9.1
6.2
-0.2
-
28.7
18.6
-22.4
-
-25.6
2.9
-286.4
-
Block 47
-
-
-
-
-
-
-
-
-
-
-
-
-
DNO Yemen AS
Norway
-
-
-
-
-
-
-
-
-4.0
-
-4.0
-0.3
-52.7
Total Yemen
-
-
-
-
-
-
-
-
-4.0
-
-4.0
-0.3
-52.7
2
DNO Mena AS
Norway
-
-
-
-
-
-
-
-
-0.0
-
-0.0
-
8.4
DNO ASA
Norway
-
-
-
-
-
-
1.1
24.2
-35.3
3.0
222.2
-
340.1
59
DNO Technical Services AS
Norway
-
-
-
-
-
-
0.0
23.3
-23.2
-
0.0
-
5.3
77
DNO North Sea plc
UK
-
-
-
-
-
-
-
0.0
-1.9
7.7
-87.1
-
619.6
22
Other
-
-
-
-
-
-
-
0.0
-7.6
1.0
-6.6
-
7.8
Other *
-
-
-
-
-
-
1.1
47.6
-68.0
11.7
128.5
-
981.3
158
Eliminations/ Intercompany
-51.4
40.6
-0.1
-302.4
4.4
-867.9
GRAND TOTAL
-226.4
94,477
39.8
-867.2
-2.4
-2.2
307.7
1,004.1
-603.1
-
220.1
-16.3
1,018.8
1,327
* Other includes subsidiaries of DNO ASA that did not hold oil and gas licenses during the year.
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 relates to a tax refund of exploration costs and tax losses. 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
Annual Report and Accounts 2021
DNO
89
Auditor’s report 2021
Auditor’s report
90
DNO
Auditor’s report 2021
Auditor’s report
Annual Report and Accounts 2021
DNO
91
Auditor’s report 2021
Auditor’s report
92
DNO
Auditor’s report 2021
Auditor’s report
Annual Report and Accounts 2021
DNO
93
Auditor’s report 2021
Auditor’s report
94
DNO
Auditor’s report 2021
Alternative performance measures
Annual Report and Accounts 2021
DNO
95
Alternative performance measures
DNO discloses alternative performance measures (APMs) as a supplement to the Group’s financial statements prepared based on
issued guidelines from the European Securities and Markets Authority (ESMA). DNO believes that the APMs provide useful
supplemental information to management, investors, securities analysts and other stakeholders and are meant to provide an enhanced
insight into the financial development of DNO’s business operations, financing and future prospects and to improve comparability
between periods. Reconciliations of relevant APMs, definitions and explanations of the APMs are provided below.
EBITDA
USD million
2021
2020
Revenues
1,004.1
614.9
Lifting costs
-184.2
-181.1
Tariffs and transportation
-34.5
-36.2
Movement in overlift/underlift
-18.3
-11.3
Exploration expenses
-132.3
-55.9
Administrative expenses
-16.2
-4.8
Other operating income/expenses
-11.5
-2.7
EBITDA
606.9
322.8
EBITDAX
USD million
2021
2020
EBITDA
606.9
322.8
Exploration expenses
132.3
55.9
EBITDAX
739.3
378.8
Netback
USD million
2021
2020
EBITDA
606.9
322.8
Tax refund received/-paid
174.7
236.3
Netback
781.6
559.1
2021
2020
Netback (USD million)
781.6
559.1
Net production (MMboe)
34.5
36.6
Netback (USD/boe)
22.7
15.3
Lifting costs
2021
2020
Lifting costs (USD million)
-184.2
-181.1
Net production (MMboe)
34.5
36.6
Lifting costs (USD/boe)
5.3
4.9
Capital expenditures
USD million
2021
2020
Purchases of intangible assets
-86.8
-62.8
Purchases of tangible assets
-193.8
-162.2
Capital expenditures*
-280.6
-225.0
* Exclude estimate changes on asset retirement obligations.
Operational spend
USD million
2021
2020
Lifting costs
-184.2
-181.1
Tariff and transportation expenses
-34.5
-36.2
Exploration expenses
-132.3
-55.9
Exploration cost previously capitalized carried to cost (Note 6 in the consolidated accounts)
54.1
17.5
Capital expenditures
-280.6
-225.0
Payments for decommissioning
-86.2
-30.7
Operational spend
-663.8
-511.4
Alternative performance measures
96
DNO
Alternative performance measures
Equity ratio
USD million
2021
2020
Equity
1,018.8
845.6
Total assets
2,947.8
2,708.7
Equity ratio
34.6%
31.2%
Free cash flow
USD million
2021
2020
Net cash from/-used in operating activities*
728.8
406.2
Capital expenditures
-280.6
-225.0
Payments for decommissioning
-86.2
-30.7
Free cash flow
362.0
150.5
* From 2021, tax refund received/-taxes paid and net interest paid are included in this APM. Comparison figures have been updated.
