INFORMATION MEMORANDUM - DNO ASA · 2019-02-22 · Information Memorandum should consult with his...

INFORMATION MEMORANDUM

in connection with the acquisition of

FAROE PETROLEUM PLC

by

DNO ASA

(a public limited liability company incorporated under the laws of Norway)

The information contained in this information memorandum (the "Information Memorandum") relates to the

completion of a public cash offer for the shares in Faroe Petroleum plc ("Faroe") (the "Transaction") by DNO

ASA, a public limited liability company existing under the laws of Norway (the "Company"). When used herein,

"DNO” refers to the Company together with its subsidiaries, but not including Faroe, and the "Group" refers to

the Company together with all its subsidiaries, including Faroe and its subsidiaries.

This Information Memorandum serves as an information document as required under section 3.5 of the Oslo

Børs Continuing Obligations for Stock Exchange Listed Companies (the "Continuing Obligations"). The

Continuing Obligations apply in respect of companies with shares admitted to trading on Oslo Børs (the "Oslo

Stock Exchange") and this Information Memorandum has been submitted to the Oslo Stock Exchange for

inspection before it was published. This Information Memorandum is not a prospectus and has neither been

inspected nor approved by Finanstilsynet (“Norwegian Financial Supervisory Authority”) in accordance with

the rules that apply to prospectuses.

THIS INFORMATION MEMORANDUM DOES NOT CONSTITUTE AN OFFER OR SOLICITATION TO

BUY, SUBSCRIBE FOR OR SELL THE SECURITIES DESCRIBED HEREIN, AND NO SECURITIES ARE

BEING OFFERED OR SOLD PURSUANT TO THIS INFORMATION MEMORANDUM.

In reviewing this Information Memorandum, you should carefully consider the matters described in Section 1

“Risk Factors” beginning on page 4.

***

The date of this Information Memorandum is 22 February 2019.

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IMPORTANT INFORMATION

The information contained herein is current as of the date hereof and subject to change, completion and amendment

without notice. The publication and distribution of this Information Memorandum shall not under any circumstances

create any implication that there has been no change in the affairs of the Group or that the information herein is correct as

of any date subsequent to the date of this Information Memorandum. No person is authorised to give information or to

make any representation in connection with the Transaction other than as contained in this Information Memorandum.

The contents of this Information Memorandum are not to be construed as legal, business or tax advice. Each reader of this

Information Memorandum should consult with his or her own legal, business or tax advisor as to legal, business or tax

advice. No due diligence has been made on the Company in connection with preparation of this Information

Memorandum.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Information Memorandum includes forward-looking statements that reflect the Company’s current views with respect

to future events and financial and operational performance, including, but not limited to, statements relating to the risks

specific to the Group’s businesses and the implementation of strategic initiatives, as well as other statements relating to the

Group’s future business development and economic performance. These forward-looking statements can be identified by

the use of forward-looking terminology, including the terms "assumes", "projects", "forecasts", "estimates", "expects",

"anticipates", "believes", "plans", "intends", "may", "might", "will", "would", "can", "could", "should" or, in each case, their

negative, or other variations or comparable terminology. These forward-looking statements are not historic or present

facts. They include statements regarding the Company’s intentions, beliefs or current expectations concerning, among

other things, goals, objectives, financial condition and results of operations, liquidity, prospects, growth, strategies, impact

of regulatory initiatives, capital resources, and the industry trends and developments. Readers are cautioned that forward-

looking statements are not guarantees of future performance and that the actual financial condition, operating results and

liquidity of the Group and the development of the industries in which it operates, may differ materially from that suggested

by the forward-looking statements contained herein. By their nature, forward-looking statements involve and are subject to

known and unknown risks, uncertainties and assumptions as they relate to events and depend on circumstances that may

or may not occur in the future. Because of these known and unknown risks, uncertainties and assumptions, the outcome

may differ materially from those set out in the forward-looking statements.

The information contained in this Information Memorandum, including the information set out under Section 1 "Risk

Factors", identifies certain factors that could adversely affect the business, financial condition, operating results, liquidity,

performance and prospects of the Group. Readers are urged to read all sections of this Information Memorandum and, in

particular, Section 1 "Risk Factors".

The Company undertakes no obligation to publicly update or publicly revise any forward-looking statement, whether as a

result of new information, future events or otherwise. All subsequent written and oral forward-looking statements

attributable to the Company or to persons acting on the Company’s behalf are expressly qualified in their entirety by the

cautionary statements referred to above and contained elsewhere in this Information Memorandum.

This Information Memorandum shall be governed by and construed in accordance with Norwegian law. The courts of

Norway, with Oslo as legal venue, shall have exclusive jurisdiction to settle any dispute which may arise out of or in

connection with this Information Memorandum.

INFORMATION SOURCES FROM THIRD PARTIES

The information in this Information Memorandum that has been sourced from third parties has been accurately

reproduced and as far as the Company is aware and able to ascertain from information published by that third-party, no

facts have been omitted which would render the reproduced information inaccurate or misleading.

INFORMATION INCORPORATED BY REFERENCE

The Continuing Obligations allow the Company to incorporate by reference information in this Information Memorandum

that has been previously approved by or filed with a relevant competent authority in accordance with Directive 2003/71/EC

of the European Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses as

well as the format, incorporation by reference and publication of such prospectuses and dissemination of advertisements.

See Section 12 "Incorporation by Reference – Documents on Display" for an overview of documents which have been

incorporated into this Information Memorandum by reference. Accordingly, this Information Memorandum is to be read

in conjunction with these documents.

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TABLE OF CONTENTS

1. RISK FACTORS ............................................................................................................................................... 4

2. RESPONSIBILITY STATEMENT................................................................................................................... 23

3. PRESENTATION OF DNO PRIOR TO THE FAROE ACQUISITION ...................................................... 24

4. BUSINESS OF DNO ...................................................................................................................................... 27

5. THE TRANSACTION .................................................................................................................................... 39

6. PRESENTATION OF FAROE ........................................................................................................................ 41

7. THE GROUP FOLLOWING THE TRANSACTION ................................................................................... 50

8. INDUSTRY AND MARKET OVERVIEW..................................................................................................... 52

9. SELECTED FINANCIAL INFORMATION FOR DNO ............................................................................... 54

10. UNAUDITED PRO FORMA FINANCIAL INFORMATION ("UPFFI") ..................................................... 61

11. BOARD OF DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE.................................. 72

12. INCORPORATION BY REFERENCE – DOCUMENTS ON DISPLAY ...................................................... 76

13. DEFINITIONS ............................................................................................................................................... 78

APPENDIX A – Independent assurance report on UPFFI

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1. RISK FACTORS

Holders of shares in the Company ("Shares") should consider the risks described below, as well as the other

information in this Information Memorandum. These risks are not the only ones of relevance to the business of

the Group. Additional risks and uncertainties not known at present or that are deemed immaterial may also

impair the business, financial condition, operating results, liquidity, performance and prospects of the Group. The

order in which the risks are presented below is not intended to provide an indication of the likelihood of their

occurrence nor of their severity or significance. These risks should also be considered in connection with the

cautionary statement regarding forward-looking statements set forth on page 2 of this Information

Memorandum.

1.1 Risks relating to the Transaction

The UPFFI included in this Information Memorandum has been prepared solely to show what the

significant effects of the Transaction might have been had the Transaction occurred at an earlier date

and does not purport to present the results of operations or the financial condition of the Group, nor

should it be used as the basis of projections of the results of operations or the financial condition of

the Group for any future period or date

This Information Memorandum includes unaudited pro forma consolidated financial information for the

Group as of and for the year ended 31 December 2017. Although the UPFFI is based on estimates and

assumptions based on current circumstances believed to be reasonable, actual results can materially differ

from those presented herein. There is a greater degree of uncertainty associated with pro forma figures than

with actual reported results. The UPFFI has been prepared for illustrative purposes only and, because of its

nature, it addresses a hypothetical situation and therefore does not purport to present the results of operations

of the Group as if the Transaction had occurred at the commencement of the period being presented, or the

financial condition of the Group as of the date being presented, nor should it be used as the basis of

projections of the results of operations for the Group for any future period or the financial condition of the

Group for any date in the future.

The Group may not be able to successfully implement the expected benefits or achieve the

anticipated synergies of the Transaction

The Transaction involves the integration of two companies that have previously operated independently.

Achieving the expected benefits of the Transaction will depend in part on meeting the challenges inherent in

the successful combination and integration of the business enterprises of DNO and Faroe. There can be no

assurance that the Group will meet these challenges, that any diversion related to meeting such challenges will

not negatively affect operations, or that the benefits expected from the Transaction will be realised. In

addition, delays encountered in the transition process could have a material adverse effect on revenues,

expenses, operating results and the financial condition of the Group. There can be no assurance that the Group

will actually achieve anticipated synergies or other benefits from the Transaction. Should any of these risks

associated with acquisitions materialise, it could have a material adverse effect on the Group’s business, results

of operations, financial condition or prospects.

The Group may not be able to review, maintain or transfer the contracts currently held by Faroe or

review, maintain or transfer these on the same terms

Some of Faroe’s contracts contain consent requirements triggered by the Transaction. The Group may not be

able to obtain such consents or may be unable to renew the existing contracts entered into by Faroe or

establish new contracts on terms as favourable as those contracts Faroe currently holds. Further, the Group

may incur transfer or change in control fees under certain contracts as a result of the Transaction. The Group’s

business, operating results, cash flow and financial condition may be adversely affected due to such transfer or

change in control fees, loss of contracts or failure to continue the current contracts or to establish new

contracts on similar terms.

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The Group may be subject to potential loss of key employees as a result of the Transaction

Acquisitions generally involve risk that the employees of the acquired company leave and therefore the Group

risks losing the experience of employees of Faroe in connection with the Transaction. The loss of key

employees in Faroe could have a material adverse effect on the Group’s business, results of operations,

financial condition or prospects.

The Company may discover contingent or other liabilities within Faroe

Following the Transaction, the Company may discover issues relating to Faroe’s business that may have a

material adverse effect on the Group’s business, results of operations, financial condition or prospects, for

which the Company may not be entitled to seek remedy.

1.2 Risks relating to the oil and gas industry

Substantial or extended volatility in oil and gas prices may adversely affect the Group's profitability,

reserves or net income

The Group's future revenues, cash flows, profitability and rate of growth depend substantially on prevailing

international oil and gas prices and realised sales prices (adjusted for quality and transportation differentials).

Oil and gas are globally traded commodities and the Group is unable to control the prices it receives for the oil

and gas it produces.

Historically, oil and gas prices have been highly volatile and subject to wide fluctuations for many reasons,

including, but not limited to:

changes in global and regional supply and demand, and expectations regarding future supply and

demand for oil and gas, even when such changes are relatively minor;

geopolitical uncertainty;

availability of pipelines, tankers and other transportation facilities and processing facilities;

proximity to, and capacity and cost of, transportation;

oil refining capacity;

price, availability and government subsidies of alternative fuels;

price and availability of new technologies;

decisions of the members of OPEC and other oil and gas-producing nations to set and maintain

specified levels of production and prices;

political, economic and military developments in key oil and gas producing regions, and domestic and

foreign governmental regulations and actions, including import and export restrictions, taxes,

repatriations and nationalisations;

global and regional economic conditions;

trading activities by market participants and others either seeking to secure access to oil and gas, to

hedge against commercial risks, or carried out as part of investment portfolio activity;

weather conditions and natural disasters; and

terrorism or the threat of terrorism, war or threat of war, and civil unrest which may affect supply,

transportation or demand for oil and gas and refined products.

It is not possible to accurately predict future oil and gas price movements. The Group’s profitability is

determined in large part by the difference between the income received from the oil and gas the Group

produces and its operational costs, taxation costs relating to extraction (which are assessable irrespective of

sales) and costs incurred by transporting and selling its oil and gas. Therefore, lower oil and gas prices may

reduce the quantities of oil and gas the Group is able to produce economically or may reduce the economic

6

viability of the production levels of specific wells or projects planned or in development. A decline in future oil

and gas prices may accordingly reduce the Group’s reserves and net income.

Further, under IFRS as adopted by the EU, the carrying amount of the capitalised exploration and evaluation

expenditures, development expenditure on the construction, installation or completion of infrastructure

facilities such as platforms, pipelines and the drilling of production wells may not exceed their recoverable

amount. The recoverable amount is based, in part, upon estimated future net cash flows from oil and gas

reserves. If the carrying amount of such capitalised costs exceeds this limit, the Group must charge the amount

of the excess against earnings. If oil and gas prices decline, the Group's net capitalised costs may approach or

exceed their recoverable amount, resulting in a charge against earnings.

Volatility in global financial markets and other macroeconomic factors may adversely affect the

Group's revenues and growth strategy

Deterioration in the global economic environment could have a material adverse effect on the Group's

business, results of operations, financial condition or prospects, particularly to the extent it impacts the prices

of oil and gas or affects the Group's ability to access the capital markets or obtain credit for future funding on

commercially acceptable terms.

Uncertainty in the global financial markets and the potential impact on the liquidity of major financial

institutions and host countries may have a material adverse effect on the Group's cost of funding and the

conditions under which funding is obtained. General economic conditions and geopolitical turmoil could have

a material adverse effect on the Group's business, results of operations, financial conditions or prospects.

Oil and gas prices are also affected by global demand, particularly demand from the US, Europe and Asia

(notably China and India). Changes in the global economic climate could result in lower demand and lower oil

and gas prices, which could adversely affect the Group's revenues and cash flows. In addition, factors such as

trade restrictions, sanctions, embargoes, boycotts, trade measures, and exchange controls, including currency

controls and limitations on the repatriation of funds from operations, could have a material adverse effect on

the Group's business, results of operations, financial condition or prospects.

If the global economy experiences a downturn, the Group's ability to maintain its revenues and implement its

strategy for growth and development may be adversely affected, which could have a material adverse effect on

the Group’s business, results of operations, financial condition or prospects.

Oil and gas E&P activities are inherently uncertain in their outcome and do not necessarily result in a

return on investment or recovery of cost

Oil and gas E&P activities are capital intensive and inherently uncertain in their outcome. The Group's existing

and future oil and gas exploration and appraisal activities may involve unprofitable efforts, either due to

encountering dry wells or wells that are productive but are not commercial in that they would or do not result

in sufficient net revenues to return a profit after incurring development, operating and other costs.

Any inability of the Group to recover its costs and generate profits from its E&P activities could have a material

adverse effect on the Group's business, results of operations, financial conditions or prospects.

E&P operations involve numerous operational risks and hazards which may result in material losses

or additional expenditures

E&P activities are inherently risky and hazardous. Risks typically associated with these operations include

unexpected geological variations and drilling conditions, formations or pressures, premature decline of

reservoirs and technical problems with equipment, any of which may result in operational difficulties. Hazards

typically associated with these operations include the release of hydrogen sulphide gas during flaring, fires,

explosions and blowouts, any of which could result in substantial damage to oil and gas wells, production

facilities and other property, the environment, as well as harm to persons involved in such operations. Drilling

7

operations are also vulnerable in cases of natural disasters, including earthquakes, droughts, floods, fires and

storms, all of which are outside the Group's control. Oil and gas installations can be exposed to, and even be

targets of, military operations and terrorism. E&P operations are also subject to risks relating to transportation

infrastructure, including pipeline failures and problems with tankers, and oil and gas processing, including

bottlenecking and other problems associated with processing or refinery operations. Such problems, either in

relation to the Group's facilities and operations or those of other operators, could result in unexpected

shutdowns, significant losses and expenditures. The materialisation of any of the above risks, hazards or

natural disasters could result in unexpected shutdowns, significant losses and expenditures, and could in turn

have a material adverse effect on the Group's business, results of operations, financial condition or prospects.

Exchange rate fluctuations and inflation may increase the Group's operating costs

Exchange rate fluctuations and currency devaluations could have a material adverse effect on the Group's

results of operations. The Group's revenues are received in USD and EUR; its operational costs are primarily in

USD, but also in NOK, GBP, IQD, YER and AED. The Group's reporting currency is USD. Inflation in the

countries in which the Group operates could cause the Group's operating costs to rise, which could have an

adverse effect on the Group's business, results of operations, financial condition or prospects.

The Group operates in a competitive industry

Given that the oil and gas industry is a competitive business in all phases, the Group's ability to increase

reserves in the future will depend not only on its ability to exploit and develop its present assets but also on its

ability to select and acquire suitable producing assets or prospects for appraisal or exploratory drilling and to

fund the exploration, appraisal and development of such assets. The Group competes with numerous other

participants in the search for, and the acquisition of, oil and gas assets, in the marketing of oil and gas and in

the access to equity and debt funding. The Group's competitors include major international oil and gas

companies that may have substantially greater financial and technical resources, staff and facilities than those

of the Group. These companies have strong market power as a result of several factors, including the

diversification and reduction of risk, financial resources facilitating major capital expenditure, exploitation of

economies of scale in technology and organisation, broad technical experience, established infrastructure,

robust reserve bases and brand recognition. The Group's competitors also include companies with a profile

similar to its own, which will aim to attract and divert equity or debt investors from the Company. Due to this

competitive environment, the Group may be unable to acquire attractive, suitable assets or prospects on terms

that it considers acceptable to fund its operations. As a result, the Group's revenues may decline over time,

thereby causing a material adverse effect to its business, results of operations, financial condition or prospects.

1.3 Risks related to the Group's operations

The Group may be unable to obtain, retain or renew required licenses, concessions, permits and

other authorisations necessary for its operations

The Group conducts its exploration, development and production operations pursuant to rights granted under

PSCs/PSAs and E&P licenses (together with PSCs/PSAs, "licenses") by relevant host country authorities. The

ability of the Group to operate its business depends on the granting and continued validity of such licenses,

which may be subject to the discretion of the relevant host country authorities and therefore cannot be

assured.

The Group may face significant financial penalties, claims or have its existing and future licenses suspended,

terminated or revoked if it fails to fulfil the specific terms of any of its licenses or if it operates its business in a

manner that violates applicable laws or regulations, which could result in increased costs, reputational harm

and adverse changes to the Group's strategy.

Even where the Group is acting in compliance with the terms of its licenses and all applicable laws and

regulations, its licenses could be terminated, revoked, materially altered, or successfully challenged or

impugned by counterparties or third parties. Furthermore, some of the Group's licenses may expire before the

8

end of what the Group estimates to be the productive life of its licensed fields. There can also be no assurance

that the Group's existing licenses will be renewed or that any applications for additional licenses or extensions

will be granted at all or on terms and within a timeframe satisfactory to the Group.

Although the Group believes that its licenses are valid and that the consents necessary for its operations have

been obtained, the Group also operates in jurisdictions with unpredictable legislative, regulatory and judicial

environments and there can be no assurance that the Group would not have difficulty enforcing rights under

its licenses or defending claims of invalidity or permission to conduct certain operations.

Any inability of the Group to comply with the terms of its licenses, successfully defend claims against it,

obtain, retain, extend or renew its licenses on terms satisfactory to it or enforce its rights or defend claims in

relation to its contracts and government consents could have a material adverse effect on the Group's business,

results of operations, financial condition or prospects.

The Group may be unable to bring its assets under license from exploration to development and

production

The ability of the Group to initiate production following a discovery can depend on its ability to bring its assets

from an exploration phase to a development and production phase. Any inability of the Group to move from

exploration to development and production at all or in a timeframe that is satisfactory to the Group could

delay or prevent production activities and the successful execution of the Group's development strategy, which

would limit future revenues and could have a material adverse effect on the Group's expected return on

investment.

Typically, licenses grant rights to companies to explore for oil and gas within defined areas provided the

companies undertake certain commitments (such as exploration and drilling commitments) which have to be

completed within specified timeframes. The Group may be unable to meet the specified deadlines for

commitments set out in its licenses in the exploration phase and may be unable to secure an amendment or

extension of such licenses, which could result in premature termination, expiration, suspension or withdrawal

of any of the Group's licenses.

From time to time, the Group must also maintain, extend and obtain other permits and authorisations in

addition to its licenses. These may include land use and access permits, approvals of design and feasibility

studies, pilot production projects and development plans, environmental permits, and permits for the

construction of facilities. If the Group fails to receive any such permits or authorisations in the future – or

current permits or authorisations are terminated or not renewed – the Group may have to delay or cancel its

investment and development programs.

Any of the above factors could have a material adverse effect on the Group's business, results of operations,


HSE laws and regulations may expose the Group to significant liabilities and increased compliance

costs, litigation, interruptions to operations, unforeseen environmental remediation expenses and

loss of reputation

The Group's operations are subject to HSE rules established internationally, nationally and regionally. HSE

laws and regulations typically govern, among other things, the discharge of hazardous substances into the

environment, the handling and disposal of waste, and the health and safety of the Group's employees and local

communities in the vicinity of its operations. When it ceases operations in an area, the Group can also be

subject to decommissioning obligations of facilities, plugging and abandonment of wells, site restoration and

clean-up in relevant areas. The technical requirements of these HSE laws and regulations can be complex,

stringently enforced and can result in significant compliance costs.

9

The Group is subject to generally applicable laws and regulations on emission of greenhouse gases such as

carbon dioxide, methane and nitrous oxide. Such legislation is designed to reduce the emission of greenhouse

gases and other harmful substances. Compliance with existing or future emissions legislation could impact oil

and gas prices and the Group's ability to market its oil and gas could involve significant costs to the Group.

These factors may accordingly have a material adverse effect on the Group's business, results of operations,


Certain HSE laws and regulations provide for strict joint and several liabilities without regard to negligence or

fault for damage caused to persons, property and the environment by E&P activities. Such laws and regulations

may expose the Group to liabilities incurred either due to its own conduct or the conduct of others.

Compliance with HSE laws and regulations may lead to the Group incurring substantial future expenditures,

for instance due to requirements to modify operations, upgrade employee and contractor accommodation or

other infrastructure, install pollution control equipment, perform clean-up operations, or to curtail or cease

certain operations.

Any future changes in HSE laws and regulations, stricter enforcement or new interpretations or enforcement of

existing laws and regulations, discovery of previously unknown contaminations or community expectations

governing the Group's operations could have a significant impact on the Group's compliance and remediation

costs.

The Group’s primary operational HSE risks are those inherent in the oil and gas industry generally. In addition,

some of the jurisdictions in which the Group operates do not have a developed infrastructure for waste

management, which may lead to increased risk of pollution to the surrounding environment.

Any failure by the Group to comply with HSE laws and regulations may result in regulatory actions and

liabilities, including withdrawal of licenses or permits; temporary or permanent closure of the Group's

facilities; imposition of fines or penalties; obligations to compensate for environmental damage and to restore

environmental conditions or other obligations; or payment of compensation to third parties and employees,

each of which could lead to a decrease in revenues or an increase in costs. The Group may also become

involved in claims, lawsuits and administrative proceedings relating to HSE compliance or claims that could

result in reputational damage, industrial action or difficulty in recruiting and retaining skilled employees.

Any of the factors above could have a material adverse effect on the Group's business, results of operations,


The Group's operations could be compromised by criminal or terrorist action

The Group may be a target for criminal or terrorist actions, or threats of actions, in particular against its

employees, properties, facilities or workplaces or third-party infrastructure. Criminal or terrorist action, or

threats of action, could disrupt the Group's operations or increase operating costs associated with security,

insurance and other protections against criminal and terrorist action, which could have a material adverse

effect on the Group’s business, results of operations, financial condition or prospects.

Recovery, reserve and resource data in this Information Memorandum are only estimates and may

prove incorrect or inaccurate

All estimates of oil and gas reserves and resources, and the future net cash flows expected, involve uncertainty.

Important factors that could cause actual results to differ from estimates include, but are not limited to:

technical, geological and geotechnical conditions; economic and market conditions; operating costs; oil and

gas prices; and changes in government regulations, interest rates and currency exchange rates. Specific

parameters of uncertainty related to fields and reservoirs include but are not limited to: reservoir pressure and

porosity, recovery factors, water cut development, production decline rates, gas/oil ratios and oil properties.

