RockRose Energy plc...2019/07/19 · Apart from the responsibilities and liabilities, if any, which...

THIS DOCUMENT IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION. If you are in any doubt about the contents

of this document or the action you should take, you are recommended to seek your own financial advice immediately from an

appropriately authorised stockbroker, bank manager, solicitor, accountant or other independent financial adviser who, if you are

taking advice in the United Kingdom, is duly authorised under the Financial Services and Markets Act 2000 (“FSMA”) or, if you are

not resident in the United Kingdom, from another appropriately authorised independent financial adviser in your own jurisdiction.

This document comprises a prospectus relating to RockRose Energy plc (the “Company” or “RockRose”) prepared in

accordance with the prospectus rules of the United Kingdom Financial Conduct Authority (the “FCA”) made under section 73A of

FSMA (the “Prospectus Rules”) and approved by the FCA under section 87A of FSMA. This document has been filed with the

FCA and made available to the public in accordance with Rule 3.2 of the Prospectus Rules by being made available, free of

charge, at www.rockroseenergy.com and at the Company’s registered office at c/o Cooley Services Limited, Dashwood, 69 Old

Broad Street, London EC2M 1QS, United Kingdom.

The current entire issued ordinary shares of nominal value 20 pence each (the “Ordinary Shares”) in the capital of the Company

(the “Existing Issued Share Capital”) is admitted to listing on the standard segment of the official list (“Standard Listing”)

maintained by the FCA (the “Official List”), in its capacity as competent authority under FSMA under Chapter 14 of the listing

rules published by the FCA under section 73A of FSMA (the “Listing Rules”) and to trading on the main market for listed

securities (the “Main Market”) of London Stock Exchange plc (the “London Stock Exchange”).

As the Company’s acquisition of (i) the entire membership interest in Marathon Oil U.K. LLC (“MOUK”) from Marathon Oil

Holdings UK Limited (“MOHL”) and (ii) the entire issued share capital of Marathon Oil West of Shetlands Limited (“MOWOS”) and,

together with MOUK and its subsidiaries, the “Marathon Group”) from Marathon International Oil Holdings LLC (“MIOH”), a

subsidiary of Marathon Oil Corporation (together with MOHL and MIOH, “Marathon”) (the “Marathon Acquisition”) together

constituted a “reverse takeover” under the Listing Rules (“Reverse Takeover”), upon announcement of the Marathon Acquisition

on 25 February 2019, the Standard Listing of the Existing Issued Share Capital was suspended by the FCA. In accordance with

the Listing Rules, upon publication of this document the FCA will cancel the Company’s existing Standard Listing.

Applications have been made for the admission of the Ordinary Shares to a Standard Listing on the Official List and to trading on

the Main Market of the London Stock Exchange (together, “Admission”). It is expected that Admission will become effective, and

that unconditional dealings in the Ordinary Shares will commence, at 8:00 a.m. on 24 July 2019.

The whole of the text of this document should be read by prospective investors. Your attention is specifically drawn to the

discussion of certain risks and other factors that should be considered in connection with an investment in the Ordinary Shares,

as set out in Part II – Risk Factors of this document.

The Company and the directors, whose names appear on page 51 of this document (the “Directors”), accept responsibility for

the information contained in this document. To the best of the knowledge of the Company and the Directors (each of whom have

taken all reasonable care to ensure that such is the case), the information contained in this document is in accordance with the

facts and does not omit anything likely to affect the import of such information.

RockRose Energy plc(Incorporated and registered in England and Wales with registered number 09665181)

Admission to the Official List of 13,090,595 Ordinary Shares of nominal value 20 pence each

(by way of a Standard Listing under Chapter 14 of the Listing Rules) and

to trading on the Main Market of the London Stock Exchange

Financial Adviser and Joint Broker

H&P Advisory Limited

Joint Broker Joint Broker

Whitman Howard Limited Cantor Fitzgerald Europe

R

LR 2.2.10(2)(a)

LR 2.2.3

LR 2.2.9(1)

Annex III, 6.1

Annex I, III, 1.1,

1.2

Annex I, 5.1.1,

5.1.2

LR 2.2.1(1), (2)

172846 Proof 2 Thursday, July 18, 2019 21:48

This document does not constitute an offer to sell or an invitation to subscribe for, or the solicitation of an offer or invitation to buy

or subscribe for, Ordinary Shares in any jurisdiction.

A Standard Listing will afford investors in the Company a lower level of regulatory protection than that afforded to investors in

companies which are admitted to listing on the premium segment of the Official List (“Premium Listing”), which are subject to

additional obligations under the Listing Rules.

The Ordinary Shares have not been and will not be registered under the US Securities Act of 1933 (the “Securities Act”), or the

securities laws of any state or other jurisdiction of the United States or under applicable securities laws of Australia, Canada or

Japan. Subject to certain exceptions, the Ordinary Shares may not be, offered, sold, resold, transferred or distributed, directly or

indirectly, within, into or in the United States or to or for the account or benefit of persons in the United States, Australia, Canada,

Japan or any other jurisdiction where such offer or sale would violate the relevant securities laws of such jurisdiction.

The Ordinary Shares have not been approved or disapproved by the US Securities and Exchange Commission, any State

securities commission in the United States or any other US regulatory authority, nor have any of the foregoing authorities passed

comment upon or endorsed the merits of the adequacy of this document. Any representations to the contrary is a criminal offence

in the United States.

Apart from the responsibilities and liabilities, if any, which may be imposed on each of H&P Advisory Limited (“Hannam” or

“Financial Adviser and Joint Broker”) in its capacity as financial adviser and joint broker to the Company, Whitman Howard

Limited (“Whitman Howard”) and Cantor Fitzgerald Europe (“Cantor Fitzgerald”) in their respective capacities as joint brokers

to the Company (the “Joint Brokers”) by FSMA or the regulatory regime established thereunder, none of Hannam, Whitman

Howard or Cantor Fitzgerald accepts any responsibility whatsoever for, or make any representation or warranty, express or

implied, as to the contents of this document or for any other statement made or purported to be made by them, or on their behalf,

in connection with the Company, the Ordinary Shares and nothing in this document will be relied upon as a promise or

representation in this respect, whether or not to the past or future. Each of Hannam, Whitman Howard and Cantor Fitzgerald

accordingly disclaims all and any responsibility or liability, whether arising in tort, contract or otherwise (save as referred to

above), which it might otherwise have in respect of this document or any such statement.

None of Hannam, Whitman Howard or Cantor Fitzgerald nor any of their respective representatives, are making any

representation to any prospective investor of the Ordinary Shares regarding the legality of an investment in the Ordinary Shares

by such prospective investor under the laws applicable to such prospective investor. The contents of this document should not

be construed as legal, financial or tax advice. Each prospective investor should consult his, her or its own legal, financial or tax

adviser for legal, financial or tax advice.

Each of Hannam, Whitman Howard and Cantor Fitzgerald is authorised and regulated by the FCA and is acting exclusively for

the Company and for no one else in connection with the production of this document and/or Admission. None of Hannam,

Whitman Howard or Cantor Fitzgerald will regard any other person as a client in relation to the production of this document and/or

Admission and will not be responsible to anyone (whether or not a recipient of this document) other than the Company for

providing the protections afforded to its clients, nor for providing advice in connection with the production of this document and/or

Admission or any other matter, transaction or arrangement referred to in this document.

The distribution of this document in or into jurisdictions other than the United Kingdom may be restricted by law and therefore

persons into whose possession this document comes should inform themselves about and observe any such restrictions. Any

failure to comply with these restrictions may constitute a violation of securities laws of any such jurisdiction.

The date of this document is 19 July 2019.

Annex III, 3.4

2


TABLE OF CONTENTS

PAGE

PART I SUMMARY 4

PART II RISK FACTORS 27

PART III IMPORTANT INFORMATION 44

PART IV EXPECTED TIMETABLE 50

PART V DIRECTORS, AGENTS AND ADVISERS 51

PART VI INFORMATION ON THE COMPANY AND THE ENLARGED GROUP 52

PART VII REGULATORY AND OPERATING ENVIRONMENT 94

PART VIII THE BOARD, THE SENIOR MANAGERS AND CORPORATEGOVERNANCE 100

PART IX UNAUDITED PRO FORMA FINANCIAL INFORMATION FOR THEENLARGED GROUP 104

PART X SELECTED FINANCIAL INFORMATION ON THE ENLARGED GROUP 111

PART XI HISTORICAL FINANCIAL INFORMATION OF THE COMPANY 123

PART XII HISTORICAL FINANCIAL INFORMATION ON MOUK 124

PART XIII HISTORICAL FINANCIAL INFORMATION ON MOWOS 157

PART XIV OPERATING AND FINANCIAL REVIEW OF THE GROUP (INCLUDING LIQUIDITY AND CAPITAL RESOURCES AND CAPITALISATION ANDINDEBTEDNESS FOR THE ENLARGED GROUP) 184

PART XV OPERATING AND FINANCIAL REVIEW OF MOUK 191

PART XVI OPERATING AND FINANCIAL REVIEW OF MOWOS 198

PART XVII TAXATION 203

PART XVIII CONSEQUENCES OF A STANDARD LISTING 207

PART XIX ADDITIONAL INFORMATION 208

PART XX GLOSSARY 234

PART XXI DEFINITIONS 236

PART XXII DOCUMENTS INCORPORATED BY REFERENCE 243

PART XXIII COMPETENT PERSON’S REPORT 245

3


PART I

SUMMARY

Summaries are made up of disclosure requirements known as “Elements”. These Elements are

numbered in Sections A – E (A.1 – E.7).

This summary contains all the Elements required to be included in a summary for this type of

securities and issuer. Because some Elements are not required to be addressed, there may be

gaps in the numbering sequence of the Elements.

Even though an Element may be required to be inserted in the summary because of the type of

securities and issuer, it is possible that no relevant information can be given regarding the Element.

In this case a short description of the Element is included in the summary with the mention of “not

applicable”.

Section A – Introduction and warnings

A.1 Warning to investors This summary should be read as an introduction to thisdocument.

Any decision to invest in the Ordinary Shares should bebased on consideration of this document as a whole by theinvestor.

Where a claim relating to the information contained in thisdocument is brought before a court, the plaintiff investormight, under the national legislation of the EEA States, haveto bear the costs of translating this document before legalproceedings are initiated.

Civil liability attaches only to those persons who have tabledthis summary including any translation thereof, but only ifthis summary is misleading, inaccurate or inconsistent whenread together with the other parts of this document or it doesnot provide, when read together with the other parts of thisdocument, key information in order to aid investors whenconsidering whether to invest in such securities.

A.2 Not applicable. There will be no sale or placement ofsecurities nor any resale or final placement of securities byfinancial intermediaries.

Section B – the Issuer

B.1 The legal and commercial name of the issuer is RockRoseEnergy plc.

B.2 Domicile and legal form The Company was incorporated in England and Wales on1 July 2015 as a public company with limited liability underthe Companies Act 2006 (the “Companies Act”) with anindefinite life.

Annex XXII (I, II,

III), A.1

Annex XXII (I, II,

III), A.2

Subsequent resale ofsecurities or finalplacement of securitiesthrough financialintermediaries

Annex XXII (I),

B.1

Annex I, 5.1.1

Legal and commercialname

Annex XXII (I),B.2

4


B.3 Introduction

The Company was formed to make acquisitions ofcompanies or businesses in the oil and gas, exploration anddevelopment sector. Following the initial admission of theOrdinary Shares to Standard Listing and to trading on theMain Market of the London Stock Exchange on 13 January2016 (“Initial Admission”), the Company identified and hassubsequently acquired a number of targets.

Acquisition history

On 22 March 2017, the Company entered into an agreementwith Arunvill Capital Limited (“Arunvill”) and John McKeown(together with Arunvill, “Egerton Sellers”) to acquire theentire issued share capital of Egerton Energy VenturesLimited (“Egerton”) (the “Egerton Acquisition”). At thesame time the Company entered into a subscriptionagreement with Arunvill pursuant to which it agreed tosubscribe in cash in the total amount of £4,000,000 forOrdinary Shares in the Company at a price of £1.50 perOrdinary Share, on the basis that such funds would besufficient to cover anticipated decommissioning costs of theEgerton Interests. The total consideration for the EgertonAcquisition was £1.00 payable to the Company in cash anddeferred consideration payable to the Company of £666,000over an 18 month period. The Egerton Acquisition was notmaterial in the context of resources, net assets or potentialliabilities. The Egerton Acquisition completed on22 December 2017.

On 2 August 2017, the Company signed an acquisitionagreement in the form of a put and call option for theacquisition of the entire issued share capital of Sojitz EnergyProject Limited (“Sojitz”) with Sojitz Corporation, aJapanese corporate entity, and Sojitz Europe plc, an Englishcompany, who together agreed to sell Sojitz to the Company(the “Sojitz Sellers”) (the “Sojitz Acquisition”). The totalconsideration for the acquisition was US$2,500,000,however US$1,750,000 was received by the Company atcompletion. The Sojitz Acquisition completed on22 December 2017.

On 18 October 2017, the Company signed an agreement(the “Idemitsu UK Acquisition Agreement”) with IdemitsuKosen Co., Limited (the “Idemitsu Group”) for theacquisition of the entire issued share capital of IdemitsuPetroleum UK Limited (the “Idemitsu UK”) (the “Idemitsu

UK Acquisition”). The total consideration wasUS$29.7 million (subject to certain adjustments). TheIdemitsu UK Acquisition completed on 8 December 2017.

On 24 May 2018, the Company (as a guarantor) signed asale and purchase agreement with SHV Nederland B.V.(the “Dyas Seller”) and RockRose Energy (NL) B.V.(as purchaser) (the “Dyas Acquisition Agreement”) toacquire the entire issued and to be issued share capital of

Current operations/principal activities andmarkets

Annex XXII (I),

B.3

Annex I, 6.1.1

Annex III, 6.2

5


Dyas B.V. and its subsidiary Dyas Infrastructure B.V.(together, “Dyas”) (the “Dyas Acquisition”), which ownednon-operated Netherlands gas and condensate producingassets, for a total consideration of EUR 107 million. TheDyas Acquisition completed on 1 October 2018.

On 8 August 2018, RockRose UKCS4 Limited signed a saleand purchase agreement (the “Arran Acquisition

Agreement”) to acquire a 20.43% interest in blocks, 23/11a,23/16b and 23/16c, which contain the Arran field in the UKCentral North Sea, from Dana Petroleum (E&P) Limited(the “Arran Seller”) (the “Arran Acquisition”) for a nominalconsideration of US$1. On 19 September 2018, theCompany, further to the Arran Acquisition Agreement, signedan equity realignment letter agreement, which increased theCompany’s interest in the Arran field to 30.43%. The ArranAcquisition completed on 10 October 2018.

On 25 February 2019, the Company entered into (i) a saleand purchase agreement with MOHL to acquire the entiremembership in MOUK (the “MOUK Acquisition

Agreement”) and (ii) an agreement with MIOH to acquirethe entire issued share capital of MOWOS (the “MOWOS

Acquisition Agreement”) (together with the MOUKAcquisition Agreement, the “Marathon Acquisition

Agreements”). The total consideration payable under theMarathon Acquisition was US$140 million (subject tocustomary adjustments). As the Marathon Acquisitionconstituted a Reverse Takeover, the Standard Listing of theOrdinary Shares was suspended by the FCA on 25 February2019 pending the Company publishing a prospectus inrelation to Admission. The Marathon Acquisition completedon 1 July 2019.

Business objective, strategy and execution

The objective of the Company is to operate the Companyand its subsidiaries from time to time (the “Group”) andimplement a strategy with a view to generating value for itsshareholders (the “Shareholders”) through its acquisitionand management of operated and non-operated interests inonshore and offshore oil and gas production and powergeneration projects.

The strategy is likely to involve the making of furtheracquisitions. Further acquisitions will need to be assessedunder the Listing Rules and depending on the size of furtheracquisitions the transaction may, if it is a very significantmagnitude, be deemed a Reverse Takeover and theCompany’s Standard Listing may be cancelled in suchcircumstances. The Company would then intend to seekadmission of the new enlarged group to listing on the OfficialList and trading on the Main Market of the London StockExchange by publishing a new prospectus on the thenenlarged group but may, in certain circumstances, seekre-admission to trading on AIM, the market of that nameoperated by the London Stock Exchange (“AIM”).

6


The Company’s efforts in identifying further acquisitions inthe oil and gas, exploration and development sector will notbe limited to a particular geographic region, however theCompany’s present focus will be the UK and WesternEurope.

Unless required by applicable law or other regulatoryprocess, no Shareholder approval will be sought by theCompany in relation to any further acquisition(s).

The Directors will draw on their experience, in conjunctionwith their contacts and advisers, to target suitable furtheracquisition candidates in the oil and gas, exploration anddevelopment sector.

B.4a Significant recent trends The oil and gas, exploration, development and productionindustry continues to experience volatility, driven by anumber of factors including the uncertainties in globaleconomy and geopolitical events and the technicaladvancements affecting energy consumption and extractionmethods. In general, the industry is healthier than it was twoyears ago as the price of oil has rebounded. After appearinglimited to a range between the mid-US$40s and US$50 perbarrel (bbl), Brent crude is now trading above US$65. Theindustry is thus recovering from the brutal last few years ofweak prices, enforced capital discipline, portfoliorealignments, and productivity efficiencies. Natural gasconsumption worldwide grew by an estimated 4.6% in 2018,or 170 bcm, its strongest increase since 2010 when gasdemand was rebounding from the 2008 global financialcrisis. This second consecutive year of strong growth (aftera 3% gain in 2017) was nearly three times the averagegrowth of 1.5% over the previous five years. The switch fromcoal to gas accounted for over one-fifth of the rise in gasdemand, with the United States leading the growth, followedby China.

Global oil demand rose by 1.3% in 2018, led by stronggrowth in the United States. Oil demand in advancedeconomies remained relatively robust, but, in emergingmarkets, oil demand slowed markedly in 2018. AverageBrent oil prices were 30% higher in 2018 than in 2017. Oildemand in China was up by 445 kb/d, or 3.5%, with the rateof growth slowing down as the country moved toward a lessoil-intensive model of development and curbed vehicle useto improve urban air quality. In particular, environmentalpolicies have reduced diesel demand growth, as provincialgovernments are keen to develop cleaner transport fuels orelectric buses. European oil demand remained stagnant onslowing economic activity and rising prices. Germany sawan important decline in oil demand, falling by 135 kb/d or5.4% in 2018.

Annex XXII (I),

B.4a

Annex I, 12.1,

12.2

7


Oil demand growth by region (mb/d), 2017-18

Source: International Energy Agency, Global Energy & CO2 Status

Report, 2019

Global upstream capital expenditure, which dropped nearly45% between 2014 and 2016 is now forecast to rise 6%year-on-year in the medium term. This recovery has been aresult of various factors, including the sustained success ofthe production restraint agreement between OPEC and non-OPEC countries in force since the beginning of 2017, less oilcoming to market from challenged producers, and continuedstrong global oil demand growth (estimated by the EnergyInformation Administration at about 1.6 million b/d in 2018).In the US, natural gas prices have not seen greatmovement, as plentiful low-cost US supply continued tomeet growing demand in domestic and export markets.

Europe experienced a decline in natural gas consumption in2018 after two years of growth. This was partly due to thetemperature sensitivity of gas demand, with demand forspace heating reduced by a mild fourth quarter (in spite ofcold snaps over the first quarter). Additionally, the Dutchgovernment has decided first to lower and then stopproduction of natural gas from the Groningen field as earlyas possible. The decision implies that the European Union’slargest exporter of natural gas will become a large importerof gas within four years.

In the supply side, Nord Stream 2, TurkStream andSouthern Gas Corridor pipelines under development willcompete with liquefied natural gas (“LNG”) and existingproduction. Bunkering of LNG as a marine transportationfuel will provide a new source of gas demand as newemission rules encourage shipowners to switch away frommarine fuels. This could add around 6.5bn m3/yr toEuropean gas demand by 2025 and 18.5bn m3/yr by 2035.Wood Mackenzie estimates gas demand among the currentEU-28 will rise to a peak of 460bn m3/yr in around 2025 fromsome 445bn m3/yr in 2018.

Oil and gas rig activity levels are rising, driven by the NorthAmerican market, and major projects are being approved.Exploration is on the rise again for the first time since theglobal recession.

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8


Global oil and gas capital expenditures

Despite these signs of a renaissance, the sector faces anumber of supply-related challenges. First is an ongoingdecline in new discoveries. By the end of 2017, the volumeof new oil and gas discoveries, was at its lowest since theearly 1950s. To put this into perspective, only 3.5 billionbarrels of liquids (crude, condensate, and natural gasliquids) were discovered in 2017, which was enough to meetonly 10% of demand.

The long decline in new oil and gas discoveries

This contraction was exacerbated by a second challenge: theslowness of the rise in exploration spending since it fell withthe price collapse of 2014–16. Globally, spending fell by morethan 60%, from a high of US$153 billion in 2014 to aboutUS$58 billion in 2017. It is forecast to recover modestly overthe near term at a 7% compound annual growth rate. Theinvestment slump in traditional supply sources looks like it willcontinue to have an effect on new production.

As a result of these two challenges, the market is currentlyexperiencing what the International Energy Agency (“IEA”)calls a “two-speed oil market.” Although U.S. tight oil, orshale oil, is a dynamic new source of supply, investment inmore conventional sources of output has dropped and, as aresult, “the world needs to find an additional 2.5 million mb/dof new production each year, just for conventional output toremain flat,” according to the IEA World Energy Outlook2017. Given that it takes about three to six years fromproject sanctioning to coming onstream, the decline ininvestment approvals during the price slump could continue

Source: Rystad Energy; Strategy& research

100k

200k

300k

400k

500k

600k

700k

800k

US$ millions

’20’19’18’17’16’15’14’13’12’11’10 ’21 ’22 ’24’23 ’25

Middle EastRussia

South AmericaAfrica

AustraliaEurope

North America

Asia

North America driving growth in capex

6%

12%

-44%


40,000

80,000

120,000

160,000

200,000

240,000

Millions of barrels

19601950 2017200019901970 20101980

Crude oilCondensateNatural gas liquidsGas

Global volumes of new discoveries in oil and gas

9


to hurt the sector if financial investment decisions remainconstrained.

Regulatory developments

In 2016 the Oil and Gas Authority (the “OGA”) replaced theDepartment of Energy and Climate Change as the entityresponsible for petroleum licensing and regulation of theupstream oil and gas sector in the UK. In the same year,the OGA was granted greater regulatory powers through thepassing of the Energy Act 2016. These regulatory powersinclude the ability to participate in meetings with operators,to have access to data, provide dispute resolution andintroduce a range of sanctions such as enforcement noticesand fines up to £1 million.

Sources: PwC Oil and Gas Trends 2018–19; Deloitte: 2019 oil, gas and

chemicals industry outlook; International Energy Agency, Global Energy &

CO2 Status Report, March 2019.

B.5 Group structure The Company is a public company with limited liabilitydomiciled in England and Wales and is the holding companyof the Group. As at the date of this document and Admission,the Company holds the following percentages of the sharecapital in the Group companies listed below, all of which areincorporated in England and Wales:

Company’s percentage

ownership in the issued share

capital of the relevant

Group company:

Name of Group company:

RockRose (UKCS1) Limited(1)(3) 100%RockRose (UKCS2) Limited(1) 100%RockRose (UKCS3) Limited(1) 100%RockRose UKCS4 Limited(1) 100%RockRose UKCS5 Limited(2)(3) 100%RockRose UKCS6 Limited(2)(3) 100%RockRose UKCS7 Limited(2)(3) 100%RockRose UKCS8 LLC(1) 100%RockRose UKCS9 Limited(4) 100%RockRose UKCS10 Limited(1) 100%RockRose UKCS11 Limited(4) 100%RockRose UKCS12 Limited(4) 100%RockRose UKCS13 LLC(4) 100%RockRose Energy (NL) B.V.(1) 100%RockRose (NL) CS1 B.V.(5) 100%RockRose (NL) Infrastructure B.V.(5) 100%

(1) The Company holds a 100% direct ownership interest in this entity.

(2) The Company holds a 100% direct ownership interest in RockRose

UKCS4 Limited, which in turn holds a 100% direct ownership stake in

this entity.

(3) This entity is dormant.


UKCS8 LLC, which in turn holds a 100% direct ownership stake in this

entity.

Annex XXII (I),

B.5

Annex I, 7.1

10



Energy (NL) B.V., which in turn holds a 100% direct ownership stake

in this entity.

B.6 Major shareholders Save for the interests of the Directors, which are set outbelow, as at the date of this document and Admission theDirectors are aware of the following holdings of OrdinaryShares, which will represent 3% or more of the Company’sissued share capital or voting rights:

As at the date of this

document and Admission

Number of Percentage of

Name Ordinary Shares share capital

Andrew Austin* 3,563,234 27.21%Cavendish Asset Management Limited 1,816,800 13.87%Macquarie Capital (Europe) Limited 747,588 5.71%

* Includes 720,000 Ordinary Shares held in Mr. Austin’s SIPP,

administered by Rowanmoor Trustees.

As at the date of this document and Admission, respectively,the interests of the Directors and each of their respectiveconnected persons in the share capital of the Company, allof which are beneficial, are and will be as follows:

As at the date of this

document and Admission

Number of

Ordinary Shares Beneficially owned, controlled or directed, directly or Percentage of

Name indirectly share capital

Andrew Austin 2,843,234 21.71%Andrew Austin’s SIPP* 720,000 5.50%Richard Benmore 320,729 2.45%John Morrow 212,808 1.62%

* Administered by Rowanmoor Trustees.

Other than those person described above, as at 18 July2019, the Company had not been notified, nor was itotherwise aware of, any persons who directly or indirectly,have an interest in the Company’s share capital or votingrights which is notifiable under English law.

Annex XXII (I),

B.6

11


B.7 The selected financial information set out below has beenextracted without material adjustment from the auditedhistorical financial information of the Group for the financialyears ended 31 December 2018 and 31 December 2017,and for the 18 month period ended 31 December 2016.

Selected Financial Information of the Group:

Consolidated Statement of Comprehensive Income

Year ended Year ended 18 months to

31 December 31 December 31 December

2018 2017** 2016*

US$000 US$000 US$000

Revenue 153,072 7,436 –

Cost of sales (105,356) (7,604) –

Gross profit/(loss) 47,716 (168) –

Change in estimate of

decommissioning provisions 14,302 – –

Foreign exchange movements on

decommissioning provision – (223) –

Administrative Costs (12,649) (5,617) (1,900)

Loss on derivatives (6,399) – –

Gain on acquisition – 87,825 –

Impairment of goodwill (18,660) (7,974) – –––––––– –––––––– ––––––––Operating profit/(loss) 24,310 73,843 (1,900)

Finance income 51 9 6

Finance costs (14,996) (915) –

Foreign exchange (loss)/gain (1,987) 1,137 – –––––––– –––––––– ––––––––Profit/(loss) before income tax 7,378 74,074 (1,894)

Income tax credit 31,481 – – –––––––– –––––––– ––––––––

Profit/(loss) for the year

attributable to shareholders 38,859 74,074 (1,894) –––––––– –––––––– ––––––––Comprehensive income to be

reclassified to profit or loss in

subsequent years when specific

conditions are met:

Foreign currency translation loss – 140 (653) –––––––– –––––––– ––––––––Total comprehensive income

for the year 38,859 74,214 (2,547) –––––––– –––––––– ––––––––Unadjusted basic earnings/

(loss) per share (cents) 261 651 (34) –––––––– –––––––– ––––––––

Unadjusted diluted earnings/

(loss) per share (cents) 242 580 (34) –––––––– –––––––– ––––––––

* All balances for the 18 month period ended 31 December 2016

presented throughout these financial statements have been restated in

US$ following the change to the Group’s presentational currency in 2017.

** The income statement for the year ended 31 December 2017 has

been presented in a format consistent with that adopted in the year

ended 31 December 2018 annual report and accounts and therefore

some sub-totals are different from those presented in the annual

report and accounts for the year ended 31 December 2017. However,

no financial information has been restated.

Selected historical keyfinancial information

Annex XXII (I),

B.7

Annex I, 3.1,

20.4.3

12


Consolidated Statement of Financial Position

As at As at As at


2018 2017 2016*

US$000 US$000 US$000

Assets

Intangible assets 32,287 1,723 –

Property, plant and equipment 359,293 180,325 –

Deferred tax – 36,472 – –––––––– –––––––– ––––––––Total non-current assets 391,580 218,520 –

Inventory 5,090 6,005 –

Trade and other receivables 28,147 14,997 313

Cash and cash equivalents 67,944 64,955 2,938

Restricted cash 53,347 55,336 – –––––––– –––––––– ––––––––Total current assets 154,528 141,293 3,251 –––––––– –––––––– ––––––––Total assets 546,108 359,813 3,251 –––––––– –––––––– ––––––––

Equity

Share capital 3,549 4,269 2,890

Share premium 129 9,902 3,222

Other reserves 11,772 (75) (558)

Retained earnings/

(Accumulated losses) 58,007 71,228 (2,846) –––––––– –––––––– ––––––––Total equity 73,457 85,324 2,708 –––––––– –––––––– ––––––––

Liabilities

Provisions for liabilities and

other charges 364,717 247,048 –

Deferred tax liability 22,788 – – –––––––– –––––––– ––––––––Total non-current liabilities 387,505 247,048 – –––––––– –––––––– ––––––––

Trade and other payables 57,015 21,882 543

Tax payable 23,012 – –


other charges 5,119 5,559 – –––––––– –––––––– ––––––––Total current liabilities 85,146 27,441 543 –––––––– –––––––– ––––––––Total liabilities 472,651 274,489 543 –––––––– –––––––– ––––––––Total equity and liabilities 546,108 359,813 3,251 –––––––– –––––––– ––––––––

* All balances for the 18 month period ended 31 December 2016

presented throughout these financial statements have been restated

in US$ following the change to the Group’s presentational currency in

2017.