Net debt
USD million
2021
2020
Cash and cash equivalents
736.6
477.1
Bond loans and reserve based lending
889.9
949.6
Net cash/-debt
-153.4
-472.5
Exploration financing facility has been excluded as it is covered by the exploration tax refund booked as an asset in the statement of financial position.
Reserve Life Index (R/P)
2021
2020
Net production (MMboe)
34.5
36.6
1P reserves
196.1
216.9
2P reserves
321.4
359.9
3P reserves
420.6
549.6
1P Reserve Life Index (R/P in years)
5.7
5.9
2P Reserve Life Index (R/P in years)
9.3
9.8
3P Reserve Life Index (R/P in years)
12.2
15.0
Definitions and explanations of APMs
ESMA issued guidelines on APMs that came into effect on 3 July 2016. The Company has defined and explained the purpose of the
following APMs:
EBITDA (Earnings before interest, tax, depreciation and amortization)
EBITDA, as reconciled above, can be found by excluding the DD&A and impairment of oil and gas assets from the profit/-loss from
operating activities. Management believes that this measure provides useful information regarding the Group’s ability to fund its capital
investments and provides a helpful measure for comparing its operating performance with those of other companies.
EBITDAX (Earnings before interest, tax, depreciation, amortization and exploration expenses)
EBITDAX, as reconciled above, can be found by excluding the exploration expenses from the EBITDA. Management believes that this
measure provides useful information regarding the Group’s profitability and ability to fund its exploration activities and provides a helpful
measure for comparing its performance with those of other companies
Netback
Netback, as reconciled above, comprises EBITDA adjusted for taxes received/-paid. Management believes that this measure is useful
because it provides an indication of the profitability of the Group’s operating activities after taxes received/-paid without regard to
significant events and/or decisions in the period that are expected to occur less frequently. This measure is also helpful for comparing
the Group’s operational performance between time periods and with those of other companies.
Alternative performance measures
Annual Report and Accounts 2021
DNO
97
Alternative performance measures
Netback (USD/boe)
Netback (USD/boe) is calculated by dividing netback in USD by the net production for the relevant period. Management believes that
this measure is useful because it provides an indication of the profitability of the Group’s operating activities after taxes received/-paid
without regard to significant events and/or decisions in the period that are expected to occur less frequently, per net boe produced. This
measure is also helpful for comparing the Group’s operational performance between time periods and with that of other companies.
Lifting costs (USD/boe)
Lifting costs comprise of expenses related to the production of oil and gas, including operation and maintenance of installations, well
intervention activities and insurances. DNO’s lifting costs per boe are calculated by dividing DNO’s share of lifting costs across
producing assets by net production for the relevant period. Management believes that the lifting cost per boe is a useful measure
because it provides an indication of the Group’s level of operational cost effectiveness between time periods and with those of other
companies.
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 and payments for decommissioning.
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.
98
DNO
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
GCA
Gaffney, Cline & Associates
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
Netback
EBITDA adjusted for taxes received/-paid
NOK
Norwegian kroner
Norwegian Public Limited Liability
Companies Act
The Norwegian Public Limited Liability
Companies Act of 13 June 1997 no. 45
(“allmennaksjeloven”)
Operator
A company responsible for managing an
exploration, development, or production
operation
Oslo Stock Exchange
Oslo Børs ASA
Annual Report and Accounts 2021
DNO
99
Glossary and definitions
Petroleum
A complex mixture of naturally occurring
hydrocarbon compounds found in rocks.
PP&E
Property, plant and equipment
Profit oil
Production remaining after royalty and
cost oil, which is split between the
government and the contractors under a
Production Sharing Contract
PSC
A Production Sharing Contract or a PSC is
an agreement between a contractor and a
host government, whereby the contractor
bears all risk and cost for exploration,
development and production in return for a
stipulated share of production
Royalty
Royalty refers to payments that are due to
the host government or mineral owner in
return for depletion of the reservoirs and the
producer contractor for having access to
the petroleum resources
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
100
DNO
DNO ASA
DOKKVEIEN 1 / AKER BRYGGE / 0250 OSLO / NORWAY / PHONE + 47 23 23 84 80 / FAX +47 23 23 84 81/ www.dno.no