10

Estimates of the economically recoverable reserves attributable to any particular group of properties,

classification of such reserves based on risk of recovery and estimates of future net revenues expected

therefrom prepared by different engineers, or by the same engineers at different times, may vary. The Group's

actual production revenues and development and operating expenditures with respect to its reserves are likely

to vary from estimates and such variations could be material.

If the actual reserves or resources of the Group are less than the current estimates or of lower quality than

expected, the Group may be unable to recover and produce the estimated levels or quality of oil or gas and, as a

result, the Group may not recover its initial outlay of capital expenditures and operating costs of any such

operation and could have a material adverse effect on the Group’s business, results of operations, financial

condition or prospects.

The Group may not be able to commercially develop its contingent and prospective resources

Under the Petroleum Resources Management System ("PRMS"), contingent resources are those deposits that

are estimated, on a given date, to be potentially recoverable from known accumulations but that are not

currently considered to be commercially recoverable. Prospective resources are those deposits that are

estimated, on a given date, to be potentially recoverable from accumulations yet to be discovered. The

probability that contingent and prospective resources will be discovered, or be economically recoverable, is

considerably lower than that for proven, probable and possible reserves. Volumes and values associated with

contingent and prospective resources should be considered to be highly uncertain. The Group's estimates of its

contingent and prospective resources are uncertain and can change with time, and there can be no guarantee

that the Group will be able to develop these resources commercially. If the Group is unable to commercially

develop its contingent and prospective resources, this could have a material adverse effect on the Group’s

business, results of operations, financial condition or prospects.

The Group cannot accurately predict its future decommissioning liabilities

Pursuant to its licenses, the Group has assumed certain obligations and liabilities with respect to

decommissioning of infrastructure (including plugging and abandonment of wells) and it is expected to

assume additional decommissioning liabilities in respect of future operations. These liabilities are derived from

legislative and regulatory requirements and require the Group to make provisions for and/or underwrite the

liabilities relating to such decommissioning.

Although the Group's accounts make provisions for such decommissioning costs, there can be no assurance

that the costs of decommissioning will not exceed the value of the long-term provisions set aside to cover such

decommissioning costs. It is difficult to accurately forecast the costs that the Group will incur in satisfying its

decommissioning obligations and the Group may have to draw on funds from other sources to bear such costs.

When its decommissioning liabilities crystallise, the Group may be jointly and severally liable for them with

former or current partners in the field. In the event that the Group's partners default on their obligations, the

Group will remain liable and its decommissioning liabilities could significantly increase through such default.

Any increase in the actual or estimated decommissioning costs of the Group could have a material adverse

effect on the Group's business, results of operations, financial condition or prospects.

The Group is jointly and severally liable with its license partners to the Norwegian and UK Governments for all

decommissioning costs and liabilities of each license in which the Group holds an interest. In Norway,

historically there is no obligation or tradition for license partners to provide security for their respective share

of decommissioning liabilities ahead of actual decommissioning. Furthermore, a licensee assigning its interest

in a license remains secondarily liable for decommissioning costs related to facilities existing at the time of

assignment. It is an established practice to provide a decommissioning guarantee or other security to cover

such secondary liability.

11

Decommissioning of UKCS offshore oil and gas installations and pipelines and related liabilities are regulated

by BEIS through the Petroleum Act. See Section 4.3.3.7 below for further details.

The Group is also jointly and severally liable with its license partners for decommissioning, abandonment and

site restoration under its PSCs in the KRI unless the KRG chooses to take over production operations after

expiry of the relevant term. A voluntary cost recoverable decommissioning reserve fund may be set up under

the Tawke and Erbil PSCs by the parties during the last ten years of the term of production operations from a

production area. Under the Baeshiqa PSC, the Group and its partners are obliged to, before the ten final years

of the term of production operations or a production area, either establish a decommissioning reserve fund, set

up an escrow account or a trust or, if required by applicable law, provide guarantees or bonds. Where such

fund is not sufficient to cover all relevant decommissioning costs, the Group and its partners are liable for the

balance.

Future and current investigations, disputes and litigation could adversely affect the Group's business,

results of operations, financial conditions or prospects

From time to time, the Group is involved in disputes and litigation matters. Some of these are ongoing. The

ultimate outcome of any such disputes and their effect on the Group cannot be predicted and may be material.

While the Group assesses the merits of each dispute and defends itself accordingly, it may incur significant

expenses or devote significant resources to defending itself in such disputes. These expenses, potential

reputational harm arising from any such dispute, as well as financial penalties or the loss of key personnel that

could result from any such dispute could have a material adverse effect on the Group's business, results of

operations, financial condition or prospects.

Oil and gas E&P are capital intensive activities and the Group must make significant capital

expenditures in order to increase its production levels and improve overall efficiency

The Group's exploration, development and production operations require significant capital expenditures.

Capital expenditures may include, among other things, the drilling of wells, the construction and improvement

of infrastructure, and investments in production technology in an effort to improve access, reduce operating

expenses and enhance profit margins. In 2017, DNO incurred acquisition and development costs of USD 130.4

million, up from USD 36.4 million in 2016. In addition, the Group will incur costs to meet its obligations under

environmental laws and regulations, including costs for decommissioning (including plugging and

abandonment of wells), site restoration and clean-up when operations cease. The Group intends to fund

planned capital expenditures from cash balances, financing and cash flow from operations. However, the

Group may not be able to generate sufficient funds to meet future capital expenditure requirements in the

longer term or to do so at a reasonable cost.

The Group's ability to arrange future financing, and the cost of such financing, depends on many factors,

including economic and capital markets conditions generally, investor confidence in the oil and gas industry

and in the Group, the business performance of the Group, regulatory developments, credit available from

banks and other lenders, and provisions of tax and securities laws that are conducive to raising capital.

The terms and conditions on which future funding or financing may be made available may not be acceptable,

or funding or financing may not be available at all. If additional funds are raised in the longer term, the Group

may become more leveraged and subject to additional or more restrictive covenants.

Any inability of the Group to procure sufficient financing for capital expenditures could adversely affect its

ability to expand its business and meet its production targets and could result in the Group facing unexpected

costs and delays in relation to the implementation of its project development plans and could adversely affect

the Group's ability to maintain its production at current levels. This could have a material adverse effect on the

Group's business, results of operations, financial condition or prospects.

12

The Group relies on the services of independent third-party contractors, the quality and availability

of which cannot be assured

The Group relies on external independent contractors to carry out various operational tasks in its E&P

operations, including carrying out drilling activities, delivering oil and gas to counterparties and maintaining

the Group's assets and infrastructure. Some of the services required for the Group's operations and

developments are currently only available from a limited number of key providers on commercially reasonable

terms.

The Group relies on the availability of independent contractors performing satisfactorily and fulfilling their

obligations. The provision of goods, services and maintenance by external contractors is outside the Group's

control. Any failure by an independent contractor may lead to delays or curtailment of the development,

production, transportation and delivery of the Group's oil and gas. In addition, the costs of third-party

operators may fluctuate, leading to changes in production and transportation expenses for the Group. Any

dispute with, or failure in performance by, third-party service providers, external contractors or consultants,

and associated increases in operating costs or inability on the part of the Group to find adequate replacement

services on a timely basis, if at all, could result in delays or curtailment of the development, production,

transportation and delivery of the Group's oil and gas, which in turn could have a material adverse effect on

the Group's business, results of operations, financial condition or prospects.

The Group could suffer unexpected costs or other losses if its partners and counterparties do not

perform or comply with license terms and applicable regulations

The Group may suffer unexpected costs or other losses if any counterparty to any contractual arrangements

entered into by the Group does not meet its obligations under such arrangements. For instance, the Group

cannot control the acts or omissions of its joint venture partners under the various licenses. The Group is

generally jointly and severally liable for the obligations of former and current partners under the licenses. If

such partners breach the terms of the licenses or any other contractual arrangements relating to their interests,

the Group may be jointly and severally liable for such breach. Such breach could also cause the relevant host

country authority to revoke, terminate, suspend or adversely amend the Group's licenses, which could in turn

have a material adverse effect on the business, results of operations, financial conditions or prospects of the

Group. Where the Group is not the operator of an asset, it will through operating or management committees

have voting and consultation rights in relation to significant or operational matters, but it will not have full

control over day-to-day operational management. In Norwegian licenses, non-operators also have a "see-to-it"

duty to ensure that the operator acts in compliance with statutory requirements. Breach of this duty may lead

to independent liability, separate to any joint and several liability it may incur as a joint venture partner. Both

mismanagement of an asset by the operator or, in the case of assets where a Group subsidiary is the operator, a

failure on the part of the Group's partners in the license to cooperate in the operation of the asset may result in

significant delays, losses or increased costs to the Group. Any such mismanagement or cooperation failures

could have a material adverse effect on the Group's business, results of operations, financial condition or

prospects.

The Group may not be able to carry insurance in respect of every risk that could have a material

impact on its operations

Although the Group carries insurance in accordance with industry standards to cover certain of the risks and

hazards described in the above risk factors, insurance is subject to conditions and limitations on liability and,

as a result, may not be sufficient to cover all of the Group's potential losses. In addition, the risks or hazards

associated with the Group's operations may not, in all circumstances, be insurable, and in certain

circumstances the Group may elect not to obtain insurance to deal with specific events due to the high

premiums associated with such insurance or for other reasons. The Group's business interruption insurance is

limited in time and the Group may suffer losses as a result of a shut-in or cessation in production. The

occurrence of a significant event against which the Group is not fully insured, or the insolvency of the insurer

of such event, could have a material adverse effect on the Group's business, results of operations, financial


13

Difficulties in the marketing or exporting of the Group's oil and gas could adversely affect the Group's

revenues

The Group’s ability to sell the oil and gas it produces will be affected by numerous factors beyond its control,

such as market fluctuations, the availability of international markets and the availability of storage, processing

and refining facilities and transportation infrastructure, including access to ports, shipping facilities, pipelines

and pipeline capacity. There is a risk that the Group does not get paid for its deliveries. In addition, disruptions

to transportation services or restrictions on access to key transportation channels, as well as disruptions in the

supply of essential utility services and access to processing facilities, could have a material adverse effect on the


The ability to export oil and gas may depend on obtaining licenses and export volumes, the granting of which

is at the discretion of the relevant regulatory authorities. Furthermore, there can be no assurance that the

Group will be paid its full entitlement for export sales. Difficulties that the Group could face in marketing or

exporting its oil and gas could have a material adverse effect on the Group’s business, results of operations,


The Group's operations and development projects could be adversely affected by shortages of key

inputs

The Group may be unable to obtain, in a timely manner and at a reasonable cost, drilling and processing

equipment, raw materials and strategic consumables that are key inputs for its business. Availability of key

inputs is limited and, particularly in periods of high demand within the industry, the Group may be unable to

secure key inputs at a reasonable cost and in a timeframe that allows it to meet its contractual and other

obligations and operational timetable.

The Group contracts or leases various services and equipment from third-party providers and suppliers. Such

equipment and services may be scarce and may not be readily available at the times and places required by the

Group. Even in a situation where the Group has secured rigs under a contract, the rigs will usually only be

available for use after the current user has finished its drilling program. If there are delays in the completion of

the user's drilling program, the Group could be delayed in procuring contracted rigs. Under the terms of its

licenses, the Group may have a commitment to drill within a certain timeframe. The Group therefore risks

losing its licenses if it is delayed in obtaining rigs and meeting its drilling commitments. Shortages or changes

in the costs of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect

the Group's exploration, development and production operations, which could have a material adverse effect

on the Group's business, results of operations, financial condition or prospects.

The Group's success depends on its ability to appraise, acquire, explore and develop oil and gas

reserves that are economically recoverable

The Group's long-term commercial success depends on its ability to acquire, explore, appraise and develop

commercially productive oil and gas reserves. There are many reasons why the Group may not be able to find

or acquire oil and gas reserves or to develop them for commercially viable production. For example, the Group

may be unable to negotiate commercially reasonable terms for its acquisition, exploration, appraisal,

development or production activities. Factors such as adverse weather conditions, natural disasters, equipment

or services shortages, procurement delays or difficulties arising from political, environmental and other

conditions in the areas where the Group's assets and licenses are located, or through which the Group's

products are transported, may also increase costs and make it uneconomical to develop potential reserves.

Furthermore, the Group's exploration activities require the coordination of a number of activities, including

obtaining seismic data, governmental and co-venturer approvals and securing rig capacity for drilling, resulting

in long lead times and the potential for missed exploration opportunities. Under the majority of the Group's

joint operating agreements, the Group's participating interest is such that the Group would need the approval

of at least one other co-venturer to make majority decisions.

14

Without successful acquisition, exploration, appraisal, development and production activities, the Group's

reserves, production and revenues will decline. The Group might not discover, acquire or develop further

commercial quantities of oil and gas, which could have a material adverse effect on the Group's business,


The Group may not realise the anticipated benefits of and may face risks and challenges from future

acquisitions

The Group is continuously considering expansion of its operations through organic growth and acquisitions.

Where the Group acquires another company or its assets, integrating and managing the operations of the

acquired assets may be challenging and may render the value of any company or assets acquired less than the

amount paid. Furthermore, due to the limited information available prior to an auction of licenses or any

acquisition, it may not be possible to correctly assess the true value of the license or asset to be acquired.

Particular challenges that the Group may face in connection with future acquisitions include complications

with consolidating corporate and administrative infrastructures, including information technology,

communications and other systems, difficulties with retaining key personnel and employees, diversion of

management’s attention and resources from on-going business concerns, attempts by third parties to

terminate or alter their contracts with the Group, difficulties in mitigating contingent and assumed liabilities.

Any of the above challenges associated with a future acquisition could have a material adverse effect on the


The Group's success is dependent upon its ability to attract and retain key personnel

The Group's success depends, to a large extent, on certain of its key personnel having expertise in the areas of

exploration and development, operations, engineering, business development, oil and gas marketing, finance

and accounting. The loss of the services of any key personnel could have a material adverse effect on the

Group.

The Group does not maintain, nor does it plan to obtain, any key person insurance. In addition, the

competition for qualified personnel in the oil and gas industry is intense. As a result, the Group may face

significant costs to attract and retain all personnel necessary for the development and operation of its business,

and there can be no assurance that it will be able to do so in each case. Any failure to attract or replace key

personnel could have a material adverse effect on the Group's business, results of operations, financial


The Group must comply with various laws and regulations regarding anti-corruption and anti-bribery

and with international sanctions regimes

The Group is subject to various laws and regulations relating to anti-bribery and corruption in each of the

jurisdictions it does business, including but not limited to provisions of the Norwegian Criminal Act of 20 May

2005 and the UK Bribery Act of 2010, which generally prohibit companies and their intermediaries from

making improper payments to government officials or private parties, or otherwise improperly influencing

such persons, for the purpose of obtaining or keeping business or other benefits. These laws and regulations on

anti-bribery and corruption may apply to actions taken on behalf of the Group or by individual subsidiaries

regardless of the jurisdiction in which such actions are carried out, and the Group may thus become liable for a

breach of such anti-bribery and corruption provisions even if such breach occurred in other jurisdictions. The

Group must also comply with sanctions regimes established or adopted by Norway and the UK, including

regimes established by the United Nations Security Council and the EU.

Although the Group has policies and procedures designed to ensure that the Group operates in compliance

with applicable laws and regulations, there can be no absolute assurance that such policies or procedures will

work effectively all of the time or protect the Group against liability for actions taken by its employees or other

parties deemed to be acting on the Group’s behalf with respect to the Group's business. If the Group or its

15

employees do not comply with applicable laws, regulations and sanctions regimes (including local laws), it may

be subject to criminal and civil penalties and other remedial measures, which could have a material adverse

effect on the Group's business, results of operations, financial conditions or prospects. Any investigation into

the Group of potential violations of these laws, regulations and sanctions regimes could also have a material

adverse effect on the Group's business, results of operations, financial conditions or prospects. Furthermore,

any remediation measures taken in response to such potential or alleged violations of these laws, regulations

and sanctions regimes, including any necessary changes or enhancements to the Group's procedures, policies

and controls and potential personnel changes and/or disciplinary actions, could have a material adverse effect

on its business, results of operations, financial condition or prospects.

The Group is exposed to counterparty risk

There is always a risk that the Group's customers or counterparties to financial instruments held by the Group

will fail to meet their contractual obligations. Any such failure could have a material adverse effect on the


The Group is exposed to financial guarantee risk

As part of governmental or joint venture partner approval conditions in the course of new or changed business

opportunities, the Group may have, or may have had, to provide financial comfort through the issuance of

parent company guarantees or other financial instruments. There is always a risk that a parent company

guarantee or other financial instrument may be called for alleged defaults in approval conditions or

performance. Any such failure could have a material adverse effect on the Group’s business, results of


A default or acceleration of repayment of debt may have a material adverse effect on the Group's

business, results of operations, financial conditions or prospects

The Group has outstanding unsecured debt in the form of bonds. Bond loan defaults, unless remedied by the

Group or waived by bondholders, could lead to acceleration and demands for repayment of the outstanding

bond loans. In the event of a default or acceleration of repayment of debt, there can be no guarantee that the

Group would be able to successfully refinance its debt, make payments from cash balances, or generate new

cash from asset divestments or new equity placements, which could have a material adverse effect on the


The Group faces risks relating to the UK's continued membership in the EU

A referendum was held in the UK on 23 June 2016 on whether the UK will remain a member of the EU, the

result of which was a vote to leave ("Brexit"). The UK and EU are still negotiating with the aim to agree on a

plan for Brexit including (the free or restricted) transfer of people, goods, capital and services post Brexit. The

consequences of the UK leaving the EU are as yet uncertain and could have unforeseen, or unforeseeable,

adverse effects on the Group’s business, financial condition or prospects.

The Group faces risks associated with both the potential uncertainty during the period following the

referendum and also the consequences that may flow from Brexit. For example, because a significant

proportion of law and regulation applicable in the UK is based on EU legislation and directives, leaving the EU

could materially change the legal and regulatory framework that would be applicable to the Group's operations

in the future, hereunder its E&P licenses. Changes in the legal and regulatory framework could increase

operating costs as well as restrict the movement of capital and mobility of personnel within the Group. In

addition, Brexit may impact on the stability and development of the financial markets (including interest rates)

and business markets in the EU and could result in increased pressure for a further Scottish independence

referendum. No guarantees can be made as to the Group's position following Brexit, the results of which could

have a material adverse effect on the Group's business, results of operations, financial condition or prospects.

16

1.4 Risks related to the Group's operations in the Middle East

Although DNO re-entered the North Sea (Norway and the UK) through the acquisition of Origo Exploration

Holding AS (“Origo”) in 2017 and Faroe through the Transaction, the Group's producing assets and related

operations are still predominantly located in the Middle East region, namely in Kurdistan. In addition to the

operational and other risks associated with E&P operations in the oil and gas industry generally, the Group is

subject to risks specifically relating to its operations in the Middle East. Some of these risks relate to the

political, social and economic instability that characterises the region at this time.

1.4.1 Risks relating to the Group's operations in the Middle East generally

Parts of the region are currently prone to political, social and economic instability

Parts of the Middle East are currently prone to political, social and economic instability. Such instability could

disrupt the Group's operations, lead to a decline in production and otherwise adversely affect the Group's

business.

Furthermore, such instability could threaten the security of the Group's assets, personnel and transportation

systems. There can be no assurance that the Group will be able to obtain or maintain effective security

arrangements for any of its assets or personnel in these regions. There can also be no assurances that the

governments of the regions where the Group operates will be able to provide the necessary degree of peace,

order, stability and security for the Group to carry out its operations.

Additionally, political, social and economic instability creates uncertainty as to whether the governments with

which the Group has negotiated licenses will remain in power and, if they are replaced, whether future

decision-makers will honour the terms of the licenses held by the Group. It also creates uncertainty about

whether the Group can safely conduct its operations and execute its development plans in the region.

The materialisation of the risks above could have a material adverse effect on the Group's business, results of


The Group operates in jurisdictions where it may be difficult to interpret the applicable laws and

regulations and obtain or enforce court rulings and arbitral awards

Some of the jurisdictions in which the Group operates, for example in Kurdistan and Yemen, have less

developed legal systems than those typically seen in established economies, for example in Norway. It may be

difficult to interpret the applicable laws and regulations in these jurisdictions or to obtain or enforce court

rulings and arbitral awards. Enforcement of laws may depend on, and be subject to, the interpretation of such

laws by the relevant local authorities, and such authorities may adopt an interpretation of an aspect of local

law that differs from the advice that has previously been given to members of the Group. Risks associated with

the Group's operations in these jurisdictions include:

the risk that it may be difficult to obtain effective legal redress in court, whether in respect of a breach

of law or regulation, or in an ownership or title dispute;

the risk that it will be difficult to enforce international arbitral awards, in particular when they are

against the local authorities;

the risk that its operations may be affected by a high degree of discretion or corruption on the part of

the governmental or judicial authorities;

the risk that a lack of judicial or administrative guidance on interpreting local laws and regulations

may make it difficult for the Group to guarantee its compliance with such laws and regulations;

the risk that there may be inconsistencies or conflicts between and within various laws, regulations,

decrees, orders, resolutions and judgments; and

the risk that judicial or administrative authorities may be relatively inexperienced in adjudicating or

regulating matters relating to the Group's E&P operations.

17

Any failure by the Group to interpret the applicable laws and regulations or to obtain or enforce court rulings

and arbitral awards in the jurisdictions where it operates could have a material adverse effect on the Group's


1.4.2 Risk relating to the Group's operations in Kurdistan

As a result of the historical and legal position of Kurdistan, and the relationships of the KRG with the FGI and

with neighbouring countries such as Turkey, the Group and other international E&P companies operating in

Kurdistan face a number of risks specific to the region as set forth below.

The FGI has historically disputed the validity of the PSCs entered into by oil and gas companies with

the KRG and there can be no assurance that the Group can protect its interests in assets in Kurdistan

Although the Group has good title to its licenses in Kurdistan, including the right to explore for and produce

oil and gas from these licenses, the FGI has in the past challenged the validity of certain PSCs signed by the

KRG. Should the FGI (pursuant to any future federal oil and gas law or otherwise) attempt to revoke or

materially alter the PSCs held by the Group in Kurdistan, it could disrupt or halt the Group’s operations in

Kurdistan, lead to administrative fines or penalties, subject the group to contractual damages or delay or

prevent the Group’s execution of its strategy, any one of which could have a material adverse effect on the


There can be no assurance that the Group will receive payments for its oil exports or recover costs as

provided in its PSCs in Kurdistan

Historically, as a result of disagreements between the FGI and the KRG, economic conditions in Kurdistan and

limited available export channels, DNO has faced constraints in fully monetising the oil it produces in

Kurdistan. There is no guarantee that oil and gas can be exported in sufficient quantities or at prices required

to sustain its operations (at profitable levels or at all) and investment plans or that the Group will promptly

receive its full entitlement payments for the oil and gas it delivers for export. Any of these risks could result in

a loss of revenue and could have a material adverse effect on the Group's business, results of operations,


The Group generates revenues in Kurdistan through the sale of oil produced from the Tawke license which is

then exported by pipeline through Turkey by the KRG. In the past, export sales have not followed the PSC

terms and there has historically been uncertainty related to both timing of revenue and receipt of payments.