13


Consolidated Statement of Cash Flows

Year to Year to 18 months to


2018 2017 2016*

US$000 US$000 US$000

Cash flows from operating

activities

Profit/(loss) before income tax 7,378 74,074 (1,894)

Non-cash adjustments to reconcile

(loss)/profit before tax to

net cash flows:

Foreign exchange loss/(gains)

on operating activities 1,987 (1,136) –

Finance income (51) (9) (5)

Finance costs 14,996 915** –

Share based payments 291 242 95

Impairment of goodwill 18,660 7,974 –

Gain on acquisitions – (87,825) –

Depreciation and amortisation 34,222 1,669 –


decommissioning provision (14,302) – –

Foreign exchange movement on

decommissioning provision – 223 –

Increase in provisions – 749 – –––––––– –––––––– ––––––––Operating cash flows before movements in working capital 63,181 (3,124) (1,804)

Decrease in inventory 915 895 –

(Increase)/decrease in trade and

other receivables (13,149) 28,381 (301)

Decrease/(increase) in

restricted cash 1,988 (55,336) –

Increase in trade and

other payables 35,048 1,710 543

Income tax paid (4,534) – – –––––––– –––––––– ––––––––Net cash generated from/(used in)

operating activities 83,449 (27,474) (1,562)

Cash flows from investing activities

Acquisition of subsidiaries net of

cash acquired (11,773) 82,311 –

Utilisation of decommissioning

liabilities (2,402) – –

Additions of intangible assets (215) – –

Additions of property, plant and

equipment (10,414) (895) – –––––––– –––––––– ––––––––Net cash (used in)/generated from

investing activities (24,804) 81,416 –

Cash flows from financing activities

Finance income 51 9 5

Finance costs (3,711) – –

Share issue costs – (2,183) (1,114)

Shareholders distribution (30,360) – –

Share buy-back (22,041) – –

Proceeds from share issue 169 10,343 6,108 –––––––– –––––––– ––––––––Net cash (used in)/generated

from financing activities (55,892) 8,169 4,999 –––––––– –––––––– ––––––––Net increase in cash and

cash equivalents 2,753 62,111 3,437

Cash and cash equivalents at

1 January 64,955 2,938 –

Effect of foreign exchange 236 (94) (499) –––––––– –––––––– ––––––––Cash and cash equivalents at

31 December 67,944 64,955 2,938 –––––––– –––––––– ––––––––

* All comparative balances presented throughout these financial

statements have been restated in US$ following the change to the

Group’s presentational currency in 2017.

14


** Finance costs for the year ended 31 December 2017 has been

presented on the same basis as adopted in the year ended

31 December 2018 annual report by combining unwind of discount on

decommissioning provision and finance expense.

During the period covered by the audited historical financialinformation set out above, the significant changes to theGroup’s financial condition and operating results were:

• the receipt of net proceeds from the issue of OrdinaryShares in conjunction with the Initial Admission;

• the receipt of net proceeds from the issue of OrdinaryShares in conjunction with the subscription by Arunvillfor 2,666,666 Ordinary Shares and the subscription bycertain of the Directors, certain of their spouses andcertain third parties for 967,074 Ordinary Shares, andplacing of 1,699,594 Ordinary Shares, whichcompleted on 6 July 2017;

• the completion of the Acquisitions;

• the completion of a share buy-back and cancellationof 2,923,240 Ordinary Shares by way of a tender offerat a price of 560 pence per Ordinary Share (the“Tender Offer”) for a cash payment of US$22 million(£16.4 million) on 22 November 2018 (the “Share

Buy-back”); and

• the completion of a shareholder distribution of £1.50per B Share on 16 February 2018 following theirredemption at the same price on 15 February 2018(the “Shareholder Distribution”).

Since 31 December 2018 (being the end of the last financialperiod of the Company for which financial information hasbeen published), the significant change to the Group’sfinancial condition and operating results was the completionof the Marathon Acquisition on 1 July 2019.

The selected financial information set out below has beenextracted without material adjustment from the auditedhistorical financial information of MOUK for the financialyears ended 31 December 2018 and 31 December 2017,and the unaudited historical financial information for thefinancial year ended 31 December 2016.

15


Selected Financial Information of MOUK:


Year ended Year ended Year ended


2018 2017 2016

Audited Audited Unaudited

US$000 US$000 US$000

Revenue 196,424 209,693 157,851Cost of sales (84,656) (180,312) (197,904) –––––––– –––––––– ––––––––Gross profit/(loss) 111,768 29,381 (40,053)Other operating income 125,550 423 281Administrative costs (13,345) (6,546) 350 –––––––– –––––––– ––––––––Operating profit/(loss) 223,973 23,258 (39,422)Finance income 16,399 11,775 11,011Finance costs (7,546) (7,773) (8,107) –––––––– –––––––– ––––––––Profit/(loss) before income tax 232,826 27,260 (36,518)Income tax (charge)/credit (98,929) 23,969 21,299 –––––––– –––––––– ––––––––Profit/(loss) for the year 133,897 51,229 (15,219) –––––––– –––––––– ––––––––Adjusted EBITDA 102,594 89,485 66,912 –––––––– –––––––– ––––––––Comprehensive income to be reclassified to profit or loss in subsequent years

when specific conditions are met:

Foreign currency translation (loss)/gain (7,832) 7,915 (11,313)

Comprehensive income that will be reclassified to profit or loss in

subsequent years when specific conditions are met:

Deferred tax relating to defined benefit pension scheme (5) (6,395) 5,459Actuarial gains on defined benefit pension scheme 11 37,623 (32,109) –––––––– –––––––– ––––––––Other comprehensive income/(expense) for the year 6 31,228 (26,650) –––––––– –––––––– ––––––––Total comprehensive income/(expense) for the year 126,071 90,372 (53,182) –––––––– –––––––– ––––––––


As at As at As at


2018 2017 2016


US$000 US$000 US$000

AssetsProperty, plant and equipment 69,763 106,033 218,127Investment property 1,302 1,382 963Pension asset 82,512 70,993 12,307Deferred tax asset 368,642 471,525 332,079 –––––––– –––––––– ––––––––Total non-current assets 522,219 649,933 563,476Inventory 11,360 8,222 9,390Trade and other receivables 42,737 41,140 54,657Loans to the group undertakings 162,867 429,503 513,413Cash and cash equivalents 30,373 62,048 24,246 –––––––– –––––––– ––––––––Total current assets 247,337 540,913 601,706 –––––––– –––––––– ––––––––Total assets 769,556 1,190,846 1,165,182 –––––––– –––––––– ––––––––EquityCapital surplus 31,797 31,797 31,797Foreign currency translation reserve (11,230) (3,398) (11,313)Retained earnings 45,568 251,665 169,208 –––––––– –––––––– ––––––––Total equity 66,135 280,064 189,692 –––––––– –––––––– ––––––––Liabilities

Accruals and deferred income 5,166 5,032 12,572

Deferred tax liability 38,782 47,671 51,038Provisions for liabilities and other charges 577,718 777,845 849,221 –––––––– –––––––– ––––––––

Total non-current liabilities 621,666 830,548 912,831 –––––––– –––––––– ––––––––

16


As at As at As at


2018 2017 2016


US$000 US$000 US$000

Trade and other payables 36,574 42,324 28,096

Tax payable – 2,315 2,335


other charges 45,181 35,595 32,228 –––––––– –––––––– ––––––––

Total current liabilities 81,755 80,234 62,659 –––––––– –––––––– ––––––––

Total liabilities 703,421 910,782 975,490 –––––––– –––––––– ––––––––

Total equity and liabilities 769,556 1,190,846 1,165,182 –––––––– –––––––– ––––––––




2018 2017 2016


US$000 US$000 US$000

Cash flows from operating activities

Profit/(loss) for the year 133,897 51,229 (15,219)

Non-cash adjustments to

reconcile profit/(loss) for the

year to net cash flows:

Foreign exchange (gain)/loss

on operating activities (1,673) 1,931 (4,614)

Revaluation of investment property – (212) –

Finance costs (8,853) (4,002) (2,904)

Share based payments (14,436) (16,796) (17,741)

(Reversal of impairment)/impairment

of property, plant and equipment (20) 1,418 –

Tax on profit/(loss) on

ordinary activities 98,929 (23,969) (21,299)

Depreciation 4,171 66,650 105,125

Profit on disposal of tangible assets – – (90)


decommissioning provision (124,674) – (14,770)

Increase in provisions (24,848) (21,909) – –––––––– –––––––– ––––––––Operating cash flows before

movements in working capital 62,493 54,340 28,488

(Increase)/decrease in inventory (3,142) 1,169 5,514

(Increase)/decrease in trade and

other receivables (2,338) 65,773 (27,711)

(Decrease)/increase in trade and

other payables (5,569) 6,688 (16,492)

Income tax paid (3,835) (124,501) (13,012)

Net cash generated from/(used in)

operating activities 47,609 3,469 (23,213)


Loan repayment receipts 265,000 30,000 –

Interest receivable and similar income 11,072 11,201 9,611

(Additions)/disposals of property,

plant and equipment (13,917) (5,642) 305 –––––––– –––––––– ––––––––Net cash generated from

investing activities 262,155 35,559 9,916


Finance costs (2,559) (4,228) (3,841)

Members distribution (340,000) – – –––––––– –––––––– ––––––––Net cash used in

financing activities (342,559) (4,228) (3,841) –––––––– –––––––– ––––––––Net (decrease)/increase in cash

and cash equivalents (32,795) 34,800 (17,138)

Cash and cash equivalents

at 1 January 62,048 24,246 44,757

Effect of foreign exchange 1,120 3,002 (3,373) –––––––– –––––––– ––––––––Cash and cash equivalents

at 31 December 30,373 62,048 24,246 –––––––– –––––––– ––––––––

17


For the years ended 31 December 2016, 31 December 2017and 31 December 2018, certain significant changes to thefinancial condition and the operating results of MOUKoccurred. These changes are set out below:

• revenue increased by 32.84% from US$157,851,000for the financial year ended 31 December 2016 toUS$209,693,000 for the financial year ended31 December 2017 but decreased by 6.32% toUS$196,424,000 for the financial year ended31 December 2018. The decline was primarily due tothe changes in production volumes and price;

• cost of sales decreased by 8.88% fromUS$197,904,000 for the financial year ended31 December 2016 to US$180,312,000 for thefinancial year ended 31 December 2017, and furtherdecreased by 53% to US$84,656,000 for the financialyear ended 31 December 2018 due to the significantreduction in depreciation charges as the Brae assetsmove further towards end of life, and one off increasein contractor costs in 2017 resulting from gas bypassworks and additional decommissioning spend inrespect of Brae Bravo; and

• MOUK noted an operating loss of US$39,422,000 forthe financial year ended 31 December 2016.Operating profit increased to US$23,258,000 for thefinancial year ended 31 December 2017, andsubstantially increased by 863% to US$223,973,000for the financial year ended 31 December 2018. The2018 financial year increase was primarily driven by areduction in the decommissioning provision (aconsequence of changes in the key estimates) ofUS$125,555,000 in excess of its net book value withinfixed assets, recognised in other income. Theremainder of the increase is explained by thedecrease in costs of sales as mentioned above.

Since 31 December 2018 (being the end of the last financialperiod of MOUK for which financial information has beenpublished), (i) MOHL entered into the MOUK AcquisitionAgreement (as defined below) and completed the MarathonAcquisition and (ii) MOUK’s wholly owned subsidiary,Marathon Oil Decommissioning Services LLC, transferredits trade and assets to MOUK.

Save as set out above, there have been no significantchanges in the financial condition and operating results ofMOUK during or after the period covered by the historicalfinancial information of MOUK set out in this document.

The selected financial information set out below has beenextracted without material adjustment from the auditedhistorical financial information of MOWOS for the financialyears ended 31 December 2018, 31 December 2017 and31 December 2016.

18


Selected Financial Information of MOWOS:




2018 2017 2016

Audited Audited Audited

US$000 US$000 US$000

Revenue 176,032 93,981 126,035

Cost of sales (100,740) (71,298) (85,947) –––––––– –––––––– ––––––––Gross profit 75,292 22,683 40,088

Administrative costs (2,672) (3,198) (3,129) –––––––– –––––––– ––––––––Operating profit 72,620 19,485 36,959

Finance income 4,274 2,040 799

Finance costs (2,444) (1,438) (1,439) –––––––– –––––––– ––––––––Profit before income tax 74,450 20,087 36,319

Income tax (charge)/credit (29,610) (8,402) (25,279) –––––––– –––––––– ––––––––Profit for the year attributable

to members 44,840 11,685 11,040 –––––––– –––––––– ––––––––Adjusted EBITDA 92,976 39,669 70,617 –––––––– –––––––– ––––––––

There were no other comprehensive income 2018, 2017 and 2016,

respectively.

Total comprehensive income

for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Unadjusted basic earnings per share (in cents) 179,360 47 44 –––––––– –––––––– ––––––––Unadjusted diluted earnings per share (in cents) 179,360 47 44 –––––––– –––––––– ––––––––


As at As at As at


2018 2017 2016


US$000 US$000 US$000

Assets

Property, plant and equipment 45,541 102,511 111,380

Deferred tax asset 100,192 113,748 108,636 –––––––– –––––––– ––––––––Total non-current assets 145,733 216,259 220,016

Inventory 56 458 4,051

Trade and other receivables 35 13,951 9,063

Loans to group undertakings 156,545 143,989 153,692

Cash and cash equivalents 1,730 9,194 7,680 –––––––– –––––––– ––––––––Total current assets 158,366 167,592 174,486 –––––––– –––––––– ––––––––Total assets 304,099 383,851 394,502 –––––––– –––––––– ––––––––

Equity

Share capital 25 25,025 25,025

Other reserves 109,591 84,591 84,591

Accumulated losses (101,264) (61,104) (47,789) –––––––– –––––––– ––––––––Total equity 8,352 48,512 61,827 –––––––– –––––––– ––––––––

Liabilities

Accruals and deferred income – – –

Deferred tax liability 18,515 40,329 43,385


other charges 250,481 284,313 271,590 –––––––– –––––––– ––––––––Total non-current liabilities 268,996 324,642 314,975 –––––––– –––––––– ––––––––

Trade and other payables 10,007 10,056 10,642

Tax payable 16,744 641 7,058 –––––––– –––––––– ––––––––Total current liabilities 26,751 10,697 17,700 –––––––– –––––––– ––––––––Total liabilities 295,747 335,339 332,675 –––––––– –––––––– ––––––––Total equity and liabilities 304,099 383,851 394,502 –––––––– –––––––– ––––––––

19





2018 2017 2016


US$000 US$000 US$000


Profit before income tax 74,450 20,087 36,319

Non-cash adjustments to

reconcile profit before tax to

net cash flows:

Finance income (4,274) (2,040) (799)

Finance costs 4 – 3

Depreciation and amortisation 20,356 20,184 33,658

Finance charge on decommissioning

provisions 2,440 1,438 1,436 –––––––– –––––––– ––––––––Operating cash flows before

movements in working capital 92,976 39,669 70,617

Decrease in inventory 402 3,593 3,368

Decrease/(increase) in trade and

other receivables 13,916 (4,888) 16,020

(Increase)/decrease in amounts

owed by group companies (12,623) 9,853 (55,748)

Increase/(decrease) in trade and

other payables 18 (736) (5,018)

Income tax paid (21,765) (22,987) (23,310) –––––––– –––––––– ––––––––Net cash generated from/(used in)

operating activities 72,924 24,504 5,929


Payments to acquire property,

plant and equipment – (30) (1,430)

Receipts from sales of property,

plant and equipment 342 – –

Finance income 4,274 2,040 799 –––––––– –––––––– ––––––––Net cash generated from/(used in)

investing activities 4,616 2,010 (631)


Finance costs (4) – (3)

Shareholder distribution (85,000) (25,000) – –––––––– –––––––– ––––––––Net cash used in financing activities (85,004) (25,000) (3) –––––––– –––––––– ––––––––

Net (decrease)/increase in cash and

cash equivalents (7,464) 1,514 5,295 –––––––– –––––––– ––––––––Cash and cash equivalents

at 1 January 9,194 7,680 2,385 –––––––– –––––––– ––––––––Cash and cash equivalents

at 31 December 1,730 9,194 7,680 –––––––– –––––––– ––––––––

For the years ended 31 December 2016, 31 December 2017and 31 December 2018, certain significant changes to thefinancial condition and the operating results of MOWOSoccurred. These changes are set out below:

• revenue decreased by 25% from US$126,035,000 forthe financial year ended 31 December 2016 toUS$93,981,000 for the financial year ended31 December 2017 but increased by 87% toUS$176,032,000 for the financial year ended31 December 2018. The increase was primarily due tothe changes in production volumes and price;

• cost of sales decreased by 17% from US$85,947,000for the financial year ended 31 December 2016 toUS$71,298,000 for the financial year ended

20


31 December 2017, and increased by 41% toUS$100,740,000 for the financial year ended31 December 2018,in line with the fall in productionduring the same periods and a significant increase incontractor spend in 2018 driven in part from pump andcompressor outages; and

• operating profit decreased by 47% fromUS$36,959,000 for the financial year ended31 December 2016 to US$19,485,000 for the financialyear ended 31 December 2017, and substantiallyincreased by 272% to US$72,620,000 for the financialyear ended 31 December 2018.

Since 31 December 2018 (being the end of the last financialperiod of MOWOS for which financial information has beenpublished), MIOH entered into the MOWOS AcquisitionAgreement (as defined below) and completed the MarathonAcquisition.

Save as set out above, there have been no significantchanges in the financial condition and operating results ofMOWOS during or after the period covered by the historicalfinancial information of MOWOS set out in this document.

B.8 The unaudited consolidated pro forma statement of netassets and income statement of the Enlarged Group havebeen prepared in accordance with Annex II of the PDRegulation and on a basis consistent with the accountingpolicies adopted by the Company in preparing the Group’saudited consolidated financial statements for the year ended31 December 2018.

The unaudited pro forma statement of net assets has beenprepared based on the net assets of the Group as at31 December 2018, which includes the consolidatedfinancial position of Dyas, and has been prepared toillustrate the impact of the Marathon Acquisition, whichcompleted on 1 July 2019, on the net assets of the Group asif they had been completed on 31 December 2018.

The unaudited pro forma income statement has beenprepared based on the consolidated income statement ofthe Group for the year ended 31 December 2018, whichincludes the post-acquisition results (from 1 October 2018 to31 December 2018) of Dyas. The unaudited pro formaincome statement has been prepared to illustrate the impactof the Dyas Acquisition and the Marathon Acquisition, whichcompleted on the 1 October 2018 and 1 July 2019respectively, on the consolidated income statement of theGroup as if they had been completed on 1 January 2018.

Due to their nature, the unaudited pro forma incomestatement and net assets statement have been prepared forillustrative purposes only and, by its nature, addresses ahypothetical situation. They do not represent the Group’sactual results of operations or financial condition or what theEnlarged Group’s actual results of operations or financial

Selected key pro formafinancial information

Annex XXII (I, II),

B.8

Annex I, 20.2,

20.4.3

21


condition would have been if the Dyas Acquisition andMarathon Acquisition had been completed on the datesindicated.

The unaudited consolidated pro forma profit before tax forthe year ended 31 December 2018 is US$340 million.

The unaudited consolidated pro forma net assets as at31 December 2018 is US$68 million.

B.9 Not applicable. The Company has not made any profitforecasts or estimates which remain outstanding as at thedate of this document.

B.10 Qualified audit report Not applicable. There are no qualifications in theaccountant’s report on the historical financial information.

B.11 Not applicable. The Company is of the opinion that theworking capital available to the Enlarged Group (which forthe avoidance of doubt includes the Marathon Group) issufficient for the present requirements of the EnlargedGroup, that is, for at least the next 12 months following thedate of this document.

Section C – Securities

C.1 No new Ordinary Shares are being offered in connectionwith Admission. Application will be made for the OrdinaryShares to be admitted to the Official List with a StandardListing and to be admitted to trading on the Main Market ofthe London Stock Exchange. The Ordinary Shares will beregistered with ISIN GB00BYNFCH09, SEDOL BYNFCH0and have a TIDM RRE.

C.2 UK Pounds Sterling.

C.3 Issued share capital 13,090,595 Ordinary Shares of a nominal value of 20 penceeach in issue and fully paid.

C.4 Shareholders will have the right to receive notice of and toattend and vote at any meetings of Shareholders. EachShareholder entitled to attend and being present in personor by proxy at a meeting of Shareholders will, upon a showof hands, have one vote and upon a poll each suchShareholder present in person or by proxy will have onevote for each Ordinary Share held by him.

In the case of joint holders of an Ordinary Share, if two ormore persons hold an Ordinary Share jointly, either of themmay be present in person or by proxy at a meeting ofShareholders and may speak on behalf of all joint owners asa Shareholder, and if two or more joint holders are presentat a meeting of Shareholders, in person or by proxy, theymust vote as one.

Pre-emption rights were disapplied (in respect of shareissues whether for cash or otherwise) in favour of existingShareholders up to a maximum nominal amount of

Profit forecast orestimate

Insufficient workingcapital

Description of the typeand the class of thesecurities being offered

Currency of thesecurities issue

Rights attached to thesecurities

Annex XXII (I),

B.9

Annex XXII (I),

B.10

Annex XXII (III),

B.11

Annex XXII (III),

C.1

Annex III, 4.1

Annex XXII (III),

C.2

Annex III, 4.4

Annex XXII (I III),

C.3

Annex XXII (III),

C.4

22


£504,002 at the Company’s annual general meeting on4 June 2019 for a period of 15 months of that date or theholding of the Company’s next annual general meeting,whichever is the earlier.

Subject to the Companies Act, on a winding-up of theCompany the assets of the Company available fordistribution shall be distributed, provided there are sufficientassets available, first to the holders of Ordinary Shares in anamount up to 20 pence in respect of each fully paid upOrdinary Share. If, following these distributions to holders ofOrdinary Shares there are any assets of the Company stillavailable, they shall be distributed to the holders of OrdinaryShares pro rata to the number of such fully paid up OrdinaryShares held (by each holder as the case may be) relative tothe total number of issued and fully paid up OrdinaryShares.

C.5 The Ordinary Shares are freely transferable and tradableand there are no restrictions on transfer.

Each member may transfer all or any of his shares which arein certificated form by means of an instrument of transfer inany usual form or in any other form which the Directors mayapprove. Each member may transfer all or any of his shareswhich are in uncertificated form by means of a ‘relevantsystem’ (i.e., CREST) in such manner provided for, andsubject as provided in, the CREST Regulations.

C.6 As the Marathon Acquisition was classified as a ReverseTakeover, upon publication of this document the StandardListing of all of the Ordinary Shares will be cancelled, andapplications have been made for the admission of theExisting Issued Share Capital to Standard Listing and totrading on the Main Market of the London Stock Exchange.It is expected that Admission will become effective and thatunconditional dealings will commence on the London StockExchange at 8:00 a.m. on 24 July 2019. The OrdinaryShares will not be listed on any other regulated market.

C.7 Dividend policy On 26 January 2018, the Company announced proposalsfor a “B Share Scheme” to return £1.50 per Ordinary Shareto Shareholders. On 16 February 2018, the Companyconfirmed that the B Shares had been redeemed by theCompany for £1.50 per B Share, following which theShareholders entitled to receive payments in respect of theproceeds of the redemption of the B Shares received suchpayments on or around 23 February 2018.

The Company intends to pay dividends on the OrdinaryShares at such times (if any) and in such amounts (if any)as the board of Directors of the Company (the “Board”)determines appropriate. The Company will only paydividends to the extent that to do so is in accordance withthe Companies Act and all other applicable laws, and theDirectors will review the Company’s dividend policy fromtime to time.

Annex XXII (III),

C.5

Restrictions ontransferability

Annex XXII (III),

C.6

Application for admissionto trading on a regulatedmarket

Annex XXII (I),

C.7

23


Section D – Risks

D.1 • The Group has developed its business through themaking of acquisitions. The agreements governingthose acquisitions, each contain certain indemnitiesand warranties given by the Company in favour of thesellers and the wider group entities of the sellers. Inparticular, the agreements contain indemnities inrespect of decommissioning liabilities andenvironmental liabilities.

• The Group, through its licence interests, hasobligations in respect of the decommissioning of itswells, fields and related infrastructure. These liabilitiesare derived from legislative and regulatoryrequirements concerning the decommissioning ofwells and production facilities. It is difficult toaccurately forecast the ultimate costs that the Groupwill incur in satisfying its decommissioning obligations.As its decommissioning liabilities become due, theGroup is liable either on its own or jointly and severallyliable for them with any other former or currentpartners in the field.

• Prevailing oil and gas prices may also have asignificant impact on the timing of decommissioning.Whilst UK Government strategy is to maximiseeconomic recovery, clearly this is only achievable inthe event that field life extension plans areeconomically viable, which in turn is almost entirelydependent on the prevailing oil price.

• The risk associated with these projects relates touncertainty in areas that impact the project costs,namely: stakeholder requirements; specific conditionsrelated to individual assets; costs for major contracts;and rig and vessel rates, estimates of costs beinginsufficient and assumption inaccurate all of whichcould lead to significant and material unplannedliabilities.

• The Marathon Acquisition Agreements contain certainindemnities and warranties given by the Company infavour of the sellers and the wider group entities of thesellers. These indemnities and warranties have thepotential to create significant liabilities. Whilst theindemnification of vendors in respect of alldecommissioning and environmental liabilities inrespect of acquired licence interests is customary intransactions of the nature of those concluded by theGroup in the North Sea, these indemnities and theassumption of these liabilities have the potential toexpose the Group to significant liabilities which mayhave arisen historically prior to the Group acquiringthe licence interest and in respect of which the Groupwill have no recourse to the vendor or historic owner.

Annex XXII (I),

D.1

Key information on thekey risks that are specificto the issuer or itsindustry

24


• The Group holds interests of a size in the some of itsunderlying licence assets which will result in limitedinfluence. Some of the licence interests acquired bythe Company are operated by joint venture partnersand any further acquisitions of licence interests mayalso be operated by joint venture partners, and theGroup’s ability to influence these operating partnersmay sometimes be limited due to the Group’s limitedequity in such ventures. The objectives and drivers ofjoint venture partners may not be aligned with those ofthe Group and this may lead to operational orproduction inefficiencies and/or delays, or a disruptivedeparture by one or more partners from the jointventure. Any mismanagement of these projects by theoperator may result in increased costs to the Groupwhich could adversely affect its business, results ofoperations, cash flow and prospects.

• The Company may face substantial competition foradditional assets or business acquisitions.

• Whilst MOUK is currently the designated operator ofcertain of the licence interests acquired pursuant tothe Marathon Acquisition, on 20 June 2019 MOUKwas notified by TAQA Bratani Limited (“TAQA

Bratani”), a significant non-operator interest holder inthose licences, following the approval of proposalsmade by TAQA Bratani to the other members of therelevant operating committees on 5 June 2019, thatMOUK would be discharged as operator ofBlocks 16/7a, Licence no. P.108 (Block 16/3a),Licence no. P313 (Block 16/3b), Licence no. P313(Block 16/3c) and East Brae and TAQA Brataniappointed in its place. No reasons were given for thechanges. A process will follow, involving OGAapproval, which could result in the Group losingoperatorship of these licences in July 2020. Whilst theGroup would not suffer any financial loss as a result oflosing its operatorship, any loss of operatorship maymake further acquisitions involving the assumption ofoperatorship more complex and cumbersome from aregulatory compliance perspective should the Grouphave to formally satisfy the OGA of its capability toassume operatorship absent current designatedoperator status.

• The Company is dependent on the Directors andSenior Managers to identify potential acquisitionopportunities and to execute them and the lossunexpected of the services of the Directors couldmaterially adversely affect the ability of the Companyto continue its current strategy.

25


• There are inherent risks associated with participationsin defined benefit staff pension schemes. The Groupmaintains an active dialogue with the trustees of thedefined benefit pension scheme which it inherited withthe marathon Acquisition and intends, in due course,to move to full buyout proposals. However this courseof action is subject to the agreement of the trusteesand potentially that of the Pensions Regulator.

• A substantial or extended decline in oil, natural gasand power prices or consumption may adverselyaffect the Group’s prospects, business, financialcondition and results of operations.

• The expense of meeting environmental regulationscould cause a significantly negative effect on theGroup’s long term profitability, as could the failure toobtain certain necessary environmental permits.

D.3 • A Standard Listing affords Shareholders lessregulatory protection than a Premium Listing, whichmay have an adverse effect on the valuation of theOrdinary Shares.

• The proposed Standard Listing of the Ordinary Sharesmay not afford Shareholders the opportunity to vote toapprove any further acquisition.

Section E – Offer

E.1 Not applicable. There is no offer of the Company’ssecurities.

E.2a Not applicable. There is no offer of the Company’ssecurities.

E.3 Not applicable. There is no offer of the Company’ssecurities.

E.4 Material interests Not applicable.

E.5 Not applicable. There is no offer of the Company’s securitiesand there are no selling shareholders.

E.6 Dilution Not applicable. There is no offer of the Company’ssecurities.

E.7 Not applicable. There are no commissions, fees orexpenses to be charged to investors in connection withAdmission.