However, DNO has received regular export monthly payments from the KRG since late 2015 and revenues from

Tawke license production are now in line with the terms of the PSC. On 24 August 2017, DNO, through its

subsidiary DNO Iraq AS, and the KRG, completed the RSA, a settlement of all outstanding receivables owed to

DNO for past oil deliveries. The RSA had an effective date of 1 August 2017. Under the settlement agreement,

DNO was assigned the 20 percent interest in the Tawke license previously held by the KRG, bringing DNO’s

operated interest to 75 percent. In addition to the 20 percent interest, DNO will receive three percent of gross

license revenues each month from the KRG over a five-year period. The KRG also discharged DNO from

certain payment obligations, including those for production bonuses, license fees and a water purification

project. In addition, the KRG has exercised its Tawke license audit rights to its satisfaction for the period up to

the effective date and has no adjustment claims.

In the past, DNO has also sold Tawke license oil into the local market and has been subject to the KRG’s

Ministry of Natural Resource’s overall guidance on volumes and price. If there are any disruptions to the

current export route, there can be no guarantee that the Group will in the future be permitted to sell oil on the

local market in quantities or at prices sufficient to generate economic benefit. Local sales prices have

historically been significantly lower than prevailing international oil and gas prices. Any limitation on the

Group's ability to sell oil and gas and refined products on the local market at adequate prices could have a

material adverse effect on the Group's business, results of operations, financial condition or prospects.

18

The Group is subject to political and legal uncertainty relating to Kurdistan's status within Iraq's

federal structure

The issue of regional autonomy in Iraq, and in particular the autonomy of Kurdistan, is a subject about which

various political factions in Iraq strongly disagree and which could lead to political and legal uncertainty that

could negatively affect the Group. In September 2017, Kurdistan held a referendum vote for independence from

Iraq which received wide support from voters. The FGI, however, strongly opposed the referendum,

subsequently imposing measures including stricter border control, closing of airports and military forces

occupying the disputed areas in the Kirkuk province. The KRG has not progressed the independence process

following the interventions but the operating and political environments in Kurdistan were interrupted for a

period when the interventions took place. Such uncertainty could have an adverse effect on the Group's


The Group’s PSC accounts are subject to audit and there is uncertainty relating to the outcome and

impact of any such audit on the Group's recovery of costs and financial results

The Group's PSC accounts are subject to audit by regulatory authorities in the respective host countries. In

Kurdistan, the FGI, in coordination with the KRG, commenced an audit of the accounts of DNO's three PSCs in

October 2011, but the audit was discontinued in February 2012. As part of the RSA, it was agreed that the KRG

has exercised its audit rights for the period up to the effective date of 1 August 2017 and has no adjustment

claims. Separately, the KRG has initiated audits in 2017 and 2018 on production data and bonuses. The audits

are not yet closed and a cost audit is also expected to take place.

In the event that these or other future audits determine that the costs recoverable by the Group are lower than

the costs actually incurred or are lower than the costs that the Group has expected it will recover, the Group

may not fully recover its costs, which would result in lower profits than expected. A significant decrease in

profits as a result of these risks could have a material adverse effect on the Group's business, results of


Kurdistan could be negatively impacted by instability resulting from military operations and

instability in the rest of Iraq

There is a risk that Kurdistan could be destabilised by a number of factors, including the threat of the self-

proclaimed Islamic State or instability in the rest of Iraq, which has a history of political and social instability.

There can be no assurance that the Group’s operations in Kurdistan will not be materially impacted by civil

unrest or cross-border military activities, or that the Group will be able to obtain or maintain effective security

arrangements for any of its assets or personnel in Kurdistan. In the event that Kurdistan is negatively impacted

by instability within Iraq or cross-border military operations, it could face disruption to, or cessation of, its

operations or lose key personnel, any of which could have a material adverse effect on the Group's business,


The Group may be unable to successfully manage its relationships with local communities

As a consequence of public concern about the perceived ill effects of economic globalisation, businesses

generally, and large multinational corporations in particular, face increasing public scrutiny of their activities.

The Group may operate in or near communities that regard the Group's presence as being detrimental to their

environmental, economic or social conditions. The Group may also operate in circumstances in which local

communities have a negative reaction to decisions by their government to facilitate development of the oil and

gas industry. Negative local community reaction to the Group could lead to disputes with national or local

governments or with local communities, give rise to material reputational damage, limit the Group’s ability to

conduct or finance its activities and threaten the viability of its operations, any of which could have a material


The Group's assets may be nationalised or expropriated

There is a risk that the Group's property in the countries in which it operates could be nationalised or

expropriated. Statutory and contractual protections of the Group’s property interests in these countries may

19

not be sufficiently robust to protect the Group against nationalisation or expropriation, and the Group may not

receive adequate compensation or be able to obtain proper redress in local or international courts or

arbitration tribunals in the event that its properties are nationalised or expropriated. Should such

nationalisation or expropriation occur, it could have a material adverse effect on the Group's business, results

of operations, financial condition or prospects.

1.4.3 Risk relating to the Group’s operations in Yemen

Operations in Yemen are currently suspended. The ongoing conflict in Yemen entails risk that the Group could

face continued disruption to its operations, which could have an adverse effect on the Group's business in

Yemen, results of operations, financial condition or prospects.

1.4.4 Risk relating to DNO's past operations in Oman

On 3 January 2019, the Company announced that its subsidiary DNO Oman Block 8 Limited had relinquished

operatorship and participation in Oman Block 8 to the Oman's Ministry of Oil and Gas and state-owned Oman

Oil Company Exploration and Production LLC (“OOCEP”). Effective 4 January 2019, with the expiry of the 30-

year commercial term of the Exploration and Production Sharing Agreement, Block 8 will be operated by the

Musandam Oil and Gas Company, fully-owned by OOCEP.

DNO held a 50 percent interest in the license alongside LG International, which held the remaining 50 percent

interest. The relinquishment has given rise to certain contested issues between Oman and DNO Oman Block 8

Limited which are currently unresolved at the date of the Information Memorandum. This could have an


1.5 Risks related to taxation

The final determination of the Group's tax liability may be materially different from what is reflected

in the Company's income tax provisions and related balance sheet accounts and future changes in, or

any new interpretation of, tax legislation applicable to Group entities may reduce net returns to the

Company's shareholders

The Group is involved in business activities in various jurisdictions and is subject to taxation in the countries in

which it operates and/or in which its subsidiaries are incorporated. Consequently, the Group is faced with a

number of different tax regimes and complex tax laws. When computing its tax obligations in these

jurisdictions, the Group is required to take various tax and accounting positions for which the Group may not

have received rulings from the relevant tax authorities. There is a risk that local tax authorities in the relevant

jurisdictions will not agree with the positions taken by the Company, which may lead to an increased tax cost

for the Group.

In addition, the manner in which the operations and the ownership of the different legal entities in the Group

are structured may have tax implications for the Company and its shareholders. The tax treatment of the

Group entities is further subject to changes in, and any new interpretations of, tax legislation in the relevant

jurisdictions. The amount of tax the Group pays could increase substantially as a result of changes in or new

interpretations of tax legislation, which could have a material adverse effect on the Group's business, results of


If the Group is successful in finding large commercially recoverable volumes of oil and gas in one of its

exploration assets, there is a risk that the host government in question may decide to increase the royalty

payable to it or change material PSC/PSA terms, which could have a material adverse effect on the Group's


20

The uncertainty of the tax system in Kurdistan may adversely affect taxation of the Group, reducing

net returns to the Company's shareholders

Taxation of the Group's operations in Kurdistan is currently governed by regional law and the terms of the

Group's PSCs. However, there is uncertainty related to the tax laws of Kurdistan and no well-established tax

regime is in place in Kurdistan. In the event that the terms of the Group's PSCs cease to be recognised as valid

or are otherwise unenforceable in Kurdistan or Iraq generally, or the legislation currently governing taxation of

the Group's operations is overridden or adversely affected by enactment of any future laws or regulations, there

could be a material adverse effect on the Group's business, results of operations, financial condition or

prospects.

The Norwegian petroleum tax refund scheme is facing legal challenges

Under current Norwegian tax rules, companies which are not in a taxable position may annually claim a refund

from the Norwegian state of the tax value of direct and indirect costs, except the financial cost, incurred in

connection with the exploration for petroleum resources on the NCS. The tax value is set to the total of

relevant direct and indirect exploration costs multiplied by the tax rate, currently at 78 percent. The refund

will reduce the tax loss to be carried forward correspondingly. The amount of exploration costs may not exceed

the annual net loss from the petroleum activities of the taxpayer, to ensure that the costs are not already set off

against taxable income. A future exploration refund claim may be used as security for financing purposes. In

addition to the exploration refund, E&P companies with petroleum activities on the NCS may also obtain a

refund of the tax value of remaining carry forward losses upon cessation of its petroleum activities on the NCS.

This refund requires that the company has ceased all of its petroleum activities on the NCS, either voluntarily

or through a bankruptcy.

These tax refund schemes have attracted criticism from certain political parties in Norway, and have been

subject to scrutiny by, inter alia, environmentalist organisations. The Bellona Foundation, a Norwegian

environmentalist non-profit organisation has filed a complaint to the ESA, claiming that the mentioned

exploration costs refund scheme is in violation of the prohibition against state aid and subsidies, ref. article 61

of the European Economic Area (“EEA”) treaty. ESA has recently requested information from Norwegian

authorities following the complaint, and the case now also addresses the cessation refund scheme. The

Norwegian government has vigorously defended the refund schemes but should the whole or part of the

refund schemes be found to violate the EEA treaty, this may lead to a claim for repayment of all or parts of

received refunds as well as preventing any future refunds. Both these scenarios could have a material adverse

effect on the Group’s cash position and in turn the Group's business, results of operations, financial condition

or prospects.

1.6 Risks related to the Shares

The price of the Shares may fluctuate significantly

The trading price of the Shares could fluctuate significantly in response to a number of factors beyond the

control of the Company, including quarterly variations in operating results, adverse business developments,

changes in financial estimates and investment recommendations or ratings by securities analysts,

announcements by competitors of new product and service offerings, significant contracts, acquisitions or

strategic relationships, publicity about their products and services or their competitors, lawsuits, unforeseen

liabilities, changes to the regulatory environment or general market conditions.

The Company’s ability to distribute dividends is subject to financial capacity and absence or fulfilment of

restrictions under loan agreements and other restrictions.

The market value of the Shares may fluctuate significantly and may not reflect the underlying asset

value of the Company

The market value of the Shares can fluctuate significantly and may not always reflect the underlying asset value

of the Company. A number of factors outside the control of the Company may have an impact on its

21

performance and the price of the Shares. Such factors include but are not limited to a change in market

sentiment regarding the Shares and the Company, the operating and share price performance of other

companies in the industry and markets in which the Group operates, speculation about the Group's business in

the press, media or investment community, changes to the Company's profit estimates, the publication of

research reports by analysts and general market conditions. If any of these factors actually occurs, this could

have a material adverse effect on the pricing of the Shares.

Future issuances of Shares or other securities may dilute the holdings of shareholders and could

materially affect the Share price

It is possible that the Company may in the future decide to offer Shares or other securities in order to finance

new projects, in connection with unanticipated liabilities or expenses or for any other purposes. Any such

offering could reduce the proportionate ownership and voting interests of holders of Shares, as well as the

earnings per Share and the net asset value per Share, and any offering could have a material adverse effect on

the market price of the Shares.

Investors may not be able to exercise their voting rights for Shares registered in a nominee account

Beneficial owners of Shares that are registered in a nominee account (such as through brokers, dealers or other

third parties) may not be able to vote for such Shares unless their ownership is (a) re-registered in their names

with the VPS, prior to the Company’s general meetings or (b) the registered nominee holder grants a proxy to

such beneficial owner in the manner provided in the Articles of Association in force at that time and pursuant

to the contractual relationship, if any, between the nominee and the beneficial owner, to vote for such Shares.

The Company cannot guarantee that beneficial owners of the Shares will receive the notice of a general

meeting of shareholders of the Company in time to instruct their nominees to either effect a re-registration of

their Shares or otherwise vote for their Shares in the manner desired by such beneficial owners. Any persons

that hold their Shares through a nominee arrangement should consult the nominee to ensure that any Shares

beneficially held are voted for in the manner desired by such beneficial owner.

The transfer of the Shares is subject to restrictions under the securities laws of the US and other

jurisdictions

The Shares have not been registered under the US Securities Act or any US state securities laws or any other

jurisdiction outside of Norway and are not expected to be registered in the future. As such, the Shares may not

be offered or sold except pursuant to an exemption from the registration requirements of the US Securities Act

and applicable securities laws. In addition, there can be no assurances that shareholders residing or domiciled

in the US will be able to participate in future capital increases or rights offerings.

Shareholders outside of Norway are subject to exchange rate risk

The Company’s Shares are priced in NOK, and any future payments of dividends on the Shares may be

denominated in NOK. Accordingly, any investor outside Norway may be subject to adverse movements in the

NOK against their local currency, as the foreign currency equivalent of any dividends paid on the shares or

price received in connection with any sale of the shares could be materially adversely affected.

Norwegian law could limit shareholders’ ability to bring an action against the Company

The rights of holders of the Shares are governed by Norwegian law and by the Articles of Association. These

rights may differ from the rights of shareholders in other jurisdictions. In particular, Norwegian law limits the

circumstances under which shareholders of Norwegian companies may bring derivative actions. For example,

under Norwegian law, any action brought by the Company in respect of wrongful acts committed against the

Company will be prioritised over actions brought by shareholders claiming compensation in respect of such

acts. In addition, it could be difficult to prevail in a claim against the Company under, or to enforce liabilities

predicated upon, securities laws in other jurisdictions.

22

Pre-emptive rights to subscribe for Shares in additional issuances may be unavailable to shareholders

Under Norwegian law, unless otherwise resolved at the Company’s general meeting of shareholders, existing

shareholders have pre-emptive rights to participate on the basis of their existing ownership of Shares in the

issuance of any new Shares for cash consideration. Shareholders in the US, however, may be unable to exercise

any such rights to subscribe for new Shares unless a registration statement under the US Securities Act is in

effect in respect of such rights and Shares or an exemption from the registration requirements under the US

Securities Act is available. Shareholders in other jurisdictions outside of Norway may be similarly affected if the

rights and the new Shares being offered have not been registered with, or approved by, the relevant authorities

in such jurisdiction. The Company is under no obligation to file a registration statement under the US

Securities Act or seek similar approvals under the laws of any other jurisdiction outside of Norway in respect of

any such rights and Shares and doing so in the future may be impractical and costly. To the extent that the

Company’s shareholders are not able to exercise their rights to subscribe for new Shares, their proportional

interests in the Company will be diluted.

23

2. RESPONSIBILITY STATEMENT

The Board of Directors of the Company accepts responsibility for the information contained in this

Information Memorandum. The members of the Board of Directors confirm that, having taken all reasonable

care to ensure that such is the case, the information contained in this Information Memorandum is, to the best

of their knowledge, in accordance with the facts and contains no omissions likely to affect its importance.

Oslo, 22 February 2019

The Board of Directors of DNO ASA

Bijan Mossavar-Rahmani Executive Chairman

Lars Arne Takla Deputy Chairman

Elin Karfjell Director

Gunnar Hirsti Director

Shelley Watson Director

24

3. PRESENTATION OF DNO PRIOR TO THE FAROE ACQUISITION

3.1 Introduction

The Company is a Norwegian public limited liability company (“allmennaksjeselskap”) organised and existing

under the laws of Norway pursuant to the Norwegian Public Limited Companies Act. The Company was

incorporated on 6 August 1971 and its registration number in the Norwegian Register of Business Enterprises is

921 526 121. The Shares in the Company have been listed on the Oslo Stock Exchange since 1981, currently

under the ticker "DNO". The Company's registered office is located at Dokkveien 1, 0250 Oslo, Norway, its

telephone number is +47 23 23 84 80 and its fax number is +47 23 23 84 81.

DNO ranks among the largest independent Norwegian oil and gas producers and is one of the largest listed

independent E&P companies in Europe.

The organisation is based in five office locations, namely Oslo and Stavanger (Norway), Dubai (UAE), Erbil

(Iraq) and Sana'a (Yemen). Following the Transaction, the Group is also located in Aberdeen, London and

Great Yarmouth (UK).

For information about Faroe and its subsidiaries, please refer to Section 6 “Presentation of Faroe” below.

3.2 Legal structure

The Company is a holding company and the operations of DNO are carried out through the operating

subsidiaries of the Company.

The following chart sets out the Company’s legal group structure as of the date of this Information

Memorandum (excluding Faroe and its subsidiaries):

As a holding company, the Company is dependent upon the performance of its subsidiaries. The following

table sets out information about the entities in DNO (prior to the Faroe acquisition):

Company

Country of

incorporation Field of activity

Holding

(percent)

DNO Iraq AS Norway Oil and gas extraction and related services 100

DNO Yemen AS Norway Oil and gas extraction and related services 100

DNO Somaliland AS Norway Oil and gas extraction and related services 100

DNO Oman AS Norway Dormant 100

DNO Exploration UK Limited UK Oil and gas extraction and related services 100

DNO Norge AS Norway Oil and gas extraction and related services 100

Northstar Exploration Holding AS Norway Dormant 100

DNO UK Limited UK Oil and gas extraction and related services 100

DNO MENA AS Norway Management of oil and gas extraction and related services 100

25

DNO Tunisia Limited Guernsey Dormant 100

DNO Technical Services Limited Guernsey Dormant 100

DNO Al Khaleej Limited Guernsey Dormant 100

DNO Oman Limited Bermuda Oil and gas extraction and related services 100

DNO Oman Block 8 Limited Guernsey Oil and gas extraction and related services 100

DNO Oman Block 30 Limited Guernsey Dormant 100

DNO Invest AS Norway Dormant 100

DNO Technical Services AS Norway Management of oil and gas extraction and related services 100

3.3 Share capital

The Company's share capital is NOK 270,953,540.25 divided into 1,083,814,161 Shares, each with a nominal value

of NOK 0.25. All the Shares have been created under the Norwegian Public Limited Companies Act and are

validly issued and fully paid. The Company has one class of Shares.

The following table sets out a history of the Company's Shares since 1 January 2015:

Date of resolution

Type of change

Change in number of

shares

New number of

shares

New share capital (NOK)

10 March 2015 Private Placement 60,534,906 1,083,814,161 270,953,540.25

3.4 Major shareholders

As of 4 February 2019, the Company had 15,987 shareholders. The Company's twenty largest shareholders as of

the same date are shown in the table below:

# Shareholders Number of shares Percent

1 RAK PETROLEUM HOLDINGS B.V. 438,379,418 40.45

2 DNO ASA 35,000,000 3.23

3 STATE STREET BANK AND TRUST COMP 15,795,257 1.46

4 EUROCLEAR BANK S.A./N.V. 13,175,901 1.22

5 JPMORGAN CHASE BANK, N.A., LONDON 12,686,126 1.17


7 VERDIPAPIRFONDET PARETO INVESTMENT 9,364,591 0.86


9 RBC INVESTOR SERVICES TRUST 7,681,952 0.71

10 BARCLAYS CAPITAL SEC. LTD FIRM 7,620,614 0.70



13 THE NORTHERN TRUST COMP, LONDON BR 6,672,572 0.62


15 NORDNET BANK AB 5,740,783 0.53

16 KLP AKSJENORGE INDEKS 5,663,303 0.52

17 FIRST GENERATOR 5,475,000 0.51

18 CLEARSTREAM BANKING S.A. 5,316,046 0.49

19 J.P. MORGAN BANK LUXEMBOURG S.A. 5,100,000 0.47

20 JPMORGAN CHASE BANK, N.A., LONDON 5,052,841 0.47 TOP 20 TOTAL

OTHER

618,848,340

464,965,821

57.10

42.90

TOTAL 1,083,814,161 100.0

RAK Petroleum Holdings B.V. holds more than one-third of the Shares and is the largest shareholder.

Other than RAK Petroleum Holdings B.V., the Company is not aware of any shareholder holding Shares or rights

which is notifiable under Norwegian law (the lowest notifiable threshold being five percent).

26

3.5 Articles of Association

The objective of the company is to carry out operations within petroleum, shipping, offshore, transport, trade,

industry and finance, as well as any other activities related thereto, and to participate as a shareholder or in

other ways in other companies. The Company's objectives can be found in section 3 of the Company's Articles

of Association.

27

4. BUSINESS OF DNO

This Section provides information on the business and assets of the Company and its subsidiaries. Except where

otherwise stated, it does not include the business or assets of Faroe which are further described separately in

Section 6 "Presentation of Faroe".

4.1 Overview

DNO is a Norwegian oil and gas operator focused on the Middle East and the North Sea. Founded in 1971 and

listed on the Oslo Stock Exchange, DNO holds stakes in onshore and offshore licenses at various stages of

exploration, development and production in Kurdistan, Norway, the UK and Yemen.

4.2 DNO's assets

4.2.1 Overview of DNO's assets

DNO holds interests in three licenses in Kurdistan, all of which are PSCs. The Tawke PSC contains the

producing Tawke and Peshkabir fields. The Erbil PSC contains the Benenan and Bastora fields. The Baeshiqa

PSC contains two large structures with multiple independent stacked target reservoirs, including in the

Cretaceous, Jurassic and Triassic.

DNO currently holds 39 offshore exploration licenses in Norway, including the 18 licenses it was awarded

under Norway’s Awards in Predefined Areas (“APA”) 2018 licensing round. DNO also holds one offshore

exploration license in the UK and one license in Yemen at Block 47, where operations are suspended.

As is customary in the oil and gas E&P industry, most of DNO's assets are held in partnership with other

companies. Below is an overview of DNO's licenses, which are held through several wholly owned subsidiary

companies (licenses held by Faroe are described separately in Section 6 "Presentation of Faroe"):

Region/license Participating interest (percent) Paying interest (percent)1 Operator Status2

Kurdistan

Baeshiqa PSC 32.0 40.0 DNO E

Erbil PSC 40.0 60.0 DNO A/D/P

Tawke PSC 75.0 75.0 DNO A/D/P

Norway

PL248 F 20.0 20.0 Wintershall Norge E

PL248 GS 20.0 20.0 Wintershall Norge E

PL248 HS 20.0 20.0 Wintershall Norge E

PL293 B 20.0 20.0 Equinor Energy AS E

PL767 10.0 10.0 Lundin Norway AS E

PL825 10.0 10.0 Faroe Petroleum E

PL827 S 30.0 30.0 Equinor Energy AS E

PL859 20.0 20.0 Equinor Energy AS E

PL889 20.0 20.0 Neptune Energy E



PL922 20.0 20.0 Spirit Energy Norge E




PL929 10.0 10.0 Neptune Energy E

PL931 40.0 40.0 Wellesley Petroleum E



PL951 20.0 20.0 Aker BP ASA E

PL953 30.0 30.0 Wintershall Norge E

UK

P2074 25.0 25.0 Chrysaor CNS Limited E

28

Yemen

Block 47 64.0 80.0 DNO E/D/S

1. Under the terms of some of its PSCs and PSAs, DNO carries the costs of the interest held by a participating government entity, resulting in a DNO paying interest that is larger than the DNO participating interest.

2. A = Appraisal, E = Exploration, D = Development, P = Production, R = Under Relinquishment, S = Operations Suspended.

DNO's licenses in the Middle East are structured as PSAs or PSCs, which govern the manner in which costs and

revenues from oil and gas production are shared between the host government and the license holders. Under

a PSA or PSC, E&P activities are carried out by the license holders. Typically, all risks and costs of E&P in these

licenses are carried by DNO and its joint venture partners. If exploration is successful, DNO recovers its share

of investments and operating costs from the so-called “cost oil", a percentage of oil and gas produced and sold

after the government has deducted a royalty. Additionally, DNO is entitled to receive "profit oil" which is a

share of the remaining production, if any, after payment of royalty and deduction of cost oil. This profit oil is

shared among the license holders and the government under terms set out in each PSA or PSC.

4.2.2 Reserves and resources data

The reserves and resources data contained in this Information Memorandum, as related to DNO, are derived

from DNO's ASRR for the year ended 31 December 2018 (incorporated hereto by reference, see Section 12

"Incorporation by Reference – Documents on Display"). The ASRR is prepared based on the PRMS jointly

published by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of

Petroleum Geologists and the Society of Petroleum Evaluation Engineers. The system is a recognised resource

classification system in accordance with the listing and disclosure requirements for oil and gas companies on

the Oslo Stock Exchange, cf. section 3.7 of the Continuing Obligations.

The system uses "reserves", "contingent resources" and "prospective resources" to classify oil and gas resources

of varying technical maturity. The maturity within each class is also described to help guide classification of a

given asset.

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of

development projects to known accumulations from a given date forward under defined conditions. Reserves

must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on

the development project(s) applied.

Reserves are further categorised in accordance with the level of certainty associated with the estimates:

i. "Proven reserves (“1P”)" are those quantities of petroleum which, by analysis of geoscience and

engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a

given date forward, from known reservoirs and under defined economic conditions, operating methods,

and government regulations. If deterministic methods are used, the term reasonable certainty is

intended to express a high degree of confidence that the quantities will be recovered. If probabilistic

methods are used, there should be at least a 90 percent probability that the quantities actually

recovered will equal or exceed the estimate.

ii. "Unproven reserves" are based on geoscience and engineering data similar to that used in estimates of

proven reserves, but technical and other uncertainties preclude such reserves being classified as

proven. Unproven reserves may be further categorised as probable reserves and possible reserves:

(a) "Probable reserves" are those additional reserves which analysis of geoscience and

engineering data indicate are less likely to be recovered than proven reserves but more

certain to be recovered than possible reserves. It is equally likely that actual remaining

quantities recovered will be greater than or less than the sum of the estimated proven plus

probable reserves ("2P"). In this context, when probabilistic methods are used, there should

29

be at least a 50 percent probability that the quantities actually recovered will equal or exceed

the 2P estimate. 2P reserves include but are not limited to 1P reserves.

(b) "Possible reserves" are those additional reserves which analysis of geoscience and

engineering data suggests are less likely to be recoverable than probable reserves. The total

quantities ultimately recovered from the project have a low probability to exceed the sum of

proven plus probable plus possible reserves ("3P"), which is equivalent to the high estimate

scenario. In this context, when probabilistic methods are used, there should be at least a 10

percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

3P reserves include but are not limited to 2P reserves.

This Information Memorandum also includes descriptions of contingent and prospective resources. Special

uncertainties exist with respect to the estimation of contingent and prospective resources in addition to those

set forth above that apply to reserves.

Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be

potentially recoverable from known accumulations by application of development projects, but which are not

currently considered to be economically recoverable due to one or more contingencies. In the PRMS, the

uncertainty of the contingent resources is classified into categories 1C, 2C and 3C in a classification scheme

corresponding to the scheme used for reserves (1P, 2P and 3P).

Prospective resources are defined as those quantities of petroleum that are estimated, as of a given date, to be

potentially recoverable from undiscovered accumulations by application of future exploration and

development projects.

This Information Memorandum describes reserves on a gross CWI and NE basis:

(i) CWI reserves are the product of gross reserves and the company working interest held by DNO in a

specific field, which is based on DNO's contractual working interest in a particular license and is

DNO's share of operating expenses and capital costs, including any carried interest, reduced by any

royalty burden; and

(ii) NE reserves comprise DNO's entitlement to cost oil and profit oil. NE reserves reflect DNO's

additional share of cost oil covering its advances towards the government carried interest (if any). NE

reserves also include any notional tax paid by the government on behalf of DNO.

4.2.3 DNO's reserves and resources

At yearend 2018, DNO’s CWI 1P reserves stood at 239.7 million barrels of oil (MMbbls), unchanged from 239.8

MMbbls at yearend 2017, after adjusting for production during the year and technical revisions. On a 2P basis,

DNO’s CWI reserves stood at 376.1 MMbbls, down 8.0 MMbbls from 384.1 MMbbls at yearend 2017. On a 3P

basis, DNO’s CWI reserves were 538.9 MMbbls, compared to 665.7 MMbbls at yearend 2017. DNO’s CWI 2C

resources were 76.8 million barrels of oil equivalent (MMboe), compared to 98.9 MMboe at yearend 2017.

DNO’s CWI production in 2018 was 29.9 MMboe (of which 29.1 MMbbls in Kurdistan and the balance in

Oman), up from 26.9 MMboe in 2017 (of which 26.1 MMbbls in Kurdistan and the balance in Oman).

DNO's CWI yearend 2018 Reserve Life Index (“R/P”) stood at 8.2 years on a 1P reserves basis, 12.9 years on a 2P

reserves basis and 18.5 years on a 3P reserves basis.

Reported reserves fall within class 1-3 of the NPD classification and 2C resources fall within class 4-7 of the

NPD classification.

30

The following table shows a summary of remaining 1P, 2P and 3P reserves per field on a gross, CWI and NE

basis at yearend 2018, derived from DNO’s ASRR for the year ended 31 December 2018, which is prepared based

on the PRMS reporting standards.

Remaining reserves at yearend 2018 (Gross, CWI and NE):

CWI and 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). CWI reserves reflect pre-tax shares while NE

reserves reflect post-tax shares. NE reserves are based on economic evaluation of the license agreements,

incorporating projections of future production, costs and oil prices. NE reserves may therefore fluctuate over

time, even if there are no changes in the underlying gross and CWI volumes.

Following the RSA, DNO’s interest in the Tawke license increased to 75 percent plus, until 31 July 2022, DNO is

paid three percent of aggregate license revenues. CWI and NE reserves in the table above include the reserves

attributable to DNO from this settlement agreement.

The 2018 ASRR is available on DNO's website at www.dno.no.

4.3 DNO's operations

The table below summarises DNO's oil and gas production on a daily gross production and CWI basis for each

of the regions in which it has producing assets for the years ended 31 December 2018, 2017 and 2016.

2018 2017 2016

Gross production (boepd)

Kurdistan 113,149 109,047 107,299

Oman 4,458 4,484 5,325

Total 117,607 113,530 112,624

Company working interest (CWI) production (boepd)

Kurdistan 79,747 71,436 66,525

Oman 1,965 2,243 2,663

Total 81,712 73,679 69,188

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4.3.1 Kurdistan

4.3.1.1 Description of Assets

DNO’s operations in Kurdistan are regulated by the Tawke, Erbil and Baeshiqa PSCs, which were entered into

with the KRG through its subsidiary DNO Iraq AS, which is the operator of each of the PSCs.

DNO’s participating and paying interest in the Tawke PSC is 75 percent. DNO is the operator of the Tawke PSC

and its partner is Genel, which holds a 25 percent participating and paying interest. The Tawke PSC 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 PSC will be

commercial for the duration of its contractual term and through subsequent extensions.

DNO’s participating interest in the Erbil PSC is 40 percent and its paying interest is 60 percent as it carries the

costs of the 20 percent interest held by the KRG. DNO is the operator of the Erbil PSC and its partners are Gas

Plus Erbil, which holds a 40 percent participating and paying interest, and the KRG, which holds a 20 percent

participating interest. The Erbil PSC expires in 2031, but DNO has the right to one automatic five-year

extension (i.e., to 2036) and, if commercial production is still possible at the end of this extended period, DNO

is entitled, upon request to the KRG, to a further five-year extension (i.e., to 2041).

DNO acquired a 32 percent participating (40 percent paying) interest and operatorship of the Baeshiqa license

in 2017. Partners include ExxonMobil with a 32 percent participating (40 percent paying) interest, Turkish

Energy Company with a 16 percent participating (20 percent paying) interest and the KRG with a 20 percent

carried interest. The Baeshiqa PSC is currently in the first sub-period of the exploration period. This first sub-

period expires on 19 December 2019, but DNO has the right to a one-year extension on certain conditions. If a

commercial discovery is declared at any time during the exploration period, the exploration period will

terminate and the PSC will on certain conditions enter into the development period, which is 20 years. If

commercial production is still possible at the end of the 20-year period, DNO is entitled to a five-year

extension.

Under each of the PSCs, DNO and its partners must perform certain minimum work obligations during the

applicable exploration periods. DNO, as operator under each PSC, has performed all of the minimum work

obligations mandated by the Tawke and Erbil PSCs. Separately, under the Baeshiqa PSC, DNO has an

obligation to drill two wells during the exploration phase of the contract period.

The PSCs operate on a cost oil/profit oil basis. After payment of the royalty, DNO and its partners can recover

their costs, with cost oil entitlements capped at a certain percentage of production in a given calendar year.

Unrecovered costs can be carried forward until complete cost recovery is achieved. If all costs are not

recovered by the end of the PSC’s term, then (with the exception of decommissioning costs) such costs cannot

be cost recovered from another PSC.

Following deductions for cost recovery, the percentage of profit oil allocated to DNO and its partners, on the

one hand, and to the KRG, on the other hand, varies according to a sliding scale determined by reference to

cumulative revenue and cumulative costs under each PSC, such that the profit oil percentage to which DNO

and its partners are entitled decreases as cumulative revenue increases relative to cumulative costs. DNO’s

profits are also subject to income tax, which is paid by the KRG on behalf of each license partner out of the

government’s share of profit oil.

PSC Cost oil entitlement cap (percent) Profit oil entitlement cap (percent)

Tawke 45 16-38

Erbil 43 16-32

Baeshiqa 43 16-32

32

4.3.1.2 Tawke

Gross output at the Tawke PSC, containing both the Tawke and Peshkabir fields, averaged 113,041 bopd during

2018.

DNO ramped up production from the Peshkabir field to more than 50,000 bopd less than 18 months after

commencement of operations, beating its end-2018 target ahead of schedule and below budget. January 2019

Peshkabir production from six wells averaged 54,000 bopd. DNO’s 2019 field drilling campaign at Peshkabir

consists of up to four wells.

At the Tawke field, three wells were completed in the fourth quarter of 2018. January 2019 Tawke production

averaged around 74,000 bopd. DNO has an active 2019 Tawke drilling program of up to 14 wells in the

Cretaceous and Jeribe to stabilise production and add reserves through exploration, including a deep Tawke

well.

Cumulative Tawke field production since inception stood at 255 million barrels at yearend 2018, with

cumulative Peshkabir field production at more than 11 million barrels at yearend 2018.

4.3.1.3 Erbil

The Erbil PSC contains both the Benenan and Bastora fields. Testing is ongoing at the Hawler-1A well at the

Benenan heavy oil field. Estimates of oil-in-place at Benenan stand at more than two billion barrels.

4.3.1.4 Baeshiqa

The Baeshiqa PSC contains two large structures with multiple independent stacked target reservoirs, including

in the Cretaceous, Jurassic and Triassic. In October 2018, DNO spud the Baeshiqa-1 exploration well to test the

Cretaceous at the Baeshiqa structure. The well was drilled to a depth of 1,488 meters and well testing has been

delayed by extensive rainfall but is expected to commence this month. A second Baeshiqa well targeting the

deeper Jurassic and Triassic on the same structure spuds during the first quarter of 2019 and a third well also

targeting the Jurassic and Triassic, but on a separate structure, will spud later this year.

4.3.1.5 Sales

The oil that DNO produces from the Tawke license is delivered to the DNO-operated Fish Khabur export

facility where it is then exported by the KRG by pipeline through Turkey and on to international markets. Up

until the end of the third quarter of 2018, revenues from Kurdistan were recognised upon receipt of cash

payment. Following an assessment of facts and circumstances, effective 1 October 2018, DNO recognises

revenue in Kurdistan in line with invoiced oil sales following monthly deliveries to KRG and not upon cash

receipt. The funds are shared by DNO and partner Genel Energy plc (“Genel”) pro-rata to the companies’

interests in the license. Monthly export payments reflect the revenue derived from Tawke production on a

netback basis, adjusted for crude quality differentials to Dated Brent in addition to deductions for pipeline

transit fees.

4.3.2 Yemen

DNO’s operations in Yemen are regulated by the Block 47 PSA which was entered into between DNO’s

subsidiary DNO Yemen AS with the Ministry of Oil and Mineral Resources on 16 July 1998 and in which DNO

acts as the operator. Activity at Block 47 is currently suspended.

4.3.3 Norway and the UK

In 2017, DNO re-entered the North Sea by acquiring Origo, with its experienced exploration team and an

existing portfolio of offshore exploration licenses in Norway and the UK. Origo was subsequently renamed

DNO Norge AS (“DNO Norge”) and the portfolio has since expanded.

33

On 15 January 2019, the Company announced that DNO Norge was awarded participation in 18 exploration

licenses on the NCS, of which five are operatorships, under Norway’s 2018 APA licensing round. Prior to the

announcement, DNO held interests in 22 licenses offshore Norway and the UK, of which 21 are on the NCS and

one on the UKCS. The awarded licenses are set out in the table below:

License Participating interest (percent) Paying interest (percent) Operator

PL 767 B 10.0 10.0 Lundin Norway AS

PL 902 B 10.0 10.0 Lundin Norway AS

PL 967 60.0 60.0 DNO Norge AS



PL 986 20.0 20.0 Aker BP ASA

PL 987 20.0 20.0 Suncor Energy Norge AS

PL 988 30.0 30.0 Lundin Norge AS

PL 990 30.0 30.0 Equinor Energy AS


PL 994 30.0 30.0 Neptune Energy Norge AS


PL 1015 30.0 30.0 INEOS E&P Norge AS

PL 1021 50.0 50.0 DEA Norge AS

PL 1022 30.0 30.0 Aker BP ASA

PL 1024 30.0 30.0 Repsol Norge AS

PL 1027 20.0 20.0 Lundin Norway AS

PL 1029 40.0 40.0 Lundin Norway AS

4.3.3.1 Regulatory framework in Norway

Norway has adopted detailed legislation on petroleum activities through the NPA and regulations issued

thereunder. The NPA establishes that the Norwegian State has the proprietary right to subsea petroleum

deposits on the NCS and that companies are required to obtain licenses to have the right to engage in

petroleum activities. Further consents and approvals from the competent authorities are required for key steps

in all phases of the petroleum activities.

4.3.3.2 Production licenses on the NCS

A production license grants exclusive rights to exploration for and production of oil and gas in the area covered

by the license. It also sets out more detailed conditions for activities in a particular area.

Licensees become the owners of a share of the oil and gas produced proportional to their participating interest

shares in the license.

Production licenses are awarded either through the ordinary license rounds which usually take place every

other year or through Norway’s APA licensing rounds, which take place annually.

Participating interest shares in production licenses can also be obtained through direct purchase or indirectly

by purchasing shares in companies that hold licenses. Any such purchases are subject to the approval of the

MPE and the MOF.

4.3.3.3 Main terms of the production licenses on the NCS

The terms of NCS production licenses are to a large degree standardised. Key terms are established in both the

NPA and regulations issued under the NPA. Norwegian authorities also use standardised license documents

and require the use of a standard joint operating agreement. The fiscal terms are also set out in legislation. The

rules set out in the NPA and regulations issued thereunder are comprehensive and detailed. The authorities,

34

notably the MPE, the NPD and the Petroleum Safety Authority are given wide discretionary powers under the

NPA and the regulations thereunder.

As for the production licenses, the two main license terms require completion of specified work obligations

and the entry into an “Agreement Concerning Petroleum Activities,” which includes a standardised JOA and

Accounting Agreement.

The work obligation typically involves collecting and processing seismic data and/or drilling of exploration

wells. The content of the work obligation may vary from license round to license round, as between ordinary

license rounds and the APA rounds and from license to license. Each individual production license will

stipulate a specific deadline for completion of each of the various elements of the work obligation. The

deadline must be completed for each element. When the licensees have completed the entirety of the work

obligation, it may request that the initial period of the production license be extended. The general rule is that

the production license is extended for 30 years, but in certain circumstances the extension may stretch up to 50

years. The MPE also has the power to require that the work obligations are fulfilled prior to any surrender of

the production license.

The JOA governs all matters pertaining to the joint venture and is the fundamental legal basis for the licensees’

obligations toward one another. An operator is responsible for the daily operations of each joint venture and

conducts its role on a “no gain, no loss” basis, meaning that the operator neither receives compensation nor

assumes liability for the activities of the joint venture.

The joint venture participants are primarily liable to each other on a pro rata basis, meaning that each is

secondarily, jointly, and severally liable for all obligations arising out of the joint venture’s activities. The

participants are also obligated to contribute sufficient funds to cover all expenses relating to the joint venture’s

activities in accordance with their respective participating interest. If a participant defaults on its obligation to

provide sufficient funds to the joint venture or to cover its liabilities, non-defaulting participants are obligated

to advance the deficient amounts. Strict default rules apply for a defaulting party.

4.3.3.4 The exploration phase

Once awarded, a production license is valid for an initial period of up to ten years, which is reserved for

exploration activities. To ensure that the area to which the production license applies is explored properly, the

licensee group is obliged under the terms of the license to carry out a work programme, as mentioned above. If

all the licensees agree, they may relinquish the production license once they have completed the work

obligations.

4.3.3.5 The development and operation phase

If the licensees make a discovery and wish to continue work under the license after they have fulfilled their

work obligations, they are entitled to an extension period for the license. The duration of the extension period

is determined by the MPE when the license is awarded, and in most cases is 30 years. Field development and

operations take place during the extension period. If the licensees wish to develop a field, they are obliged to

do this in a responsible way. The companies are responsible for planning and implementing development

projects, but each project requires prior approval from the MPE.

The licensees must submit a PDO of a new deposit to the MPE as a basis for approval. If the project includes

pipelines or onshore terminals, a separate PIO of these must also be submitted and approved. A PDO/PIO

consists of a development plan and an impact assessment. The latter provides an overview of the likely impacts

of the project on the environment, fisheries and society. The report on the impact assessment is sent to all

those who may be affected by the project so that they have an opportunity to put forward their views. The

process ensures that all relevant arguments for and against the project are known before a decision on

development is taken, that the field developments approved are responsible, and that their impacts on other

35

public interests are acceptable. In special cases, the MPE may exempt licensees from the requirement to

submit a PDO/PIO.

A license can be renewed when it expires. As long as the licensees fulfil their obligations, the authorities do not

normally revoke a license.

4.3.3.6 Production licenses on the UKCS

The Petroleum Act establishes the regulatory regime applying to oil and gas E&P in the UKCS. All rights to

petroleum vest in the Crown, but the OGA grants licenses through annual competitive licensing rounds. Any

bid for a license or the acquisition of an interest in an existing license is subject to OGA approval. There are

four types of licenses available: production licenses (offshore/onshore), innovative licenses and exploration

licenses.

Offshore production licenses run for three successive terms, each connected with a particular activity (i.e.,

exploration, appraisal and production) and a specific work program. The license will expire at the end of its

initial term unless the licensee has completed an agreed initial term work program and surrendered a fixed

amount of acreage (normally 50 percent). The license will expire at the end of the second term unless the OGA

has approved a development plan. The third term is intended for production. The licensee is not restricted

from starting production before the third term, provided the minimum work program is completed and the

OGA has approved a development plan.

Licenses impose an escalating annual rental fee over the acreage covered by the license to encourage licensees

to surrender fallow areas. Licensees are further required to pay an annual OGA levy. All licenses are governed

by Model Clauses, set out in secondary legislation under the Petroleum Act.

Where more than one company holds an interest in a license, their relationship is governed by a JOA which

follows the same main principles as in the NCS. Legally there is only ever a single licensee and all companies

on a license are jointly and severally liable for operations conducted under the license.

Decommissioning of offshore oil and gas installations and pipelines is regulated by BEIS through the

Petroleum Act. Decommissioning obligations arise when the OPRED issues a "Section 29 notice" on license

holders requiring the submission of a decommissioning program. The Section 29 holders are then obliged to

carry out the approved decommissioning plan on a joint and several basis; failure to comply is a criminal

offence. As the objective of the regime is to shield the UK taxpayers from decommissioning costs, the OPRED

may serve a Section 29 notice on a wider group of parties, not just the current licensees, including a parent or

affiliate of the licensee and any former licensees who held an interest in the license after the first Section 29

notice was issued by the OPRED. Section 29 holders are required to post security for the cost of

decommissioning, normally in the form of a letter of credit or facility agreement.

Under Section 34 of the Petroleum Act, the authorities also retain the right to require any company that has

previously been released from a Section 29 notice, or any company that could have been served with a Section

29 notice at any time after the first Section 29 notice was issued, to carry out a decommissioning program,

although this is seen as a remedy of last resort. In practice, decommissioning programs will be implemented by

the current licensees pursuant to the relevant JOA unless they were all to default, in which case the

responsibility would fall to the Section 29 holders and, should they all default, potentially to further entities

under Section 34 of the Petroleum Act.

It is also common UKCS industry practice, but not a legal requirement, for joint ventures to enter into field

decommissioning security agreements (“DSAs”) whereby the relevant licensees will be obliged to post security

for their individual shares of future decommissioning liability when the relevant field reaches a certain point in

its production life. Such security will usually take the form of a letter of credit, or, where a licensee’s parent

36

company has a sufficient credit rating, a parent company guarantee. Bi-lateral security arrangements may also

be entered into between a seller and a purchaser of field participating interests in order to protect the seller

against potential future decommissioning liability. Should a company fail to fulfil its decommissioning

obligations the relevant security can be called.

4.3.3.7 Summary of DNO's license portfolio on the UKCS

DNO currently holds one UKCS exploration license. See Section 4.2.1 above for further details.

4.4 Material transactions

In the last two fiscal years, other than in relation to the Transaction, DNO has entered into the following

material transactions outside the ordinary course of business:

On 4 May 2017, the Company announced the acquisition of Origo with an effective date of 31 March

2017. Through this acquisition, DNO obtained 11 exploration and appraisal licenses in the North Sea; 7

on the NCS and 4 on the UKCS.

On 24 August 2017, the Company announced that DNO had entered into the RSA with the KRG.

On 30 July 2018, the Company announced the sale of DNO Tunisia AS to Panoro Energy AS (“Panoro”)

and that subsequently the Company had subscribed to 2,641,465 shares in Panoro Energy ASA. As part

of the transaction, Panoro assumed all existing permit interests, rights and remaining work obligations

at the Sfax offshore exploration permit, Ras El Besh concession and Hammamet offshore exploration

permit. All DNO Tunisia employees were also transferred to Panoro.

4.5 Capital resources

4.5.1 Sources of liquidity

DNO’s principal sources of liquidity are operating cash flows from its producing assets. In addition to its

operating cash flows, the Company relies on the debt capital markets for both short- and long-term funding.

Currently, the Company has outstanding senior unsecured debt in the form of bonds totalling USD 600 million

and has available (i) a revolving exploration facility in an aggregate amount of NOK 1 billion (equivalent to

USD 115.1 million as of 31 December 2018) and (ii) a short-term bank credit facility in an aggregate amount of

USD 200 million.

The Company prepares projections on a regular basis in order to plan DNO’s liquidity requirements. These

plans are updated regularly for various scenarios and form part of the decision basis for the Company’s Board

of Directors and Management.

As of the date of this Information Memorandum, the Company is not, nor about to be, in breach of any of its

covenants under its borrowing arrangements.

4.5.2 DNO's borrowing arrangements

USD senior unsecured bond loans

The Company has two outstanding bond loans:

DNO01: On 19 June 2015, the Company completed the placement of USD 400 million of a five-year

senior unsecured bond loan with a fixed coupon rate of 8.75 percent and an issue price of 87.5 percent

of par value. The bond loan is listed on the Oslo Stock Exchange under ticker DNO01. Interest is paid

bi-annually.

37

DNO02: On 31 May 2018, the Company completed the placement of USD 400 million of a five-year

senior unsecured bond loan issued at 100 percent of par with a coupon rate of 8.75 percent. The bond

loan is listed on the Oslo Stock Exchange under ticker DNO02. In connection with this bond

placement, the Company rolled over USD 200 million in nominal value of DNO01 bond loans into

DNO02. The rolled over bonds were cancelled and USD 200 million of outstanding DNO01 bond loans

remain. The principal amount as of 31 December 2018 is USD 400 million and falls due on 31 May 2023.