The costs and expenses of Admission will be borne by theCompany and are not expected to exceed an aggregate of£4,000,000, which comprise: pensions advice of £254,000,corporate finance advisory fees of £754,000, specialistaccountancy services of £164,000; reporting accountantscosts of £500,000, legal fees of £1,130,000, competentpersons costs of £330,000, printing and production costs of£120,000 and other third party consultancy fees of £748,000.

Annex XXII (III),

D.3

Key information on thekey risks that are specificto the securities

Annex XXII (III),

E.1 Annex III, 3.4

Total net proceeds/expenses

Annex XXII (III),

E.2a

Reasons for the offerand use of proceeds

Annex XXII (III),

E.3

Terms and conditions ofthe offer

Annex XXII (III),

E.4

Annex XXII (III),

E.5

Selling Shareholders/Lock-up agreements

Annex XXII (III),

E.6

Expenses charged toinvestors

Annex XXII

(I, II, III), E.7

26

172846 Proof 3 Friday, July 19, 2019 12:30

PART II

RISK FACTORS

Investment in the Company and the Ordinary Shares carries a significant degree of risk, including

risks in relation to the Company’s business strategy, risks relating to taxation and risks relating to

the Ordinary Shares.

Prospective investors should note that the risks relating to the Group, its industry and the Ordinary

Shares summarised in Part I – Summary of this document are the risks that the Directors believe

to be the most essential to an assessment by a prospective investor of whether to consider an

investment in the Ordinary Shares. However, as the risks which the Group faces relate to events

and depend on circumstances that may or may not occur in the future, prospective investors should

consider not only the information on the key risks summarised in Part I – Summary of this

document but also, inter alia, the risks and uncertainties described below.

The risks referred to below are those risks the Group and the Directors consider to be the material

risks relating to the Group. However, there may be additional risks that the Group and the Directors

do not currently consider to be material or of which the Group and the Directors are not currently

aware that may adversely affect the Group’s business, financial condition, results of operations or

prospects. Investors should review this document carefully and in its entirety and consult with their

professional advisers before acquiring any Ordinary Shares. If any of the risks referred to in this

document were to occur, the results of operations, financial condition and prospects of the Group

could be materially adversely affected. If that were to be the case, the trading price of the Ordinary

Shares and/or the level of dividends or distributions (if any) received from the Ordinary Shares

could decline significantly. Further, investors could lose all or part of their investment.

Prospective investors should pay particular attention to the fact that some of the Group’s assets

are located overseas, which have legal and regulatory regimes that differ from the legal and

regulatory regimes of the United Kingdom.

RISKS RELATING TO THE OPERATORSHIP AND ACQUIRED LICENCE INTERESTS

Indemnities, warranties and parent company guarantees under acquisition agreements

The Group has developed its business through the making of acquisitions. The agreementsgoverning those acquisitions, each contain certain indemnities and warranties given by theCompany in favour of the sellers and the wider group entities of the sellers. In particular, theagreements contain indemnities in respect of decommissioning liabilities and environmentalliabilities.

The Group may be subject to unforeseen liabilities and risks arising from the Marathon

Acquisition

Whilst the Company has access to information on the underlying licence interests it has acquiredand reviewed information disclosed by the respective sellers during the acquisition processes,there can be no assurance that the licence assets are not subject to third party rights and liabilitiesof which the Company is unaware. Whilst some warranty and other protection is provided for bythe sellers under the relevant acquisition agreements, these warranties and protections are subjectto financial and other customary limitations and there is no certainty that the Group would be ableto enforce its contractual or other rights against the sellers or recover the full amount of any lossessuffered by the Group. The effect of these provisions is that the Group has assumed all futureresponsibility for decommissioning and environmental liabilities regardless of when those liabilitiesarose. Whilst this reflects market practice with respect to the sale and purchase of interests inlicences in the North Sea (or the sale of corporate entities owning licence interests), it substantiallyincreases risks associated with historic liabilities, some of which may be unknown at the time ofthe acquisition. Whilst decommissioning is a certain future event and decommissioning liabilities

Annex I, 4

Annex III, 2

27


are capable of reasonable estimation, environmental liabilities relating to historic acts or omissionsmay take many years to manifest themselves or even be capable of discovery (particularly at sub-sea level) at which point they may have become issues of significant magnitude. There isaccordingly a significant risk that, particularly in respect of environmental liabilities, an issue whollyunknown or undiscoverable at the time of acquisition may give rise to a material future liability forwhich the Group will have no recourse to the relevant vendor or historic owner.

The Group cannot predict its future decommissioning liabilities with complete accuracy

The Group, through its licence interests, has assumed certain obligations in respect of thedecommissioning of its wells, fields and related infrastructure. These liabilities are derived fromlegislative and regulatory requirements concerning the decommissioning of wells and productionfacilities contained in, inter alia, the Petroleum Act 1998, the OSPAR Decision 98/3 and OSPARRecommendation 2006/5 on a management scheme for offshore cuttings piles and require theGroup to make provisions for and/or underwrite the liabilities relating to such decommissioning. Itis difficult to accurately forecast the costs that the Group will incur in satisfying its decommissioningobligations. This is largely because the expenditure associated with decommissioning a field willnot be incurred until it has ceased production. The economic limit tests conducted by ERCEquipoise for most of the producing fields in which the Company has an interest shows that thisdate is more than six years in the future; for a significant number of fields, this is more than adecade in the future. When a particular decommissioning liability falls due, the Group will be liableeither on its own or jointly and severally liable for it with other former or current partners in the field.In the event that it is jointly and severally liable with other partners and such partners default ontheir obligations, the Group could remain liable and its decommissioning liability could bemagnified significantly through such default. Any significant increase in the actual or estimateddecommissioning costs that the Group incurs may adversely affect its financial condition.

Decommissioning planning

The Group is required to contribute potentially substantial sums to fund its share of planned andactual decommissioning costs. Generally, liability for decommissioning costs falls upon the licenceholders in proportion to their respective working interests in the relevant licences. Howeverdecommissioning costs may also be substantially mitigated by tax relief which is given whendecommissioning costs are actually paid.

The current total decommissioning obligations of the Group have been audited by ERC Equipoiseand are based on estimates from the relevant appointed operators where available and onRockRose’s internal estimates in other cases where the operator is yet to produce an estimate. Asof 31 March 2019, these amount to an estimated £456.9 million (US$567 million) in respect of UKassets and an estimated €115.8 million (US$129.8 million) in respect of Dutch assets on a “post-tax” basis, of which US$211.8 million has been posted in cash or alternative security under variousdecommissioning security agreements (“DSAs”) or alternative interim arrangements. £37.0 million(US$50.0 million) plus €0.6 million (US$0.7 million) of these “post-tax” amounts are expected to bespent between 1 April 2019 and 31 December 2020.

Whilst all actual and estimated decommissioning liabilities have been factored into the Company’sfinancial projections, there can be no assurance that estimates will prove to be accurate either interms of amount or timing. Where operator plans have been prepared, there can be no guaranteeor assurance that circumstances will not materially change, that cost estimates will not becomedated, that assumptions will not turn out to be unrealistic and/or unreliable, or that the actual timingof activities or contributions will not materially change in an adverse way.

Whilst the Group will continue to budget conservatively for its ultimate decommissioning liabilities,a lack of detailed plans, budgets and formal decommissioning agreements (where assets are stillsome way from the formal decommissioning stage) combined with the risk of earlydecommissioning on certain later stage assets create uncertainties and potentially materialfinancial risks for the Group. The fact that the Group is a minority interest holder in many of the

28


later life field interests creates the additional risk that the Group may have little or no control overthe timing of decommissioning nor the ability to exert significant influence over planning andcostings for decommissioning, which is generally determined and decided by the operator and theholders of the majority interests in each field interest.

The risk associated with decommissioning projects relates to uncertainty in areas that impact theproject costs, including: stakeholder requirements; specific conditions related to individual assets;costs for major contracts; and rig and vessel rates. All of these could lead to significant andmaterial unplanned liabilities. For these reasons initial operator estimates of decommissioningcosts may be unreliable and significantly underestimate the eventual liabilities of the parties withinterests in the fields to be decommissioned. This risk is however likely to decrease over time asmore decommissioning exercises are completed.

Timing of decommissioning

Whilst it is UK Government strategy to maximise economic recovery in the North Sea, theeconomic viability of field life extension plans, often at lower levels of production and at amarginally greater cost of recovery, will be highly sensitive to commodity price fluctuations.Prolonged periods of low oil prices and/or commodity price fluctuations, may render field lifeextension plans uneconomic or practicably unachievable and this in turn may lead to anacceleration of decommissioning plans and the payment of the associated costs with such plans.DSAs are designed to ensure that the holders of licence interests post cash or alternative securityfor their decommissioning liabilities over a period of time, particularly towards the later stage of theproducing life of a field, so that all partners in the licence have protection in the event that one oftheir number was unable to finance a significant sum on cessation of production. However regularpostings of cash or equivalent security under the terms of the DSAs are determined by theoperator, generally annually. The sums posted are determined on the basis of the then prevailingcircumstances, including primarily anticipated decommissioning costs and the estimated net valueof the hydrocarbons expected to be recovered during the remaining life of the field. A sudden andsustained drop in oil prices or a technical event or events could cause cessation of production tobe brought forward and the licence interest holders having to fund decommissioning costs whichthey might have expected to have been funded out of future production. In such circumstances theGroup may have to use existing cash resources to fund accelerated decommissioningprogrammes. Whilst the Group has paid all of its actual decommissioning costs on time anddecommissioning activities to date have been completed on time and to budget, the Groupcontinues to adopt a prudent and conservative approach to maintaining cash reserves to covercontingencies, it is possible that unexpected or unanticipated accelerated decommissioning costsmight have a negative effect on the Group’s ability to pursue other acquisitions or developmentopportunities within its existing portfolio of licence interests.

Joint venture partner alignment and other contractual counterparties

Except in respect of the licence interests owned by the Marathon Group (the “Marathon

Interests”), the Group is a holder of certain economic interests in the underlying assets and is notthe operator of any of the acquired licence interests. Participation in the licence interests isconducted in a joint venture environment. All of such licence interests are (exclusive of theMarathon Interests) operated by joint venture partners and the Group’s ability to influence certainof these operating partners may be limited due to the Group’s limited equity in such ventures.There is a risk that joint venture partners are not aligned in their objectives and drivers and thismay lead to operational or production inefficiencies and/or delays, or a disruptive departure by oneor more partners from the joint venture. Any mismanagement of these projects by the operator mayresult in increased costs to the Group which could adversely affect its business, results ofoperations, cash flow and prospects.

Whilst MOUK is currently the designated operator of Blocks 16/7a, Licence no. P.108(Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) and East Brae, on20 June 2019 MOUK was notified by TAQA Bratani, a significant non-operator interest holder in

29


those licences, following the approval of proposals made by TAQA Bratani to the other membersof the relevant operating committees on 5 June 2019, that MOUK would be discharged as operatorof Blocks 16/7a, Licence no. P.108 (Block 16/3a), Licence no. P313 (Block 16/3b), Licence no.P313 (Block 16/3c) and East Brae and TAQA Bratani appointed in its place. The situation isconsidered unusual in that TAQA Bratani did not cite any reasons for its proposals relating toperformance (or otherwise). Any change of operatorship is subject to the approval of the OGA andis not expected to occur prior to 1 July 2020 (at the earliest). Whilst the Group should not sufferany financial loss as a result of losing its operatorship, achieving operatorship on a significantasset portfolio was seen as a strategic benefit to the Group going forward with respect to otherpotential acquisition targets (where assuming operatorship may have been more achievable on amore expedient basis as an entity with a current operatorship designation).

Accordingly, any loss of operatorship may make further acquisitions involving the assumption ofoperatorship more complex and cumbersome from a regulatory compliance perspective should theGroup have to formally satisfy the OGA of its capability to assume operatorship absent currentdesignated operator status.

There can be no assurance that the Company will be able to make returns for Shareholders

in a tax-efficient manner

It is intended that the Company will structure and operate the Group, including any company orbusiness acquired, to maximise returns for Shareholders in as fiscally efficient a manner as ispracticable. The Company has made certain assumptions regarding taxation of the Group.However, if these assumptions are not correct, taxes may be imposed with respect to the assetsof the Group, or the Group may be subject to tax on its income, profits, gains or distributions (eitheron a liquidation and dissolution or otherwise) in a particular jurisdiction or jurisdictions in excess oftaxes that were anticipated. This could alter the post-tax returns for Shareholders (or Shareholdersin certain jurisdictions). The level of return for Shareholders may also be adversely affected. Anychange in laws or tax authority practices could also adversely affect any post-tax returns of capitalto Shareholders or payments of dividends. In addition, the Group may incur costs in taking stepsto mitigate any such adverse effect on the post-tax returns for Shareholders.

RISKS RELATING TO OPERATING IN THE OIL AND GAS EXPLORATION, DEVELOPMENT

AND PRODUCTION SECTOR

A substantial or extended decline in oil, natural gas and power prices or consumption may

adversely affect the prospects, business, financial condition and results of operations of

the Group

Historically, hydrocarbon and energy prices have been subject to large fluctuations in response toa variety of factors beyond the control of individual companies, including operation issues, naturaldisasters, weather, political instability or conflicts, and economic conditions or actions by major oil-exporting countries. Price fluctuations can affect business assumptions, investment decisions andfinancial position of the companies in the upstream oil gas and power sector and thereforeprospectively the Group. In particular, a substantial or extended decline in the price or consumptionof oil and gas could have a short or long term effect on the Company’s strategy and ultimately itsbusiness financial condition. Lower hydrocarbon prices or reduced demand for oil and gas orpower could reduce the economic viability of the Group’s strategy and ultimately its business,result in a reduction in revenues or net income, adversely affect the Group’s ability to maintainworking capital requirements, impair its ability to make planned expenditures and could materiallyadversely affect its prospects, financial condition and results of operations.

Oil and natural gas exploration and development are highly speculative activities

Oil and natural gas exploration is a highly speculative activity and there are a number of riskswhich may impact on the overall investment. There is no certainty that the expenditures theCompany makes towards the search and evaluation of oil and gas deposits will result indiscoveries of commercial quantities. The Company’s longer-term profitability is directly related to

Annex I, 9.2.3

30


the success of the project development and exploration activities. In the event that an explorationproject is unsuccessful, the value of the Company’s business and any associated explorationlicences may be diminished.

The longer-term success of the Group is dependent on accessing oil and natural gas

resources

The further appraisal and development of discoveries are uncertain and may involve unprofitableefforts, not only from dry wells, but also from wells that are productive but uneconomic to develop.Appraisal and development activities may be subject to delays in obtaining governmentalapprovals or consents, shut-ins of connected wells, insufficient storage or transportation capacityor other geological and mechanical conditions all of which may variously increase the Company’scosts of operations. Producing natural gas reservoirs are typically characterised by decliningproduction rates that vary depending upon reservoir characteristics and other factors. Producingwells may be enhanced by supplemental work programmes and by the drilling of new wells,however these processes carry an inherent risk of failure. In addition, the Company may not beable to economically develop, find, or acquire future reserves at acceptable costs.

The Group’s actual future exploration and production costs may differ materially from its

estimates, which may materially and adversely affect its viability in the long term

Exploration and production expenditure estimates are based on certain assumptions with respectto the method and timing of activities. By their nature, these estimates and assumptions aresubject to significant uncertainties and, accordingly, the actual costs may materially differ fromestimates and assumptions. Additionally, unconventional methods of exploration, recovery andproduction enhancement (often of particular importance in context of fields in the later stages oftheir productive life) are required which can be more expensive than conventional explorationmethods or production from fields in the initial stages of their productive lives. This could materiallyand adversely affect the Group’s viability and long term prospects.

If the Group is not granted licences or licence extensions, it could have a material adverse

effect on its reserves, business, operations and prospects

The Group may be unable or unwilling to comply with the terms or requirements of a licence incircumstances that entitle the relevant authority to refrain from granting, suspend or withdraw theterms of such licence. Moreover, exploration and production licences may expire before the end ofwhat might be the productive life of the licensed fields. There can be no assurance that extensionswill be granted and any failure to receive such extensions or any premature termination,suspension or withdrawal of licences may have a material adverse effect on the Group’s reserves,business, results of operations and prospects if the terminated licence relates to material assetsof the Group, although this risk has not materialised thus far.

The Group may suffer material losses from uninsurable or uninsured risks or insufficient

insurance coverage

The Group may be subject to substantial liability claims due to the inherently hazardous nature ofthe business of the target company or for acts and omissions of subcontractors, operators or jointventure partners. Any contractual indemnities it may receive from such parties may be difficult toenforce if such sub-contractors, operators or joint venture partners lack adequate resources. Therecan be no assurance that the proceeds of insurance applicable to covered risks will be adequateto cover related losses or liabilities. In addition, the Group may also suffer material losses fromuninsurable or uninsured risks. The occurrence of any of these risks could adversely affect thefinancial performance of the Group.

31


Estimation of resources, reserves and production profiles are based on judgments and

assumptions

In general, there is inherent risk in estimates of oil reserves, gas reserves and power generation,and their anticipated production profiles, because it involves subjective judgments anddeterminations based on available geological, technical, contractual and economic information.They are not exact determinations and the actual resources, reserves and production may begreater or less than those calculated. In addition, these judgments may change based on newinformation from production or drilling activities or changes in economic factors, as well as fromdevelopments such as acquisitions and disposals, new discoveries and extensions of existingfields and the application of improved recovery techniques. If any estimates of hydrocarbonresources, reserves or production profiles (including any competent person’s report (“Competent

Person’s Report”) upon which the Group relies upon in making any operational decision) prove tobe substantially incorrect, the Group may be unable to recover and produce the estimated levelsor quality of hydrocarbons set out in such estimates and the business, prospects, financialcondition or results of operations of the Group could be materially adversely affected.

The Group’s operations and assets expose it to significant compliance costs and liabilities

in respect of environmental and health and safety (“EHS”) matters

The operations and assets in which the Group will be involved are affected by numerous laws andregulations concerning EHS matters including, but not limited to, those relating to discharges ofhazardous substances into the environment, the handling and disposal of waste and the healthand safety of employees. The technical requirements of these laws and regulations are becomingincreasingly complex, stringently enforced and expensive to comply with and this trend is likely tocontinue. Any failure to comply with EHS laws and regulations may result in regulatory action(which strict, joint and several liability can include statutory orders requiring steps to be taken orprohibiting certain operations), the imposition of fines or the payment of compensation to thirdparties. For instance, on 20 May 2019 MOUK (now RockRose UKCS8) was fined £1,160,000 afteran investigation by the Health & Safety Executive (“HSE”) following a release of gas from the BraeAlpha platform on 26 December 2015. All of these liabilities and any other regulatory actions couldhave a material adverse effect on the Group’s business, financial condition, results of operationsand prospects.

A violation of EHS requirements and the occurrence of any accidents could disrupt the

Group’s operations and increase operating costs

EHS authorities such as the UK Department for Business, Energy & Industrial Strategy, HSE andSafety Executive and Offshore Safety Directive Regulator have extensive enforcement powersunder EHS laws and regulations. These powers extend to statutory notices to require operationalsteps and to prohibit certain activities or operations until compliance is achieved. A violation of EHSlaws and regulations, or failure to comply with the instructions of the relevant EHS authorities couldtherefore lead to, inter alia, a temporary shutdown of all, or a portion of, the Group’s facilities andthe imposition of costly compliance procedures. If EHS authorities shut down all, or a portion of,the Group’s facilities or impose costly compliance measures, the Group’s business, financialcondition, results of operations and prospects would be materially and adversely affected.

The nature of the operations in which the Group will be participating creates a risk of accidents andfatalities among its workforce, and the Group may be required to pay compensation or suspendoperations as a result of such accidents or fatalities, which could have a material adverse effecton the Group’s business, financial condition, results of operations and prospects.

Changes in global supply and demand owing to an economic downturn may adversely

affect the business, results of operations, cash flows and financial condition of the Group

Commodity prices are affected by global supply and demand, as well as widespread tradingactivities by market participants and others, either seeking to secure access to such commoditiesor to hedge against commercial risks, or as part of investment portfolio activity. Fluctuations in

Annex I, 8.2

32


commodity prices give rise to commodity price risk for the Group. Historically, such prices can besubject to substantial variation which cannot be accurately predicted.

If the global economic environment experiences a substantial downturn or remains relatively weakfor the medium to long term, the ability of the Group to grow or maintain revenues in future yearsmay be adversely affected, and at certain long term price levels for a given commodity, extractiveoperations with respect to that commodity may not be economically viable.

Adverse and volatile economic conditions may also limit the Group’s ability to anticipate revenuesand costs and can affect the Group’s ability to implement planned projects. In addition, industryanalysts are likely to take such conditions into account when assessing the prospective businessand creditworthiness of the Group and any adverse determinations, may make it more difficult forthe Group to raise capital in the future to finance the business.

The oil and gas, exploration, development and production sector is subject to commodity

price fluctuations, which may adversely impact the results of operations, financial

conditions and prospects of the Group

The Group, through its operations and assets, may be a market participant as seller (and may, incertain situations, be a buyer) in any one or more commodities. Accordingly, the Group’s revenueand earnings may depend upon prevailing prices for the commodities it relies on and produces.These commodities are globally traded and as a result, and in common with its competitors, theGroup is unable to control the prices it receives for such commodities. However, the Group saw anincrease in the average crude oil price US$72.95 per bbl for the financial year ended 31 December2018 compared to US$66.1 per bbl for the financial year ended 31 December 2017. In addition,the range of the commodities which the activities produce may not be sufficiently broad and/or theacquired activities may be concentrated in one or more commodities within the oil and gas,exploration, development and production sector. As a result, the Group may not be able to offsetprice changes in one commodity with countercyclical changes in another commodity within theGroup’s range of commodities in an attempt to mitigate the effects of adverse price changes.

Historically, commodity prices have been volatile and subject to wide fluctuations for manyreasons. It is impossible to predict accurately future commodities price movements andcommodities prices may not remain at their current levels. Any material declines in commoditiesprices, to the extent they are not addressed by meaningful hedging arrangements, could result ina reduction of the Group’s net production revenue.

Political, legal and commercial instability, as well as political and fiscal pressure on

governments, in the countries and territories in which the oil and gas, exploration,

development and production sector may operate could affect the viability of the Group’s

operations and assets

The Group may have operations and assets in jurisdictions with varying degrees of political, legaland commercial stability. Political, civil and social pressures may result in administrative change,policy reform, changes in law or governmental regulations, which in turn can result in expropriationor nationalisation of a target’s assets. Renegotiation or nullification of pre-existing agreements,concessions, leases and permits held by a target business, changes in fiscal policies (includingincreased tax or royalty rates) or currency restrictions are all possibilities. Commercial instabilitycaused by bribery may lead to similar consequences, any of which could have a material adverseeffect on the profitability, the ability to finance or, in extreme cases, the viability of an operation.

In addition, fiscal constraints or political pressure may also lead governments to impose increasedtaxation on operations in the oil and gas, exploration, development and production sector within agiven jurisdiction. Such taxes or other expropriation of assets could be imposed by any jurisdictionin which the Group operates. If operations are delayed or shut down as a result of political, legalor commercial instability, or if the Group’s operations are subjected to increased taxation or other

33


expropriation, the Group’s earnings growth may be constrained and the ability of the Group togenerate long term value for Shareholders could be adversely impacted.

Inflation and other cost increases may have an adverse effect on the Group’s results of

operations and cash flows

Significant inflation or other production cost increases in the countries in which the Group mayoperate could increase operational costs without a corresponding increase in the sales price of thecommodities the Group may produce. Alternatively, a lag in the reduction of input costs relative todeclining commodity prices will have a similar adverse effect on the Group’s operations. Any suchincreased costs or delays in cost reductions may adversely affect the Group’s profitability, cashflows and results of operations.

Existing and proposed legislation and regulation affecting greenhouse gas and other

emissions may adversely affect certain of the Group’s operations and assets

Many participants in the oil and gas, exploration, development and production sector are subjectto current and planned legislation in relation to the emission of carbon dioxide, methane and otherso called ‘greenhouse gases’, together with other pollutants, including nitrous oxide.

Failure to comply with existing legislation or any future legislation could adversely affect theGroup’s profitability if its business has material greenhouse gas intensive assets. Future legislativeinitiatives designed to reduce the consumption of hydrocarbons could also have an impact on theability of the Group to market its commodities and/or the prices which it is able to obtain. Thesefactors could have a material adverse effect on the Group’s business, results of operations,financial condition or prospects.

The Group may be unable to obtain or renew required drilling rights or exploration and

extraction rights and concessions, licences, permits and other authorisations (“Licences”)

and/or such Licences may be suspended, terminated or revoked prior to their expiration

An acquired company or business may conduct its operations pursuant to a wide variety ofLicences. Any delay in obtaining or renewing any Licence may result in a delay in investment ordevelopment of a resource and may have a material adverse effect on the acquired business’results of operations, cash flows and financial condition. There is no guarantee that all requiredLicences will be granted in accordance with the applications, nor that they will be granted onconditions satisfactory for the Group to operate its business. Such Licences contain conditions andrequirements that must be met in order to maintain such Licences. The Licences may besuspended, terminated or revoked if the Group fails to comply with the relevant requirements.Further, there can be no assurance that the relevant authorities will not significantly alter theconditions or area of, or that any third party will not challenge, the Licences held by the Group.There can further not be any assurance that an expired licence will be renewed. In addition, alicence may be revoked, in whole or in part, by the relevant competent authority in the Netherlandsin a limited number of circumstances set out in the Mining Act 2003 (the “Mining Act”).

If the Group fails to fulfil the specific terms of any of its Licences or if it operates its business in amanner that violates applicable law, government regulators may impose fines or suspend orterminate the Licences, any of which could have a material adverse effect on the Group’s resultsof operations, cash flows and financial condition.

The use of independent contractors in the Group’s operations may expose those

operations to delays or suspensions of activities

Independent contractors are typically used in operations in the oil and gas, exploration,development and production sector to perform various operational tasks, including carrying outdrilling and mining activities and delivering raw commodities to processing or beneficiation plants.In periods of high commodity prices, demand for such contractors may exceed supply resulting inincreased costs or lack of availability of key contractors. Disruptions of operations or increased

34


costs also can occur as a result of disputes with contractors or a shortage of contractors withparticular capabilities. Additionally, because the Group will not have the same control overindependent contractors as it does over its own employees, there is a risk that such contractorswill not operate in accordance with the Group’s safety standards or other policies. Any of theforegoing circumstances could have a material adverse effect on the Group’s operating results andcash flows.

Drilling operations are vulnerable to natural disasters, operating difficulties and damage to

or breakdown of a physical asset, any of which could have a material impact on the

productivity of the operations and not all of which may be covered by insurance

Drilling operations are vulnerable to natural disasters, including earthquakes, drought, floods, fire,tropical storms and the physical effects of climate change, all of which are outside the Group’scontrol. Operating difficulties, such as unexpected geological variations that could result insignificant failure, could affect the costs and viability of its operations for indeterminate periods. Inaddition, damage to or breakdown of a physical asset, including as a result of fire, explosion ornatural catastrophe, can result in a loss of assets and subsequent financial losses. Insurance canprovide protection from some, but not all, of the costs that may arise from unforeseen events.Although the Group intends to maintain suitable insurance, the Group’s insurance may not coverevery potential risk associated with its operations. Adequate coverage at reasonable rates is notalways obtainable. In addition, the Group’s insurance may not fully cover its liability or theconsequences of any business interruptions such as equipment failure or labour dispute. Theoccurrence of a significant adverse event not fully or partially covered by insurance could have amaterial adverse effect on the Group’s business, results of operations, financial condition andprospects.

Labour disruptions could have an adverse effect on the Group’s results of operations, cash

flows and financial condition

There is a risk that strikes or other types of conflict with unions or employees may occur at anyone of the Group’s operations or in any of the geographic regions in which the Group operates.Any labour disruptions could increase operational costs and decrease revenues by delaying thebusiness activities of the Group or increasing the cost of substitute labour, which may not beavailable. Furthermore, if such disruptions are material, they could adversely affect the Group’sresults of operations, cash flows and financial condition.

Restrictions on the Group’s ability to access necessary infrastructure services, including

transportation and utilities, may adversely affect the Group’s operations

Inadequate supply of the critical infrastructure elements for drilling activity could result in reducedproduction or sales volumes, which could have a negative effect on the Group’s financialperformance. Disruptions in the supply of essential utility services, such as water and electricity,can halt the Group’s production for the duration of the disruption and, when unexpected, maycause loss of life or damage to its drilling equipment or facilities, which may in turn affect its abilityto recommence operations on a timely basis. Adequate provision of transportation services, suchas timely pipeline and port access and rail services, are critical to distributing products anddisruptions to such services may affect the Group’s operations. The Group may be dependent onthird party providers of utility and transportation services. As such, third party provision of services,maintenance of networks and expansion and contingency plans will be outside of the Group’scontrol.

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Exploration, development and production activities are capital intensive and inherently

uncertain in their outcome. As a result, the Group may not generate a return on its

investments or recover its costs and it may not be able to generate cash flows or secure

adequate financing for its discretionary capital expenditure plans

Exploration, development and production activities are capital intensive and inherently uncertain intheir outcome. The Group’s future oil and gas, exploration, development and production projectsmay involve unprofitable efforts, either from dry wells or from wells that are productive but do notproduce sufficient net revenues to return a profit after development, operating and other costs.Furthermore, completion of a well does not guarantee a profit on the investment or recovery of thecosts associated with that well. In addition, drilling hazards or environmental damage couldsignificantly affect operating costs, and production from successful wells may be adverselyaffected by conditions including delays in obtaining governmental approvals or consents, shut-insof connected wells resulting from extreme weather conditions, aged or defective facilitycomponents, insufficient storage or transportation capacity or adverse geological conditions.Production delays and declines, whether or not as a result of the foregoing conditions, may resultin lower revenue or cash flows from operating activities until such time, if at all, that the delay ordecline is cured or arrested.