Interest is paid on a quarterly basis.

The financial covenants of the bonds require a minimum of USD 40 million of liquidity, and that DNO

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.

Revolving exploration facility

Through DNO Norge, DNO has available a revolving exploration facility in an aggregate amount of NOK 1

billion (equivalent to USD 115.1 million as of 31 December 2018). Utilisation requests need to be delivered for

each proposed loan. The aggregate of the proposed loan shall not exceed 95 percent of the tax value of eligible

costs which have not already been refunded by the tax authorities. DNO shall repay each loan when the tax

refunds have been received. The interest rate equals three months NIBOR plus a 1.55 percent margin. The

facility is secured against the tax refund and is repaid when the refunds have been received which is

approximately eleven months after the end of the calendar year.

Short-term credit facility

In January 2019, the Company entered into a USD 200 million short-term bank credit facility to strengthen the

liquidity subsequent to the acquisition of Faroe.

4.5.3 Restrictions on the use of capital resources

Each of DNO’s financing facilities may be used for general corporate purposes with the exception of the

revolving exploration facility which can be used on expenses that give rise to tax refund in accordance with

Norwegian tax rules.

4.6 Recent developments and significant trends

On 7 February 2019, in connection with the publication of the 2018 interim results, DNO announced the

following:

2018 net profit of USD 354 million on revenues of USD 829 million, the highest annual revenues in

DNO's 47-year history. Cash flow from operations increased 40 percent to USD 472 million in 2018, of

which USD 334 million represented free cash flow.

Operated production averaged 117,600 barrels of boepd including 81,700 boepd on a CWI basis, up

from 113,500 boepd and 73,700 boepd, respectively, during 2017. January 2019 operated production

averaged 128,000 bopd or 90,000 bopd on a CWI basis.

Step up of its operational spend in 2018 to nearly USD 300 million to support the fast-track

development of the Peshkabir field in Kurdistan and the ongoing drilling program at the Tawke field

within the same license.

Spending levels in 2019 are projected to rise more than 40 percent from 2018 levels to an estimated

USD 420 million. DNO's 2019 drilling program includes up to 20 wells in Kurdistan, including up to 14

38

wells at the Tawke field, four at Peshkabir and two at the Baeshiqa license. Another five wells are

planned in Norway on DNO's licenses.

In Kurdistan, two recently completed wells, Peshkabir-9 and Tawke-52, will be placed on production

in February 2019. Testing of the first Baeshiqa exploration well targeting the Cretaceous reservoir had

been delayed by extensive rainfall but is also expected to commence this month.

The Company's Board of Directors have approved a dividend payment of NOK 0.20 per share to be

made on or about 27 March 2019 to all shareholders of record as of 18 March 2019. DNO shares will be

traded ex-dividend as of 15 March 2019.

Save for completion of the Transaction, there has not been any significant change in the financial or trading

position of DNO which has occurred since 31 December 2018.

4.7 Working capital statement

As of the date of this Information Memorandum, the Company is of the opinion that the working capital of

DNO is sufficient for its present requirements.

4.8 Legal and arbitration proceedings

As described in note 17 to DNO's Annual Report for 2017, the Ministry of Oil and Minerals of Yemen has filed

an arbitration claim against the partners on Block 53 for allegedly wrongful withdrawal from the PSC. DNO

Yemen AS is disputing the claim.

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 which may have, or

have had, significant effects on DNO’s financial position or profitability.

39

5. THE TRANSACTION

This Section provides information on the background and reasons for the Transaction as well as a discussion of

certain related arrangements and agreements entered into or to be entered into in conjunction with the

Transaction.

5.1 Overview and description of the Transaction

On 26 November 2018, the Company announced a cash offer by it (the "Offer") for the whole of the issued and

to be issued share capital of Faroe (other than the Faroe shares already held by the Company), to be made to

those Faroe shareholders who could validly receive and accept the Offer. The Offer was made at 152 pence in

cash for each share of Faroe (the "Offer Price"), valuing Faroe’s existing issued and to be issued share capital at

approximately £607.9 million. The Offer Price represented a premium of 44.8 percent to Faroe’s share price of

105 pence at the close of business on 3 April 2018, the last business day before the Company announced its first

acquisition of shares in Faroe, and a premium of 20.8 percent to Faroe’s share price of 125.8 pence at the close

of business on 23 November 2018, the last business day before the Offer was announced.

On 12 December 2018, the Company published an offer document (the "Initial Offer Document") containing

the full terms and conditions of the Offer. The Offer and the Initial Offer Document were made in accordance

with applicable take-over rules in the UK, as set out in the Code.

On 3 January 2019, the Company announced that it had acquired more than 30 percent of the Faroe shares and

as such, the Offer became mandatory pursuant to Rule 9 of the Code.

On 8 January 2019, the Company announced the terms of an increased and final cash offer for the entire issued

and to be issued share capital of Faroe at a price of 160 pence in cash for each Faroe share (the "Final Offer"), as

further set out in a final offer document (the "Final Offer Document") published the same day. The price in the

Final Offer valued Faroe’s existing issued and to be issued share capital at approximately £641.7 million.

On 9 January 2019, Faroe announced the Faroe board of director’s recommendation of the Final Offer.

On 14 January 2019, the Company announced that the Final Offer became unconditional in all respects on 11

January 2019. On 4 February 2019, the Company reported that it had settled valid acceptances of the Final Offer

in respect of a total of 128,595,577 Faroe shares representing approximately 32.48 percent of the issued share

capital of Faroe. Combined with shares already held as a result of market purchases, DNO held on that date

380,538,003 Faroe shares, representing 96.11 percent of Faroe’s issued share capital.

Further background for the Offer and transaction details are set out in the Initial Offer Document and the

Final Offer Document, which are incorporated hereto by reference and which together with other relevant

announcements and documents in connection with the Transaction can be obtained from the Company’s

website.

5.2 Compulsory acquisition

As a consequence of acquiring more than 90 percent of the Faroe shares to which the Offer applied, DNO

initiated a compulsory acquisition procedure to acquire the remaining Faroe shares under Chapter 3 of Part 28

of the Act, as contemplated by the Final Offer Document. This includes having despatched formal compulsory

acquisition notices under Sections 979 and 980 of the Act (the “Compulsory Acquisition Notices”) to Faroe

shareholders who had not accepted the Final Offer. On the expiry of six weeks from the date of the

Compulsory Acquisition Notices (expected to be on or about 20 March 2019) the Faroe shares held by those

Faroe shareholders who have not accepted the Final Offer will be acquired compulsorily by the Company on

the same terms as the Final Offer pursuant to the Act. The consideration to which those Faroe shareholders

will be entitled will be held by Faroe as trustee on behalf of those Faroe shareholders who have not accepted

40

the Final Offer and they will be requested to claim their consideration by writing to Faroe at the end of the six-

week period.

5.3 Delisting from AIM

As a consequence of the success of the Offer, cancellation of the admission to trading on AIM of the Faroe

shares took effect on 14 February 2019. Following the cancellation of the admission to trading of the Faroe

shares on AIM, Faroe will be re-registered as a private company under the relevant provisions of the Act.

5.4 Financing and financial effects of the Offer

The consideration payable by the Company under the terms of the Final Offer will be funded from its existing

cash resources.

For financial effects of the Offer, see Section 10 "Unaudited Pro Forma Financial Information (“UPFFI”)" below

for further details and UPFFI.

The Transaction has triggered certain change of control provisions in Faroe's financing agreements, including

Faroe's eight percent senior unsecured callable bond issue with maturity in 2023, giving bondholders a right of

pre-payment at a price of 101 percent of par value (plus accrued interest). The put option period expired on 16

February 2019.

5.5 Agreements with members of the Board of Directors and Management in connection with the

Transaction

The Company did not enter into any agreements or arrangements with its Board of Directors or Management

with respect to the Transaction, nor with any member of the board of directors or management of Faroe.

5.6 Regulatory matters

Pursuant to the NPA section 10-12, the Company has applied for and received consent from the MPE for the

Company’s indirect shareholding in Faroe's Norwegian subsidiary Faroe Petroleum Norge AS ("Faroe Norge").

Consistent with the conditions set out in the consent, DNO is preparing for consolidation of DNO's and

Faroe's Norwegian businesses, by combining the businesses of Faroe Norge and DNO Norge into one entity. In

the period prior to such consolidation, DNO Norge and Faroe Norge will fully align their voting in the

management committees where both companies are licensees.

In addition to the above, the Company has also provided relevant notifications to the relevant authorities in

the UK and Ireland. No notification is required for the Netherlands.

5.7 Advisors

Lambert Energy Advisory Ltd (authorised and regulated by the FCA in the UK) and Pareto Securities AS acted

as financial advisors to DNO in connection with the Transaction. Freshfields Bruckhaus Deringer LLP and

Advokatfirmaet Schjødt AS acted as legal advisors.

41

6. PRESENTATION OF FAROE

This Section provides an overview of the business of Faroe as of 31 December 2018. The following discussion

contains forward-looking statements that reflect plans and estimates; see "Cautionary Note Regarding Forward-

Looking Statements" on page 2. You should read this Section in conjunction with the other parts of this

Information Memorandum, in particular Section 1 "Risk Factors" and Section 7 "The Group Following the

Transaction".

6.1 Introduction

Faroe is an oil and gas company with a primary focus on exploration, appraisal and production. It is

incorporated in England and Wales with registration no. 04622251 and registered office at 30 Crown Place,

London, EC2A 4ES, UK.

Faroe was founded in 1997 and entered the UKCS in 2004 and the NCS in 2006. The company is headquartered

in Aberdeen, with offices in Stavanger, London and Great Yarmouth. Faroe has 115 employees across its four

locations.

Faroe has 67 licenses in total, of which 52 are in Norway, 12 are in the UK, one in Ireland and two in the

Netherlands. The 52 Norway licenses includes the eight licenses Faroe was awarded under Norway’s 2018 APA

licensing round, which require regulatory approval by Norwegian authorities.

Faroe has been listed on AIM under the ticker "FPM" since June 2003. Following and as a consequence of the

success of the Offer, the admission to trading on AIM was cancelled on 14 February 2019.

Faroe has two wholly owned direct subsidiaries, Faroe Petroleum (UK) Limited and Faroe Norge, and one

wholly owned indirect subsidiary, Faroe Petroleum (ROGB) Limited.

Faroe Petroleum (UK) Limited is an operating company incorporated in England and Wales, and the principal

owner of Faroe's UK oil and gas interests. Faroe Norge is an operating company incorporated in Norway, and

the principal owner of Faroe's Norwegian oil and gas interests. Faroe Petroleum (ROGB) Limited is

incorporated in England and Wales and holds Faroe's interests in the Schooner, Ketch and Enoch fields as well

as part of Faroe’s interest in the Blane field.

6.2 Board and management

On 28 January 2019, Faroe announced that Bjørn Dale (DNO ASA’s Managing Director) was appointed as

Chairman of the Faroe board of directors and Ørjan Gjerde (DNO Norge’s Managing Director) was appointed

as Non-Executive Director, both with immediate effect.

At the same time, Faroe announced that five of the prior members, namely John Bentley (Chairman), Graham

Stewart (CEO), Helge Hammer (COO), Jonathan Cooper (CFO) and Roger Witts, had resigned as directors of

the company. The remaining former Faroe members resigned as of Faroe’s delisting from AIM.

6.3 Business overview, licence portfolio, reserves and resources

Faroe's license portfolio consists of more than 60 exploration, appraisal, development and production licenses

in the West of Shetland, the North Sea, Norwegian Sea and the Celtic Sea located in Norway, the UK, Ireland

and the Netherlands.

As of 31 December 2017, Faroe’s daily production for 2017 averaged 14,349 boepd.

42

Faroe’s production base is spread across a portfolio of oil and gas assets in Norway and the UK. Approximately

76 percent of 2017 total production came from Norwegian fields and approximately 54 percent of total

production was oil. In Norway, the currently producing fields are Trym (PL147), Tambar (PL065/PL065

B/PL300), Ula (PL019/PL019 B), Brage (PL053 B/PL055/PL055 B/PL055 D/PL185) and Ringhorne East (PL169 E).

In the UK, the currently producing fields are Blane (P111), East Foinaven (P803), Enoch (PL048 D/P219) and

Orca (P454/P611).

Faroe's internal estimate of 2P reserves at 1 January 2018, prepared in accordance with the PRMS guidelines

endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of

Petroleum Geologists and Society of Petroleum Evaluation Engineers, has been estimated at 114.1 MMboe,

before adjusting for the disposal of a 17.5 percent interest in the Fenja field. Following this adjustment 2P

reserves were 97.7 MMboe.

At 1 January 2018, 2C resources were estimated to be 86.0 MMboe (before adjusting for the disposal of a 17.5

percent interest in the Fenja field). Additional 2C resources, mainly in Ula, Tambar and Oselvar, did not fully

compensate for the transfer of Brasse to 2P reserves at end-2017. Adjusting for the divestment of a 17.5 percent

interest in the Fenja field, 2C resources at 1 January 2018 were 78.6 MMboe.

As is customary in the oil and gas E&P industry, most of Faroe's assets are held in partnership with other

companies. Below is an overview of the licenses, which are held through several wholly owned subsidiary

companies:

Region/license Participating interest (percent) Paying interest (percent)1 Operator Status1

Norway

PL048D 9.3 9.3 Equinor Energy AS P


PL348 7.5 7.5 Equinor Energy AS D

PL348 B 20.0 20.0 Equinor Energy AS D

PL836 S 30.0 30.0 Wintershall Norge E


PL053 B 14.26 14.26 Wintershall Norge P

PL055 14.26 14.26 Wintershall Norge P

PL055 B 14.26 14.26 Wintershall Norge P

PL055 D 14.26 14.26 Wintershall Norge P

PL185 14.26 14.26 Wintershall Norge P

PL740 50.0 50.0 Faroe Petroleum D

PL740 B 50.0 50.0 Faroe Petroleum E

PL740 C 50.0 50.0 Faroe Petroleum E


PL586 7.5 7.5 Neptune Energy D

PL433 15.0 15.0 Spirit Energy Norge D

PL881 30.0 30.0 Wellesley Petroleum E

PL845 20.0 20.0 ConocoPhillips E


PL644 20.0 20.0 OMV Norge E

PL644 B 20.0 20.0 OMV Norge E


PL810 B 40.0 40.0 Faroe Petroleum E

PL107 7.5 7.5 Equinor Energy D

PL107 C 7.5 7.5 Equinor Energy D

PL132 7.5 7.5 Equinor Energy D

PL405 15.0 15.0 Spirit Energy Norge D

43

PL274 55.0 55.0 Faroe Petroleum S

PL 274 CS 55.0 55.0 Faroe Petroleum S



PL169 E 7.8 7.8 Vår Energi P



PL906 20.0 20.0 Aker BP ASA E

PL006 C 85.0 85.0 Faroe Petroleum E

PL006 D 85.0 85.0 Faroe Petroleum E

PL065 45.0 37.8 Aker BP ASA P

PL065 B 45.0 37.8 Aker BP ASA P


PL147 50.0 50.0 Faroe Petroleum P


PL019 B 20.0 20.0 Aker BP ASA P

UK

P1763 25.0 25.0 Azinor Catalyst E

P111 54.27 54.27 Repsol Norge P

P803 10.0 10.0 BP Exploration P

P2401 100.0 100.0 Faroe Petroleum E

P219 18.18 18.18 Repsol Sinopec North Sea P

PL039 23.1 23.1 Tullow Oil SK Ltd S

P611 5.89 5.89 Neptune Energy P

P454 5.89 5.89 Neptune Energy P

P516 57.04 57.04 Faroe Petroleum S

P453 60.00 60.00 Faroe Petroleum S

P520 25.00 25.00 Ineos UK S

P558 10.00 10.00 BP Exploration P

Ireland

L016/23 20.0 20.0 Nexen Petroleum UK E

Netherlands

D18 A 5.0 5.0 Neptune Energy P

D15 10.0 10.0 Neptune Energy P

1. A = Appraisal, E = Exploration, D = Development, P = Production, R = Under Relinquishment, S = Operations Suspended.

For further information on licenses and reserves, please refer to Faroe's annual financial statements for the

years ending on 31 December 2016 and 2017 respectively as well as Faroe's interim results 2018 for the six month

period ending on June 2018, incorporated hereto by reference. See Section 12 "Incorporation by reference –

documents on display".

6.4 Current trading and prospects

On 18 September 2018, Faroe released its notice of interim results, an extract of which is set out below together

with extracts from Faroe’s Annual Report 2017 and other operational updates and presentations by Faroe in

November and December 2018 without material adjustment:

Average H1 2018 production of 12,402 boepd from existing portfolio (H1 2017: 14,800 boepd) and full-

year 2018 production guidance of approximately 12,000 boepd.

Adjusted revenue of £102.2 million (H1 2017: £95.5 million) - reflecting higher commodity prices,

partially offset by lower production during the period. Statutory revenue of £67.8 million (H1 2017:

44

£80.1 million) excludes produced but not lifted oil and gas (underlift) of £37.3 million (H1 2017: £15.6

million).

Operating profit of £82.5 million (H1 2017: loss £0.3 million) and profit after tax of £42.5 million (H1

2017: loss £2.9 million) - reflecting higher EBITDAX and £24.5 million post-tax gain on Fenja part-

divestment.

Net Faroe capital expenditure for 2018 is estimated at approximately £225 million pre-tax.

Rungne well, operated by Faroe, announced as a technical discovery on 14 November 2018, but no

hydrocarbons encountered in the main Oseberg target. The preliminary gas and condensate

recoverable volume range for the discovery in the Ness formation is likely to be in the range of 2.7-17.0

MMboe gross and therefore unlikely to be commercial in isolation.

Agar appraisal well announced on 15 November 2018 has recoverable resources estimated between 3.8

and 12.5 MMboe net to Faroe.

Plantain announced as a discovery although no resource estimates were disclosed.

Spud of Brasse East well was announced on 21 November 2018 and the Cassidy well on 5 December

2018.

Trym is scheduled to temporarily shut in production from the second half of 2019.

Production from Schooner and Ketch in the UK ceased on 15 August 2018 following the planned

closure of the Conoco-operated Theddlethorpe onshore host facility.

An agreement with Equinor to swap its interests in the Njord, Hyme redevelopment and Bauge

development assets in return for interests in four producing assets on the NCS: Alve, Marulk,

Ringhorne East and Vilje on a cashless basis. The transaction has an effective date of 1 January 2019 and

is subject only to consent from the Norwegian authorities.

6.5 Recent developments and significant trends

On 16 January 2019, Faroe announced it had been awarded participation in eight exploration licenses, of which

four are operatorships, under Norway’s 2018 APA licensing round. The awarded licenses are set out in the table

below:

License Participating interest (percent) Paying interest (percent) Operator

PL 969 45.0 45.0 Faroe Petroleum





PL 644 C 20.0 20.0 OMV Norge

PL 019 H 20.0 20.0 Aker BP ASA

PL 006 F 85.0 85.0 Faroe Petroleum

Faroe also announced a partnership with subsidiaries of Royal Dutch Shell plc and Spirit Energy Limited

following the award of PL 969 in the recent APA licensing round with the intention to advance the large, cross-

border Edinburgh prospect towards a drill decision during 2019. Except for this and the completion of the

Transaction, there has not been any significant change in the financial or trading position of Faroe which has

occurred since 31 September 2018.

6.6 Financial information

As a company listed on AIM, Faroe has prepared and made public both annual and interim financial

statements. The annual financial statements for the years ending on 31 December 2016 and 2017 respectively as

45

well as the interim results 2018 for the six month period ending on June 2018 are incorporated hereto by

reference. See Section 12 "Incorporation by reference – documents on display" below for further details.

The financial statements of Faroe have been prepared in accordance with IFRS as adopted by the EU and as

applied in accordance with the Act. A summary of the IFRS accounting principles used are incorporated by

reference to Faroe’s Annual Report 2017 note 1 in the consolidated accounts.

The following selected financial information has been extracted from the audited consolidated financial

statements for Faroe as of and for the years ended 31 December 2017 and 2016. The historical results of Faroe

are not necessarily indicative of its results for any future period. For a discussion of certain risks that could

impact the business, operating results, financial condition, liquidity and prospects of Faroe, see Section 1 "Risk

Factors".

***

(Selected financial information follows overleaf)

46

Selected income statement information

As reported in Faroe`s audited consolidated financial statements for the years ended 31 December 2017, 2016 and

2015, and unaudited consolidated interim financial statements for the six months ended 30 June 2018, with

comparable figures for the six months ended 30 June 2017.

First Half-Year Full-Year Full-Year Full-Year

Q2 2018 Q2 2017 2017 2016 2015

IFRS IFRS IFRS IFRS IFRS

(in GBP thousand) (unaudited) (unaudited) (audited) (audited) (audited)

Revenue 67,840 80,139 152,924 94,779 112,980

Cost of sales -21,280 -74,324 -132,508 -96,666 -99,838

Asset impairment - -3,000 -12,992 -2,923 -45,108

Gross profit/(loss) 46,560 2,815 7,424 -4,810 -31,966

Other income/(expense) 18,735 21,725 17,353 -8,412 13,867

Gain on disposal of asset 24,520 - 7,229 - -

Exploration and evaluation expenses -2,049 -22,796 -25,851 -33,468 -89,537

Administrative expenses -5,274 -2,021 -7,678 -10,189 -3,718

Operating profit/(loss) 82,492 -277 -1,523 -56,879 -111,354

Finance revenue 617 238 4,790 6,423 909

Finance costs -10,151 -6,092 -17,006 -11,139 -11,855

Profit/(loss) on ordinary activities before tax 72,958 -6,131 -13,739 -61,595 -122,300

Tax credit -30,488 3,191 2,313 28,686 69,382

Profit/(loss) for the year from continuing operations 42,470 -2,940 -11,426 -32,909 -52,918

Profit/(loss) per share – basic (pence) 11.54 -0.80 -3.10 -10.50 -19.70

Profit/(loss) per share – diluted (pence) 10.83 -0.80 -3.10 -10.50 -19.70

Profit/(loss) for the year 42,470 -2,940 -11,426 -32,909 -52,918

Items that may be reclassified subsequently to profit or loss:

Exchange differences on retranslation on partial disposal of foreign operations net of tax

1,915 - - - -

Exchange differences on retranslation on foreign operations net of tax 4,763 -7,160 -13,274 21,855 -1,503

Total comprehensive loss attributable to equity holders of the parent 49,148 -10,100 -24,700 -11,054 -54,421

47

Selected balance sheet information

As reported in Faroe`s audited consolidated financial statements as of 31 December 2017, 2016 and 2015, and

unaudited consolidated interim financial statements as of 30 June 2018, with comparable figures as of 30 June

2017.

As of 30

June As of 31 Dec

2018 2017 2017 2016 2015



Non-current assets

Goodwill 9,635 7,534 9,386 7,744 -

Intangible assets 110,382 110,203 68,857 107,376 73,521

Property, plant and equipment: development & production 259,628 159,986 201,216 157,328 110,594

Property, plant and equipment: other 701 495 695 611 503

Financial assets - - - - 12

Deferred tax asset 61,115 112,974 114,499 122,055 32,398

441,461 391,192 394,653 395,114 217,028

Current assets

Inventories 11,015 10,478 10,644 10,456 5,922

Trade and other receivables 156,053 86,931 102,088 63,063 27,964

Current tax receivable 62,517 50,999 35,610 41,764 35,195

Financial assets - 2,072 - - 10,621

Cash and cash equivalents 158,596 117,574 149,084 96,769 91,515

388,181 268,054 297,426 212,052 171,217

Assets held for sale - - 50,987 - -

388,181 268,054 348,413 212,052 171,217

Total assets 829,642 659,246 743,066 607,166 388,245

Current liabilities

Trade and other payables -150,178 -105,436 -113,989 -53,900 -32,418

Current taxation payable -1,286 - -65 -31 -689

Provisions -61,196 - -10,002 - -

Financial liabilities - borrowings -54,115 -44,968 -32,948 -35,845 -55,776

Financial liabilities - other -1,085 - -767 -1,383 -

-267,860 -150,404 -157,771 -91,159 -88,883

Non-current liabilities

Interest bearing loans and borrowings -74,726 - -72,742 - -19,888

Provisions -214,635 -270,533 -254,697 -269,469 -87,118

-289,361 -270,533 -327,439 -269,469 -107,006

Liabilities directly associated with assets held for sale - - -31,854 - -

Total liabilities -557,221 -420,937 -517,064 -360,628 -195,889

Net assets 272,421 238,309 226,002 246,538 192,356

Equity attributable to equity holders

Equity share capital 37,284 36,657 36,664 36,453 26,824

Share premium account 315,580 315,580 315,580 315,580 262,453

Cumulative translation reserve 11,144 10,580 6,381 17,740 -4,055

Retained earnings -91,587 -124,508 -130,708 -123,235 -92,866

Reserves of a disposal group held for sale - - -1,915 - -

Total equity 272,421 238,309 226,002 246,538 192,356

48

Selected cash flow information

As reported in Faroe`s audited consolidated financial statements for the years ended 31 December 2017, 2016 and

2015, and unaudited consolidated interim financial statements for the six months ended 30 June 2018, with

comparable figures for the six months ended 30 June 2017.

First Half-Year Full-Year Full-Year Full-Year

Q2 2018 Q2 2017 2017 2016 2015



Profit/(loss) before tax 72,958 -6,131 -13,739 -61,595 -122,300

Depreciation, depletion and amortisation 12,259 20,663 45,179 23,369 38,447

Exploration asset write off 63 21,175 21,524 29,908 83,569

Unrealised hedging (gains)/losses -344 -3,975 -369 13,095 -4,580

Asset impairment - 3,000 12,992 2,923 45,108

Fair value of share-based payment 3,615 1,662 4,948 4,408 1,916

Cash settlement of share options - - -670 - -

Gain on disposal of asset -24,520 - -7,229 - -

Disposal of decommissioning provision - - -1,092 - -

Decommissioning expenditure -3,998 - - - -

Purchase of SIP shares -104 - -216 - -

Movement in trade and other receivables -53,965 -25,940 -42,263 -24,478 2,768

Movement in inventories -371 -22 -188 -4,534 -1,580

Movement in trade and other payables 36,507 50,153 61,728 22,865 -1,896

Currency translation adjustments -1,803 -1,988 -4,060 -5,814 1,587

Expense recognised in respect of equity-settled share-based payments - - - - -67

Interest received -617 -238 -730 -609 -909

Interest and financing fees 11,955 8,081 17,006 11,139 10,268

Tax rebate 64 -193 41,031 44,729 40,284

Net cash generated in operating activities 51,699 66,247 133,852 55,406 92,615

Investing activities

Purchases of intangible and tangible assets -98,636 -55,432 -144,239 -79,447 -84,585

Proceeds from sale of intangible assets 40,430 - - - 1,300

Interest received 617 238 730 609 909

Net cash used in investing activities -57,589 -55,194 -143,509 -78,838 -82,376

Financing activities

Proceeds from interest bearing loans and borrowings - - 75,915 - -

Issue costs of bond instruments - - -1,920 - -

Proceeds from issue of equity instruments of the group - 204 - 66,901 138

Issue costs of shares - - - -4,145 -

Repayments from borrowings 19,637 9,123 -1,404 -19,931 -9,908

Interest and financing fees paid -4,935 -1,661 -4,022 -4,225 -5,322

Net cash inflow from financing activities 14,702 7,666 68,569 38,600 -15,092

Net increase in cash and cash equivalents 8,812 18,719 58,912 15,168 -4,853

Cash and cash equivalents at the beginning of the year 149,084 96,769 96,769 91,515 92,571

Effect of foreign exchange rate differences 700 2,086 -6,597 -9,914 3,797

Cash and cash equivalents at the end of the year 158,596 117,574 149,084 96,769 91,515

49

6.7 Legal and arbitration proceedings

DNO is not aware of any governmental, legal or arbitral proceedings (including any such proceedings which

are pending or threatened) initiated against Faroe which may have, or have had, significant effects on Faroe's

financial position or profitability.

50

7. THE GROUP FOLLOWING THE TRANSACTION

This Section provides information about the prospects of the results of the Transaction and its expected

implications on the Group following the Transaction and should be read in conjunction with other parts of the

Information Memorandum, in particular Section 6 "Presentation of Faroe" and Section 10 "Unaudited Pro Forma

Financial Information (“UPFFI”)”. The following discussion contains forward-looking statements that reflect the

Company’s plans and estimates. Factors that could cause or contribute to differences to these forward-looking

statements include, but are not limited to, those discussed in Section 1 "Risk Factors" and the "Cautionary Note

Regarding Forward-Looking Statements" on page 2.

7.1 The Group following the Transaction

The combination of DNO and Faroe will hold a total of 110 licenses across its portfolio, of which 3 are in

Kurdistan, 90 in Norway, 13 in the UK, 1 in Ireland, 2 in the Netherlands and 1 in Yemen. The total Norway

licenses includes the 18 exploration licenses awarded to DNO and the eight licenses awarded to Faroe under

Norway’s 2018 APA licensing round, which require final regulatory approval by Norwegian authorities.

DNO has strong operational and financial metrics, with operated production in January 2019 of around 128,000

bopd and 2018 revenues of USD 829 million, the highest annual revenues in DNO’s 47-year history. Cash flow

from operations increased 40 percent to USD 472 million in 2018, of which USD 334 million represented free

cash flow. As of the date of this Information Memorandum, no full-year 2018 figures have been published for

Faroe.

In 2019, the Group plans to drill or participate in up to 30 wells across its portfolio, including exploration,

development and production wells, representing the highest number of wells in DNO’s history. DNO’s drilling

program includes up to 20 wells in Kurdistan, including up to 14 wells at the Tawke field, 4 at Peshkabir and 2

at the Baeshiqa license. Including Faroe, the Group plans to participate in up to 10 wells in Norway.

The combined entities’ production is currently located in Kurdistan, Norway and the UK. In Kurdistan, DNO

produced an average of 79,747 boepd on a CWI basis in 2018. For its part, Faroe produced a combined 12,402

boepd on a net basis in Norway and the UK during the first half of 2018, of which roughly 62 percent consisted

of oil production and the balance gas production.

At yearend 2018, on a CWI basis, DNO’s proven and probable (2P) reserves stood at 376.1 million barrels of oil

(MMbbls) and contingent (2C) resources at 76.8 MMbbls. At yearend 2017, Faroe had stated 2P reserves of 97.7

MMboe and 2C resources of 78.6 MMboe.

The Group has more than 1,100 employees across offices in Oslo, Stavanger, Erbil, Dubai, Sana’a, London,

Aberdeen and Great Yarmouth. The Group’s corporate headquarters are located in Oslo.

7.2 Strengths and strategies following the Transaction

Already the leading international oil company in Kurdistan, with a 75 percent operating interest in fields

contributing a third of the region’s total exports, DNO is now firmly establishing itself in Norway as it

completes the takeover of Faroe. The combination places the Company among the top three European-listed

independent oil and gas companies in production and reserves. With 90 licenses, of which 22 are operated, the

Group will leapfrog to the ranks of the top 5 companies in total licenses held in Norway.

The Faroe acquisition bolsters the Group's portfolio and operational capabilities in Norway, transforming the

Group into a more diversified company with a strong, second leg. Through the Transaction, the Group picks up

attractive exploration, production and development projects and an experienced team with extensive

knowledge of the North Sea. Faroe currently has nine producing fields, of which five are in Norway (Trym,

Tambar, Ula, Brage and Ringhorne East) and four are in the UK or cross border with the UK (Blane

51

(UK/Norway), East Foinaven, Enoch (UK/Norway) and Orca (UK/Netherlands)). This serves to complement

DNO’s two currently producing fields, Tawke and Peshkabir, both located within the Tawke license in

Kurdistan.

The Transaction also establishes a platform to pursue more transactions, including for producing assets. In

addition to providing greater financial capacity, the combined company opens up new financing opportunities

and is expected to lower DNO’s WACC.

DNO has among the lowest finding and development costs of any company anywhere in the world. Combined

with low lifting costs, this gives the Group a significant competitive advantage when oil prices are weak and

strong cash flow when oil prices are robust. In 2018, DNO’s lifting costs in Kurdistan averaged less than USD

3.0 per barrel. For its part, Faroe’s operating expenditure averaged around USD 27.0 per barrel of oil equivalent

during the first half of 2018.

52

8. INDUSTRY AND MARKET OVERVIEW

This Section discusses the industry and markets in which the Group operates. Certain of the information in this

Section relating to market environment, market developments, growth rates, market trends, industry trends,

competition and similar information are estimates based on data compiled by professional organisations,

consultants and analysts in addition to market data from other external and publicly available sources, and the

Group’s knowledge of the markets. There are different views related to market developments reflecting the overall

uncertainties. Any forecast information and other forward-looking statements in this Section are not guarantees

of future outcomes and these future outcomes could differ materially from current expectations. Numerous

factors could cause or contribute to such differences, see Section 1 "Risk Factors" for further details.

8.1 Overview of the Group's areas of operation

8.1.1 Kurdistan

Kurdistan is estimated to hold four billion barrels of proven oil reserves and the KRG estimates that it holds 45

billion barrels in reserves and unproven resources.1 Kurdistan is currently exporting in excess of 400,000 bopd

via pipeline to the Ceyhan terminal in Turkey to international markets. DNO’s contribution from the Tawke

license represents around one third of total exports. Other international operators in the region include

ExxonMobil, Chevron, Rosneft, TAQA, Genel and Gulf Keystone.

8.1.2 Norway

Norway is a significant oil and gas producer, producing close to two million bopd and 123 bcm of gas per year.

Since production started in 1971, oil and gas has been produced from a total of 107 fields on the NCS. At the end

of 2017, 85 fields were in production: 66 in the North Sea, 17 in the Norwegian Sea and 2 in the Barents Sea.

Five new fields started producing in 2017, while a further nine were still under development at the end of the

year.2

Many of the producing fields are ageing, but some still have substantial remaining reserves. Moreover, the

economically recoverable resource base in these fields increases when small discoveries in the area are tied in

to existing infrastructure. According to the NPD, only 45 percent of estimated oil and gas resources have been

produced.

At the end of 2017, a total of 43 E&P companies were active on the NCS: 27 companies as operators and a

further 16 as partners in production licenses. The diversity of companies of all sizes promotes competition and

efficiency. It also ensures interest in different types of projects, and implementation of different kinds of new

and cost-effective technologies.

8.1.3 UK

The UK is a mature region that has been producing oil and gas offshore since 1967. Despite this, Wood

Mackenzie estimated in July 2016 that about 15 percent of the remaining reserves are yet to be produced.

In 2017, oil and gas production amounted to nearly one million bopd and 42 bcm of gas over the course of the

year, respectively. As of end-2017, proved remaining oil and gas reserves were estimated to 2.3 billion barrels of

oil and 184 bcm of gas.3

There is an even larger and more diverse number of oil and gas companies active in the UK than in Norway.

1 EIA Energy (https://www.eia.gov/beta/international/analysis_includes/countries_long/Iraq/iraq.pdf) (April 2016). 2 BP Statistical Review of World Energy June 2018, and the NPD. 3 BP Statistical Review of World Energy June 2018.

53

8.2 Segment reporting

In 2018, DNO reported three operating segments: Kurdistan, Oman and Norway. The operating segments equal

the reportable segments.

For an overview of DNO's revenue by segment, please refer to note 2 “Segment Information” of the Annual

Report of DNO for 2017, 2016 and 2015, incorporated hereto by reference as set out in Section 12 "Incorporation

by reference – documents on display".

54

9. SELECTED FINANCIAL INFORMATION FOR DNO

The following selected financial information has been extracted from DNO’s audited annual financial statements

as of and for the years ended 31 December 2017, 2016 and 2015 (the "Annual Financial Statements") and DNO’s

unaudited interim financial statements for the three and 12 months ended 31 December 2018 and 2017 the "Interim

Financial Statements". The historical results of DNO are not necessarily indicative of its results for any future

period. For a discussion of certain risks that could impact the business, operating results, financial condition,

liquidity and prospects of the Group, see Section 1 "Risk Factors". The following summary of consolidated

financial data should be read in conjunction with the other information contained in this Information

Memorandum, including the Annual Financial Statements and the notes therein and the Interim Financial

Statements, which have been incorporated in this Information Memorandum by reference; see Section 12

"Incorporation by Reference – Documents on Display".

9.1 Accounting principles

The Company prepares its financial statements in accordance with IFRS as adopted by the EU and the

Norwegian Accounting Act.

Summary of IFRS accounting principles are incorporated by reference to the Company’s Annual Report 2017

note 1 in the consolidated accounts. Summary of IFRS accounting principles applicable for 2018 are

incorporated by reference to the Company’s Interim Financial Statements 2018 note 1.

9.2 Auditor

The Company's independent auditor is Ernst & Young AS with registration number 976 389 387, and business

address at Dronning Eufemias gate 6, 0191 Oslo, Norway. Ernst & Young AS is a member of Den Norske

Revisorforeningen (“The Norwegian Institute of Public Accountants”). Ernst & Young has been the Company's

independent auditor since 2002. Accordingly, the Annual Financial Statements, incorporated by reference in

this Information Memorandum, have been audited by Ernst & Young AS. The auditors’ reports on the Annual

Financial Statements are included together with the Annual Financial Statements, as incorporated by reference

in this Information Memorandum. The audit reports have been issued without qualifications. Ernst & Young

AS has not audited, reviewed or produced any report on any other information provided in this Information

Memorandum, save as expressly set out herein.

***

(Selected financial information follows overleaf)

55

9.3 Selected income statement information

As reported in DNO`s audited consolidated financial statements for the years ended 31 December 2017, 2016 and

2015, and unaudited consolidated interim financial statements for the three and 12 months ended 31 December

2018, with comparable figures for the three and 12 months ended 31 December 2017.

Quarters Full-Year Full-Year Full-Year Full-Year

Q4 2018 Q4 2017 2018 2017 2016 2015

IFRS IFRS IFRS IFRS IFRS IFRS

(in USD million) (unaudited) (unaudited) (unaudited) (audited) (audited) (audited)

Revenues 368.8 116.0 829.3 347.4 201.8 187.4

Cost of goods sold -106.8 -57.1 -350.6 -202.2 -128.7 -197.0

Gross profit 262.0 58.9 478.7 145.2 73.1 -9.5

Other operating income 0.1 - 4.8 1.5 18.9 2.0

Other income past oil sales - - - 556.0 - -1.8

Tariffs and transportation - - - - - -19.0

Administrative expenses -13.0 -9.3 -36.7 -33.2 -31.0 -29.3

Other operating expenses 0.5 0.2 -3.4 -7.0 -5.4 -92.9

Impairment oil and gas assets - - -1.9 -108.4 -29.2 -23.5

Exploration costs expensed -19.6 -24.1 -64.7 -33.0 -20.3 -0.0

Profit/-loss from operating activities 230.0 25.7 376.8 521.1 6.1 -174.0

Financial income 4.6 2.3 12.6 11.8 17.4 15.8

Financial expenses -19.9 -13.1 -66.9 -57.9 -56.8 -78.3

Profit/-loss before income tax 214.6 14.9 322.5 475.1 -33.3 -236.5

Tax income/-expense 15.6 15.7 31.8 20.0 -2.1 24.1

Net profit/-loss 230.3 30.6 354.3 495.0 -35.3 -212.3

Other comprehensive income

Currency translation differences 1.1 -0.9 1.4 -0.4 - 0.3

Items that may be reclassified to profit or loss in later periods

1.1 -0.9 1.4 -0.4 - 0.3

Net fair value changes from financial instruments -42.3 -2.3 12.1 3.4 3.2 -

Items that are not reclassified to profit or loss in later periods

-42.3 -2.3 12.1 3.4 3.2 -

Total other comprehensive income, net of tax -41.2 -3.2 13.5 3.0 3.2 0.3

Total comprehensive income, net of tax 189.1 27.4 367.7 498.0 -32.1 -212.0

Net profit/-loss attributable to:

Equity holders of the parent 230.3 30.6 354.3 495.0 -35.3 -212.3

Total comprehensive income attributable to:

Equity holders of the parent 189.1 27.4 367.7 498.0 -32.1 -212.0

Earnings per share, basic 0.22 0.03 0.34 0.47 -0.03 -0.20

Earnings per share, diluted 0.22 0.03 0.34 0.47 -0.03 -0.20

56

9.4 Selected financial position information

As reported in DNO`s audited consolidated financial statements as of 31 December 2017, 2016 and 2015, and

unaudited consolidated interim financial statements as of 31 December 2018.

ASSETS

As of 31 Dec As of 31 Dec

2018 2017 2016 2015

IFRS IFRS IFRS IFRS

(in USD million) (unaudited) (audited) (audited) (audited)

Non-current assets

Deferred tax assets 7.0 3.5 - -

Other intangible assets 32.8 31.4 86.5 133.2

Property, plant and equipment 758.1 863.3 403.1 396.6

Financial investments 230.8 17.4 14.0 10.8

Other non-current assets 0.1 0.5 30.3 12.5

Total non-current assets 1,028.8

916.0

533.9

553.1

Current assets

Inventories 8.3 7.4 57.3 62.0

Trade and other receivables 209.8 27.8 117.4 155.5

Tax receivables 28.3 33.7 - -

Cash and cash equivalents 729.1 430.2 261.1 237.6

Total current assets 975.5

499.1

435.9

455.1

TOTAL ASSETS 2,004.3

1,415.1

969.8

1,008.2

Equity

Share capital 35.0 35.0 35.8 35.9

Other reserves 239.6 262.7 286.4 288.4

Retained earnings 943.2 578.2 79.8 111.9

Total equity 1,217.8

875.9

401.9

436.2


Interest-bearing liabilities 575.7 372.8 361.7 350.7

Provisions for other liabilities and charges 68.1 45.7 167.3 97.1

Total non-current liabilities 643.8

418.5

529.0

447.8

Current liabilities

Trade and other payables 116.4 99.6 33.1 52.5

Income tax payable 0.5 0.7 0.4 1.7

Current interest-bearing liabilities 18.4 17.6 - -

Provisions for other liabilities and charges 7.4 2.7 5.3 70.0

Total current liabilities 142.7

120.7

38.8

124.2

Total liabilities

786.5

539.2

567.8

572.0

TOTAL EQUITY AND LIABILITIES 2,004.3

1,415.1

969.8

1,008.2

57

9.5 Selected changes in equity information

As reported in DNO`s audited consolidated financial statements as of 31 December 2017, 2016 and 2015, and

unaudited consolidated interim financial statements as of 31 December 2018.

Share Other Retained Total

capital reserves earnings equity

IFRS IFRS IFRS IFRS

(in USD million) (audited) (audited) (audited) (audited)

Total equity as of 1 January 2015 33.6 175.1 324.1 532.8

Fair value gains, net of tax:

- available-for-sale financial assets - - - -

Currency translation differences - 0.3 - 0.3

Other comprehensive income/-loss - 0.3 - 0.3

Profit/-loss for the period - - -212.3 -212.3

Total comprehensive income - 0.3 -212.3 -212.0

Issue of share capital, net of transaction costs 1.9 95.0 - 96.9

Purchase of treasury shares -0.1 -2.7 - -2.8

Sale of treasury shares 0.6 20.8 - 21.3

2.3 113.0 - 115.3

Total equity as of 31 December 2015 35.9 288.4 111.8 436.2


Fair value gains, net of tax:

- available-for-sale financial assets - - 3.2 3.2

Currency translation differences - - - -

Other comprehensive income/-loss - - 3.2 3.2

Profit/-loss for the period - - -35.3 -35.3

Total comprehensive income - - -32.1 -32.1

Issue of share capital, net of transaction costs - - - -


Sale of treasury shares - - - -

-0.1 -2.0 - -2.1


58

Share Other Retained Total

capital reserves earnings equity

IFRS IFRS IFRS IFRS

(in USD million) (audited) (audited) (audited) (audited)


Fair value changes from equity instruments - - 3.4 3.4

Currency translation differences - -0.4 - -0.4

Other comprehensive income/-loss - -0.4 3.4 3.0

Profit/-loss for the period - - 495.0 495.0

Total comprehensive income - -0.4 498.4 498.0

Issue of share capital - - - -



-0.8 -23.3 - -24.1



Fair value changes from equity instruments - - 12.1 12.1

Currency translation differences - 2.6 -1.3 1.4

Other comprehensive income/-loss - 2.6 10.8 13.4

Profit/-loss for the period - - 354.3 354.3

Total comprehensive income - 2.6 365.1 367.7

Issue of share capital - - - -

Purchase of treasury shares - - - -


Payment of dividend - -25.8 - -25.8

- -25.8 - -25.8

Total equity as of 31 December 2018 35.0 239.6 943.2 1,217.8

59

9.6 Selected cash flow information

As reported in DNO`s audited consolidated financial statements for the years ended 31 December 2017, 2016 and

2015, and unaudited consolidated interim financial statements for the three and 12 months ended 31 December

2018, with comparable figures for the three and 12 months ended 31 December 2017.

Quarters Full-Year Full-Year Full-Year Full-Year

Q4 2018 Q4 2017 2018 2017 2016 2015

IFRS IFRS IFRS IFRS IFRS IFRS

(in USD million) (unaudited) (unaudited) (unaudited) (audited) (audited) (audited)

Operating activities

Profit/-loss before income tax 214.6 14.9 322.5 475.1 -33.3 -236.5

Adjustments to add/-deduct non-cash items:

Previously capitalised exploration and evaluation expenses - - - - - 5.1

Depreciation, depletion and amortisation 74.9 35.5 260.1 106.1 60.1 110.5

Impairment oil and gas assets - - 1.9 108.4 29.2 92.9

Impairment of financial assets - - - - - 34.1

Non-cash Kurdistan Receivables Settlement Agreement - - - -556.0 - -

Other * 15.9 19.0 50.2 64.4 24.5 11.7

Change in working capital items and provisions:

- Inventories -0.8 1.3 -2.4 5.9 10.1 13.8

- Trade and other receivables -170.6 12.0 -181.7 72.4 13.6 14.3

- Trade and other payables 16.4 -7.5 16.8 54.1 -19.4 -87.2

- Provisions for other liabilities and charges -2.3 -6.1 4.7 8.4 13.9 7.1

Cash generated from operations 148.1 69.3 472.0 338.8 98.7 -34.2

Income taxes received/-paid - - - -2.4 -2.1 -7.2

Tax refund received 33.2 33.2 33.2 33.2 - -

Net interests received/-paid -12.0 -14.8 -34.1 -32.3 -34.6 -31.6

Net cash from/-used in operating activities 169.3 87.7 471.1 337.4 62.0 -73.0

Investing activities

Purchases of intangible assets -5.2 - -7.8 -1.3 -9.4 -0.1

Purchases of tangible assets -40.9 -27.9 -130.3 -129.1 -27.1 -50.5

Acquisition of subsidiary net of cash acquired - - - 2.6 - -

Acquisition of financial investments -12.0 - -201.3 - - -

Net cash from/-used in investing activities -58.1 -27.9 -339.4 -127.8 -36.4 -50.6

Financing activities

Proceeds from borrowings net of issue costs 8.6 2.3 223.9 14.5 - 344.8

Repayment of borrowings -31.0 -30.9 -31.0 -30.9 - -211.4

Purchase of treasury shares, including options - - - -24.1 -2.1 -3.0

Proceeds from sale of treasury shares - - - - - 21.4

Proceeds from issuance of shares, net - - - - - 96.9

Paid dividend - - -25.8 - - -

Net cash from/-used in financing activities -22.3 -28.6 167.1 -40.5 -2.1 248.8

Net increase/-decrease in cash and cash equivalents 88.9 31.2 298.8 169.1 23.5 124.9

Cash and cash equivalents at beginning of the period 640.2 399.0 430.2 261.1 237.6 113.8

Exchange gain/-losses on cash and cash equivalents - - - - - -1.1

Cash and cash equivalents at the end of the period 729.1 430.2 729.1 430.2 261.1 237.6

Of which restricted cash 3.2 3.9 3.2 3.9 2.9 3.1

Of which held on restricted account in relation to the Transaction

418.1 - 418.1 - - -

* Net interest income/-expense and amortisation of bond issue costs are included in the line Other.