Exploration, development and production activities are inherently subject to a number of

potential drilling and production risks and hazards which may affect the ability of the

Group, if it acquires or establishes any oil and gas, exploration, development and

production activities to produce oil and gas at expected levels, increase operating costs

and/or expose the Group and/or its directors and officers to legal liability

The production and development operations of the Group will involve risks normally associatedwith such activities, including blowouts, explosions, fires, equipment damage or failure, geologicaluncertainties, unusual or unexpected rock formations and abnormal pressures and environmentalhazards such as accidental spills, releases or leakages of petroleum liquids, gas leaks, rupturesor discharges of toxic gas. Operations are also subject to hazards inherent in marine operations,which include damage from severe weather conditions, capsizing or sinking, and damage topipelines and subsea facilities from fishing nets, anchors and vessels. The occurrence of any ofthese events could result in production delays or the failure to produce oil and gas in commercialquantities from the affected operations. These events could also lead to environmental damage,injury to persons and loss of life or the destruction of property, any of which could expose theGroup and/or its directors and officers to the risk of litigation and clean-up or other remedial costs.Damages claimed in connection with any consequent litigation and the costs to the Group indefending itself against such litigation are difficult to predict and may be material. For example, on20 May 2019 MOUK (now RockRose UKCS8) was fined £1,160,000 after an investigation by theHSE following a release of gas from the Brae Alpha platform on 26 December 2015. In addition,the Group could experience adverse publicity as a result of any such litigation. Any loss ofproduction or adverse legal consequences stemming from production hazards could have amaterial adverse effect on the Group’s business, results of operations, financial condition orprospects.

RISKS RELATING TO THE GROUP’S BUSINESS AND ACQUISITION STRATEGY

The Group’s principal source of operating cash will be income received from the sale of

petroleum products extracted from the wells on the licence interests

The Group will be dependent on the income generated by its licence interests to meet theexpenses and operating cash requirements of the Group in the longer term. The amount ofdistributions and dividends, if any, which may be paid from any operating subsidiary to the Groupwill depend on many factors, including such subsidiary’s results of operations and financialcondition, limits on dividends under applicable law, its constitutional documents, documentsgoverning any indebtedness of the Group, and other factors which may be outside the control of

36


the Group. If the licence interests fail to generate sufficient cash flow in the longer term, the Groupmay be unable to pay its expenses or make distributions and dividends on the Ordinary Shares.

There is no assurance that any operating improvements will be successful or that they will

be effective in increasing the valuation of any business acquired

There can be no assurance that the Group will be able to propose and implement effectiveoperational improvements for any company or business which the Group acquires, particularly ifthe Group acquires a stake in a licence asset which does not give it operational control orsignificant influence. In addition, general economic and market conditions or other factors outsidethe Group’s control could make the Group’s operating strategies difficult or impossible toimplement. Any failure to implement these operational improvements successfully and/or thefailure of these operational improvements to deliver the anticipated benefits could have a materialadverse effect on the Group’s results of operations and financial condition.

The Group may face substantial competition for additional assets or business acquisitions

At the time of the Initial Admission, oil prices were at levels below US$30 per barrel and the OGAMER strategy had not been formally adopted. As a result many asset owners put portfolios ofassets in the North Sea, particularly later stage assets, on the market, looking to raise cash and/orseek to avoid or mitigate decommissioning costs. Oil prices have since recovered and stabilisedwith the consequence that many parties who might have historically been sellers at low prices (oreven for negative consideration) have now revisited their own strategies and might be less willingto sell at prices driven by an ultra-low oil price environment. In addition, several companies havebeen established with a strategy similar to that of RockRose in the past 36 months, some listed onpublic markets and others backed by private equity finance, such as Israel’s Delek Group andChrysaor. Increased competition for assets, particularly from private equity backed entities with theability to rapidly call upon substantial debt financing, may impact the ability of the Group tocontinue to be able to make future acquisitions on the advantageous terms that it has been ableto secure with respect to historic transactions.

The Group is dependent on the Directors and Senior Managers and the unexpected loss of

the services of any of the Directors and Senior Managers could materially adversely

affect it

The Group remains dependent upon the Directors and Senior Managers. The unexpected loss ofthe services of any or all of the Directors and Senior Managers could have a material adverseeffect on the Group’s ability to identify potential additional acquisition opportunities and to executefurther acquisitions.

The Group is dependent on Andrew Austin and the Senior Managers (the “Executive Team”)

to operate the business and may be unable to recruit replacement personnel with the

requisite skills

The Group depends on the Executive Team to lead its business effectively. Although it is notanticipated that any Senior Managers will be lost or replaced in the near future, competitors mayseek to recruit the Group’s key personnel and the loss of the services of any or all of the ExecutiveTeam could have a material adverse effect on the Group’s business, results of operations andoverall financial condition. There may be a limited number of persons with the requisite skills toserve in such positions and the Group cannot be certain that it would be able to locate or employsuch qualified personnel on acceptable terms in a timely manner or at all.

The Company may be subject to foreign investment and exchange risks

The Company’s presentational currency is US Dollars. As a result, the Company’s consolidatedfinancial statements will carry the Company’s assets in US Dollars. Any business the Companyacquires may denominate its financial information in a currency other than US Dollars, conductoperations or make sales or incur expenditure in currencies other than US Dollars. When

Annex III, 4.4

37


consolidating a business that has functional currencies other than US Dollars, the Company willbe required to translate, inter alia, the balance sheet and operational results of such business intoUS Dollars. Due to the foregoing, changes in exchange rates between US Dollars and othercurrencies could lead to significant changes in the Company’s reported financial results fromperiod to period. Among the factors that may affect currency values are trade balances, levels ofshort-term interest rates, differences in relative values of similar assets in different currencies,long-term opportunities for investment and capital appreciation and political or regulatorydevelopments. Although the Company may seek to manage its foreign exchange exposure,including by active use of hedging and derivative instruments, there is no assurance that sucharrangements will be entered into or available at all times when the Company wishes to use themor that they will be sufficient to cover the risk.

The Company may be subject to risks particular to one or more countries in which it

ultimately operates, which could negatively impact its operations

The Company’s efforts in identifying further prospective target companies or businesses in the oiland gas, exploration and development sector are not limited to a particular geographic region. TheCompany may acquire further companies or businesses in, or with substantial operations in, anumber of jurisdictions, any of which may expose it to considerations or risks associated withcompanies operating in such jurisdictions, including but not limited to: regulatory and politicaluncertainty; tariffs, trade barriers and regulations related to customs and import/export matters;international tax issues, such as tax law changes and variations; cultural and language differences;rules and regulations on currency conversion or corporate withholding taxes on individuals;currency fluctuations and exchange controls; employment regulations; crime, strikes, riots, civildisturbances, terrorist attacks and wars; and deterioration of relevant political relations. Anyexposure to such risks due to the countries in which the Company operates following a furtheracquisition could negatively impact the Company’s operations.

RIKS RELATED TO THE DEFINED BENEFIT PENSION SCHEME

There are inherent risks associated with participations in defined benefit pension schemes

The Group currently operates a defined benefit pension scheme (the “DB Scheme”) and a definedcontribution schemes (the “DC Scheme”) for employees and former employees of the MarathonGroup which it acquired pursuant to the Marathon Acquisition. In March 2010, the DB Scheme wasclosed to new entrants and the DC Scheme was established on 1 April 2010 for new employees.The DB Scheme was closed to future accrual on a defined benefit basis in December 2015.Employees who were accruing benefits in the DB Scheme at that point transferred to the DCScheme for future service accrual.

To manage and curtail risks associated with the DB Scheme the Company intends to advanceproposals to move the DB Scheme to a full buy-out position in the near term. This involvestransferring all of the DB Scheme to an insurance company who will, in return for a lump sumpayment, take over the DB Scheme and all of its liabilities to the members. Completing a buy-outprocess is subject to certain specific risks, primarily the agreement of the cost of such a transferand determining the agreement to such a process from the transfer of the DB Scheme.

Factors that affect the position of the DB Scheme includes: investment performance of the DBScheme’s assets; contributions; changes to actuarial assumptions; and experience relative to theassumptions. Changes in fixed income, credit, equity, property, derivative and other markets mayimpact both the value of the DB Scheme assets and the value placed on scheme liabilities. Otherchanges in market conditions, the economic environment (such as inflation), demographics(including, but not limited to, member longevity) and the choices of the DB Scheme members canalso impact the financial position of the DB Scheme. Additionally, the strength and reportedposition of the DB Scheme could be affected by applicable changes in regulation and legislationand relevant changes in financial reporting standards, guidance and interpretation.

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As required by applicable law and regulatory guidance, matters including the funding position ofthe DB Scheme and the amount of contributions payable are reviewed and agreed with the DBScheme trustees on a regular basis. Such matters could also be reviewed following any materialchange to the financial position of the DB Scheme. A deterioration in the funding position mayrequire a revised funding plan to be agreed to make good the deficit over a period of time, andcould also include a range of other actions to manage the liabilities. The financial position of theDB Scheme may affect the Group’s financial performance and financial statements.

RISKS RELATING TO THE ORDINARY SHARES

Disapplied pre-emption rights and indebtedness related liquidity

The Directors anticipate that the Company may issue a substantial number of additional OrdinaryShares, or incur substantial indebtedness to complete one or more further acquisitions.

Pre-emption rights were disapplied (in respect of future share issues whether for cash orotherwise) in favour of existing Shareholders up to a maximum nominal amount of £504,002 at theCompany’s annual general meeting on 4 June 2019 for a period of 15 months of that date orthe holding of the Company’s next annual general meeting, whichever is earlier. In addition, theCompany may issue shares or convertible debt securities or incur substantial indebtedness tocomplete a further acquisition, which may dilute the interests of Shareholders.

Any issue of Ordinary Shares, preferred shares or convertible debt securities may:

• significantly dilute the value of the Ordinary Shares held by existing Shareholders;

• cause a change of control if a substantial number of Ordinary Shares are issued, which may,

• inter alia, result in the resignation or removal of one or more of the Directors;

• in certain circumstances, have the effect of delaying or preventing a change of control;

• subordinate the rights of holders of Ordinary Shares if preferred shares are issued with rightssenior to those of Ordinary Shares; or

• adversely affect the market prices of the Ordinary Shares.

If Ordinary Shares, preferred shares or convertible debt securities are issued as consideration fora further acquisition, existing Shareholders will have no pre-emptive rights with regard to thesecurities that are issued. The issue of such Ordinary Shares, preferred shares or convertible debtsecurities is likely to materially dilute the value of the Ordinary Shares held by existingShareholders. Where a target company has an existing large shareholder, an issue of OrdinaryShares, preferred shares or convertible debt securities as consideration may result in suchshareholder subsequently holding a significant or majority stake in the Company, which may, inturn, enable it to exert significant influence over the Company (to a greater or lesser extentdepending on the size of its holding) and could lead to a change of control.

If the Company were to incur substantial indebtedness in relation to a further acquisition, this couldresult in:

• default and foreclosure on the Company’s assets, if its cash flow from operations wereinsufficient to pay its debt obligations as they become due;

• acceleration of its obligation to repay indebtedness, even if it has made all payments whendue, if it breaches, without a waiver, covenants that require the maintenance of financialratios or reserves or impose operating restrictions;

• a demand for immediate payment of all principal and accrued interest, if any, if theindebtedness is payable on demand; or

Annex III, 2, 6.1

39


• an inability to obtain additional financing, if any indebtedness incurred contains covenantsrestricting its ability to incur additional indebtedness.

The occurrence of any or a combination of these factors could decrease an investor’s ownershipinterests in the Company or have a material adverse effect on its financial condition and results ofoperations.

There may be a limited market for the Ordinary Shares. A market for the Ordinary Shares

may not develop, which would adversely affect the liquidity and price of the Ordinary

Shares

The price of the Ordinary Shares after Admission can vary due to a number of factors, includingbut not limited to, general economic conditions and forecasts, the Company’s general businesscondition and the release of its financial reports. Although the Company’s current intention is thatits Ordinary Shares should continue to trade on the Main Market of the London Stock Exchange,it cannot assure investors that it will always do so. In addition, an active trading market for theOrdinary Shares may not develop or, if developed, may not be maintained. Investors may beunable to sell their Ordinary Shares unless a market can be established and maintained, and if theCompany subsequently obtains a listing on an exchange in addition to, or in lieu of, the LondonStock Exchange, the level of liquidity of the Ordinary Shares may decline.

Investors may not be able to realise returns on their investment in Ordinary Shares within

a period that they would consider to be reasonable

Investments in Ordinary Shares may be relatively illiquid. There may be a limited number ofShareholders and this factor may contribute both to infrequent trading in the Ordinary Shares onthe London Stock Exchange and to volatile Ordinary Share price movements. Investors should notexpect that they will necessarily be able to realise their investment in Ordinary Shares within aperiod that they would regard as reasonable. Accordingly, the Ordinary Shares may not be suitablefor short-term investment. Admission should not be taken as implying that there will be an activetrading market for the Ordinary Shares. Even if an active trading market develops, the market priceper Ordinary Share may fall below the market price per Ordinary Share prevailing immediatelyprior to the suspension of the Company’s listing on 25 February 2019.

Dividend payments on the Ordinary Shares are not guaranteed

To the extent the Company intends to pay dividends on the Ordinary Shares, it will pay suchdividends at such times (if any) and in such amounts (if any) as the Board determines appropriateand in accordance with applicable law, but expects to be principally reliant upon dividends receivedon shares held by it in any operating subsidiaries in order to do so. Payments of such dividendswill be dependent on the availability of any dividends or other distributions from such subsidiaries.The Company can therefore give no assurance that it will be able to pay dividends going forwardor as to the amount of such dividends, if any.

Ordinary Shares in the Company may be subject to market price volatility

The price of the Ordinary Shares could be subject to significant price and volume fluctuations thatmay be unrelated to the operating performance of the Group. The market price of the OrdinaryShares may, in addition to being affected by the Company’s actual or forecast operating results,fluctuate significantly as a result of factors beyond the Company’s control, including changes insecurities analysts’ recommendations or estimates of earnings or financial performance of theCompany, its competitors or the industry, or the failure to meet expectations of securities analysts;the occurrence (or lack of occurrence) of events such as natural disasters, fluctuations in stockmarket prices and volumes; general market volatility; changes in laws, rules, regulations andtaxes, applicable to the Group, its operations and operations in which the Group has interests; lossof key personnel, and involvement in litigation. In addition, stock markets have in the recent pastexperienced significant price and volume fluctuations, which, as well as general economic andpolitical conditions, could adversely affect the market price for the Ordinary Shares.

Annex I, 20.7

40


The price of the Ordinary Shares may also fluctuate significantly as a result of many other factors,including perceived prospects for the Group’s business and operations and the oil and gas,exploration, development and production industry in general, announcements by the Group ofsignificant acquisitions, strategic alliances or joint ventures, changes in perceptions on thegeographic areas where the Group operates and broad stock market price fluctuations.

The market price of the Ordinary Shares could be negatively affected by sales of

substantial amounts of such shares in the public markets

Certain shareholders hold significant shareholdings in the Company. Such shareholders may sellOrdinary Shares in the public or private market. The Company may also (subject to any applicableshareholder approvals) undertake a public or private offering of Ordinary Shares. There can be noassurance as to what effect, if any, future sales of Ordinary Shares will have on the market priceof the Ordinary Shares. If such shareholders were to sell Ordinary Shares or the Company wereto issue and sell a substantial number of Ordinary Shares in the public market, the market price ofthe Ordinary Shares could be adversely affected. Sales by such shareholders also could make itmore difficult for the Company to sell equity securities in the future at a time and price that it deemsappropriate. There can be no assurance that such shareholders will not effect transactions inrelation to their shares. The sale of a significant amount of Ordinary Shares in the public market,or the perception that such sales may occur, could materially affect the market price of the OrdinaryShares and could also impede the Company’s ability to raise capital through the issue of equitysecurities in the future.

The proposed Standard Listing of the Ordinary Shares will afford Investors a lower level of

regulatory protection than a Premium Listing

Application will be made for the Ordinary Shares to be admitted to a Standard Listing on the OfficialList. A Standard Listing will afford Investors in the Company a lower level of regulatory protectionthan that afforded to investors in a company with a Premium Listing, which is subject to additionalobligations under the Listing Rules.

While the Company has a Standard Listing, it is not required to comply with the provisions of,inter alia:

• Chapter 8 of the Listing Rules regarding the appointment of a sponsor to guide the Companyin understanding and meeting its responsibilities under the Listing Rules in connection withcertain matters. The Company has not and does not intend to appoint such a sponsor inconnection with Admission;

• Chapter 9 of the Listing Rules relating to the ongoing obligations for companies admitted tothe Premium List and therefore does not apply to the Company;

• Chapter 10 of the Listing Rules relating to significant transactions. It should be notedtherefore that the Marathon Acquisition did not require Shareholder consent;

• Chapter 11 of the Listing Rules regarding related party transactions. Nevertheless, theCompany will not enter into any transaction which would constitute a ‘related partytransaction’ as defined in Chapter 11 of the Listing Rules without the specific prior approvalof the Directors;

• Chapter 12 of the Listing Rules regarding purchases by the Company of its Ordinary Shares;and

• Chapter 13 of the Listing Rules regarding the form and content of circulars to be sent toShareholders.

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Transfer restrictions for Shareholders in the United States may make it difficult to resell the

Ordinary Shares or may have an adverse impact on the market price of the Ordinary Shares

The Ordinary Shares have not been registered in the United States under the Securities Act orunder any other applicable securities laws and are subject to restrictions on transfers contained insuch laws. There are additional restrictions on the resale of Ordinary Shares by Shareholders whoare in the United States and on the resale of Ordinary Shares by any Shareholders to any personwho is in the United States. These restrictions will make it more difficult to resell the OrdinaryShares in many instances and this could have an adverse effect on the market value of theOrdinary Shares. There can be no assurance that Shareholders in the United States will be ableto locate acceptable purchasers or obtain the required certifications to effect a sale.

The ability of Overseas Shareholders to bring actions or enforce judgments against the

Company or the Directors may be limited

The ability of an Overseas Shareholder to bring an action against the Company may be limitedunder law. The Company is a public company with limited liability incorporated in England andWales. The rights of holders of Ordinary Shares are governed by English law and by theCompany’s articles of association (“Articles”). These rights may differ from the rights ofshareholders in non-UK corporations. An Overseas Shareholder may not be able to enforce ajudgment against some or all of the Directors and Senior Managers. The Directors are residentsof the UK. Consequently, it may not be possible for an Overseas Shareholder to effect service ofprocess upon the Directors and executive officers within the Overseas Shareholder’s country ofresidence or to enforce against the Directors and Senior Managers judgments of courts of theOverseas Shareholder’s country of residence based on civil liabilities under that country’ssecurities laws. There can be no assurance that an Overseas Shareholder will be able to enforceany judgments in civil and commercial matters or any judgments under the securities laws ofcountries other than the UK against the Directors or Senior Managers who are residents of the UKor countries other than those in which judgment is made. In addition, English or other courts maynot impose civil liability on the Directors or executive officers in any original action based solely onforeign securities laws brought against the Company or the Directors in a court of competentjurisdiction in England or other countries.

The ability of Shareholders to participate in rights offerings may be limited and

Shareholders could therefore experience dilution of their holdings

The Company may, from time to time, distribute rights to its shareholders, including rights toacquire securities. Compliance with securities laws or other regulatory provisions in somejurisdictions may prevent certain purchasers of Ordinary Shares from participating in any rightsissuances and thereby result in dilution of their existing shareholdings. The Company is under noobligation to register the shares in any jurisdiction to permit foreign purchasers of Ordinary Sharesto participate in any rights offerings the Company may undertake. Accordingly, Shareholders whoare based outside of the UK may be unable to participate in rights offerings and may experiencedilution of their holdings as well as further dilution in their voting interest following any suchoffering. In addition, if the rights that are not exercised or not distributed are not sold or if the saleis not lawful or reasonably practicable, the Company may allow the rights to lapse, in which caseholders of the Company’s shares would receive no value for these rights.

RISKS RELATING TO TAXATION

Taxation of returns from assets located outside of the UK may reduce any net return to

investors

To the extent that the assets, company or business which the Company acquires is or areestablished outside the UK, it is possible that any return the Company receives from it may bereduced by irrecoverable foreign withholding or other local taxes and this may reduce any netreturn derived by investors from a shareholding in the Company.

Annex I, 9.2.3

42


Changes in tax law and practice may reduce any net returns for investors

The tax treatment of Shareholders of the Company, any special purpose vehicle that the Companymay establish and any company which the Company may acquire are all subject to changes in taxlaws or practices in England and Wales or any other relevant jurisdiction. Any change may reduceany net return derived by investors from a shareholding in the Company.

Investors should not rely on the general guide to taxation set out in this document and should seektheir own specialist advice. The tax rates referred to in this document are those currently applicableand they are subject to change.

There can be no assurance that the Company will be able to make returns for Shareholders

in a tax-efficient manner

The Company acts as the holding company of a trading group to maximise returns forShareholders in as fiscally efficient a manner as is practicable. The Company has made certainassumptions regarding taxation. However, if these assumptions are not borne out in practice, taxesmay be imposed with respect to any of the Group’s assets, or the Group may be subject to tax onits income, profits, gains or distributions in a particular jurisdiction or jurisdictions in excess of taxesthat were anticipated. This could alter the post-tax returns for Shareholders (or Shareholders incertain jurisdictions). The level of return for Shareholders may also be adversely affected. Anychange in laws or tax authority practices could also adversely affect any post-tax returns of capitalto Shareholders or payments of dividends (if any, which the Company does not envisage thepayment of, at least in the short to medium-term). In addition, the Company may incur costs intaking steps to mitigate any such adverse effect on the post-tax returns for Shareholders.

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PART III

IMPORTANT INFORMATION

The distribution of this document may be restricted by law in certain jurisdictions and thereforepersons into whose possession this document comes should inform themselves about andobserve any restrictions, including those set out below. Any failure to comply with these restrictionsmay constitute a violation of the securities laws of any such jurisdiction.

General

No action has been or will be taken in any jurisdiction that would permit a public offering of theOrdinary Shares, or possession or distribution of this document in any other country or jurisdictionwhere action for that purpose is required. Accordingly, the Ordinary Shares may not be offered orsold, directly or indirectly, and this document may not be distributed or published in or from anycountry or jurisdiction except under circumstances that will result in compliance with any and allapplicable rules and regulations of any such country or jurisdiction. Any failure to comply with theserestrictions may constitute a violation of the securities laws of any such jurisdiction. This documentdoes not constitute an offer to subscribe for any of the Ordinary Shares offered hereby to anyperson in any jurisdiction to whom it is unlawful to make such offer or solicitation in suchjurisdiction.

This document has been approved by the FCA as a prospectus, but is not being used by theCompany to offer securities to the public for the purposes of section 85 of FSMA and theProspectus Directive (as defined below). No arrangement has been made with any competentauthority in any other EEA State (or any other jurisdiction) for the use of this document as anapproved prospectus in such jurisdiction and accordingly no public offer is to be made in anyjurisdiction. Issue or circulation of this document may be prohibited in Restricted Jurisdictions andin countries other than those in relation to which notices are given below.

The Company does not accept any responsibility for the accuracy or completeness of anyinformation reported by the press or other media, nor the fairness or appropriateness of anyforecasts, views or opinions expressed by the press or other media regarding Admission or theGroup. The Company makes no representation as to the appropriateness, accuracy,completeness or reliability of any such information or publication.

None of Hannam, Whitman Howard or Cantor Fitzgerald accept any responsibility or liabilitywhatsoever for the contents of this document, including its accuracy, completeness or verification,or for any other statement made or purported to be made by it, or on its behalf, in connection withthe Company, the Ordinary Shares or Admission and nothing in this document will be relied uponas a promise or representation in this respect, whether or not in the past or future. Each ofHannam, Whitman Howard and Cantor Fitzgerald accordingly disclaims all and any liabilitywhether arising in tort, contract or otherwise (save as referred to above) which it might otherwisehave in respect of this document or any such statement. No representation or warranty, expressor implied, is made by any of Hannam, Whitman Howard or Cantor Fitzgerald as to the accuracyor completeness of information contained in this document and nothing in this document is, or shallbe relied upon as, a representation by any of Hannam, Whitman Howard or Cantor Fitzgerald.

This document is not intended to provide the basis of any credit or other evaluation and should notbe considered as a recommendation by any of the Company, the Directors, Hannam, WhitmanHoward or Cantor Ftizgerald or any of their respective representatives that any recipient of thisdocument should subscribe for any Ordinary Shares. Prior to making any decision as to whetherto subscribe for Ordinary Shares, prospective investors should read this document. Investorsshould ensure that they read the whole of this document carefully and not just rely on keyinformation or information summarised within it.

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In making an investment decision, prospective investors must rely upon their own examination,analysis and enquiry of the Company and the terms of this document, including the risks involved.Investors will be deemed to have acknowledged that: (i) they have not relied on any of Hannam,Whitman Howard or Cantor Fitzgerald or any person affiliated with any of them in connection withany investigation of the accuracy of any information contained in this document or their investmentdecision; and (ii) they have relied on the information contained in this document, and no personhas been authorised to give any information or to make any representation concerning theCompany or the Ordinary Shares (other than as contained in this document) and, if given or made,any such other information or representation should not be relied upon as having been authorisedby the Company, the Directors, or any of Hannam, Whitman Howard or Cantor Fitzgerald.

For the attention of all investors

In making an investment decision, prospective investors must rely on their own examination of theCompany, this document and the terms of the Admission, including the merits and risks involved.The contents of this document are not to be construed as advice relating to legal, financial,taxation, accounting, regulatory, investment or any other matter.

Prospective investors must rely upon their own representatives, including their own legal andfinancial advisers and accountants, as to legal, tax, financial, investment or any other relatedmatters concerning the Company and an investment therein.

The contents of this document are not to be construed as legal, business or tax advice. Eachprospective investor should consult their own lawyer, financial adviser or tax adviser for legal,financial or tax advice in relation to any investment in Ordinary Shares. In making an investmentdecision, each investor must rely on their own examination, analysis and enquiry of the Company,including the merits and risks involved.

An investment in the Company should be regarded as a long-term investment. There can be noassurance that the Company’s objectives will be achieved. It should be remembered that the priceof the Ordinary Shares, and any income from such Ordinary Shares, can go down as well as up.All Shareholders are entitled to the benefit of, are bound by, and are deemed to have notice of, theprovisions of the Articles, which prospective investors should review.

Forward-looking statements

This document includes statements that are, or may be deemed to be, ‘forward-lookingstatements’. In some cases, these forward-looking statements can be identified by the use offorward-looking terminology, including the terms ‘targets’, ‘believes’, ‘estimates’, ‘anticipates’,‘expects’, ‘intends’, ‘may’, ‘will’, ‘should’ or, in each case, their negative or other variations orcomparable terminology. They appear in a number of places throughout the document and includestatements regarding the intentions, beliefs or current expectations of the Company and the Boardconcerning, inter alia: (i) the Company’s objectives, acquisition and financing strategies, results ofoperations, financial condition, capital resources, prospects, capital appreciation of the OrdinaryShares and dividends; and (ii) future deal flow and implementation of active managementstrategies, including with regard to acquisitions. By their nature, forward-looking statementsinvolve risks and uncertainties because they relate to events and depend on circumstances thatmay or may not occur in the future. Forward-looking statements are not guarantees of futureperformance. The Company’s actual performance, results of operations, financial condition,distributions to shareholders and the development of its financing strategies may differ materiallyfrom the forward-looking statements contained in this document. In addition, even if the Company’sactual performance, results of operations, financial condition, distributions to shareholders and thedevelopment of its financing strategies are consistent with the forward-looking statementscontained in this document, those results or developments may not be indicative of results ordevelopments in subsequent periods.

45


Prospective investors should carefully review the ‘Risk Factors’ set out in Part II – Risk Factors ofthis document for a discussion of additional factors that could cause the Company’s actual resultsto differ materially, before making an investment decision. For the avoidance of doubt, nothingappearing under the heading ‘Forward-looking statements’ constitutes a qualification of theworking capital statement set out in paragraph 7 of Part XIX – Additional Information of thisdocument.

Forward-looking statements contained in this document apply only as at the date of this document.Subject to any obligations under the Listing Rules, the Market Abuse Regulation (EU 596/2014)(the “Market Abuse Regulation”), the Disclosure Guidance and Transparency Rules and theProspectus Rules, the Company undertakes no obligation publicly to update or review anyforward-looking statement, whether as a result of new information, future developments orotherwise.

Presentation of reserves and resources

Unless otherwise stated, statements in this document relating to the Group’s reserves andresources have been prepared using the classification system set out in the Petroleum ResourcesManagement System published in June 2018 and jointly sponsored by the Society of PetroleumEngineers, the American Association of Petroleum Geologists, the World Petroleum Council andthe Society of Petroleum Evaluation Engineers. All references to “reserves” are to proved andprobable.

The accuracy of reserves estimates and associated economic analysis is, in part, a function of thequality and quantity of available data and of engineering and geological interpretation andjudgment. This document should be accepted with the understanding that reserves, resources andfinancial performance subsequent to the date of the estimates may necessitate revision. Theserevisions may be material. Unless otherwise stated, all information about oil and gas reserves andresources, forward-looking production estimates and other geological information has beenextracted without material adjustment from the Competent Person’s Report in Part XXIII –

Competent Person’s Report of this document.

Rounding

Percentages in tables have been rounded and accordingly may not add up to 100%. Certainfinancial data have also been rounded. As a result of this rounding, the totals of data presented inthis document may vary slightly from the actual arithmetic totals of such data.

Data protection

The Company may delegate certain administrative functions to third parties and will require suchthird parties to comply with data protection and regulatory requirements of any jurisdiction in whichdata processing occurs. Such information will be held and processed by the Company (or any thirdparty, functionary or agent appointed by the Company) for the following purposes:

(a) verifying the identity of the prospective investor to comply with statutory and regulatoryrequirements in relation to anti-money laundering procedures;

(b) carrying out the business of the Company and the administering of interests in the Company;

(c) meeting the legal, regulatory, reporting and/or financial obligations of the Company in theUnited Kingdom or elsewhere; and

(d) disclosing personal data to other functionaries of, or advisers to, the Company to operateand/or administer the Company.

46


Where appropriate it may be necessary for the Company (or any third party, functionary or agentappointed by the Company) to:

(a) disclose personal data to third party service providers, agents or functionaries appointed bythe Company to provide services to prospective investors; and

(b) transfer personal data outside of the EEA to countries or territories which do not offer thesame level of protection for the rights and freedoms of prospective investors as the UnitedKingdom.

If the Company (or any third party, functionary or agent appointed by the Company) disclosespersonal data to such a third party, agent or functionary and/or makes such a transfer of personaldata it will use reasonable endeavours to ensure that any third party, agent or functionary to whomthe relevant personal data is disclosed or transferred is contractually bound to provide an adequatelevel of protection in respect of such personal data.

In providing such personal data, investors will be deemed to have agreed to the processing of suchpersonal data in the manner described above. Prospective investors are responsible for informingany third party individual to whom the personal data relates of the disclosure and use of such datain accordance with these provisions.

Presentation of financial information

Prospective investors should consult their own professional advisers to gain an understanding ofthe financial information contained in this document. An overview of the basis for presentation offinancial information in this document is set out below. Part X – Selected Financial Information on

the Group of this document presents selected financial information extracted without materialadjustment from the audited historical financial information on the Company for the financial yearsended 31 December 2018 and 31 December 2017, and for the 18 month period ended31 December 2016, which are incorporated by reference in Part XXII – Documents incorporated

by reference of this document. Part XII – Historical Financial Information on MOUK of thisdocument presents the audited historical financial information on MOUK for the financial yearended 31 December 2018, 31 December 2017 and unaudited financial information for the financialyear ended 31 December 2016. Part XIII – Historical Financial Information on MOWOS of thisdocument presents the audited historical financial information on MOWOS for the financial yearended 31 December 2018, 31 December 2017 and 31 December 2016.

The financial and volume information in the Prospectus, including in a number of tables, has beenrounded to the nearest whole number or the nearest decimal place. The sum of the numbers in acolumn in a table may not conform exactly to the total figure given for that column. In addition,certain percentages presented in the tables in this document reflect calculations based on theunderlying information prior to rounding, and, accordingly, may not conform exactly to thepercentages that would be derived if the relevant calculations were based upon the roundednumbers.

Historical financial information on MOUK (“MOUK HFI”)

The MOUK HFI has been prepared in accordance with International Financial Reporting Standardsand the IFRS Interpretation Committee (IFRS IC) interpretations as adopted by the EuropeanUnion (“IFRS”). The principal accounting policies that have been applied to the MOUK HFI are setout below. These policies have been consistently applied to all years presented unless otherwisestated.

The MOUK HFI does not constitute statutory accounts and represents the first-time preparation offinancial information for MOUK under IFRS reporting standards.

MOUK has previously prepared and reported special purpose, non-statutory financial statements,in accordance with applicable standards in the United Kingdom (“Financial Reporting

Annex I, 20.5.1

47


Standard 102”). Consequently, the opening statement of financial position at the 1 January 2016has been included in the HFI together with IFRS 1 reconciliations between financial informationprepared under Financial Reporting Standard 102 and financial information prepared inaccordance with IFRS, as required by IFRS 1 on transition to IFRS. The principle changes to thepresentation of the financial information as a result of adopting IFRS as at the 1 January 2016 aresent out in note 2 to this HFI. We have taken the exemption to reset the currency translationaccount to nil on transition.

The non-statutory financial statements for the years ended 31 December 2018 and 31 December2017 have been subject to audit. The reports of the auditors for those years were unqualified anddid not include a reference to any matters to which the auditors drew attention by way of emphasiswithout qualifying their report. The non-statutory financial statements for the year ended December2016 are unaudited, however the financial information of MOUK for the year ended December2016 has been included within the consolidation for Marathon Oil Corporation, (“MOC”) a companylisted on the New York Stock Exchange and a domestic US Securities and Exchange Commissionreporting entity.

The MOUK HFI has been prepared under the historical cost convention except for certain financialinstruments which are carried at fair value and is presented in US Dollars, which is the currency ofthe primary economic environment in which MOUK operates, rounded to the nearest thousand.

Pro forma wording

In this document, any reference to “pro forma” financial information is to information which hasbeen extracted without material adjustment from the unaudited pro forma financial informationcontained in Part IX – Unaudited Pro Forma Financial Information for the Enlarged Group of thisdocument. The unaudited pro forma statement of net assets and the unaudited pro forma incomestatement of the Enlarged Group have been prepared for illustrative purposes only in accordancewith Annex II of the Prospectus Rules and should be read in conjunction with the notes set out inPart IX – Unaudited Pro Forma Financial Information for the Enlarged Group of this document. Theunaudited pro forma financial information has been prepared to illustrate the effect of the MarathonAcquisition as if it had taken place on 1 January 2018. By its nature, the pro forma financialinformation addresses a hypothetical situation and, therefore, does not represent the EnlargedGroup’s actual financial position nor is it indicative of the results that may or may not be expectedto be achieved in the future.

Market data

Where information contained in this document has been sourced from a third party, the Companyand the Directors confirm that such information has been accurately reproduced and, so far as theyare aware and have been able to ascertain from information published by that third party, no factshave been omitted which would render the reproduced information inaccurate or misleading.

CREST

CREST is a paperless settlement procedure enabling securities to be evidenced otherwise than bya certificate and transferred otherwise than by written instrument. The Articles permit the holdingof Ordinary Shares under the CREST System. The Ordinary Shares are admitted to CREST andaccordingly, settlement of transactions in the Ordinary Shares following Admission may take placewithin the CREST System if any investor so wishes.

CREST is a voluntary system and Shareholders who wish to receive and retain certificates for theirOrdinary Shares will be able to do so. Shareholders may elect to receive Ordinary Shares inuncertificated form if such Shareholder is a system-member (as defined in the CRESTRegulations) in relation to CREST.

Annex I, 23.2

Annex III, 10.4

Annex III, 4.3

48


Transferability

The Ordinary Shares are freely transferable and tradable and there are no restrictions on transfer.

International Financial Reporting Standards

As required by the Companies Act and Article 4 of the European Union (“EU”) IAS Regulation, thefinancial statements of the Company are prepared in accordance with International FinancialReporting Standards as adopted by the EU (“IFRS”) issued by the International AccountingStandards Board (“IASB”) and interpretations issued by the International Financial ReportingInterpretations Committee of the IASB as adopted by the EU.

Parts of this document contain information on the non-IFRS financial measures described below.There are no generally accepted accounting principles governing the calculation of such non-IFRSmeasures and the criteria upon which they are based can vary from company to company. TheDirectors consider certain non-IFRS measures to be useful to better understand the tradingperformance.

Such measures by themselves do not provide a sufficient basis to compare the performance of theGroup, MOUK and MOWOS with that of other companies and should not be considered inisolation, or as a substitute for, or as an alternative to, any other measures of performance underIFRS.

EBITDA

EBITDA represents earnings before interest, tax, depreciation and amortisation.

Adjusted EBITDA

Adjusted EBITDA represents EBITDA adjusted for the one-off non-cash adjustments in respect ofthe Asset Retirement Obligation provision included within other income.

Incorporation of information by reference

The contents of the Company’s website (www.rockroseenergy.com), any website mentioned in thisdocument or any website directly or indirectly linked to these websites have not been verified anddo not form part of this document, and prospective investors should not rely on them.

Definitions

A list of defined terms used in this document is set out in ‘Definitions’ at Part XXI – Definitions ofthis document.

Currency

Unless otherwise indicated, all references in this document to:

• “Pounds Sterling”, “GBP”, “£”, “p”, “pence” or “pound” are to the lawful currency of the UnitedKingdom;

• “US Dollars”, “USD”, “US$” or “$” are to the lawful currency of the United States; and

• “Euro”, “EUR”, or “€” are to the lawful currency of the Eurozone countries.

Annex III, 4.8

LR 2.2.4(1)

Annex III, 4.4

49


PART IV

EXPECTED TIMETABLE

Publication of this document 19 July 2019

Cancellation of trading of Ordinary Shares 7:30 a.m. 24 July 2019

Admission of the Company’s share capital effective andcommencement of dealings in Ordinary Shares 8:00 a.m. on 24 July 2019

All references to time in this document are to London time, unless otherwise stated.

Any changes to the expected timetable will be notified by the Company through a Regulatory Information Service.

ADMISSION STATISTICS

Total number of Ordinary Shares(1) 13,090,595

Total number of outstanding options 148,005

Market capitalisation at Admission(2) £106.68 million

(1) In accordance with Listing Rule 4.2.2, at Admission at least 25% of the Ordinary Shares of this listed class will be in

public hands (as defined in the Listing Rules).

(2) The market capitalisation of the Company at any given time will depend on the market price of the Ordinary Shares

at that time. The market price per Ordinary Share may fall below the market price prevailing immediately prior to the

suspension of the Company’s listing on 25 February 2019.

DEALING CODES

The dealing codes for the Ordinary Shares will be as follows:

ISIN GB00BYNFCH09

SEDOL BYNFCH0

TIDM RRE

LR 2.2.7(1)

LR 14.2.2

Annex III, 4.4

Annex III, 4.1

50


PART V

DIRECTORS, AGENTS AND ADVISERS

Directors Andrew Austin (Executive Chairman)Richard Benmore (Non-Executive Director)John Morrow (Non-Executive Director)

Company Secretary Cooley Services LimitedDashwood69 Old Broad StreetLondon EC2M 1QS

Registered Office c/o Cooley Services LimitedDashwood69 Old Broad StreetLondon EC2M 1QS

Financial Adviser and Joint Broker H&P Advisory Limited2 Park StreetLondon W1K 2HK

Joint Brokers Whitman Howard LimitedFirst FloorConnaught HouseMount StreetLondon W1K 3NB

Cantor Fitzgerald EuropeOne Churchill PlaceCanary WharfLondon E14 5RB

PricewaterhouseCoopers LLP1 Embankment PlaceLondon WC2N 6HR

Solicitors to the Company Cooley (UK) LLPDashwood69 Old Broad StreetLondon EC2M 1QS

Registrar Link Asset Services LimitedThe Registry34 Beckenham RoadBeckenhamKent BR3 5TU

Competent Person ERC Equipoise Limited6th Floor Stephenson House2 Cherry Orchard RoadCroydon CR0 6BA

Auditors and ReportingAccountants

Annex I, 2.1,

14.1, 23.1

Annex III, 5.4.1,

10.1, 10.3

ESMA update

para 133

51


PART VI

INFORMATION ON THE COMPANY AND THE ENLARGED GROUP

Introduction

The Company was incorporated on 1 July 2015 as a public company with limited liability under theCompanies Act. In January 2016, the Company raised £4.4m before expenses and was admittedto Standard Listing on the Official List and to trading on the Main Market of the London StockExchange.

At the time of the Initial Admission, the Directors stated that they believed an opportunity existedto create a new entity focused on onshore and offshore oil and gas production and powergeneration projects. It was intended that the Company should pursue an acquisition strategydesigned to create an operating company with a diverse portfolio of licence interests focusing onmature assets in the North Sea whilst avoiding significant initial exploration costs.

Since January 2016, the Company has completed a series of transactions that were in line with itsstrategy and objectives. These have resulted in it holding interests in oil and gas fields in the UKand the Netherlands with net proved and probable reserves, as assessed by ERC Equipoise, of62.9 MMboe at 31 March 2019.

The Company’s strategy will continue to involve making acquisitions as well as reviewing organicgrowth opportunities and, as was the case with the Marathon Acquisition, one or more of thesemay be deemed a Reverse Takeover and the Company’s Standard Listing may be suspendedpending publication of a prospectus in such circumstances.

The Company’s issued share capital will, on Admission, consist of Ordinary Shares. It is intendedthat the Ordinary Shares will be admitted by the FCA to a Standard Listing on the Official List inaccordance with Chapter 14 of the Listing Rules and to trading on the Main Market of the LondonStock Exchange.

Company objectives

A Rockrose is a plant that grows in harsh environments with minimal external support. Creating anenergy company that is equipped to do business in the harsh environment of sub US$50 oil witha minimal cost base was the objective behind the establishment of RockRose Energy plc inmid-2015. The Directors stated that they will target cash generative production assets where thepotential exists to consolidate working interests and operatorship to achieve critical mass.

The Directors remain focused on pursuing these objectives and believe RockRose is now adifferentiated and scalable energy business, capable of delivering shareholder returns in a lowcommodity price environment. The Company has concentrated on opportunities to acquireinterests in producing oil and gas fields in circumstances where certain key criteria are met. Theseinclude situations where:

• the designated operator is experienced and has a history of excellent asset stewardship;

• the OGA’s maximising economic recovery UK strategy (the “MER Strategy”) are likely toresult in the increase of economically recoverable reserves and resources and thesubsequent extension of field life; and

• the existing minority interest holders might regard a mid-life to late-life asset as non-core andhence be prepared to strike a deal on terms that satisfy the commercial objectives of boththe vendor and the Company.

The Company will continue to pursue opportunities that meet these criteria. In the meantime,RockRose assumed operatorship of the Brae Complex on completion of the Marathon Acquisition

LR 2.2.1(1), (2)

LR 2.2.2(1)

Annex I, 5.1.3,

5.1.4, 5.1.5, 14.1

Annex III, 6.2

Annex I, 5.1.5, 6.2

Annex I, 5.2.1,

5.2.2, 5.2.3, 9.2.2

52


on 1 July 2019. Having done so, the Company will seek to maintain or, where necessary, improvethe policies and procedures that the Marathon Group established in relation to these assets and,as part of the Marathon transaction, RockRose has transferred the employment of the keymembers of Marathon’s Brae operational team. In addition, the operatorship will allow theCompany to exert significant influence over the planning and execution of capital projects in theBrae Complex and give it the ability to pursue further acquisition opportunities as an operator.RockRose will continue to work with the operators of the fields in which it is a partner to ensurethey are working in a safe and environmentally responsible manner.

To maximise returns to shareholders and to ensure it can survive in a low commodity priceenvironment, RockRose is committed to minimising the overheads and administrative costsassociated with running its assets. However, other than in respect of the Marathon Interests, theGroup is not the designated operator of its licence interests. Typically, the designated operator ofa licence manages the activity on behalf of all the interest holders (“partners”) pursuant to theterms of a joint operating agreement. The operator produces forward projections of activity andcostings both for operating and for capital expenditure and the partners are responsible for thatexpenditure in proportion to their interest in the licence.

RockRose reviews and evaluates the plans and budgets produced by the operators of the licencesin which it has interests. However, the Company has specifically chosen licence interests in partbased upon the track record of the operators and their approach to asset stewardship. Therefore,RockRose generally expects to be supportive of economically viable plans advanced to complywith the principals and obligations on all relevant persons under the MER Strategy.

Due to its commitment to minimising overheads and operating costs and because it is not anexploration company focused primarily on making new discoveries, often the Company is able toevaluate marginal projects on a different basis to large oil and gas multinationals, which may havevery different priorities in terms of capital allocation. Accordingly, the Directors believe theCompany’s objectives are aligned both to the MER Strategy and to the OGA’s published principalpolicy objectives on decommissioning.

Business strategy

The Company operates a strategy designed to meet its objectives and generate value for itsshareholders through the acquisition and management of operated and non-operated interests inoil and gas production assets. This strategy will involve the pursuit of further acquisitionopportunities and will not be limited to a particular geographic region. However, at present theCompany’s focus remains on the UK and Western Europe. The Directors will draw on theirexperience, in conjunction with their contacts and advisers, to identify suitable acquisitioncandidates. Unless required by applicable law or other regulatory process, no Shareholderapproval will be sought by the Company in relation to further acquisitions.

Thus far, the Company has selected most of the assets it has acquired on the basis that, whilstthey are mid-life or late-life field licences, they remain capable of economic viability even in a lowoil price environment. In so doing, the Company also recognised that non-operated interests of thistype have been of limited interest to larger oil and gas exploration and production companies.Nonetheless, the Directors believe that the majority of the Company’s field licence interests are stillcapable of producing positive net cash flows in the short-term to medium-term. Dependent onfuture development plans and enhanced recovery techniques, it is possible some of them willcontinue to produce beyond the end of the period currently assumed to represent their economiclife. For instance, in respect of the Blake Field, the operator is in the process of executing a fieldlife extension (“FLE”) project, which will maintain FPSO operability until 2029. These incomestreams could be material to a company of RockRose’s size. Decommissioning has commenced(and in some cases has been completed) with respect to some of the Group’s less significantinterests. To date, decommissioning activity has occurred on a timely basis and within the budgetset aside for the purpose.

Annex III, 10.2

53


The Company has no debt facilities and has financed, and is able continue to finance, its capitaland operating expenditure and its decommissioning liabilities through cash generated throughhistoric issues of equity and revenues from its producing assets.

In 2018, the Company acquired an interest in the Shell-operated Arran development project in theUK North Sea. This field represented approximately 15% of the RockRose’s reserves at31 March 2019 (as assessed by ERC Equipoise in the Competent Person’s Report reproduced inPart XXIII – Competent Person’s Report of this document) and is due onstream in the first half of2021. The Directors expect to target further projects of this nature, which allow the Company toredeploy surplus cash flow from its existing producing assets into projects that are earlier in theirlife-cycle. In turn, this will help RockRose to offset future production declines and reduce theoverall maturity of the portfolio.

Competition

At the time of the Initial Admission, oil prices were at levels below US$30 per barrel and the OGAMER strategy had not been formally adopted. As a result many asset owners put portfolios ofassets in the North Sea, particularly later stage assets, on the market, looking to raise cash and/orseek to avoid or mitigate decommissioning costs. Oil prices have since recovered and stabilisedwith the consequence that many parties who might have historically been sellers at low prices (oreven for negative consideration) have now revisited their own strategies or might be less willing tosell at prices driven by an ultra-low oil price environment. In addition, several companies havebeen established with a strategy similar to that of RockRose in the past 36 months, some listed onpublic markets and others backed by private equity finance, such as Israel’s Delek Group andChrysaor. Increased competition for assets, particularly from private equity backed entities with theability to rapidly call upon substantial debt financing, may impact the ability of the Group tocontinue to be able to make future acquisitions on the advantageous terms that it has been ableto secure with respect to historic transactions.

Strategy execution

Since the Initial Admission, the Company has completed six acquisitions. All of these transactionswere material to the Company at the time they were undertaken. However, owing to thesubsequent growth of RockRose, some of the interests acquired no longer reach the Company’smateriality threshold. The following table provides an overview of the Company’s acquisitionhistory:

Entity/interest acquired Announcement Completion Reserves (31/3/19)*

Egerton Energy Ventures March 2017 December 2017 0.0 MMboeSojitz Energy Project August 2017 December 2017 0.7 MMboeIdemitsu Petroleum UK October 2017 December 2017 12.7 MMboeDyas BV May 2018 October 2018 11.6 MMboeArran field Interest August 2018 October 2018 9.5 MMboeMarathon Interests February 2019 July 2019 28.4 MMboe

* Source: ERC Equipoise Competent Person’s Report.

Although the assets acquired with Egerton and Sojitz no longer reach the Company’s materialitythreshold, these transactions were important at the time they were undertaken. The Directorsbelieve that the Egerton Acquisition and the Sojitz Acquisition had the effect of giving the Companycredibility with the vendors of larger asset packages and demonstrating RockRose’s ability toexecute transactions as well as their good stewardship of assets and liabilities.

In turn, this enabled the Group to cement its position as a participant in the UK North Sea oil andgas industry with the Idemitsu Acquisition, which was a Reverse Takeover and ultimately led to theCompany’s suspension of listing on 18 October 2017. When the Ordinary Shares were readmittedto the Official List and trading on the Main Market of the London Stock Exchange on 19 February2018, the competent person’s report prepared by ERC Equipoise in the accompanying prospectus

54


published on 14 February 2018 attributed net reserves of 9.7 MMboe to the key producing assets(Nelson, Howe, Blake, and Ross).

In the latest Competent Person’s Report, also prepared by ERC Equipoise, the same assets areestimated to contain reserves net to RockRose of 12.5 MMboe. This is despite such assets havingcontinued to produce in the 15 months between the effective dates of the two assessments. Theincrease is attributable principally to extension of the anticipated cessation of production at theBlake and Ross fields from 2024 to 2029. The Directors believe this is a good example ofRockRose’s strategy and approach to asset stewardship at work. The Company is working with itspartners to achieve similar results elsewhere, both in its operated portfolio and in its non-operatedportfolio.

The Dyas Acquisition was consistent with RockRose’s strategy and objectives and representedanother significant addition to the Group’s reserves. Nonetheless, it also represented adiversification of risk both in terms of (i) geography, by taking the Company into the Netherlands,and (ii) hydrocarbon, by providing meaningful exposure to gas.

Also in 2018, the Company completed the Arran Acquisition. This is an example of the Companyredeploying surplus cash flow from its existing mid-life to late-life producing assets into less matureprojects that will generate future production and cash flow growth to offset declines elsewhere inthe portfolio.

The Company’s most recent acquisition, the Marathon Acquisition, completed on 1 July 2019. Thetransaction was funded out of the Company’s existing cash resources. This acquisition representsa further step change for the Company in terms of reserves and production. However, thistransaction also brought operatorship for the first time in the Group’s history, with MOUK operatingthe Brae Complex in the UK sector of the North Sea. Although this will bring new managementchallenges, MOUK has its own existing and well established management structure and,historically, has operated largely independently of MOC. The Directors expect MOUK to continueoperating autonomously on a day-to-day basis, and believe its operating capability will enableRockRose to target a wider range of acquisition opportunities than has been the case thus far.However, on 20 June 2019, MOUK was notified by TAQA Bratani a significant non-operator interestholder in those licences, that it would be discharged as operator of Blocks 16/7a, Licence no. P.108(Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) and East Brae noearlier than 1 July 2020. Any such discharge and the appointment of a new operator remainssubject to OGA approval and is not expected to have a material impact on the Company’s financialposition. It should be stressed that becoming an operator has been part of the strategy of theGroup since completion of the acquisitions in 2018. Operatorship is not, of itself, a profit centre asoperations are carried on for the partners on any licence on a recharge basis pro rata their relevantpercentage interests and not with a view to profit. However holding operatorship does, in theopinion of the Directors, open up further acquisition opportunities.

Should TAQA Bratani be successful in its proposals to assume the role of operator of Blocks 16/7a,Licence no. P.108 (Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c)and East Brae, such further change of operatorship would, subject to the approval of the OGA,take place no earlier than 1 July 2020 and RockRose would be fully compensated for all continuingcosts associated with operatorship.

From a strategic perspective concerning operatorship, the OGA, in delivering comfort letters inrespect of the Marathon Acquisition, raised no objection to the Group acting as operator.Accordingly whilst RockRose sees the potential loss of operatorship of Blocks 16/7a, Licence no.P.108 (Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) and EastBrae as the possible loss of a strategic advantage, any such loss of operatorship is unlikely to haveany material effect on RockRose’s financial position in respect of Blocks 16/7a, Licence no. P.108(Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) and East Brae orotherwise.

55


Decommissioning

The cessation of production dates shown in this section do not necessarily match the expiry datesof the corresponding licences. In the UK, offshore production licences can be extended beyondtheir original expiry date to allow approved fields to finish their production. An extension isimplemented by an amendment that removes all acreage from the licence other than the approvedfield(s) and continues for as long as the field(s) is in production. In the Netherlands, onshorelicences do not have a formal expiry date. Offshore, RockRose’s licences expire on various datesbetween December 2019 and June 2036. Extensions have to be applied for by the operator ingood time, but are not to be unreasonably withheld and – as far as RockRose is aware – neverhave been.

Marathon Interests

The following table details the currently anticipated cessation of production dates for each of theproducing fields included in the Marathon Interests plus the estimated, gross pre-taxdecommissioning liability (in real terms as at 31 March 2019) and RockRose’s estimate of its netpost-tax decommissioning liability (in real terms as at 31 March 2019).

Cessation of Gross, pre-tax Net, post-tax

Field production decommissioning decommissioning

Braemar 2021 £39MM £4MMCentral Brae 2030 £110MM £18MMEast Brae 2021 £257MM £38MMSouth Brae 2030 £253MM £40MMWest Brae 2030 £373MM £60MMFoinaven 2025 £507MM £85MMEast Foinaven 2025 £72MM £20MMT25 2025 £31MM £4MMT35 2025 £20MM £2MM

Source: ERCE Competent Persons Report Effective 31 March 2019

In addition, £193 million (gross, pre-tax) is expected to be spent decommissioning the Brae Bravoplatform and pipelines on block 16/7a between 2019 and 2033. RockRose estimates its net,post-tax share of this sum will be £31 million.

Dyas Interests

The following table details the currently anticipated cessation of production dates for each of theproducing fields included in the Dyas Interests plus the estimated, gross and net decommissioningliabilities (in real terms).



A&B Blocks 2028 €94MM €14MMBergen 2029 €39MM €5MMHanze 2039 €92MM €19MMK4/K5 2036 €215MM €25MMP15/P18 Rijn 2021 €52MM €24MMP/Q Blocks 2021 €113MM €14MM


56


Idemitsu Interests

The following table details the currently anticipated cessation of production dates for each of theproducing fields included in the Idemitsu Interests plus the estimated, gross pre-taxdecommissioning liability (in real terms) and RockRose’s estimate of its net post-taxdecommissioning liability (in real terms).



Nelson 2027 £228MM £10MMHowe 2022 £30MM £4MMBlake & Ross 2029 £415MM £77MMBalmoral & Stirling 2019 £320MM £19MMBeauly 2019 £20MM £5MMBurghley 2019 £23MM £6MM


In addition, RockRose is liable for 17.4% of the costs of decommissioning the Galley field once itceases production. In real terms, RockRose estimates its net, post-tax share of this will be£10 million.

Working capital

The Company is of the opinion that the working capital available to the Enlarged Group (which forthe avoidance of doubt includes the Marathon Group) is sufficient for the present requirements ofthe Enlarged Group, that is, for at least the next 12 months following the date of this document.

Dividend policy

On 26 January 2018, the Company announced proposals for a “B Share Scheme” to return £1.50per Ordinary Share to Shareholders which were considered by Shareholders on 14 February 2018and in respect of which the Company received irrevocable undertakings to vote in favour of theimplementing resolutions for a total of 8,226,640 Ordinary Shares representing 56.65% of theissued share capital of the Company.

Going forward, the Company intends to pay dividends on the Ordinary Shares following at suchtimes (if any) and in such amounts (if any) as the Board determines appropriate. The Company willonly pay dividends to the extent that to do so is in accordance with the Companies Act and all otherapplicable laws, and the Directors will review the Company’s dividend policy from time to time.

Annex III, 3.1

Annex I, 20.7

57


Summary of UK Licence Interest in Fields for which Reserves Have Been Audited

*Greater Brae area has commercial arrangements that mean the effective working interest for revenue and cost

calculations are not necessarily equal to the license interest.

58


Summary of Netherland Licence Interests in Fields for which Reserves Have Been Audited

Summary Licence Interests for the remaining assets

for which decommissioning costs apply

59


Ro

ckR

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eserv

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um

mary

ESMA

update para

132(a), (b), (d)

60


61


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62


63


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Spirit

Energ

y

64


The Group’s portfolio

The Group’s portfolio is summarised in the tables set out on pages 58 to 63 of this document.

The description of the Group’s assets described below, the content of which is sourced directlyfrom (where relevant) ERC Equipoise’s Competent Person’s Report, only focus on those assetsthe Directors deem to be material to the Group.

(a) The Marathon Interests

(i) Overview

The Company announced on 25 February 2019 that it had signed the MarathonAcquisition Agreements. The Marathon Acquisition involved the purchase of the entiremembership interest in MOUK from MOHL and the entire issued share capital ofMOWOS from MIOH by the Company. MOUK holds approximately 37%-40%operated interests in fields in the Greater Brae Area (which are unitised fields) andMOWOS holds a 28% interest in the British Petroleum Exploration OperatingCompany Ltd (“BP”) operated Foinaven Field unit and a 47% interest in FoinavenEast, respectively. The Marathon Acquisition also includes interests in the SAGE,Brae-Forties and West of Shetland pipeline systems infrastructure providing additionaltariff income.

On 20 June 2019, MOUK was notified by TAQA Bratani, a significant non-operatorinterest holder in those licences, following the approval of proposals made by TAQABratani to the other members of the relevant operating committees on 5 June 2019,that MOUK would be discharged as operator of Blocks 16/7a, Licence no. P.108(Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) andEast Brae and TAQA Bratani appointed in its place. No reasons were given for thesechanges. A process will follow, involving OGA approval, which could result in theGroup losing operatorship of these licences in July 2020.