60

9.7 Significant change in the Company’s financial or trading position

Other than the Transaction, there has been no significant change in the financial or trading position of the

Company since the date of the Interim Financial Statements.

9.8 Statement of no material adverse change

There has been no material adverse change in the prospects of the Company since the date of the last audited

Financial Statements. And there are no known trends, uncertainties, demands, commitments or events that are

reasonably likely to have a material effect on the Company’s prospects for at least the current financial year.

9.9 Recent events relevant to evaluation of solvency

There have been no recent events particular to the Company which are to a material extent relevant to the

evaluation of the Company's solvency.

61

10. UNAUDITED PRO FORMA FINANCIAL INFORMATION (“UPFFI”)

10.1 The Transaction

On 26 November 2018, the Company announced a cash offer for the whole of the issued and to be issued share

capital of Faroe (other than the Faroe shares already held by the Company) for 152 pence in cash for each Faroe

share. At the time of the Offer on 26 November 2018, the Company held 105,247,866 Faroe shares, representing

28.22 percent of Faroe's issued share capital. On 12 December 2018, the Offer was formally proposed to Faroe’s

shareholders.

On 8 January 2019, the Company announced the terms of an increased and final cash offer for the entire issued

and to be issued share capital of Faroe at a price of 160 pence in cash for each Faroe share, as further set out in

a final offer document published the same day.

On 14 January 2019, the Company announced the Final Offer became unconditional in all respects on 11 January

2019. For accounting purposes, this is considered to be the date the Company obtained control over Faroe by

achieving more than 50 percent ownership.

The cash consideration payable by the Company under the terms of the Offer is funded from cash resources

available to DNO.

For further details about the Offer, see Section 5 “The Transaction".

10.2 Faroe's asset swap with Equinor and the UPFFI

On 5 December 2018, Faroe announced that it had signed a binding agreement (the “Swap”) with Equinor

Energy AS (a wholly owned subsidiary of Equinor ASA) (“Equinor”) to swap its interests in the Njord, Hyme

redevelopment and Bauge development assets (the “Divested Assets”) in return for interests in four producing

assets on the NCS: Alve, Marulk, Ringhorne East and Vilje (together the “Acquired Assets”) on a cashless basis.

The effective date of the transactions is 1 January 2019 with closing subject to consent from the Norwegian

authorities.

Faroe holds a 7.5 percent working interest in each of the Divested Assets. Njord and Hyme are currently shut

down and are under redevelopment, whilst Bauge is under development. While the Swap is significant for

Faroe, Faroe is under no obligation to prepare any pro forma information for this transaction.

As a result of the Swap, Faroe will acquire Equinor’s stakes in the following licenses:

Acquired Assets

Alve Marulk Ringhorne East

Unit

Vilje Total

Faroe working interest % 32.0% 17.0% 14.82% 28.853%

Operator Equinor ENI Point AkerBP

2P reserves (MMboe) 7.7 2.3 3.1 4.4 17.6

Hydrocarbon type Gas/Condensate Gas/Condensate Oil Oil

The Swap will not reduce Faroe’s current production, as the Divested Assets swapped to Equinor are currently

not in production. Furthermore, the Swap will have no material impact on 2P reserves for Faroe. Further

details of the Swap can be found in Faroe’s presentation of the Swap, which is publicly available:

https://www.londonstockexchange.com/exchange/news/market-news/market-news-

detail/FPM/13891660.html

62

As none of the Divested Assets were in production during 2017 or 2018, the production of Faroe as reflected in

the 2017 financial statements is still representative for the unaudited pro forma statements of comprehensive

income for 2017. As Faroe has no available income statements for the Acquired Assets, the unaudited pro forma

statements of comprehensive income as prepared do not reflect the Acquired Assets from Equinor. However,

based on the 2018 production profile for the Acquired Assets, Faroe expects that the Swap will increase Faroe’s

production by 7,000-8,000 boepd for 2019.

The Swap has been considered a balanced swap by Faroe and Equinor when it comes to fair values of the

reserves, hence the Swap included no cash consideration. The Swap will not have a material impact on 2P

reserves for Faroe, as the Swap was based on a “reserves neutral basis”. The PPA will therefore in all material

respects reflect fair values for Faroe’s reserves at yearend 2018.

10.3 Cautionary note regarding the UPFFI

The following tables included in this Section 10 set out the UPFFI for the Group as of and for the year ended 31

December 2017.

The UPFFI has been prepared solely to show how the Transaction would have impacted on the consolidated

statements of comprehensive income for DNO for the 12 months ended 31 December 2017 had the Transaction

occurred on 1 January 2017, and the consolidated statements of financial position as of 31 December 2017 had

the Transaction occurred on 31 December 2017.

The UPFFI is based on certain management assumptions and adjustments made to illustrate what the financial

results of the Group might have been, had the Company completed the Transaction at an earlier point in time.

Because of its nature, the UPFFI addresses a hypothetical situation and therefore does not represent the

Group's actual consolidated statements of financial position or results if the Transaction had in fact occurred

on those dates; the UPFFI is further also not representative of the results of operations for any future periods.

It should be noted that greater uncertainty is attached to the UPFFI than historical financial information.

Investors are cautioned against placing undue reliance on this UPFFI.

Both DNO and Faroe prepare its financial statements in accordance with IFRS, as approved by the EU.

However, International Accounting Standards (“IAS”) and IFRS 6 Exploration for and Evaluation of Mineral

Resources provide the companies some latitude to the accounting of exploration and drilling (policy choices),

and DNO has identified that Faroe’s accounting policies differ from DNO’s accounting policies with regards to

capitalisation of E&E. While DNO’s accounting policy is to temporarily recognise expenses relating to the

drilling of exploration wells as capitalised exploration expenditures (presented as other intangible assets)

pending an evaluation of potential oil and gas discoveries, Faroe’s accounting policy also includes capitalising

geological and geophysical surveys, administrative costs and seismic acquisition. These types of E&E costs are

normally expensed in DNO’s financial statements when they occur.

The assumptions underlying the policy adjustments applied to the historical financial information of Faroe and

the pro forma adjustments are described in the notes to the UPFFI. Neither these adjustments nor the

resulting UPFFI have been audited in accordance with International or US generally accepted auditing

standards. In evaluating the UPFFI, each reader should carefully consider the historical financial statements of

the Group and the notes thereto and the notes to the UPFFI.

It should be noted that both DNO and Faroe calculate depreciation of producing assets based on the “unit of

production” method. The rate of depreciation is equal to the ratio of oil and gas production for the period over

the estimated remaining reserves. However, while DNO calculates the rate of depreciation based on 1P

developed reserves, Faroe calculates the rate of depreciation based on 2P developed and undeveloped reserves.

The Company has considered the impact of Faroe’s policy by calculating the rate of depreciation of Faroe

63

producing assets based on 1P and have considered the impact on the financial information to be insignificant.

Furthermore, DNO and Faroe have based the estimates of 2P reserves (evaluated by independent experts) on

slightly different oil and gas price forecasts. As this is an assumption (and not an accounting policy difference)

no adjustments have been prepared in that regard.

The UPFFI is prepared under the assumption that the compulsory acquisition of the remaining Faroe Shares

will be completed as described in Section 3 "The Transaction".

10.4 Independent assurance report on UPFFI

With respect to the UPFFI, Ernst & Young AS has provided an independent assurance report as attached hereto

as Appendix A. In the assurance report, Ernst & Young AS has applied assurance procedures in accordance

with ISAE 3420 “Assurance Engagement to Report on Compilation of Pro Forma Financial Information

Included in a Prospectus”, in order to express an opinion as to whether the UPFFI has been properly compiled

on the basis stated, and that such basis is consistent with the accounting policies of the Company.

10.5 Basis for preparation

The UPFFI is prepared in a manner consistent with the accounting policies of DNO (i.e., IFRS as adopted by

EU) applied in 2017. The Company will not adopt any new policies as a result of the acquisition. Please refer to

note 1 of DNO’s consolidated financial statements 2017 for a description of the accounting policies. With effect

from 1 January 2018, the Company has implemented IFRS 9 Financial Instruments and IFRS 15 Revenue from

Contracts with Customers. Please refer to note 1 of DNO’s Interim Financial Statements for description of the

implementation of IFRS 9 and IFRS 15.

The Transaction is regarded as a business combination which is accounted for using the acquisition method in

accordance with IFRS 3 Business Combinations. The UPFFI for the year ended 31 December 2017 has been

compiled based on the audited consolidated financial statements of the Group for the year ended 31 December

2017, which were prepared in accordance with IFRS as adopted by the EU.

The UPFFI does not include all information required for financial statements under IFRS and should be read in

connection with the historical information of DNO and Faroe. The UPFFI has been prepared under the

assumption of going concern.

The UPFFI has been compiled to comply with the requirements set forth in Section 3.5.2.6 of the Continuing

Obligations by reference to Annex II of Commission Regulation (EC) 809/2004 implementing Directive

2003/71/EC of the European Parliament and of the Council of 4 November 2003 regarding information

contained in prospectuses as well as the format, incorporation by reference and publication of such

prospectuses and dissemination of advertisements, which pursuant to the Continuing Obligations apply

correspondingly to information memoranda such as this Information Memorandum.

It should be noted that the UPFFI was not prepared in connection with an offering registered with the SEC

under the US Securities Act and consequently is not compliant with the SEC's rules on presentation of pro

forma financial information (SEC Regulation S-X) and had the securities been registered under the US

Securities Act, this UPFFI, including the report by the auditor, would have been amended and/or removed

from the Information Memorandum.

10.6 Sources of the UPFFI

The historical financial information for DNO used for compilation of the UPFFI has been compiled based on

the financial statements for 2017. These documents are incorporated by reference to this Information

Memorandum, see Section 12 “Incorporation by Reference - Documents on Display”.

64

The financial information of Faroe has been extracted from the financial statements for 2017. These documents

are incorporated by reference to this Information Memorandum, see Section 12 “Incorporation by Reference -

Documents on Display”.

10.7 Translation of Faroe`s financial statements from GBP to USD and reclassifications

Certain reclassifications have been done to conform Faroe’s 2017 financial statements presentation to that of

the Company. The tables below show Faroe’s consolidated income statement for the year ended 31 December

2017 presented in GBP, the translation to USD and the necessary reclassifications made to comply with the

form of the consolidated statements of comprehensive income presented by the Company.

The currency rate for conversion to USD is the average exchange rate for 2017 of 1.2875.

Note (a) - Reclassification of changes in overlift/underlift

Faroe presents changes in underlift of USD 39.5 million as a reduction to “Cost of sales” in the financial

statements, while DNO would present such underlift as “Revenues". DNO and Faroe value underlift balances

at net realisable value.

In order to follow the same consistent presentation of changes in overlift/underlift, the amount of USD 39.5

million is reclassified in the unaudited pro forma statements of comprehensive income from a reduction of

“Cost of sales” to an increase of “Revenues”.

Note (b) - Reclassification of impairment of assets

Faroe has recognised asset impairments of USD 16.7 million as part of the gross profit. The asset impairments

are reclassified to line “Profit/loss from operating activities”, to be consistent with DNO’s presentation.

Consolidated Adjusted

Consolidated (translated) Adjustments presentation

(audited) (unaudited) (unaudited) (unaudited)

IFRS IFRS IFRS IFRS(GBP thousand) (USD million) (USD million) Notes (USD million)

Revenue 152,924 196.9 39.5 (a) 236.4 Cost of sales -132,508 -170.6 -39.5 (a) -210.1 Asset impairment -12,992 -16.7 16.7 (b) - Gross profit/(loss) 7,424 9.6 16.7 26.3

Other income/(expense) 17,353 22.3 22.3 Gain on disposal of asset 7,229 9.3 9.3 Exploration and evaluation expenses -25,851 -33.3 -33.3 Administrative expenses -7,678 -9.9 -9.9 Asset impairment -16.7 (b) -16.7 Operating loss -1,523 -2.0 - -2.0

Finance revenue 4,790 6.2 6.2 Finance cost -17,006 -21.9 -21.9 Loss on ordinary activities before tax -13,739 -17.7 - -17.7

Tax credit 2,313 3.0 3.0 Loss for the year from continuing operations -11,426 -14.7 - -14.7

Other comprehensive income

Exchange diff'es on retranslation of foreign operations net of tax -13,274 -17.1 -17.1

Items that may be reclassified subsequently to profit or loss: -13,274 -17.1 - -17.1

Total comprehensive loss attributable to equity holders of

parent -24,700 -31.8 - -31.8

Adjusted presentation of Faroe`s income

statement for the year ended 31 December 2017

65

Certain reclassifications have as well been done to conform Faroe’s 2017 financial statements to that of DNO.

The table below show Faroe’s consolidated balance sheet as of 31 December 2017 presented in GBP and the

translation from GBP to USD. Faroe’s consolidated balance sheet as of 31 December 2017 complies with the

form of the consolidated statements of financial position presented by DNO and as such, no reclassifications

were necessary.

The currency rate for conversion to USD is the exchange rate at yearend 2017 of 1.3517.

10.8 PPA

The Company has for the purposes of the UPFFI performed a preliminary PPA, based on Faroe’s unaudited

preliminary consolidated statements of financial position as of 31 December 2018, though it is subject to change

based on the final and audited consolidated financial statements as of 31 December 2018 of Faroe. Furthermore,

in accordance with IFRS 3, final adjustments to the PPA must be made within 12 months of the acquisition

date.

This PPA has formed the basis for the amortisation and depreciation costs in the UPFFI and the presentation

in the unaudited pro forma statement of financial position. The final PPA may significantly differ from this

Consolidated Adjusted

Consolidated (translated) Adjustments presentation

(audited) (unaudited) (unaudited) (unaudited)

IFRS IFRS IFRS IFRS(GBP thousand) (USD milllion) (USD million) Notes (USD million)

Goodwill 9,386 12.7 12.7

Intangible assets 68,857 93.1 93

Property, plant and equipment: development & production and other 201,911 272.9 273

Deferred tax asset 114,499 154.8 155

394,653 533.5 533

-

Current assets -

Inventories 10,644 14.4 14

Trade and other receivables 102,088 138.0 138

Current tax receivable 35,610 48.1 48

Cash and cash equivalents 149,084 201.5 202

Assets held for sale 50,987 68.9 69

348,413 471.0 471

-

TOTAL ASSETS 743,066 1,004.4 1,004

- -

EQUITY AND LIABILITIES - -

Equity share capital 36,664 49.6 50

Share premium account 315,580 426.6 427

Cumulative translation reserve 6,381 8.6 9

Retained earnings -130,708 -176.7 -177

Reserves of a disposal group held for sale -1,915 -2.6 -3

Total equity 226,002 305.5 305 -

Non-current liabilities -

Interest bearing loans and borrowings 72,742 98.3 98

Provisions 254,697 344.3 344

327,439 442.6 443

-

Current liabilities -

Trade and other payables 113,989 154.1 154

Current taxation payable 65 0.1 0

Financial liabilities - borrowings and other 33,715 45.6 46

Provisions 10,002 13.5 14

Liabilities directly associated with assets held for sale 31,854 43.1 43

189,625 256.3 256

-

Total liabilities 517,064 698.9 699

-

TOTAL EQUITY AND LIABILITIES 743,066 1,004.4 1,004

Adjusted presentation of Faroe`s

financial position as of 31 December

2017

66

allocation and this could materially have affected the depreciation and amortisation of excess values in the

UPFFI. The PPA is presented in note 5 to the UPFFI below.

10.9 Unaudited pro forma statements of comprehensive income

The table below sets out the unaudited pro forma statements of comprehensive income for the year ended 31

December 2017, as if the Transaction had occurred on 1 January 2017.

In connection with the preparation of the unaudited pro forma statements of comprehensive income, the

following adjustments have been made:

a) Policy adjustments

Note 1 – Change in accounting policy for capitalising E&E costs other than exploratory drilling

During 2017, a total of USD 10.4 million of E&E costs other than exploratory drilling costs, were capitalised in

Faroe`s consolidated balance sheet. Under DNO accounting policy these types of costs are expensed and as

such, a reversal of E&E costs capitalised during 2017 in Faroe of USD 10.4 million is recognised. Increased costs

imply lower tax expense of USD 8.1 million.

The Company has considered the impact on Faroe’s depreciation in 2017 as a result of the change in policy and

has not identified any significant changes to Faroe’s depreciation of the producing assets as a result of the

change in policy for capitalisation of E&E costs, as E&E costs capitalised under both methods for Faroe’s

producing assets would largely be unchanged regardless of policy choice.

b) Pro forma adjustments

Note 2 - Fair value adjustments recognised from the PPA

Pro forma

Faroe statements of

DNO Consolidated comprehensive

Consolidated (translated) Policy Pro forma income(audited) (unaudited) adjustments adjustments (unaudited)

(in USD millions) IFRS IFRS (unaudited) Notes (unaudited) Notes IFRS

Revenues 347.4 236.4 583.8 Cost of goods sold -202.2 -210.1 31.0 2 -381.4 Gross profit 145.2 26.3 - 31.0 202.4

Other operating income 1.5 22.3 23.8 Other income past oil sales 556.0 - 556.0 Gain on disposal of asset - 9.3 9.3 Administrative expenses -33.2 -9.9 -43.1 Other operating expenses -7.0 - -11.9 3 -18.9 Impairment oil and gas assets -108.4 -16.7 -125.1 Exploration costs expensed -33.0 -33.3 -10.4 1 -76.6 Profit/-loss from operating activites 521.1 -2.0 -10.4 19.1 527.9

Financial income 11.8 6.2 -4.4 4 13.6 Financial expenses -57.9 -21.9 -79.8 Profit/-loss before income tax 475.1 -17.7 -10.4 14.7 461.7

Tax income/-expense 20.0 3.0 8.1 1 -24.1 2 6.9 Net profit/-loss 495.0 -14.7 -2.3 -9.4 468.6

Other comprehensive incomeCurrency translation differences -0.4 -17.1 28.5 5 11.0 Fair value changes available-for-sale financial assets 3.4 - 3.4

Other comprehensive income that may be reclassified to

profit or loss in subsequent periods 3.0 -17.1 - 28.5 14.4

Other comprehensive income that will not be reclassified to

profit or loss in subsequent periods - - - - -

Total comprehensive income, net of tax 498.0 -31.8 -2.3 19.0 482.9

Unaudited pro forma statements of

comprehensive income for the year ended 31

December 2017

67

The PPA identifies fair value adjustment in total of USD 328.2 million, of which USD 145.6 million is allocated

to E&E (as part of “Intangible assets”) and USD 182.6 million is allocated to development and producing assets

(as part of PP&E). See note 3 to the unaudited pro forma statements of financial position for the PPA.

It should be noted that fair values identified and allocated to producing assets were lower than the carrying

values of Faroe’s producing assets as some of the fields are mature with declining production. To reflect how

the depreciation of the identified fair values would have impacted the unaudited pro forma statements of

comprehensive income for 2017, the fair value adjustments have been depreciated in line with the unit of

production method based on Faroe’s production during 2017. The effect is calculated to be USD 31.0 million

and recognised as a reduction to the depreciation cost. This assumes that the Transaction had taken place with

effect as of 1 January 2017 and with the production ratio as recorded for the acquired producing fields as

recorded in Faroe.

Decreased depreciation costs imply higher tax expense (by using the corporate tax rate of 78 percent as the

producing assets in question are in all material aspects within the Norwegian Petroleum tax regime). The tax

expense effect is calculated to be USD 24.1 million.

These adjustments are considered to have continuing impact, i.e., that the adjustment will have effect beyond

one year.

Note 3 - Transaction costs

Estimated transaction costs for the Transaction are approximately USD 11.9 million. As acquisition-related

costs are not part of the exchange transaction between the acquirer and the acquiree (or its former owners),

such costs are not considered part of the business combination as defined by IFRS 3, and acquisition-related

costs are hence expensed in the unaudited pro forma statements of comprehensive income.

The Company’s preliminary view is that the transaction costs will not have any tax impact.

This adjustment is not considered to have a continuing impact.

Note 4 – Reduced interest income

The acquisition of Faroe will be financed with DNO's own cash. Hence, if the Transaction had occurred with

effect from 1 January 2017, DNO would have earned less interest on its cash deposits. Interest income recorded

by DNO during 2017 was USD 4.4 million, which has been reversed. DNO has a tax loss carry forward which is

not recognised as an asset and the reduced interest income would therefore have no impact on tax expense.

This adjustment is considered to have a continuing impact, as reduced cash holdings will reduce interest

earnings for future years.

Note 5 – Translation difference

If the Transaction had occurred with effect from 1 January 2017, the consolidation of Faroe would have given

effect to a translation difference for 2017 for the translation of Faroe’s financial statements from GBP to USD.

The translation difference would have been recognised over “Other comprehensive income” with USD 28.5

million. This adjustment has no tax effects.

This adjustment is considered to have a continuing impact.

10.10 Unaudited pro forma statements of financial position

The table below sets out the unaudited pro forma statement of financial position as of 31 December 2017, as if

the Transaction had occurred on 31 December 2017.

68

In connection with the preparation of the unaudited pro forma statements of financial position the following

adjustments have been made.

a) Policy adjustments

Note 1 – Change in accounting policy for capitalising E&E costs

As of yearend 2017, a total of USD 65.7 million in E&E costs other than exploratory drilling costs were

capitalised by Faroe (partly as Intangible assets and partly as PP&E). These types of E&E costs would have been

expensed if DNO’s accounting policy would have been followed. As a result of a change in accounting policy, a

total of USD 58.4 million is in the unaudited pro forma statements of financial position recognised as a

reduction of PP&E, and USD 7.3 million has been reflected as a reduction of “Other intangible assets”. The

corresponding reduction of USD 65.7 million is reflected in retained earnings as these costs (under DNO’s

accounting policy) would have been expensed in previous years.

As the carrying values of the PP&E assets and Other intangible assets are reduced with USD 65.7 million, this

has given rise to a deferred tax asset of USD 51.1 million (applying a nominal tax rate of 78 percent), as under

IAS 12 Taxes it is required that deferred tax (tax liabilities or tax assets) is provided in full for all temporary

differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial

statements.