On 26 June 2019, the Company received a letter from the OGA confirming that itcurrently has no objection to the change of control of the Marathon Group, and theMarathon Acquisition completed on 1 July 2019.

(ii) The Marathon Acquisition Agreements

The terms of the Marathon Acquisition Agreements dated 24 February 2018, aredetailed in Part XIX – Additional Information of this document.

(iii) Brae Complex Overview

The Brae Complex fields are located some 220km north-east of Aberdeen waterdepths ranging from 100 to 120 metres. The Brae Complex has 7 main fields spreadacross six licence blocks and 3 fully integrated platforms operated by RockRose.South Brae, Central Brae and the West Brae field (formerly West Brae & Sedgwick)are black oil fields, whereas North Brae, Beinn, East Brae and Braemar are gascondensate fields.

North Brae and Beinn have now ceased production. Reserves have been assessedfor Central, West, East and South Brae, and Braemar.

RockRose is the operator and has an equal working interest in South, Central andWest Brae fields.

The Brae Bravo platform, along with the North Brae, Beinn and Kingfisher Fields arebeing decommissioned. Devenick is a third party producing field, which impacts costshare and fuel gas supplies at the East Brae platform, but in which RockRose doesnot have a working interest. East Brae and the Braemar sub-sea tieback also flow

Annex I, 6.1.1,

6.1.2, 6.4

ESMA update

para 132(c)

ESMA

update para

132(a), (b),(d)

through the East Brae platform. West Brae and Central Brae are sub-sea tiebacks tothe Brae Alpha platform. South Brae is also produced through the Brae Alpha platform.Production in the Brae Complex is limited by facility life. East Brae is scheduled to beshut in at the end of 2020. Braemar forecasts are truncated at the end of 2021. South,Central and West Brae forecasts are truncated at the end of 2030.

Oil production from the platform is transported via the Forties pipeline system to theKinneil terminal where it is processed. Gas production from the platform travels via theSAGE network to the St Fergus terminal where it is processed, natural gas liquids(“NGLs”) are extracted and sales products are distributed.

Current gas export is negligible after fuel and flare are removed at Brae Alpha and nogas or NGL reserves are quoted for Brae Alpha fields.

Figure 10.1: Central Brae Field Location map (Source: RockRose)

65


The area comprises unitised and non-unitised areas. Additional commercialarrangements have also been reached between the various parties. The results aresummarised in Table 10.1. As a result:

• For OPEX spend, Marathon pays 60% of the TAQA Bratani LNS workinginterest, and receives60% of TAQA LNS production in return.

Table 10.1: RockRose Revenue, OPEX and CAPEX Interest in the Brae Complex

(Source: RockRose)

Effective License Revenue Interest

North,

South and

Company Beinn Central Brae West Brae Braemar East Brae Kingfisher

RockRose 42.400 42.400 42.400 27.800 39.0883 0.897

Effective License OPEX Interest

North,

South and


RockRose 42.400 42.400 42.400 27.800 39.0883 0.897

Effective License CAPEX Interest

North,

South and


RockRose 44.000 44.000 44.000 29.000 40.5976 0.897

• For CAPEX spend, Marathon pays 100% of the TAQA Bratani LNS workinginterest, and receives 60% of TAQA LNS production in return.

ERC Equipoise’s audit has determined that the total probabilistic P50 cost ofdecommissioning from the third quarter of 2018 (£1224.7MM) is reasonable and hasbeen adopted at all reserve levels of confidence. ERC Equipoise has allocated costsfor the producing assets (i.e. removing forecast costs for Bravo Fields and spent costsfrom the first quarter of 2019) within the forecast profiles.

(iv) Central Brae

Oil was discovered in Central Brae in 1976 by well 16/7-3, with first productionoccurring in 1989 via sub-sea wells to the Brae Alpha platform. After five explorationwells, 13 development wells have been drilled on the Central Brae field, includingextended reach wells drilled from Brae Alpha and Bravo platforms as well as thesub-sea wells. Only one sub-sea well, C3, is currently active.

As at 31 March 2019, cumulative oil recovery has reached 61.0 MMstb, with anadditional 6.0 MMstb of NGL extracted from the gas stream.

NGL uplift from produced gas has been calculated from historical trends at 24.0%.Historical uptime performance has been analysed and a range of values are usedacross the forecasts, as presented in the table below. Averages have been calculatedusing data from the previous 6/12 months well performance. Recent uptime hasimproved since the Brae Bravo platform wells have been shut in, allowing the C3 wellto flow continuously.

66


Table 10.4: Gross Technical Recoverable Oil 31/03/2019

1P 2P 3P

Oil/Cond NGL Gas Oil/Cond NGL Gas Oil/Cond NGL Gas

Field MMSTB MMSTB Bscf MMSTB MMSTB Bscf MMSTB MMSTB Bscf

Central Brae 0.803 0.000 0.000 1.052 0.000 0.000 1.263 0.000 0.000

No capital spend is forecast on Central Brae from the second quarter of 2019. Costsincluded in the budget for 2019 associated with the rig reactivation project which ERCEquipoise understands to have been completed in the first quarter of 2019.

Forecasts for ongoing operational costs have been based on historic, actual costsreported and benchmarked against other North Sea assets of similar size and age.Broadly, forecast costs are deemed appropriate and are aligned to ERC Equipoise’sview of production.

ERC Equipoise has included direct, platform specific operational costs for the Alphaplatform which are shared, dependent on production between the Central, West andSouth Brae Fields. These costs include platform specific integrity and maintenance,routine operations and logistics.

Other direct costs include projects, studies associated with the Alpha Platform andSAGE costs which are attributable to the 16/7a block.

Indirect and other costs include primarily onshore support, general and administrationand CO2 emissions costs that are allocated to the Alpha platform. In a similar methodto the Alpha platform direct costs, these costs are then split dependent on productionbetween the Central, West and South Brae Fields.

Shipping and handling costs for usage of the Forties Pipeline System (“FPS”) areincluded in ERCE’s Central Brae profiles.

(v) West Brae

Although West Brae was discovered in 1975, the field was only brought onstream in1997. To date there have been 12 exploration and appraisal wells and 26 developmentwells, with production routed via the Brae Alpha platform. Seven production wells arecurrently active and two additional infill wells have been approved to be drilled in 2019.

The West Brae Field lies in Block 16/7a and is an oil accumulation with primary gascaps, across 2 reservoirs, Balder and Flugga, in Tertiary aged turbidite channels.Initially thought to be a separate accumulation immediately to the west, Sedgewick(Block 16/6) is an extension of the same channel complex and is now believed to bepart of the same field at the Balder level. Although RockRose has no license interestin Block 16/6, a joint development Agreement manages the combined production.There is strong aquifer support in the field, with minimal depletion seen.

West Brae reservoirs are stacked turbidite channel systems in the Balder and Fluggasandstone members, deposited in north west–south east trending submarinechannels. Separated by the Upper Sele mudstones, these reservoirs have differentfluid contacts for both gas and oil legs.

Unlike the rest of the Brae Complex which lie within the South Viking Graben, WestBrae is a Tertiary reservoir above the footwall of the bounding fault. Differentialcompaction over the Flugga sandstone Member creates topography which influencesthe deposition of the Balder sandstone Member. The main structural trap is laterformed during inversion on the margin during the Eocene and the resultant drape ofthe sandstone channels over a basement high.

67


Decline curve analysis (“DCA”) was performed by ERC Equipoise based on oil ratepotentials. Overall these aligned well with the Operator forecasts using water oil ratio(“WOR”) trends. Base case operator simulation models were supplied with and withoutthe infill wells so incremental recovery, including impact on existing wells, could beassessed. These forecasts were scaled in the low and high scenarios based on theuncertainty analysis presented by the Operator in combination with ERC Equipoise’sindependent assessment.

Table 10.7: West Brae YE2018 Technical Recoverable Oil

1P 2P 3P



West Brae 13.216 0.000 0.000 22.637 0.000 0.000 26.994 0.000 0.000

ERC Equipoise has included CAPEX for the additional infill well drilling campaignplanned for 2019 during which WPGZ and WPOZ will be drilled. Rig arrival has beendelayed from May 2019 to August 2019. WPGZ is a sidetrack of the existing WestBrae well W7, therefore no additional infrastructure is required. WPOZ is a new wellapproximately 6km from existing infrastructure, requiring a new production, gas lift andcontrol umbilical. As per the South Brae Field, direct OPEX costs for the AlphaPlatform are allocated to the Central, West and South Brae Fields depending onproduction. These costs include platform specific integrity and maintenance, routineoperations and logistics.

Other direct costs allocated to West Brae include an allowance for a Diving SupportVessel campaign during which minor inspection work can be undertaken on subseawells.

Indirect and other costs include primarily onshore support, general and administrationand CO2 emissions costs that are allocated to the Alpha platform. In a similar methodto the Alpha Platform direct costs, these costs are then split dependent on productionbetween the Central, West and South Brae Fields.

Shipping and Handling costs for usage of the FPS are included in ERC Equipoise’sWest Brae profiles.

(vi) South Brae

Oil was discovered in South Brae in 1977 by well 16/07a-8, with first production in1983 via the Brae Alpha platform. After 11 exploration and appraisal wells,53 development wells have been drilled on the South Brae field. Currently there are12 active production wells which are all gas lifted. Initial field rates were over100,000 bbl/d oil, however as water broke through production declined rapidly due toseveral factors including oil displacement efficiency, decline in well productivity due torelative permeability effects and significant wellbore scaling problems associated withmixing of formation and injected waters. As of 31 March 2019, cumulative oil recoveryhas reached 261.5 MMstb, with an additional 35.0 MMstb of NGL extracted from thegas stream.

Reserves have been forecast for South Brae using trends of WOR against cumulativeoil on an individual well basis on the following currently producing wells: A1, A2, A16,A18, A24, A36, A37, A40, A45z, A47, A48 and A49. Three activities influence theforecast; one predicted well failure and recompletions of A48 and A49.

A47 was drilled and first began production in October 2014. During completionoperations, the permanent production packer was pre-set which exposed sections ofthe carbon steel liner to corrosive reservoir fluids. This is directly analogous to what

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happened at A42z which failed after seven years. This activity is expected to takeplace and cost for this is included in 2021 across the 1P to 3P profiles.

A48 (A3 twin) was brought online in 2015 and produces dry oil from the deeper Cchorizon. Whilst the platform is currently constrained by water handling, it is beneficialto produce from this zone rather than the more productive main target intervals (layersBa/Bc/Ca). Water handling constraints are planned to be lifted during July 2019. Torecomplete to the target horizons will require a plug set and perforation job, and anotional start date for the main horizon is 1 January 2020. Forecast profiles have beengenerated from historical well performance from the A3 well, which A48 twinned toaccess volumes left behind.

A49 (re-drill of A42z) was brought online in 2018 and produces low water cut oil fromthe deeper Ad, Ba and Bc layers. Like A48, whilst water handling restriction apply onthe platform it is beneficial to produce these zones as opposed to the main target Aaand Ac layers. Similar to A48, a start date of 1 January 2020 is used to switch the wellto the main intervals. Due to scaling tendencies of the formation and injected watermixing, the deeper horizons cannot be commingled with the shallower main targets forboth of these wells.

Table 10.9: Gross Technical Recoverable Oil @ 31/03/2019

1P 2P 3P



South Brae 12.347 0.000 0.000 14.581 0.000 0.000 18.887 0.000 0.000

No capital spend is forecast on South Brae from the second quarter of 2019. Costsincluded in the annual budget for 2019 were associated with the Bravo Gas Bypass,which ERC Equipoise understands to have been completed in the first quarter of 2019.

Direct OPEX costs for the South Brae Field are allocated depending on productionthrough the Alpha Platform. These costs include platform specific integrity andmaintenance, routine operations, logistics and pipeline maintenance costs.

Other direct costs allocated to South Brae include an annual allowance for remedialwork undertaken on the platform wells. Other direct costs include projects, studiesassociated with the Alpha Platform and SAGE costs which are attributable to the 16/7ablock.

Indirect and other costs include, primarily, onshore support, general andadministration cost and CO2 emissions costs that are allocated to the Alpha platform.In a similar method to the Alpha Platform direct costs, these costs are then splitdependent on production between the Central, West and South Brae Fields.

Shipping and Handling costs for usage of the FPS are included in ERC Equipoise’sSouth Brae profiles

(vii) Braemar

Gas-condensate was discovered in Braemar in 1985 by well 16/03a-8Z. The well wasre-entered and deepened in 1995 (designated 16/03a-8Y), with first production in2003 via the East Brae platform. The exploration well was completed and tied back viaa sub-sea pipeline to dedicated production facilities on the platform. The wellcontinues to produce on natural depletion and negligible water production.

Gas production has been steadily declining with a corresponding reduction inproduced condensate to gas ratio as the field pressure has gone below the dew point.As of 31 March 2019, cumulative gas recovery has reached 175.2 Bscf, with anadditional 10.4 MMstb of condensate and 4.2 MMstb of NGL extracted from the gas

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stream. Reserves have been forecast for the single Braemar gas producer using adecline curve analysis (“DCA”) of gas rate against the cumulative gas production.

Table 10.11: Gross Technical Recoverable Fluids @ 31/03/2019

1P 2P 3P



Brarmar 2.075 1.723 48.705 2.343 1.995 56.401 2.638 2.296 64.912

No capital spend is forecast on Braemar from the second quarter of 2019, thereforeno costs are included in ERC Equipoise profiles.

ERC Equipoise has assumed that, in line with current operations, Braemar pays ashare of the East Brae platform operating costs, split dependent on production.

Indirect and other costs include primarily onshore support, general and administrationand CO2 emissions costs that are allocated to the East Brae platform.

Shipping and Handling costs for usage of the FPS are included in ERC Equipoise’sBraemar profiles. Gas production from Braemar is also subject to the NationalTransmission System (“NTS”) commodity and capacity charge.

(viii) East Brae

Gas-condensate was discovered in East Brae in 1980 by well 16/03a-8Z. The well wasre-entered and deepened in 1995 (designated 16/03a-8Y), with first production in2003 via the East Brae platform. The exploration well was completed and tied back viaa subsea pipeline to dedicated production facilities on the platform. The well continuesto produce by natural depletion with negligible water production.

Due to the high liquid yield, a gas cycling scheme was implemented in earlydevelopment years to attempt to keep reservoir pressure above the dew point andmaximise liquid recovery. Problems were encountered with this scheme and yieldsdropped rapidly from initial values of over 300 bbl/MMscf, with gas injection eventuallyceasing in 2006 and the field moving to a blow down strategy. As of 31 March 2019,cumulative gas recovery has reached 2,915 Bscf, with an additional 120 MMstb ofcondensate and 36 MMstb of NGL extracted from the gas stream on the platform tomake up platform liquids export to the Forties pipeline system. NGL’s are alsoextracted and sold separately at the SAGE terminal but historical production of theseis not shown here. Gas injection has totalled 1,515 Bscf, giving a net gas productionof 1,400 Bscf.

Reserves have been forecast for East Brae on a well-by-well basis using DCA of gasrate against the cumulative gas production.

Historical uptime performance has been analysed and a range of values are usedacross the wells and confidence levels, as presented in the table below. Averageshave been calculated using data from the previous 6/12/24 months well performancefor the 3P/2P/1P levels respectively. Well uptime is varied as most are unstable. Dueto the nature of E21 production performance, it is assumed to fail to return toproduction in the low case.

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Table 10.13: East Brae Unplanned Uptime

ERCE ERCE ERCE

Well Reserves 1P Reserves 2P Reserves 3P

E01 51% 61% 71%E03 90% 91% 93%E12 6% 6% 8%E14 86% 91% 94%E21 0% 36% 36%E25 84% 93% 94%E28y 4% 14% 15%E30 86% 92% 94%

Currently E12 is flowing at 0.6 MMscf/d for two days per month which is thejustification for setting a minimum technical rate cutoff of 0.5 MMscf/d to the wellprofiles.


1P 2P 3P



East Brae 0.314 0.566 15.332 0.486 0.980 26.548 0.699 1.496 40.509

No capital spend is forecast on East Brae from the second quarter of 2019, thereforeno costs are included in ERC Equipoise profiles.

Direct OPEX costs for the East Brae platform include platform specific integrity andmaintenance, routine operations and logistics. ERC Equipoise has assumed that, inline with current operations, both Braemar and Devenick pay a share of the East Braeplatform operating costs, dependent on production share.

Indirect and other costs include primarily onshore support, general and administration,fuel gas and CO2 emissions costs that are allocated to the East Brae platform.

Shipping and Handling costs for usage of the FPS are included in ERC Equipoise’sEast Brae profiles. Gas production from East Brae is also subject to the NTScommodity and capacity charge.

(ix) Foinaven

Oil was discovered in Foinaven in 1990 by well 204/24-1A, with first productionoccurring in 1997 via the Foinaven FPSO which is owned and operated by Teekay.After 12 exploration and appraisal wells, 41 development wells have been drilled onthe field. Currently there are 16 active producers with two wells shut in due toproduced water re-injection restrictions.

Foinaven is located approximately 150km west of the Shetland Islands. The main fieldproduction is through two drill centres, with Foinaven East being developed through a7km sub-sea tieback to the FPSO.

Foinaven is scheduled to have production cease at the end of 2025. All forecasts havebeen truncated based on this assumption, although the partners are examining waysof recovering post-2025 the material discovered hydrocarbons that will be unproducedat this date.

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Figure 11.1 Foinaven Field Location (Source: RockRose)

Reserves have been forecast for Foinaven using trends of WOR against thecumulative oil on an individual basis. The main activity that impacts the forecast is theremoval of produced water re-injection constraints that currently impact production.These constraints are scheduled to be lifted following the TAR planned for the thirdquarter of 2019 which will enable additional wells P24 and P26 to resume productionand for wells P15 and P27ST to be flowed harder as they are currently choked backdue to them being the largest producers in the field.


1P 2P 3P



Foinaven 46.473 0.000 5.917 55.357 0.000 6.233 66.208 0.000 6.548

Fonaven Main 39.612 0.000 5.917 46.853 0.000 6.233 55.816 0.000 6.548

Fonaven

East Flank 3.215 0.000 0.000 4.147 0.000 0.000 5.119 0.000 0.000

Foirraven T25 2.161 0.000 0.000 2.584 0.000 0.000 3.167 0.000 0.000

Foinaven T35 1.485 0.000 0.000 1.773 0.000 0.000 2.106 0.000 0.000

Capital costs on Foinaven carried in ERC Equipoise forecasts are aligned to theoperator’s budgetary information, from the second quarter of 2019. These costs areassociated with the maintenance and upgrade of the Foinaven FPSO. The majorprojects include:

• Purchase of critical spares – Riser

• Thruster upgrade project

• Flowline Termination Assembly and jumper change out

OPEX costs forecast by ERC Equipoise are benchmarked with, and based on,previous years’ historic costs. Forward annual operating including the maintenance of

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subsea infrastructure and payment to Teekay for the operation of the FPSO. Teekayowns and operates the Foinaven FPSO, which is then due a tariff payment inaccordance with the FPSO Services Agreement. This consists of the following:

• Basic day rate

• Supplemental Efficiency Payment

• Production Tariff

• Supplemental Price Tariff based on Brent Price

Field and Direct OPEX over and above the operation of the FPSO includes fuel,ongoing studies, offshore manpower and support to Teekay from the Operator, wellmaintenance, EU ETS fees and logistics.

Specific subsea OPEX projects include the WP14 jumper replacement planned in2019 and the Subsea Control Module change out.

The following table details the currently anticipated cessation of production dates foreach of the producing fields included in the Marathon Interests plus the estimated,gross pre-tax decommissioning liability (in real terms) and RockRose’s estimate of itsnet post-tax decommissioning liability (in real terms).



Braemar 2021 £39MM £4MMCentral Brae 2030 £110MM £18MMEast Brae 2021 £257MM £38MMSouth Brae 2030 £253MM £40MMWest Brae 2030 £373MM £60MMFoinaven 2025 £507MM £85MMEast Foinaven 2025 £72MM £20MMT25 2025 £31MM £4MMT35 2025 £20MM £2MM

(x) Rationale for Marathon Acquisition

The Directors believe that the Marathon Acquisition marked a major step change in theGroup’s reserves and production profile and given the quality of the assets the Board’swas of the view that it is this is a good opportunity to make the transition to the role ofoperator.

(b) The Dyas interests

(i) Overview

The Company announced on 24 May 2018 that it had signed the Dyas AcquisitionAgreement. In October 2018, the Company announced the completion of the DyasAcquisition.

(ii) Dyas Acquisition Agreement

The terms of the Dyas Acquisition Agreement dated 23 May 2018, are detailed inPart XIX – Additional Information of this document.

(iii) A&B Block

The A&B Block asset comprises six fields of varying maturity all operated by Petrogasas follows:

• A12 (RockRose 14.63%); startup Dec. 2007

• A18 (RockRose 14.63%); startup Dec. 2015

• B13 (RockRose 14.63%); startup Dec. 2012

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The A&B Fields are low relief, four-way dip closures in stacked Pleistocene marinesands, at shallow depths of less than 3200 ftTVDSS. The reservoirs vary from cleansands of 1-8m thickness, to more laminated intervals. These reservoirs are laterallycontinuous and in general lack faulting and compartmentalisation.

Collectively, the three fields on production currently produce at the delivery capacity of3.6 M Nm3/d (c. 135 MMscf/d). The A&B fields have produced 12.0 B Nm3 (447 Bscf)by 31 March 2019.

Figure 14.1: A&B Block Assets, location map (Source: RockRose)

The A&B fields have had numerous drilling campaigns in its development. The mostrecent is two-well drilling campaign, UDS2. One well, a sidetrack which started up atthe beginning of 2019, lies in field A12 and is currently producing at around150 kNm3/d (c. 5.5 MMscf/d). The other, started up at the end of 2018, lies in the A18field and is currently producing at around 380 kNm3/d (c.14 MMscf/d). Future drillingcampaigns are planned by the operator.

Table 14.2: AB Field Recovery Factors

GIIP EUR (nBCM) Recovery Factor

A12 (nBCM) Low Mid High Low Mid High

Stage 1a Reservoirs 9.21 6.27 6.45 6.58 68% 70% 71%UDS 2.07 1.13 1.30 1.59 55% 63% 77%UDS 2 0.23 0.13 0.15 0.18 56% 67% 80%


B13 (nBCM) Low Mid High Low Mid High

Q4A/Q4B reservoirs 5.35 3.76 4.02 4.27 70% 75% 80%


A18 (nBCM) Low Mid High Low Mid High

Stage 1c Reservoirs 5.48 3.57 3.84 4.36 65% 70% 80%Q7 0.56 0.20 0.25 0.31 36% 45% 55%

No development CAPEX have been included in RockRose’s forecasts.

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Wells A12-A04-ST and A18-A05 are not included in ERC Equipoise’s cost forecast, asthey were completed by the effective date of their report. Compression trainre-wheeling; 2-6MM Euro based on initial scoping. A capital cost of 4MM Euro hasbeen included in ERC Equipoise forecasts, 2021-2022. RockRose field OPEX, outwiththe tariffs, is broadly based on historical costs. This has been accepted by ERCEquipoise.

(iv) Bergen, Groet and Schermer Fields

The Bergen concession, operated by TAQA, is located onshore Netherlands,approximately 25km north-west of Amsterdam, and comprises the Bergen(Rotliegend), Bergermeer, Groet, Schermer (Platten dolomite), Starnmeer, ZuidSchermer fields. The minor part (23.5%) of the West Beemster field also lies in theBergen Concession, although its gas is evacuated through the NAM operated facilitiesin Middelie. Gas was discovered in the concession in 1964, with the main reservoirbeing the Rotliegend.

Figure 15.1: Bergen Concession location map (Source: RockRose)

Gas was discovered in the concession in 1964, with the main reservoir being theRotliegend. Gas has also been discovered in the Bunter Sandstone and the ZechsteinPlatten Dolomites.

Production in the Bergen concession is currently from three wells in the Groet, Bergenand Schermer fields. The Groet Oost, Starnmeer, Zuid Schermer fields have ceasedproduction.

ERC Equipoise used DCA to forecast field production. Ber-03 has encountered liquidloading problems reducing production potential, leaving the Bergen field with a singleproducer, Ber-04. Field production is maintained at rates of around 2 MMscf/d.Schermer-01P is the only producer in the Schermer – Plattendolomite at rates ofaround 0.5 MMscf/d. The field has an operating efficiency of 50% and is encounteringissues with salt precipitation. Schermer-01P is the only producer in the Groet field atrates of around 2.5 MMscf/d.

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(v) West Beemster Field

The West Beemster field is located within the Middelie concession and was developedby NAM in 2008. The Bergen joint venture pays its share of costs and receives 23.5%of production under an utilisation agreement.

It is anticipated that a compression project at the field will begin in November 2019, toenable an increase in recoverable volume (0.85 B Nm3). The compression projectincreases the recovery factor by 23%, from 61% to 84%, which ERC Equipoiseconsiders to be reasonable.

ERC Equipoise was not provided with production rate history data, however based onthe limited information available, ERC Equipoise considers the operator’s forecast tobe reasonable and has been used as the basis for its forecasting.

No forward CAPEX or projects are included in RockRose profiles for either Bergen orMiddelie (West Beemster). The CAPEX for the compression project has been fullyspent, as of the effective date of ERC Equipoise’s report.

Direct production expenses and West Beemster charge is varied with ERC Equipoiseproduction profile. General and Administration and well costs are expected to be fixedthroughout asset life.

(vi) Hanze Oil Field

The Hanze Field Licence F02a is located within approximately 212km north of DenHelderand contains the Hanze Oil field and the a Pliocene gas field (shut-in). TheHanze oil field, which started production in 2001, is operated by is Dana Petroleumand RockRose holds a 20% interest in.

Reserves are only assigned to the producing Cretaceous chalk oil reservoir. The oilleg is underlain by a strong and mobile aquifer. Oil production from the Hanze Fieldstarted in 2001 and has produced 63 MMbbls to date. There are currently fourproduction wells and one water injection. The field’s production and waterflood arenow mature and artificial lift is used including gas lift and electric submersible pumps(“ESP”). A significant workover was undertaken early 2019 whereby the artificial lift inplace was upgraded or changed. Following this workover, two wells are using ESPswhile two others are using continuous gas lift.

The field is now mature, producing at approximately 94% water cut with an establishedlate-field life WOR trend. ERC Equipoise uses DCA to generate production forecastsfor the Hanze Oil Field. In the 2P and 3P case, ERC Equipoise used the WOR trendto forecast production assuming a constant liquid production rate in line with recentproduction. In the 1P case, ERC Equipoise used an exponential decline based uponthe decline of the recent oil trend. ERC Equipoise assumes the recent acceleration inproduction due to production restart following ESP changeout is in the short term andhas a negligible effect on long-term reserves recovery. Given the historicalperformance, we predict the oil production rate will fall back to the general historicaltrend quickly.

The operator’s estimates of CAPEX have been adopted. These include EUR 11.9 MMin 2019 for a variety of necessary facility and well upgrades including ESP changereplacements, tanker loading hose reel replacement and water debottlenecking.Future CAPEX is forecast to be spent on periodic ESP replacements.

OPEX for Hanze oil allows for gas import at a cost of 1.9MM Euro per year, as Hanzeis anticipated to go gas deficient in 2019. Hanze oil OPEX is set at a fixed cost of EUR18.5MM per year, with minor variable cost for oil transport.

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(vii) K4/K5 Fields

Discovered in 1988, the K4b-K5a blocks contain ten existing gas fields situated on theCleaver Bank High in the west of the Netherlands Offshore Continental Shelf in theNorth Sea and proximal to the Dutch and UK median line. Water depths range from34 to 68 meters with gas produced from the Rotliegend and Westphalian reservoirs.The wells at the K4/K5 fields is operated by Total and the Company’s interest in thesewells range from 6.98%-11.66%.

Figure 16.1: K4/K5 Fields location map (Source: RockRose)

The ten fields are broken down into associations based on platform, proximity andreservoirs as follows (Association: Fields): K4K5 Unit: K4-A, K4-B, K4-E, K4-N, K5-A,K5-B; K5EC2 Unit: K5-EC2; K4b/K5a: K5-D, K5-E; K5-F Unit: K5-F.

As of 31 March 2019, the asset has produced 49.8 B Nm3 (1.9 Tcf) of sales gas at anasset wide sale gas rate of 3 MM Nm3/d (c.112 MMscf/d).

The K4/K5 area comprise several working interest areas.

For the K4/K5 unit fields, RockRose’s effective working interest is equal to the productof the unitisation percentage in the K4b/K5a group (59.883%) and the RockRoseworking interest in the licence (11.662%), which results in 6.984%.

For the K5-EC2 unit, ERC Equipoise has been informed that RockRose’s effectiveworking interest is 11.276% of 68.000%, resulting in 7.668% in the unit.

For the purposes of economic modelling and net reserves assessment, we determineda weighted average Net Entitlement from the production forecasts, resulting in aRockRose working interest of 7.02% to the Total K4/K5 field area.

ERC Equipoise has adopted the provided forecasts of CAPEX and OPEX withoutmodification.