Pro forma

Faroe statements of

DNO Consolidated financial

Consolidated (unaudited) Policy Pro forma position

(audited) (translated) adjustments adjustments (unaudited)

(in USD millions) IFRS IFRS (unaudited) Notes (unaudited) Notes IFRS

Assets

Non-current assets

Goodwill - 12.7 - 424.9 3 437.6

Deferred tax assets 3.5 154.8 51.1 1 209.4

Other intangible assets 31.4 93.1 -7.3 145.6 3 262.7

Property, plant and equipment 863.3 272.9 -58.4 1 182.6 3 1,260.5

Available-for-sale investments 17.4 - - 17.4

Other non-current assets 0.5 - - 0.5

Total non-current assets 916.1 533.5 -14.6 753.1 2,188.1

Current assets

Inventories 7.4 14.4 21.8

Trade and other receivables 27.8 138.0 165.8

Tax receivables 33.7 48.1 81.8

Cash and cash equivalents 430.2 201.5 -430.2 3 201.6

Assets held for sale - 68.9 - 68.9

Total current assets 499.1 471.0 - -430.2 539.9

TOTAL ASSETS 1,415.1 1,004.4 -14.6 323.0 2,728.0

EQUITY AND LIABILITIES

Equity

Share capital 35.0 49.6 -49.6 4 35.0

Other reserves 262.7 432.6 -432.6 4 262.7

Retained earnings 578.2 -176.7 -14.6 1 178.9 4 565.8

Total equity 875.9 305.5 -14.6 -303.3 863.5


Interest-bearing liabilities 372.8 98.3 6.4 3 477.5

Provisions for other liablities and charges 45.7 344.3 44.4 3 434.4

Deferred tax liabilities - - 182.3 3 182.3

Total non-current liabilities 418.5 442.6 - 233.1 1,094.2

Current liabilities

Trade and other payables 99.6 154.1 11.8 2 265.6

Income taxes payable 0.7 0.1 - 0.8

Current interest-bearing liabilities 17.6 45.6 381.5 3 444.6

Provisions for other liabilities and charges 2.7 13.5 16.2

Liabilities directly associated with assets held for sale - 43.1 - 43.1

Total current liabilities 120.7 256.3 - 393.2 770.3

Total liabilities 539.3 698.9 - 626.3 1,864.5

TOTAL EQUITY AND LIABILITIES 1,415.1 1,004.4 -14.6 323.0 2,728.0

Unaudited pro forma statements of

financial position at 31 December 2017

69

b) Pro forma adjustments

Note 2 - Transaction costs

Estimated transaction costs for the Transaction are approximately USD 11.9 million. DNO’s assessment is that

the transaction costs will not have a tax impact.

Note 3 - Purchase price allocation and fair values

The table below sets out the preliminary PPA in line with IFRS 3. As of 5 February 2019, the Company had

received acceptances amounting to 380,538,003 shares, representing 96.11 percent of the shares in Faroe.

With an acceptance rate of more than 90 percent, the Company is in a position to exercise its rights pursuant

to the provisions of Chapter 3 of Part 28 of the UK Companies Act to acquire compulsorily the remaining Faroe

shares in respect of which the Final Offer has not been accepted.

*The number of shares is based on the assumption that the Company will complete the compulsory acquisition of remaining minority shareholders.

Furthermore, the total consideration is calculated on the basis of 160 pence per share, as this was the share price whereby which the Company

achieved full control over Faroe. Shareholders that accepted the Offer for 152 pence per share will be settled with the increased Offer price of 160

pence per share. Furthermore, Faroe shares acquired by the Company prior to the Offer at a lower share price (and where sellers will not be granted

the Offer price) will for the purpose of the PPA be revalued to a share price of 160 pence per share as required by IFRS 3. The adjustment pursuant to

this revaluation will be recognised directly to equity.

IFRS 3 requires that the deferred fair values and goodwill are calculated based on the most recent, updated

figures for Faroe, hence the PPA is based on a preliminary, unaudited consolidated balance sheet of Faroe as of

31 December 2018.

As of 1 January 2017, DNO had USD 430.2 million of cash available. Since 31 December 2017 DNO has through

positive cash flow from operations increased its cash holdings which enabled the Company to finance the

acquisition of Faroe with its own available cash holding. Given that the Transaction had taken place on 31

December 2017 instead of January 2019, DNO would not have had enough available cash. For the UPFFI

purposes the net difference between USD 811.7 million (the consideration) and USD 430.2 million (cash at 1

January 2017) of USD 381.5 million would have been borrowed, hence for UPFFI purposes this amount has been

Preliminary PPA

Calculation of consideration

Number of shares to be acquired * 395,942,468

Offer price (pence per share) 160

Total consideration in GBP 633,507,949

Exchange rate USD/GBP, as of 11 January 2019 1.2812

Total consideration in USD 811,650,384

Calculation of excess value in USD million

Total consideration in USD 811.7

Consolidated quity in Faroe, at 31 December 2018 (adj. for policy adjustments) 291.6

Excess value 520.1

Breakdown of excess values, in USD million

Previously recognized Goodwill booked in Faroe`s financial position -12.7

Fair values allocated to Exploration & Evaluation licenses 145.6

Fair values allocated to Development & Producing assets 182.6

Long-term bank funding -6.4

Abandonment provision -44.4

Deferred tax liability -182.3

Technical Goodwill (identified in the Transaction) 446.8

Ordinary Goodwill (identified in the Transaction) -9.2

Total fair value adjustments and Goodwill 520.1

70

reclassified to the line “Current interest-bearing liabilities” in the unaudited pro forma statements of financial

position.

Further details about the values making up the excess value are:

Fair value of USD 328.2 million are based on net present values of the various licenses and fields

acquired in the Transaction. The net present values have been based on updated assumptions for oil

production, recovery and oil price as of yearend 2018. However, the figures are preliminary figures and

may be updated when the final PPA is recognised in 2019.

Deferred tax liabilities of USD 182.3 million represents the tax liabilities calculated as the nominal tax

rate (Norwegian tax rate of 78 percent and UK tax rate of 40 percent) of the fair value adjustments, as

IAS 12 Taxes requires that deferred tax is provided in full for all temporary differences arising between

the tax bases of assets and liabilities and their carrying amounts in the financial statements.

Goodwill of USD 12.7 million recognised in the Faroe consolidated financial statements of 2017 is

considered to have no value in the PPA and as such, is a negative adjustment.

The Company has identified that long term bank funding of Faroe has a fair value which is USD 6.4

million higher than recognised in Faroe’s consolidated statements of financial position, at yearend

2018.

The Company has further assessed the abandonment provisions in Faroe to be USD 44.4 million

higher than the carrying value in Faroe’s statements of financial position.

Goodwill recognised in the PPA amounts to USD 437.7 million, which consist of USD 446.8 million in

technical goodwill and USD 9.2 million in ordinary goodwill. The technical goodwill arises from the

Transaction due to the requirement to recognise deferred tax liabilities on temporary differences

between fair values of assets and liabilities and the related tax basis of these assets/liabilities in the

business combination. The fair values of the licenses recognised as part of the business combination

are based on cash flows after tax. The acquirer is not entitled to a tax deduction for consideration paid

above the tax basis of the seller. IAS 12 requires DNO to make a provision for deferred tax liabilities

corresponding to the difference between the acquisition cost (mainly of licenses acquired) and the tax

depreciation basis for these licenses. The offsetting entry to this deferred tax is goodwill. Goodwill

therefore arises as a technical effect of the deferred tax liability recognised from the business

combination. Technical goodwill is not a defined IFRS term.

In addition to technical goodwill as set out above, an amount of USD 9.2 million (of the total goodwill)

is regarded as negative, ordinary goodwill (also referred to as “negative goodwill”). The sum of

technical goodwill and negative goodwill amounts to goodwill of USD 437.6 million.

Note 4 - Equity adjustments

The USD 49.6 million and USD 432.6 million amounts represent the elimination of share capital and other

reserves in Faroe. The USD 178.9 million amount is the sum of the following adjustments, in USD million:

71

10.11 Additional notes to the UPFFI

The notes to the UPFFI form an integral part of the UPFFI.

Foreign exchange rates

For purposes of converting Faroe’s financial information reported in GBP to DNO’s reporting currency of USD,

the Company has extracted the following rates from Norges Bank (the Norwegian National Bank):

Average exchange rate USD/GBP for the year ended 31 December 2017: 1.2875

Yearend exchange rate USD/GBP for the year ended 31 December 2017: 1.3517

Equity adjustments

Elmination of retained earnings (Faroe) -176.7

Change in equity from yearend 2017 to yearend 2018 (Faroe) 0.5

Subtotal (eliminations and changes from 2017 to 2018) -176.2

Expensing of E&E costs (Note 3) -65.7

Tax effect on expensing E&E costs (Note 3) 51.1

Transaction costs expensed in accordance with IFRS 3 (Note 5) 11.9

Subtotal (unaudited pro forma adjustments) -2.7

Total equity adjustments -178.9

72

11. BOARD OF DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE

11.1 Introduction

The general meeting is the highest authority of the Company. All shareholders in the Company are entitled to

attend and vote at general meetings of the Company.

The overall management of the Group is vested in the Company’s Board of Directors and the Company’s

Management.

The Company's Articles of Association provide that the Board of Directors shall consist of a minimum of three

and a maximum of seven members. The current Board of Directors consist of five members, as listed in the

table below.

11.2 Board of Directors

The names, positions and current terms of office of the members as of the date of this Information

Memorandum are set out in the table below.

Name Position Served since Term expires Shares in the Company

Bijan Mossavar-Rahmani Executive Chairman 2011 2019 *

Lars Arne Takla Deputy Chairman 2012 2019 30,000**

Elin Karfjell Member 2015 2019 33,000

Gunnar Hirsti Member 2007 2019 250,000

Shelley Watson Member 2010 2019 *

* Mr. Mossavar-Rahmani and Ms. Watson hold an indirect interest in the Company through their interest in RAK Petroleum plc.

** Mr. Takla is also the majority shareholder of Takla Energy AS, which owns an additional 10,000 shares in the Company.

The Company's registered business address, Dokkveien 1, 0250 Oslo, Norway, serves as the c/o address for the

Board of Directors in relation to their directorship of the Company.

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 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

73

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 Managing Partner of Atelika AS and has held various management positions across a broad

range of industries.

Ms. Karfjell has served as Chief Executive Officer of Fabi Group, Director of Finance and Administration at

Atea AS and partner of Ernst & Young AS and Arthur Andersen. Other board directorships include Aker

Philadelphia Shipyard, North Energy ASA and Contesto AS. Ms. Karfjell is a state authorised public accountant.

She has a Bachelor of Science in Accounting from Oslo and Akershus University College of Applied Sciences

and a Higher Auditing degree from the Norwegian School of Economics and Business Administration. Ms.

Karfjell was elected to the Company's Board of Directors in 2015 and is a member of the audit committee.

Gunnar Hirsti (Director)

Gunnar Hirsti has extensive experience from various managerial, executive and board positions in the oil and

gas industry as well as the information technology industry in Norway.

Mr. Hirsti was Chief Executive Officer of DSND Subsea ASA (now Subsea 7 S.A.) for a period of six years. He

also served as Executive Chairman of the Board of Blom ASA, which is listed on the Oslo Stock Exchange, 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.

Subsequently she held management positions with Novus Petroleum, Indago Petroleum and RAK Petroleum

PCL where she served as General Manager until 2014. She was appointed as Chief Operating Officer of RAK

Petroleum plc in February 2017 and Chief Financial Officer in May 2017. Ms. Watson holds a First Class

Honours degree in Chemical Engineering and a Bachelor of Commerce degree from the University of

Melbourne. She has served on the Company’s Board of Directors since 2010 and is a member of the audit

committee.

11.3 Management

The Company's Management consists of six individuals. The names of the members as of the date of this

Information Memorandum, and their respective positions, are presented in the table below:

Name Position Employed since Shares in the Company*

Bjørn Dale Managing Director 2011 -

Haakon Sandborg Chief Financial Officer 2001 -

Ute Quinn General Counsel and Corporate Secretary 2017 -

Chris Spencer Commercial Director 2017 29,000

Nicholas Whiteley Exploration Director 2015 -

Jon Sargeant Managing Director DNO Technical Services AS 2008 -

* Shares in the Company calculated as of 31 December 2018.

The Company's registered business address, Dokkveien 1, 0250 Oslo, Norway, serves as the business address for

the Management in relation to their employment with the Company.

74

Bjørn Dale (Managing Director)

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

MBA from the Stockholm School of Economics.

Haakon Sandborg (Chief Financial Officer)

Mr. Sandborg joined DNO in 2001. In addition to his oil and gas experience, he has a background in banking,

including positions at DNB Bank. Mr. Sandborg holds a Master of Business Administration from the

Norwegian School of Business Administration.

Ute Quinn (General Counsel and Corporate Secretary)

Ms. Quinn joined DNO in 2017. Ms. Quinn previously served as General Counsel of Sakhalin Energy and in

various legal executive roles at Royal Dutch Shell and Hess Corporation. She holds a Bachelor of Arts in

Political Science from Vassar College and a Juris Doctor from Temple University School of Law.

Chris Spencer (Commercial Director)

Mr. Spencer joined DNO in 2017. Mr. Spencer previously served as the CEO of Rocksource ASA and in various

commercial and technical roles at Royal Dutch Shell and BP. Mr. Spencer is a Chartered Engineer with the

Institution of Chemical Engineers in the UK.

Nicholas Whiteley (Exploration Director)

Dr. Whiteley joined DNO in 2015 from Cairn India, where he served as General Manager of Exploration. He

commenced 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.

Jon Sargeant (Managing Director DNO Technical Services AS)

Mr. Sargeant joined DNO in 2008. He previously served in various drilling and technical management roles at

Norsk Hydro for more than 30 years. Mr. Sargeant holds a Bachelor’s degree from the University of Manchester

in Chemical Engineering.

11.4 Conflicts of interest

Board of Directors

As of the date hereof no conflicts of interest or, to the knowledge of the Company, potential conflicts of

interest exist between the duties of the members of the Company's Board of Directors and their private

interests and/or other duties. RAK Petroleum plc, 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 plc. Shelley Watson is the Chief Operating Officer and Chief Financial

Officer of RAK Petroleum plc.

Management

As of the date hereof no conflicts of interest or, to the knowledge of the Company, potential conflicts of

interest exist between the duties of the members of the Company's Management and their private interests

and/or other duties. The Managing Director of the Company, Bjørn Dale, is a member of the board of directors

of RAK Petroleum plc, the largest shareholder in the Company.

11.5 Nomination committee

The Company's Articles of Association provide for a nomination committee. The current members of the

nomination committee are Bijan Mossavar-Rahmani and two external members, Kåre Tjønneland and Anita

Marie Hjerkinn Aarnæs. The nomination committee's mandate is to propose candidates for the Board of

Directors and its various committees to the annual general meeting. It also proposes the level of board

75

members’ remuneration. The current composition of the nomination committee will be assessed at the next

annual general meeting.

11.6 Audit committee

The Board of Directors has established an audit committee composed of three board members. The current

members of the audit committee are Gunnar Hirsti, Shelley Watson and Elin Karfjell. The audit committee's

mandate includes undertaking quality control of the Company's financial reporting and monitoring internal

control and risk evaluation systems.

11.7 Remuneration committee

The Board of Directors has established a remuneration committee composed of two members, whose current

members are Bijan Mossavar-Rahmani and Gunnar Hirsti. Its mandate is to consider matters relating to

compensation of Management and to make related recommendations to the Board of Directors.

Severance payment agreements (up to two times annual salary) apply to the following members of

Management: Bjørn Dale, Haakon Sandborg and Nicholas Whiteley. For further Management remuneration

details, please refer to note 5 of the Company's Annual Report for 2017.

11.8 HSSE committee

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

operational risks and HSSE performance.

11.9 Corporate governance

The Company has adopted and implemented a corporate governance regime which complies with the

Corporate Governance Code, except in relation to section 14 of the Corporate Governance Code, whereby the

Company has not established guiding principles for takeover bid situations. In the event of a takeover bid, the

Board of Directors has a responsibility to ensure that 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 this 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 should clearly state whether the Board of Directors' evaluation is

unanimous and the reasons for any dissent.

76

12. INCORPORATION BY REFERENCE – DOCUMENTS ON DISPLAY

12.1 Cross reference table

The information incorporated by reference in this Information Memorandum should be read in connection

with the following cross-reference table. References in the table to "Annex" and "Items" are references to the

disclosure requirements as set forth in the Continuing Obligations by reference to such Annex (and Item

therein) of Commission Regulation (EC) no. 809/2004 implementing Directive 2003/71/EC of the European

Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses as well as

the format, incorporation by reference and publication of such prospectuses and dissemination of

advertisements, which pursuant to the Continuing Obligations apply correspondingly to information

memoranda such as this Information Memorandum.

Section in the IM Disclosure requirements Reference document and link

Page in reference document 4

4.2.2 Specialist issuer requirements

for mineral companies

(CESR/05-054b part III chapter 1

item 132)

2018 Reserve Report

https://www.dno.no/globalassets/4.-

investors/documents/asr-dno-asa-2018.pdf

All pages

5.1 A description of the

transaction (Continuing

obligations Section 3.5.2.1 first

subsection)

Initial Offer Document


investors/documents/dno-offer-for-faroe-petroleum_-

offer-document-12-december-2018.pdf

Final Offer Document


investors/documents/increased-and-final-cash-offer-

for-faroe-petroleum-plc-by-dno-asa_8-january-

2019.pdf

All pages

All pages

6.3 Specialist issuer requirements

for mineral companies

(CESR/05-054b part III chapter 1

item 132)

Faroe Competent Person Report (Reserves, Resources

and Economic Assessment of the Assets of Faroe

Petroleum plc dated July 2016)

https://www.fp.fo/investors/investor-briefcase/

Faroe Annual Report 2017


All pages

23

6.6 Key figures from the balance

sheet and profit and loss

account of Faroe (Continuing

obligations Section 3.4.2, cf.

Section 3.5.2.4 first subsection

and Section 3.5.2.5 first

subsection)

Faroe Q2 2018 Interim Results Report








All pages

69 - 129

63 - 120

63 - 117

4 The original page number as stated in the reference document

77

Section in the IM Disclosure requirements Reference document and link

Page in reference document 4

9 Audited historical financial

information for the issuer

(Annex 1 item 20.1)

DNO Annual Report 2017

https://www.dno.no/en/investor-relations/reports-

and-presentations/



and-presentations/



and-presentations/

All pages

All pages

All pages

9 Unaudited interim financial

information for the issuer

(Annex I item 20.6.1 and

20.6.2)

DNO 2018 Interim Results Report


and-presentations/

All pages

12.2 Information sourced from third parties and statements regarding competitive position

Any information sourced from third parties contained in this Information Memorandum has been accurately

reproduced and, as far as the Company is aware and is able to ascertain from information published by that

third party, no facts have been omitted which would render the reproduced information inaccurate or

misleading.

Unless otherwise indicated in the Information Memorandum, the basis for any statements regarding the

Group's competitive position in the future is based on the Company's own assessment and knowledge of the

potential market in which the Group may operate.

12.3 Documents on display

For 12 months from the date of this Information Memorandum, copies of the following documents will be

available for inspection at the Company's registered office during normal business hours from Monday through

Friday each week (except public holidays):

The Articles of Association of DNO ASA;

All reports, letters, and other documents, historical financial information, valuations and statements

prepared by any expert at the Company's request any part of which is included or referred to in the

Information Memorandum;

DNO's financial statements as of and for the years ending 31 December 2017, 2016 and 2015, and the related

auditor reports thereto;

DNO's interim financial statements as of and for the three months ended 31 December 2018 and 2017;

The historical financial statements of the subsidiaries of DNO as of and for the years ended 31 December

2017 and 2016; and

This Information Memorandum.

78

13. DEFINITIONS

Capitalised terms used throughout this Information Memorandum shall have the meaning ascribed to such terms

as set out below or defined herein, unless the context require otherwise.

Accounting Agreement The accounting procedures under the Norwegian model JOA.

Act UK Companies Act 2006.

AED United Arab Emirates dirham, the lawful currency of the UAE.

AIM UK Alternative Investment Market.

Articles of Association The governing document of a company.

Annual Financial Statements The Company's audited consolidated financial statements as of and

for the years ended 31 December 2017, 2016 and 2015.

ASRR Annual Statement of Reserves and Resources.

bcm Billion cubic meters.

BEIS UK Department for Business Energy and Industrial Affairs.

Board of Directors The Board of Directors of the Company.

boe Barrels of oil equivalent.

bopd Barrels of oil per day.

boepd Barrels of oil equivalent per day.

Code The UK City Code on Takeovers and Mergers, as amended from time

to time.

commercial discovery Has the meaning assigned to it in the licenses, generally a discovery

that is potentially commercial when considering all technical,

operational, commercial and financial factors, all in accordance with

prudent international petroleum industry practices.

Corporate Governance Code The Norwegian Code of Practice for Corporate Governance dated 17

October 2018.

crude oil 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. It does not include solution gas or natural gas liquids.

CWI Company Working Interest, as described in Section 4.2.2.

ESA EFTA Surveillance Authority.

EU The European Union.

EUR Euros, the lawful currency of the European Union.

E&E Exploration & evaluation costs.

79

E&P Exploration and production.

Management The members of the Company’s management.

Faroe Faroe Petroleum plc.

FGI Federal Government of Iraq.

Final Offer Means as described in Section 5 “The Transaction”.

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. Gas may contain sulphur or other non-hydrocarbon

compounds.

GBP Pound sterling, the lawful currency of the UK.

HSE Health, safety and environment.

HSSE Health, safety, security and environment.

IFRS International Financial Reporting Standards

Interim Financial Statements The Company's unaudited consolidated interim financial statements

as of and for the three and 12 months ended 31 December 2018, with

comparable figures as of and for the three and 12 months ended 31

December 2017.

IQD Iraqi dinar, the lawful currency of Iraq.

JOA Joint Operating Agreement

KRG Kurdistan Regional Government.

Kurdistan Kurdistan region of Iraq.

MMboe Million barrels of oil equivalent.

MPE Norwegian Ministry of Petroleum and Energy.

MOF Norwegian Ministry of Finance.

NCS Norwegian Continental Shelf.

NE Net Entitlement as described in Section 4.2.2.

Netherlands The Kingdom of the Netherlands.

Norway The Kingdom of Norway.

NOK Norwegian kroner, the lawful currency of Norway.

Norwegian Public Limited

Companies Act

The Norwegian Public Limited Companies Act of 13 June 1997 no. 45

(“allmennaksjeloven").

NPA Norwegian Petroleum Act.

NPD Norwegian Petroleum Directorate.

Offer Means as described in Section 5 "The Transaction".

80

OGA UK Oil and Gas Authority.

Oman The Sultanate of Oman.

OPEC Organisation of the Petroleum Exporting Countries.

OPRED UK Offshore Petroleum Regulator for Environment &

Decommissioning.

PDO Plan for development and operation.

Petroleum Act UK Petroleum Act 1998.

PIO Plan for instalment and operation.

PP&E Property, plant & equipment.

PRMS The Petroleum Resources Management System.

PSC/PSA Production Sharing Contracts/Agreements. A PSC or PSA is used

interchangeably as an agreement between a contractor and a host

government, whereby the contractor bears all risk and costs for

exploration, development and production in return for a stipulated

share of production.

PPA Purchase Price Allocation.

RSA Receivables Settlement Agreement, as described in Section 1.4.2.

SEC US Securities and Exchange Commission.

Shares The shares in the Company.

UAE The United Arab Emirates.

UK The United Kingdom.

UKCS United Kingdom Continental Shelf.

UPFFI Unaudited Pro Forma Financial Information.

US United States of America.

USD United States dollar, the lawful currency of the US.

US Securities Act United States Securities Act of 1933, as amended.

WACC Weighted Average Cost of Capital.

YER Yemeni rial, the lawful currency of Yemen.

Yemen The Republic of Yemen.

Appendix A

81

DNO ASA

Dokkveien 1

0250 Oslo

Norway

Legal advisor:

ADVOKATFIRMAET SCHJØDT AS

Ruseløkkveien 14-16

0251 Oslo

Norway

Auditor:

ERNST & YOUNG AS

Dronning Eufemias gate 6

0191 Oslo

Norway

Financial advisors:

PRICEWATERHOUSECOOPERS AS

Dronning Eufemias gate 8

0191 Oslo

Norway

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