• No projects included

• Low CAPEX through field life – capitalised workovers, studies

• 100% pre-unitised basis

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Table 16.1: K4/K5 OPEX Forecast in €MM (Source: Operator)

NLDA4 Opex 26.737 26.522 25.029NLDA40 Current 5.935 8.237 7.983

NLDA4000 K4b/K5a Opex Studies 186 436 375

NLDA4010 K4b/K5a Routine Maintenance 11.889 13.339 12.811

NLDA4020 K4b/K5a Gas Treatment 5.845 5.845 5.606

NLDA4021 K4b/K5a Gas Treatment revenues –12.222 –12.222 –11.052

NLDA4030 K4b/K5a Other Costs (Surface rights) 237 239 243

NLDA41 Non-Current 7.004 6.061 6.176

NLDA4100 K4b/K5a Non-Routine Maintenance 7.004 6.061 5.896

NLDA4110 K4b/K5a Work-Overs 278

NLDA42 Gas Transport 12.529 11.194 10.067

NLDA4200 K4b/K5a Gas Transport 12.498 10.855 10.067

NLDA4205 K4b/K5a Gas Transport (K5F-K6 partners) 25 300

NLDA4210 K4b/K5a Gas Transport (K5F-K5 partners) 6

NLDA4215 K4b/K5a Gas Transport (K5F-100% Dyas) 39

NLDA49 Other Opex cost 1.269 1.031 804

NLDA4908 K4b/K5a Overhead (noc-in) 959 726 509

NLDA4909 K4b/K5a PCO (Noc-out) 310 305 295

(viii) Rijn Oil Field

The Rijn oil field is located within the P15-ab licence block and came on-stream inDecember 1985 and initially ceased production in 1998. In 2010, following acquisitionand significant redevelopment of the area by TAQA, production was restarted.

RockRose owns a 45.69% interest in the field.

The Rijn oil field contains five production wells and six water injectors. By 1998, thefield had produced some 24 MMbbls of oil and has produced a further 2.5 MMbblssince 2010.

The Rijn Oil Field produces at a water cut of between 80-90% with a GOR of 400-700scf/stb. ERC Equipoise was provided with production data following theredevelopment in 2010 only. The field is supported by water injection, most recently ata rate of 4 Mbbls/d.

Following successful ESP replacement, wells A01 and A02z are scheduled for to bebrought back online. From the 2017 production performance, an uptime of 85%,including TAR, is assumed (uptime, excluding TAR, is taken as 94%). ERCEquipoise’s forecasts assume there are no additional Rijn field production wells, andno significant other activities, however, an increase in production in the operator’sforecasts following 2020 suggests an additional well is being planned.

The end of the forecast is taken as the end of 2028 as provided by the operator.

(ix) P Block Fields

The P/Q block is operated by Wintershall and contains producing and non-producingfields. The producing fields are P6-A and P6-B (unitised as P6-AB), P6-D, P9-B(P9-AB), Q4-A and Q4-B. The field P9-AB has not produced since 2017. Thenon-producing fields are P6-S and P12. P6-S is plugged and abandoned and P12 isdiscontinued, however, the facilities may be used in the future to re-route gas fromnearby producing fields.

All fields are evacuated to the P6-A platform. The platform is expected to reach CoPat the end of 2021 and due to this imminent abandonment has an exemption toreducing NOx emissions. The operator does not currently plan to invest in NOx

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reduction measures at the P6-A platform (extending field life), however, the operatorhas provided sales gas forecasts up to 2024. The licence for the P6-A platform throughwhich these fields are produced is due to expire end 2021.

P6-AB fieldsP6-AB is a grouping of two fields – P6-A and P6-B and is operated by Wintershall.RockRose holds a 15% working interest in the fields. Production at the P6-AB fieldsbegan in January 1983 and has collectively produced around 10.5 B Nm3 to date(c. 393 Bscf).

P6-A contains three producing wells (P6-A1, P6-A3 and P6-A6), which produce fromthe Bunter Sandstone. Well P6-A3 has been shut-in since February 2017. P6-Bcontains one production well (P6-B2), which produces from the Platten Dolomite. Theoperator regularly considers the two fields collectively and as such, ERC Equipoisehas evaluated them together.

The licence in respect of these fields expires in August 2033, however P6-A platformoperations are expected to cease in 2021. There are no major works to be undertakenuntil the abandonment of the field in 2022, although the P6-A platform has anexemption to reduce nitrous oxide emissions due to the imminent abandonment.

P6-D fieldThe P6-D field contains a single well (P6-D1), which produces from Bunter Sandstoneand is tied back to the P6-A platform, which will cease operations in 2021 at the latest.Production began in October 2001 and the licence at the oil field is due to expire inApril 2022. The Group owns a 30.60% working interest in the field. There are no majorworks to be undertaken until the abandonment of the field in 2022, although the P6-Aplatform has an exemption to reduce nitrous oxide emissions due to the imminentabandonment. The field has produced 2.3 B Nm3 to date (c. 84.6 Bscf).

P9-AB fieldThe P9-AB field consists of two fields, which are tied back to the P6-A platform:(i) P9-A, which began production in September 2009 and (ii) P9-B, which beganproduction in October 2009. The Group owns a 15.58% working interest in the fields.

The licence in respect of the fields expires in August 2033, however the P6-A platformoperations are expected to cease in 2021. According to available production data,downtime has been significant since 2013. Production from P9-AB has beensuspended since the beginning of 2018 and it is unclear if or when the operatorintends to resume production. In addition, two small prospects have been identified tothe west of P9-AB, P9 Bravo and P9 Delta but it is unclear whether these prospectswill be drilled.

Non-producing fieldsThe P6-S field discontinued production, with wells and pipelines plugged andabandoned. The P12 field discontinued production but facilities in the area may beused in the future to re-route gas from nearby producing fields.

(x) Q Block Fields

The Q4 Block contains two producing fields: Q4-A and Q4-B. The fields are expectedto reach CoP at the end of 2021, due to nitrous oxide emissions.

There is a high probability that the licences will be extended for Q4-A and Q4-B until31 December 2021. There are no major works to be undertaken until the

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abandonment of the field in 2021, although the P6-A platform has an exemption toreduce Nitrous oxide emissions due to the imminent abandonment.

Q4-A came on stream in 2001 and has three production wells tied-in to the P6-Afacilities, where the gas is compressed. The Group owns a 10.35% working interest inthe field. The Q4-A field has produced 2.5 B Nm3 sales gas to date (91 Bscf).

Q4-B began production in 2002 and has one production well tied-in to the P6-Afacilities, via the Q4-A platform. The Q4-B Field has produced 2.1 B Nm3 sales gas todate (80 Bscf). The Q4-B Field is located across the Q4 and the Q5d licence boundaryand is unitised, with 72.5% of reserves allocated to the Q4 licence and the remaining27.5% to the Q5d licence. RockRose’s effective interest in the Q4-B field is forecast at10.25%.

(xi) Decommissioning with respect to the Dyas interests

The following table details the currently anticipated cessation of production dates foreach of the producing fields included in the Dyas Interests plus the estimated, grossand net decommissioning liabilities (in real terms).



A&B Blocks 2028 €94MM €14MMBergen 2029 €39MM €5MMHanze 2039 €92MM €19MMK4/K5 2036 €215MM €25MMP15/P18 Rijn 2021 €52MM €24MMP/Q Blocks 2021 €113MM €14MM

The Group’s interest in Petrogas operated Halfweg platform (1.14% interest) wassuccessfully and safely decommissioned within budget and in accordance with Dutchregulations in early 2019.

(xii) Rationale for Dyas Acquisition

The Directors believed that the Dyas Acquisition was an excellent opportunity toexpand the Group’s portfolio in the North Sea to a level of production that is over10,000 boepd and in addition to providing significant free cash flow diversifies theportfolio and strengthens the Company’s position. The Board also saw significantupside in the combined portfolio and the opportunity for the Company to organicallymaintain or grow profitable production from these levels without necessitatingadditional funding, with the potential of adding long term value by making a furthersignificant acquisition in a low oil price environment.

(c) The Arran interests

(i) Overview

The Company announced on 9 August 2018 that it had entered the Arran AcquisitionAgreement. The Company partnered in the field with Shell UK, Zennor North Sea Ltdand Dyas UK. The Arran Acquisition did not involve operatorship of the development.On 19 September 2018, the Company further to the Arran Acquisition Agreementsigned an Equity Realignment Letter Agreement on Arran, which increased theCompany’s interest to 30.43%. On 10 October 2018, the Company announced thecompletion of the Arran Acquisition and noted that the final investment decision hasbeen made by the joint venture partners to develop the Arran field and that Shell hasbecome the operator of the Arran project.

80


(ii) Arran Acquisition Agreement

The terms of the Arran Acquisition Agreement dated 8 August 2018, are detailed inPart XIX – Additional Information of this document.

(iii) Arran Field

The Company owns a 30.43% interest in the Arran field. The interest will continue tobe operated by Shell.

The Arran Field lies within Blocks 23/11a, 23/11c, 23/16b and 23/16c at a water depthof 260-360ft, 300ft, with four wells drilled on the field in total. Two wells encounteredgas in a low-relief Forties pinch-out closure against the Jaeren High, whilst twotargeted a high relief salt-cored closure to the north.

The Arran Field also lies close to the eastern edge of the Forties depositional system,with thin-bedded turbidite sands deposited into a background shale. As such thereservoir is laterally and vertically various, with an effective and base seal. Two wellsfound gas in Arran North and two in Arran South.

The field development plan submission was made to the OGA in September 2018. TheArran field will be produced by means of natural depletion, assumed to be exportedvia a 58km pipeline to the Shearwater Host facility, with production of the first gasexpected to be delivered in the first quarter of 2021. Reserves have been assignedunder the Petroleum Reserves and Resources Classification System and Definitionssub-classification of Approved for Development.

Figure 9.1: Arran Field location map (Source: Dana Petroleum

Environmental Statement)

ESMA

update para

132 (a), (c), (d)

81


Depending on the performance of the initial development wells, further infill drillingmay be required to optimise recovery from the field or fully exploit poorly drained areasof the field. There is a spare well slot on the Arran south tie-in structure and ability toconnect a further well to Arran North tie-in structure should additional required targetsbe identified. ERC Equipoise assumes a facilities level efficiency of 81%, with welluptimes of 96.7%. In addition, a minimum flow rate of 5 MMscf/d is assumed.

Along with the gas, Arran will produce condensate. There is uncertainty in thecondensate-gas-ratio that will be realised, as sampling to date has resulted in dataranging from 40 bbl/MMscf to 90 bbl/MMscf depending on the depth of sampling andthe vintage of the well. ERC Equipoise has assumed initial CGRs of 40 to 46bbl/MMscf in the 1P to 3P levels of confidence that are forecast to fall in time, as thefield is depleted.

Arran is scheduled to have gas exported via the Shell Esso Gas and AssociatedLiquids system and condensate via the FPS. NGLs will be extracted for gastransported via the Shell Esso Gas and Associated Liquids. A gas shrinkage of 15%and an NGL yield of 38 bbl/MMscf is forecast. Condensate exported via the FPS willhave excess gas extracted. In addition the condensate is expected to receive a smallvolumetric uplift for sales purposes. A GOR of 223 scf/bbl of condensate exported viathe FPS is forecast, with an associated liquid shrinkage of 8.6%.

ERC Equipoise has accepted the operator CAPEX and ABEX forecast for the four welldevelopment. The partnership has begun to invest capital in long lead items and£290MM of remaining gross CAPEX is forecast to be spent, as of the effective date ofERC Equipoise’s report.

OPEX for the field will be a combination of tariffs and OPEX share. Tariffs have beennegotiated with the FPS, SEGAL, NTS and GAEL. ERC Equipoise has been providedwith the forecast of tariff costs which we have relied upon in preparing the costforecast. Until 2025, Arran will pay a tariff to cross the Shearwater facility. From 2025onward, Arran will enter into an OPEX share with other fields crossing the facility. Forthe purposes of forecasting the OPEX share, ERC Equipoise has assumed theShearwater 1P plan for liquids crossing the platform. This scenario was one of anumber provided to the Arran joint venture for the basis of project Final Investment andERC Equipoise has relied upon this forecast when evaluating costs.

(iv) Decommissioning with respect to the Arran interests

Given that Arran is yet to enter production, there is no current decommissioning plan.

(v) Rationale for Arran Acquisition

The Directors believed that the Arran Acquisition was an excellent opportunity toexpand the Group’s portfolio and was a major milestone for the Company as the firstdevelopment project it had participated in and provided infill drilling opportunitiescontinues as part of our portfolio’s evolution.

Summary of existing assets

(d) The Idemitsu interests

(i) Overview

The Company announced on 18 October 2017 that it had signed the Idemitsu UKAcquisition Agreement. On 30 November 2017, the Company received a letter fromthe OGA confirming that it currently has no objection to the change of control ofIdemitsu UK, and the Idemitsu UK Acquisition completed on 8 December 2017. By

Annex I, 6.1.1

82


virtue of the Idemitsu UK Acquisition, the Company acquired interests in a number ofproducing fields in the North Sea, as follows:

Field Working Interest Operator

Ross 30.82% RepsolBlake 30.82% RepsolNelson 7.48% ShellHowe 20.0% ShellBalmoral 7.5% PremierStirling 16.0% PremierBeauly 40.0% RepsolBurghley 41.1% RepsolGalley 17.4% Repsol

(ii) The Idemitsu UK Acquisition Agreement

The terms of the Idemitsu UK Acquisition Agreement dated 18 October 2017, aredetailed in Part XIX – Additional Information of this document.

(iii) The Nelson Field

The Group owns a 7.48% interest in the Nelson Field. The interest will continue to beoperated by Shell.

The Nelson Field is located south-east of the Forties Field in the Central North Sea. Itis operated by Shell and has been on production for over 25 years. The Nelsonstructure is a low relief anticline at a depth of some 7,000 ftTVDSS. The quality of thePalaeocene Forties sandstone is very good. Recovery is through a combination ofaquifer influx and water injection, as well as gas lift.

The Nelson Field has been developed through several cycles of infill drilling followingthe initial development of the Nelson Field. A total of 37 production wells and fourwater injectors have been drilled. The oil production rate peaked at around 185 Mbbl/din 1994. The Nelson Field is now at a mature stage of production, producing some9 Mbbl/d of oil and 155 Mbbl/d of water, a water cut of some 94%. The cumulative oilproduction as at 31/03/2019 is 482 MMbbl pipeline barrels.

Oil from the fixed platform is transported by pipeline to the Forties Field, and then toshore via the Forties pipeline system. Excess gas not used for fuel is exported via aseparate pipeline to St Fergus for sale.

As part of the well services campaign for 2019, workovers were planned for WellsN12, N20x and N25z. Well N12 workover commenced in the late first quarter of 2019and was completed in the early second quarter of 2019. The initial flow tests wereused to guide the forecast profiles. Well N20x was restored in September 2017,producing via a de-sander, with sand production being monitored, it was anticipatedthat a coiled tubing operation to replace the well’s sand screens would be undertakenin the fourth quarter of 2018. In May 2018, the well experienced a greater anticipatedsand production, raising an imminent risk of failure and was subsequently shut-in. Anoperation to replace the sand screens is now rescheduled to be carried out in thesecond quarter of 2019. This well was capable of producing at >1,000 stb/d so is amajor potential producer in the field. The N25z well has been shut in since the thirdquarter of 2016 due to sand issues. A sand clean-out coil tubing operation, which ispart of the same campaign as the N20X well, is expected to commence in the secondquarter of 2019 and return approximately 150 bbls/d of oil production to Nelson.

The Nelson Field is a mature field with established production trends. For existingwells, reserves have been calculated from production performance assessment usingDCA. Initial uptimes of 82% have been assumed in our analysis, based on recent and

ESMA

update para

132(a), (b), (c), (d)

83


forecast performance with an increase in uptime of 88% expected from the thirdquarter of 2020 onwards.

Since March 2018 to January 2019 the well oil production rate has declined from4.2 Mstb/d to 2.8 Mstb/d while the GOR and watercut have increased. In February2019 the well was choked back to 1.7 Mstb/d to prevent any kick off issues with thewell and to steady the rising GOR and watercut. Howe associated gas production iscurrently essential to the Nelson platform operations where it is used as fuel gas. Inorder to ensure both continued production from Howe and to ensure continuedproduction in the mid-term from the Nelson field, a gas lift deepening intervention onHowe has been scheduled to be carried out in the second quarter of 2020.

The Nelson platform requires approximately 6 MMscf/d of fuel gas to enable coldrestart to its wells. This fuel gas is currently supplied by both Nelson and Howeassociated gas production. In the Howe well 1P case the well can no longer continueto produce at the current operating conditions from October 2019 up until July 2020when a gas lift deepening intervention is scheduled to have been completed. Thismeans that the Nelson platform is shut in over the same period in the 1P productionforecast.

On the basis of past drilling results, and following the operator’s intention to put onhold any development projects, ERC Equipoise does not assign any reserves toundeveloped locations. The lack of foreseeable drilling activity in the near future hasled the joint venture to cold stack the Nelson platform rig. Current projects still includedin the future plans are the fuel gas import project and the Nelson South Umbilicalreplacement.

The Nelson fuel gas import heater installation and commissioning work is envisagedto be carried out on the platform in the second quarter and third quarter of 2020. Thecosts for the entire project are spread over both 2019 and 2020. ERC Equipoise’sforecast of costs considers a total cost for the work of £9.31 MM including installation.

For the Nelson OPEX forecast during the period 2019-2021, there were few materialchanges in the operator’s 2019 Work Program and Budget from ERC Equipoise’shistorical assumptions. Therefore, the operator’s profile was accepted.

• £58-74MM (gross) per year, including tariffs

• Transportation tariff to FPS

• TAR scheduled every two years, with the next one in 2020 elevating OPEX

• ERC Equipoise has assumed that all allocated overheads are included.

(iv) The Howe Field

The Group owns a 20% interest in the Howe Field. The interest will continue to beoperated by Shell.

The Howe Field has been developed through a single sub-horizontal well and hasbeen producing since 2004, and lies 14 kilometres east of Nelson. It is operated byShell and contains 41 degrees of API oil in good quality Fulmar Jurassic sandstone ata depth of ca 10,300ftTVDSS. The Howe Field was appraised by Well 22/12a-8, whichencountered an oil water contact in a 160 feet thick reservoir section down dip ofcrestal Well 21/12a-1. The initial reservoir pressure was a 6,700 psi, some 2,700 psiover-pressured.

The Howe Field well produced through a sub-sea template tied back by pipeline to theNelson Field.

ESMA

update para

132(a), (b), (c), (d)

84


The Howe Field has been developed through this single sub-horizontal well onproduction since 2004. The oil production rate peaked at around 11 Mstb/d in 2005.The Howe field is now at a mature stage of production.

Between 2009 and 2018, the single Howe well was choked back due to a constrainton gas production (driven by Nelson TPOSA) which limited the field to 6 MMscf/d. Inthe first quarter of 2018, this commercial agreement was lifted, and the choke wasopened to allow for greater flow rates. The field is now at a mature stage of production.

From March 2018 to January 2019 the well oil production rate declined from4.2 Mstb/d to 2.8 Mstb/d while the gas oil ratio (“GOR”) and water cut have increased.In February 2019 the well was choked back to 1.7 Mstb/d in order to maintain reservoirpressure and to steady the rising GOR and water cut. The associated gas productionat the Howe field is currently essential to the Nelson platform operations where it isused as fuel gas. In order to ensure both continued production from the Howe field andto ensure continued production in the mid-term from the Nelson Field, a gas liftdeepening intervention on the Howe field has been scheduled to be carried out in thethird quarter of 2020. This will safeguard future production in the Howe well until theend of the commercial field life.

At the Howe Field, ERC Equipoise had historically accepted the operator’shistory-matched material balance model for its forecasts. However, due to a recentchange in operating strategy, this model was no longer deemed fit for purpose by theoperator. The operator has since developed a 2D simulation model (the “V Model”) forits production forecasting. ERC Equipoise reviewed the V Model which was updatedin the first quarter of 2019 to significantly improve the history match. The V Modelallowed for more reliable forecasts to be generated than could be generated usingDCA due to the recent rapid changes in operating strategy combined with GOR andWOR trends. ERC Equipoise has therefore adopted the V Model for use in generatingthe Howe Field reserves.

There is a gas constraint on Howe production which is limited to 15.8 MMscf/d, as setout by the operator. The 2P CoP is assumed to be the second quarter of 2022, basedon the operator’s revised operating assumptions.

In the Howe well 1P case the well can no longer continue to produce at the currentoperating conditions from October 2019 up until July 2020 when a gas lift deepeningintervention is scheduled to have been completed. In the 3P case the operatingstrategy is changed following the gas lift deepening and the operating oil productionrate is increased to 2.7 Mstb/d.

The Howe gas lift valve deepening work required to ensure continued mid-termproduction from both Howe and Nelson is scheduled for the third quarter of 2020. ERCEquipoise has considered a total cost for the work of £3 MM.

Concerning the Howe Operating costs, according to the most recent operator’sestimate, £0.96 MM will be spent from the second quarter to the end of 2019(excluding tariffs). A three year OPEX forecast has been detailed by the operator in theHowe 2018 Work Program and Budget released November 2018. This OPEXcaptures the well work on both N25z and N20x scheduled to be carried out in thesecond quarter of 2019.

(v) The Blake Field

The Group owns a 30.82% interest in the Blake Field. The interest will continue to beoperated by Repsol.

The Blake field lies some 12km north east of the Ross Field and has been onproduction since 2001. Repsol Sinopec is the operator of the Blake field.

85


Hydrocarbons are contained in Lower Cretaceous turbiditic sands. The main reservoiris a massive channel sand sequence known as the Blake Channel which has excellentquality reservoir properties. Blake Flank comprises lower quality, thinner Coraclesands located to the north east of Blake Channel.

The two areas of the field have been developed separately. A total of six productionwells and two water injectors have been drilled in the Channel, of which five and tworespectively were in use in 2018. In the Flank, two production wells and one injectionwell have been drilled, although the injection well is no longer used. The oil productionrate in the Channel peaked at around 61 Mstb/d in 2001 and in the Flank at around13 Msbt/d in 2004. The field is now at a mature stage of production. The cumulativeoil production from the whole field as at 31/03/2019 is 113 MMstb.

The Blake Channel is at a depth of ca 5,200 ftTVDSS and contains a 97 ft thick oil rimoverlain by a gas cap. Blake Channel has been developed by six horizontal producersand two deviated water injectors, with both oil production and water injectioncommencing in June 2001.

In 2016 the partner group developed updated static and dynamic models for the BlakeChannel area. These were provided to ERC Equipoise in 2017 and updated withproduction history to the effective date. ERC Equipoise have audited the constructionof the static and dynamic models, evaluated the history match and the applicability ofthe models for production forecasting. After our review, we have concluded that 2Pforecasts compare well to actual production and the model is suitable for 2P Reservesestimation of producing wells in the Blake Channel.

Our review of the model indicated that the forecast oil production from the BlakeChannel area has a strong correlation to water injection and field uptime, thereforethese are the key uncertainties impacting oil production rates. Over the past12 months, water injection has averaged approximately 80 Mbbl/d, consistent withvolumes achieved in 2017.

In addition to existing production, in the Channel, ERC Equipoise now includes thedrilling of two wells in our reserves forecasts, sub-categorised as Justified forDevelopment. These are the 2Z Attic well and the NW1 Infill well. After reviewingoperator simulation results and sensitivity studies, ERC Equipoise has assigned 2.1,4.1 and 5.4 MMstb at the 1P, 2P and 3P levels of confidence for the 2Z Attic well. TheNW1 well has been assigned reserves at the 2P and 3P levels of confidence only.Recoveries are forecast at 1.24 and 3.1 MMstb respectively. Recent TCM informationindicates that these wells will be onstream in the third quarter of 2020. ERC Equipoisehas assumed an onstream date of 1 September 2020 in our forecasts for both wells.

The oil from the Blake Field is produced via a subsea manifold and dual flowlines tothe Bleo Holm floating production storage and offloading unit (“FPSO”). In 2015 Rossstopped participating in the cost share for the FPSO. Instead OPEX for Ross waslimited to a tariff based on produced oil rate, plus field specific OPEX.

The operator is in the process of executing a FLE project, which will maintain FPSOoperability until 2029. With respect to costs, the operator and RockRose continue toexecute the FLE work scope and refine costs.

(vi) The Ross Field

The Group owns a 30.82% interest in the Ross Field. The interest will continue to beoperated by Repsol Sinopec.

The Ross Field lies approximately 110km north-east of Aberdeen. It has been onproduction since 1999, producing undersaturated oil from variable quality, relatively

ESMA

update para

132(a), (b), (c), (d)

86


thin Ross sands of Upper Jurassic age at a depth from 8,850 to 10,500 ftTVDSS, andalso from the underlying Parry sand, Reservoir performance is influenced by faulting,which causes compartmentalisation.

The Ross sand has been developed by six horizontal gas lifted production wells andfour water injectors. The oil is produced into the leased into the leased Bleo HolmFPSO where it is processed and then exported via shuttle tanker.

The Ross field has been developed through several cycles of infill drilling following theinitial development of the Ross field. The oil production rate peaked briefly at around39 Mstb/d oil in 1999. The Ross Field is now at a mature stage of production,producing some 0.4 Mstb/d oil and 0.5 Mbbl/d water, a water cut of some 57%. Thecumulative oil production as at 31/03/2018 is 33.1 MMstb.

The Ross Field is a mature field with established production trends. The Ross Fieldhas experienced downtime throughout 2018 due to, amongst other factors, high oil inwater levels control valve issues and a subsea hydraulic leak. Reserves havetherefore been calculated using decline analysis, accounting for well and field uptime.

Reserves have been assigned under the assumption that the Bleo Holm vesselcontinues to be in operation until 2029, at which point it will be decommissioned. Rossis assumed to be produced by the operator until 2029 under an abandonment deferralprocess.

(vii) The Balmoral, Stirling, Beauly and Burghley fields (B-Block)

The Group also has interests ranging from 7.48% to 41.1% in the Balmoral, Stirling,Beauly and Burghley fields (together, the “Secondary Field Interests”). The SecondaryField Interests are all late stage assets and are new in the process of having ceasedproduction or being close to cessation of product. Premier operates the Balmoral andStirling fields and Repsol Sinopec operates the Beauly and Burghley fields.

All B-Block field production is routed through the Balmoral FPV. The B-Block jointventure executed the B-Block Life Extension Project which deferred CoP from 2019 to2021. There is currently only one producing well per field for all of the B-Block fieldsin which RockRose has an interest.

In 2017, Balmoral well B3 suffered a leak and was shut-in. All B-Block production wasshut-in in September 2018 due to a flare-tip issue at Balmoral. This has since beenrepaired, with production having recommenced at Stirling, Beauly and Burghley on1 December 2018. Well B29 on the Balmoral Field is currently planned forreinstatement during the second quarter of 2019. Burghley is currently producing at arate of 1,450 bbl/d, Stirling is currently producing at 350 bbl/d and Beauly is currentlyproducing at 730 bbl/d.

All ERC Equipoise forecasts are made using WOR trends, apart from Stirling which isbased on oil decline due to its variable water-cuts. ERC Equipoise has assumed anOE of 70% for all fields and applied a CoP of 2019 for all forecasts, which is the datein which the commercial arrangement between the operator and RockRose expires.

However, this commercial agreement is subject to negotiation and is re-issued to theJV annually, whilst we note that the operator has committed to continue productionuntil the end of March 2021. Future production is contingent on a new agreementbeing signed. If so, it is technically feasible for production to continue on the B-Blockfields until the Balmoral FPV CoP.

Following a few months shut-in due to issues at the Balmoral hub, Stirling, Beauly andBurghley came back online at full capacity by December 2018. The Balmoral well B29

87


is planned to be reinstated in May 2019 at full capacity following flowline intervention.ERC Equipoise has assumed an initial rate of 400 bbl/d for Well B29.

(viii) Decommissioning with respect to the Idemitsu Interests

The following table details the currently anticipated cessation of production dates foreach of the producing fields included in the Idemitsu Interests plus the estimated,gross pre-tax decommissioning liability (in real terms) and RockRose’s estimate of itsnet post-tax decommissioning liability (in real terms).



Nelson 2027 £228MM £10MMHowe 2022 £30MM £4MMBlake & Ross 2029 £415MM £77MMBalmoral & Stirling 2019 £320MM £19MMBeauly 2019 £20MM £5MMBurghley 2019 £23MM £6MM

In addition, RockRose is liable for 17.4% of the costs of decommissioning the Galleyfield once it ceases production. In real terms, RockRose estimates its net, post-taxshare of this will be £10 million.

(ix) Rationale for the Idemitsu UK Acquisition

The Directors believe that the Idemitsu UK Acquisition was an excellent opportunity toexpand the Group’s portfolio in the UK North Sea, with the potential of adding longterm value by making a further significant acquisition in a low oil price environment.

The Directors believe that the key benefits of the Idemitsu UK Acquisition are:

• the acquisition of quality assets, complementary to the focus of the Group’sbase in the UK North Sea;

• a compelling acquisition valuation that is immediately and materially valueenhancing; and

• a portfolio with limited decommissioning risk and decommissioning provisionsestimated and provided for.

88


Current corporate structure at the date of this document and Admission

Corporate structure at the date of this document and Admission, following completion of theMarathon Acquisition:

RockRose (UKCS1) Limited is a company incorporated in England and Wales. This entity isdormant.

RockRose (UKCS2) Limited is a company incorporated in England and Wales. This entity holdsthe licence interests in the Galahad and Mordred fields.

RockRose (UKCS3) Limited is a company incorporated in England and Wales. This entity holdsthe licence interests in the Tors, Grove fields and Seven Seas.

RockRose UKCS4 Limited is a company incorporated in England and Wales. This entity holds thelicence interests in the Blake, Ross, Nelson, Howe fields and the remaining licence interestsacquired from Idemitsu Group.

RockRose UKCS5 Limited is a company incorporated in England and Wales. This entity isdormant. RockRose UKCS6 Limited is a company incorporated in England and Wales. This entityis dormant. RockRose UKCS7 Limited is a company incorporated in England and Wales. Thisentity is dormant.

RockRose UKCS8 LLC is a company incorporated in Delaware, United States. This entity holdsthe licence interests in the Brae, East Brae, Braemar and Kingfisher fields.

RockRose UKCS9 Limited is a company incorporated in the United Kingdom. This entity is thewholly owned subsidiary of RockRose UKCS8 LLC.

RockRose UKCS10 Ltd is a company incorporated in the United Kingdom. This entity holds thelicence interests in the Foinaven fields.



RockRose UKCS13 LLC is a company incorporated in Delaware, United States. This entity is thewholly owned subsidiary of RockRose UKCS8 LLC, is dormant and will be dissolved in due course.

RockRose Energy (NL) B.V. is a company incorporated in the Netherlands. This entity is anintermediate holding company which does not directly hold any licence interests.

71674535 RockRose Energy

(NL) B.V.

0822875 RockRose UKCS8

LLC (was Marathon Oil

UK LLC)

100%

100

100%

04620801 RockRose

(UKCS3) Ltd (was Sojitz

Energy Project Ltd)

02552901 RockRose UKCS4 Ltd

(was Idemitsu Petroleum UK Ltd)

08724360 RockRose

(UKCS2) Ltd (Egerton Energy

Ventures Ltd)

100%

100%

100%

10448997 RockRose

(UKCS1) Ltd (Dormant)

100


(was Idemitsu UK Oil Ltd - Dormant)

01908768 RockRose

UKCS7 Ltd (was Idemitsu North

Sea Ltd - Dormant)

09665181 RockRose Energy

plc


(was Idemitsu E&P Ltd - Dormant)

100

100%

100%

100%

30108055 RockRose (NL) CS1

B.V.

30108055 RockRose (NL)

Infrastructure B.V.

4466992 RockRose UKCS13 LLC

(was Marathon Oil Decommissioning

Services LLC)

100

100%

100%

100 100%


(was Marathon International Oil (GB)

Limited)

981126 RockRose UKCS12 Ltd (was Marathon Oil North

Sea (GB) Ltd)

1293052 RockRose UKCS9 Ltd (was Marathon Service

(GB) Ltd)

04105025 RockRose

UKCS10 Ltd (was Marathon Oil West of Shetlands

Limited)

Registered in England & Wales

Registered in the Netherlands

Registered in Delaware, USA

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25

89


RockRose Energy (NL) CS1 B.V. is a company incorporated in the Netherlands. This entity holdsvarious licence interests in Dutch oil and gas fields acquired from the Dyas Group.

RockRose Energy Infrastructure B.V. is a company incorporated in the Netherlands. This entityholds various interests in associated infrastructure assets in support of the Group’s Dutch oil andgas fields.

Current locations of the Group’s licence interests at the date of this document and

Admission

Location of the Group’s licence interests at the date of this document and Admission, followingcompletion of the Marathon Acquisition:

90


91


Significant recent trends1

The oil and gas, exploration, development and production industry continues to experiencevolatility, driven by a number of factors including the uncertainties in global economy andgeopolitical events and the technical advancements affecting energy consumption and extractionmethods. In general, the industry is healthier than it was two years ago as the price of oil hasrebounded. After appearing limited to a range between the mid-US$40s and US$50 per barrel(bbl), Brent crude is now trading above US$65. The industry is thus recovering from the brutal lastfew years of weak prices, enforced capital discipline, portfolio realignments, and productivityefficiencies. Natural gas consumption worldwide grew by an estimated 4.6% in 2018, or 170 bcm,its strongest increase since 2010 when gas demand was rebounding from the 2008 global financialcrisis. This second consecutive year of strong growth (after a 3% gain in 2017) was nearly threetimes the average growth of 1.5% over the previous five years. The switch from coal to gasaccounted for over one-fifth of the rise in gas demand, with the United States leading the growth,followed by China.

Global oil demand rose by 1.3% in 2018, led by strong growth in the United States. Oil demand inadvanced economies remained relatively robust, but, in emerging markets, oil demand slowedmarkedly in 2018. Average Brent oil prices were 30% higher in 2018 than in 2017. Oil demand inChina was up by 445 kb/d, or 3.5%, with the rate of growth slowing down as the country movedtoward a less oil-intensive model of development and curbed vehicle use to improve urban airquality. In particular, environmental policies have reduced diesel demand growth, as provincialgovernments are keen to develop cleaner transport fuels or electric buses. European oil demandremained stagnant on slowing economic activity and rising prices. Germany saw an importantdecline in oil demand, falling by 135 kb/d or 5.4% in 2018.

Oil demand growth by region (mb/d), 2017-18

Source: International Energy Agency, Global Energy & CO2 Status Report, 2019

Global upstream capital expenditure, which dropped nearly 45% between 2014 and 2016 is nowforecast to rise 6% year-on-year in the medium term. This recovery has been a result of variousfactors, including the sustained success of the production restraint agreement between OPEC andnon-OPEC countries in force since the beginning of 2017, less oil coming to market fromchallenged producers, and continued strong global oil demand growth (estimated by the EnergyInformation Administration at about 1.6 million b/d in 2018). In the US, natural gas prices have not

Annex I, 12.1,

12.2

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1 Sources: PwC Oil and Gas Trends 2018-19; Deloitte: 2019 oil, gas and chemicals industry outlook; International

Energy Agency, Global Energy & CO2 Status Report, March 2019.

seen great movement, as plentiful low-cost US supply continued to meet growing demand indomestic and export markets.

Europe experienced a decline in natural gas consumption in 2018 after two years of growth. Thiswas partly due to the temperature sensitivity of gas demand, with demand for space heatingreduced by a mild fourth quarter (in spite of cold snaps over the first quarter). Additionally, theDutch government has decided first to lower and then stop production of natural gas from theGroningen field as early as possible. The decision implies that the European Union’s largestexporter of natural gas will become a large importer of gas within four years.

In the supply side, Nord Stream 2, TurkStream and Southern Gas Corridor pipelines underdevelopment will compete with LNG and existing production. Bunkering of LNG as a marinetransportation fuel will provide a new source of gas demand as new emission rules encourageshipowners to switch away from marine fuels. This could add around 6.5 bn m3/yr to European gasdemand by 2025 and 18.5 bn m3/yr by 2035. Wood Mackenzie estimates gas demand among thecurrent EU-28 will rise to a peak of 460bn m3/yr in around 2025 from some 445bn m3/yr in 2018.

Oil and gas rig activity levels are rising, driven by the North American market, and major projectsare being approved. Exploration is on the rise again for the first time since the global recession.

Global oil and gas capital expenditures

Despite these signs of a renaissance, the sector faces a number of supply-related challenges. Firstis an ongoing decline in new discoveries. By the end of 2017, the volume of new oil and gasdiscoveries, was at its lowest since the early 1950s. To put this into perspective, only 3.5 billionbarrels of liquids (crude, condensate, and natural gas liquids) were discovered in 2017, which wasenough to meet only 10% of demand. The reasons for this decline are simple: It’s getting harderto find the large discoveries known as “elephants,” and most prospective areas have already beenexplored.


100k

200k

300k

400k

500k

600k

700k

800k

US$ millions

’20’19’18’17’16’15’14’13’12’11’10 ’21 ’22 ’24’23 ’25

Middle EastRussia

South AmericaAfrica

AustraliaEurope

North America

Asia

North America driving growth in capex

6%

12%

-44%

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The long decline in new oil and gas discoveries

This contraction was exacerbated by a second challenge: the slowness of the rise in explorationspending since it fell with the price collapse of 2014–16. Globally, spending fell by more than 60%,from a high of US$153 billion in 2014 to about US$58 billion in 2017. It is forecast to recovermodestly over the near term at a 7% compound annual growth rate. The investment slump intraditional supply sources looks like it will continue to have an effect on new production.

As a result of these two challenges, the market is currently experiencing what the IEA calls a“two-speed oil market.” Although U.S. tight oil, or shale oil, is a dynamic new source of supply,investment in more conventional sources of output has dropped and, as a result, “the world needsto find an additional 2.5 million mb/d of new production each year, just for conventional output toremain flat,” according to the IEA World Energy Outlook 2017. Given that it takes about three tosix years from project sanctioning to coming onstream, the decline in investment approvals duringthe price slump could continue to hurt the sector if financial investment decisions remainconstrained.


40,000

80,000

120,000

160,000

200,000

240,000

Millions of barrels

19601950 2017200019901970 20101980

Crude oilCondensateNatural gas liquidsGas

Global volumes of new discoveries in oil and gas

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PART VII

REGULATORY AND OPERATING ENVIRONMENT

United Kingdom

Philip Hammond, UK Chancellor of the Exchequer, said in his March 2017 Budget speech that anexpert panel would examine ways of making it easier to buy and sell North Sea oil and gas fields,with the aim of keeping them in production for longer. The announcement reflected HM Treasury’sfocus on how to extract as much as possible out of the remaining North Sea resources asdecommissioning costs become an increasing burden for industry and taxpayers. To determine thebest approach, the UK Government published a formal discussion paper on 20 March 2017alongside the Finance Bill 2017 on the case for allowing transfers of tax history between buyersand sellers, which along with the expert panel review, resulted in legislation in the Finance Act2019 which operates retroactively to make transferable tax histories available for transfers of fieldson or after 1 November 2018. In his October 2018 Budget speech, Philip Hammond said thegovernment would maintain headline tax rates at their current level in order to support therecovering industry.

The UK already has one of the most competitive tax regimes for oil and gas in the world. HMTreasury has recognised that to maximise economic recovery the fiscal regime needs to ensuresupport for the transfer of late-life assets. There are an estimated 10-20 billion barrels ofrecoverable oil and oil equivalent remaining beneath the North Sea, compared with 43bn barrelsextracted since production started in 1967. However, unlocking those resources will depend on theNorth Sea staying competitive against lower-cost regions elsewhere. HM Treasury and the energyindustry are both counting on new investors – especially smaller companies and private equityfunds – to help maximise the potential of the last remaining oil and gas just as many largecompanies seek to sell older fields.

The OGA was established as an executive agency of the UK Government on 1 April 2015. One ofthe key roles of the OGA is to engage with oil and gas, exploration, development and productionindustry to drive down costs and improve efficiencies and to maximise economic recovery of ouroffshore oil and gas reserves, both for Britain’s energy security as well as our long-term economicoutlook.

The Petroleum Act 1998, as amended by the Infrastructure Act 2015, places a duty of theSecretary of State to produce one or more strategies for enabling the principal objective of“maximising the economic recovery of UK petroleum to be met”.

The first MER UK Strategy was required to be produced within 12 months of the relevant clausescoming into force, therefore by April 2016. It was laid in Parliament for scrutiny on 28 January2016, and came into force on 18 March 2016.

The OGA became a UK Government company in October 2016, following Parliamentary approvalfor the Energy Act 2016. The Energy Act 2016 established the OGA as a UK government companyand equipped the body with additional powers to maximise economic recovery of oil and gas frombeneath UK waters. These powers give the OGA the ability to issue enforcement notices andfinancial penalties, and to revoke licences for clear or persistent breaches of the MER UK Strategy.

The MER UK Strategy sets out certain principles which “relevant persons” (being the holders oflicence interests) must now follow.

In particular:

a. relevant persons must ensure that technologies, including new and emerging technologies,are deployed to their optimum effect (as set out in the OGA’s Technology DeliveryProgramme published in April 2017), in maximising the value of economically recoverable

Annex I, 9.2.3

94


petroleum that can be recovered from relevant UK waters, including in relation todecommissioning (MER UK Strategy paragraph 18);

b. before commencing the planning of decommissioning of any infrastructure in relevant UKwaters, owners of such infrastructure must ensure that all viable options for their continueduse have been suitably explored, including those which are not directly relevant to therecovery of petroleum such as the transport and storage of carbon dioxide (MER UKStrategy paragraph 20);

c. relevant persons must allow others to seek to maximise the value of economicallyrecoverable petroleum from their licences or infrastructure including by divesting themselvesof such licences or assets to other financially and technically competent persons who areable to recover economically recoverable petroleum (MER UK Strategy paragraph 30);

d. where relevant persons are not able to ensure the recovery of the maximum value ofeconomically recoverable petroleum from their licences or infrastructure for financial reasonsthey must seek to secure investment from other persons. If they are not able to securesufficient investment in a reasonable time, the obligation in paragraph 30 applies (MER UKStrategy paragraph 31);

e. the obligation in paragraph 30 applies in all other circumstances where relevant personsdecide not to ensure the recovery of the maximum value of economically recoverablepetroleum from their licences or infrastructure, including where the reason for the decisionnot to recover is because recovery generates returns which are unsatisfactory to the relevantpersons, they cannot raise suitable finance or there are technical or other non-economicreasons (MER UK Strategy paragraph 32); and

f. where a relevant person is seeking to comply with the obligation in paragraph 30, thatperson must seek to do so without demanding compensation in excess of a fair market valueor unreasonable terms and conditions, in order that other financially and technicallycompetent persons who are able to recover economically recoverable petroleum may do so(MER UK Strategy paragraph 33).

The MER UK Strategy, which also imposes duties of co-operation on relevant persons, is designedto ensure the North Sea resources are effectively exploited to their maximum potential. Clearlyenvisaged in the MER UK Strategy was the situation where a particular field or licence block waspast prime or optimal production and the participants in that field or block concluded that their owncapital investment was better deployed on earlier stage assets which would yield greater returns.In many cases, and absent the obligations created by the MER UK Strategy, this would have ledto potentially premature decommissioning of that producing field as many licence participantswould prefer to decommission a field rather than become involved in a sale process. The positionwas further complicated by the tax rules relating to decommissioning which are discussed in moredetail below.

In this context the Company was able to negotiate the Acquisitions on the terms set out in thisdocument. In particular, the fact that the Company has been able to agree terms of acquisitionswhere the Company receives a substantial payment rather than itself pays for the assets, isreflective of the different corporate strategies of the Company and the sellers, who are typicallymultinational diversified industrial groups and seeking to deploy investment capital to seekmaximum returns for its shareholders; exiting certain licence interests where those assets are inthe later stages of economic life (and where continuing and uncertain liabilities such asdecommissioning costs can be closed off) may make commercial sense. By contrast, to theCompany, as a smaller focussed entity, this creates an opportunity to acquire these assets atfavourable pricing and, when coupled with the objectives of the MER UK Strategy, the Companysees the potential for the asset life to be extended or for alternative utilisation.

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OGA approval

The OGA are required to approve all persons who are new holders of licence interests (wheredirect interests in assets are acquired) and have the ability to object to any change of control of anentity owning licence interests (and accordingly have the ability to object to corporate acquisitionswhich would constitute an indirect change in ownership of a licence interest).

The OGA approval process involves a rigorous review of the financial and technical ability of newlicence holders. This includes a requirement to share with the OGA the long-term developmentplan (including decommissioning proposals) for activity on a licence interest being acquired,including the operator’s plans for operating and capital expenditure. In the case of later life assets,the OGA will not give its approval unless it is satisfied that the new entrant has the financialresources to meet its share of the financial obligations with respect to that licence.

Decommissioning

On 30 June 2016 the OGA published its strategy paper on decommissioning in the UK continentalshelf. The strategy paper sets out a number of targets with respect to decommissioning activity,which are also intended to supplement the MER UK Strategy objectives of maximising economicrecovery from all oil resources in the North Sea. One of the key strategy objectives is to maximisethe efficiency of decommissioning activities through efficiency and industry transformation with aview to achieving a 35% reduction in current decommissioning cost projections. The OGA, in thestrategy paper, specifically notes that the impact of a lower oil price has led to considerableuncertainty in the oil and gas, exploration, development and production industry and that whilstmany operators are looking at bringing forward cessation of production dates, the desire of theOGA remains to delay decommissioning expenditures when possible and appropriate, and toextend field life.

The OGA also notes in the strategy paper that the large liabilities for decommissioning can alsonegatively impact the ability to transfer assets to many small to medium size operators, leading topremature cessation of production and a failure to maximise the value of production. RockRosebelieves that it falls into the category of small operator who may benefit from many of the initiativesset out in the strategy paper.

To manage the costs and liabilities arising from decommissioning the OGA has developed atemplate for what is known as a DSA. DSAs use a trust structure that allows for parties to a licenceto put aside monies so that at the time of decommissioning there is sufficient cash available to theparties to carry out the decommissioning. Parties are generally liable for a share of the totaldecommissioning costs equivalent to their percentage share in the licence interest but if one partywith an interest in the licence were to become insolvent the remaining parties can become liablefor the share of the party who is unable to fund.

Parties to the licence can either post cash or letters of credit (provided this is acceptable to theother parties). Each year a calculation is undertaken by the operator to calculate the net presentvalue of the anticipated cost of decommissioning. This is then multiplied by a risk factor, usuallybetween 130% and 150%. From this is then subtracted the net present value of all of the cashflows anticipated from the asset for its remaining life and the amount of security the parties havealready provided. If this number is positive, this is the amount that the parties to the licence needto make available to the DSA trust in either cash or letters of credit.

The calculation is repeated each year and additional sums are required to be deposited. Thecalculation is also independently audited. As the asset approaches cessation of production, fundswill have built up in the DSA trust such that the parties should have the liquidity available to meetthe cost of decommissioning. In the event of one party going into liquidation, the DSA trust moniesare available to the other parties to ensure decommissioning can be completed with no additionalliability accruing as a consequence of the party going into liquidation.

96


Decommissioning Relief Deeds (“DRDs”) were introduced on 17 July 2013 through the FinanceAct 2013 to allow parties to a DSA who have also entered into a DRD with the UK Government tocalculate their annual security contributions on a post-tax basis. They operate by calculating abenchmark amount of tax relief for decommissioning expenditure a participant would be entitled toas determined in accordance with the tax legislation in force on 17 July 2013, and providing aguaranteed payment from the UK Government if the tax relief ultimately obtained at the time ofdecommissioning is less than the benchmark. The intention is to mitigate uncertainties around thetax relief that may be available in future for decommissioning expenditure. DRDs are in place forthe Company and all relevant UK subsidiaries.

The current fiscal regime in the UK continental shelf provides tax relief in relation todecommissioning costs incurred by oil and gas operators. The relief is only available once thedecommissioning costs are incurred; ensuring companies pay the full amount of tax (i.e., ignoringrelief on decommissioning expenditure) from all profits generated by the field during its life. Reliefis limited to the tax that has been paid.

If a tax loss arises on decommissioning, that loss can be carried back and offset against the profitschargeable to the Ring Fence Corporation Tax (“RFCT”), Supplementary Charge (“SC”) andPetroleum Revenue Tax (“PRT”). If tax was paid on profits in previous years, the Company will thenbe entitled to reclaim some of the previously paid tax. Different rules are used to calculate howmuch relief can be claimed on decommissioning costs, depending on whether the relief is claimedfor RFCT/SC or PRT.

Generally (and, in particular, subject to specific rules applicable to PRT), a company owning alicence can only off-set the costs of decommissioning against tax actually paid by that companywhilst it owned the relevant licence interest. Legislation enacted in Schedule 15 of the Finance Act2019 allows the offset of decommissioning costs incurred by the current owners of a licenceinterest against some of the tax paid by prior owners by enabling companies selling North Sea oiland gas fields to make a joint election to transfer some of their historic profit chargeable to RFCTand SC (“tax history”) to the buyers of those fields (where the transfer receives OGA approval onor after November 2018). This is intended to facilitate new entrants into licences with a view toextending their economic life.

The tax history will be transferred on a ‘last in, first out’ basis, with tax history from more recentyears being transferred first. The maximum amount of transferrable tax history is linked to theexpected decommissioning costs of the relevant field(s). The transferred tax history will only beavailable for use against carried back decommissioning losses after the transferred field haspermanently ceased production, and only to the extent that losses incurred on decommissioningthe transferred field exceed the post-acquisition profits of that field, which may increase ordecrease as further decommissioning costs are incurred and further profits or losses are accrued.If the field is transferred again, transferred tax history can generally go with it. Transferable taxhistory will only be available for intra-group transfers of fields provided a transfer to a third party iscompleted within certain strict time periods.

The timing and uncertainties surrounding cessation of production dates and the commencementof decommissioning activity are driven by a number of factors, all of which are subject to inherentuncertainty. ERC Equipoise in Part XXIII – Competent Person’s Report of this document assessespotential cessation of production dates based on the probabilities of extractable reserves in place,basing these calculations on current producing wells. These assessments and calculations arethemselves carried out in accordance with industry accepted standards. The potential exists forthese estimates to be inaccurate, with the consequence that economic life is shorter thanexpected, or potentially longer. The other significant risk is that of oil prices; the lower the oil pricethe less economically viable it may be to extract small volumes of oil towards the end of the life ofa field and the less incentive there may be to incur additional capital expenditure on attempting torecover marginal reserves, which efforts may themselves carry a high risk of failure. Clearly factorssuch as reserve estimation calculations being overstated and a prevailing low oil price (which may

97


contribute substantially to economic viability) are matters wholly beyond the control of anyindividual company. Timing of decommissioning will be driven by the economic viability orotherwise of remaining reserves and accordingly there is potentially little that the Company can doto mitigate against these risks other than to budget prudently for the anticipated costs ofdecommissioning.

The Company will inherit decommissioning liabilities upon the completion of the MarathonAcquisition. As at 31 December 2018, the Group had approximately US$53.3 million of cash oralternative security held in DSAs and other interim arrangements.

The operator of each licence typically supplies a financial model which is used to calculate thepostings required under the relevant decommissioning arrangements for the licence interest andpostings are reviewed annually, typically in December. These additional postings are reflected inthe Group’s projections and working capital requirements. The Company has carefully reviewedthe extent of those obligations and in certain cases, where DSAs already exist, will be required tocontribute the DSA on completion of the relevant Acquisition. As decommissioning plans arerefined and developed the Company will continue to contribute its share of decommissioning costsvia the relevant DSA or alternative funding arrangements. As part of the OGA approval process theOGA has reviewed with the Company the scale of the liabilities identified in the operator plans fordecommissioning for the licence interests being acquired pursuant to the Acquisitions in order toassess the ability of RockRose to meet those obligations.

The Company has planned for the full extent of all these liabilities where the same are currentlyknown, but expects that, over time, the MER UK Strategy objectives and the OGA’sdecommissioning strategy objectives may lead to at least some currently proposed cessation ofproduction and decommissioning plans being delayed as a result of extended field life initiatives.

Netherlands

Legislation and Regulators

The Mining Act provides the legislative framework for the licence regime and state participation inthe exploration and production of minerals and geothermic heat, and for underground storage ofminerals and CO2 onshore in the Netherlands, and offshore in the Dutch part of the continentalshelf underlying the North Sea. The Mining Act applies to minerals to the extent that these occurat a depth of more than 100 metres. In addition, detailed regulations are elaborated in networkcodes determined by the Dutch regulator (the Authority for Consumers and Markets). These codesprovide secondary legislation on tariffs, technical conditions and procedures with respect to, inter

alia, system access, system operation and measuring services.

The Mining Act assigns principal regulatory powers in upstream oil and gas, apart from thoseinvolving the environment and spatial planning in general2 to the Dutch Ministry of Economic Affairs(the “MEA”) and the State Supervision of Mines (the “SSM”). The SSM is a competent authority ofthe MEA.

Licences

Ownership of the minerals is transferred to the licence holder(s) at the point of production of theminerals under a production licence issued by the MEA. The MEA may grant a licence forexploration, production or storage. Licence requirements for exploration are, inter alia, financialand technical capabilities and the agreement of a development plan satisfactory to the MEA. Theholder of an exploration licence that demonstrates the commerciality of a gas reservoir then haspriority to apply for a production licence. The holder of the production licence for a reservoir withinthe licence area is exclusively entitled to the production. The current mining legislation is still basedon historic licensing regime and traditional principles. A production licence is granted, provided thelicensee enters into an agreement of co-operation, within one year from the issuance of the

98


2 Licence holders are subject to various requirements in respect of, inter alia, waste water discharges. Compliance with

these requirements is monitored by the SSM and enforced by the MEA.

licence, with Energie Beheer Nederland, i.e., energy management Netherlands (the “EBN”), whichconfers on the EBN a 40% financial share in production. The MEA may grant an exemption to thisobligation only in circumstances where by the EBN entering into such agreement, the State couldreasonably be estimated to suffer financial loss. The co-operation agreement is subject to approvalfrom the MEA.

The EBN thus acts as an independent (non-operating) partner in the majority of Dutch fields. Uponthe acquisition of its participating interest, the EBN must reimburse licence holders its percentageshare of expenditures incurred in the exploration for and appraisal of the prospect, and any furthercapital investment in production facilities. The EBN may request the MEA’s permission for ancillaryactivities provided that such activities are closely related to and will not jeopardise the statutoryduties and serve the general energy policy interest. For such other activities, the EBN mustmaintain ring-fenced accounts.

The licence will stipulate the activity, the mineral, the term and the area of land or seabedconcerned. The exploration licence contains a certain date prior to which the exploration activitiesare to be initiated, the MEA may stipulate specific conditions in the licence. The application for alicence is published in the Dutch Government Gazette and in the Official Journal of the EuropeanUnion. During a period of 13 weeks, other parties are entitled to submit an application for a licencein that same area. If more than one person applies for a licence, they are considered as jointapplicants and when the licence is granted, they will jointly hold the licence, and one of thelicensees will be designated as the operator.

Apart from corporate income tax, the State charges certain taxes directly to the licence holder,such as surface duties (offshore exploration licence or production licence), royalties relating to theamount of natural gas produced (production licence) and State Profit Share (“SPS”). SPS, at a rateof 50%, is levied from the holder or co-holders of a production licence on profits that can be directlyand indirectly attributed to the extraction of hydrocarbons (the ring fence). The allocation principleshave been established in practice and case law. SPS is calculated similar to corporate income tax,but with (most) expenses ‘uplifted’ by an additional 10%. To prevent corporate income tax and SPSfrom accumulating, a notionally calculated amount (generally referred to as the ‘creditableamount’) can be credited against SPS.

Ownership and market access restrictions

The Mining Act does not contain (foreign) ownership constraints. Licence applications can only bedenied if the applicant fails to demonstrate its technical and financial capabilities. There are norestrictions applicable with respect to ownership of mining works or installations.

Transfers of control and assignments

Transfers of licences require the prior written approval of the MEA. The Mining Act does not requiresuch consent in the event of an indirect transfer through a change of control of the licence holder.However, the MEA may withdraw a licence under certain circumstances, such as incorrectinformation provided at the application or the licensee being in default under licence obligations.In the event that an operator no longer qualifies (regarding financial or technical capabilities), theMEA may designate another operator. Therefore, the transfer of a licence interest via a change ofcontrol of the participating entity is often notified to the MEA, in particular in the case of an operatedinterest. The transfer of a licence interest is also subject to accession to the agreement ofcooperation with the EBN. The disposal of a licence interest is subject to the fulfilment ofdecommissioning and abandonment obligations. These obligations rest with the last operator andthe last co-holders of the licence.

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PART VIII

THE BOARD, THE SENIOR MANAGERS AND

CORPORATE GOVERNANCE

The Directors

The Board, collectively, has significant experience in the UK oil and gas, exploration, developmentand production sector. Since 2011 the Directors have consummated at least 12 significantacquisitions and planned and executed three major UK onshore farm-out transactions with energymajors as counterparties.

The Directors are very familiar with the key issues facing both onshore and offshore explorationand development activity. The Board has in aggregate more than 60 years of experience in sub-surface engineering and geology and have been responsible for running complex and challengingfields and drilling operations, both onshore and offshore.

In addition the Board has significant expertise and experience of dealing with the political andsocial issues facing the industry at both the local and national governmental levels, having beenactively involved in the governmental consultation program surrounding shale gas exploration andin the challenges of local planning issues in connection with exploration activity and assetdevelopment.

Details of the Directors are listed below.

Andrew Austin – Executive Chairman (age 53)

Andrew Austin is one of the founders and the former chief executive officer of IGas Energy. Hepreviously specialised in energy projects in the gas, electricity and renewables sector. Prior tojoining IGas Energy, Mr. Austin was involved in ventures as principal and has also raisedsubstantial funds from private and public equity for clients during the course of his career to date.Mr. Austin spent 17 years working in investment banking in the City of London with Merrill Lynch,Nomura, Citibank and Barclays Capital. Latterly he was general manager of CreditanstaltInvestment Bank in London. He also has six years of management and consultancy experiencewith clean tech companies including Generics Group and Whitfield Solar.

Richard Benmore – Non-Executive Director (age 61)

Richard Benmore, B.Sc, M. Sc, Ph.D, has over 35 years of experience in the oil and gas industrywith Conoco, Oryx Energy, Nimir Petroleum, Nexen Petroleum and was most recently at IGasEnergy. Richard has held a variety of roles starting his career as a petroleum geologist beforemoving into various commercial, business development and energy and power managerialpositions. He recently managed Nexen’s unconventional projects in the UK and Poland and was aboard member of Nexen Exploration UK.

John Morrow – Non-Executive Director (age 64)

John Morrow is a Chartered Engineer and has over 30 years of experience in the oil and gasindustry. John served as head of exploration and production at Glencore plc from 2011 to 2019.John was previously the chief operating officer and on the board of directors of Bowleven plc,having joined that company in 2005. Prior to that he spent 10 years at BG Group, where he wasmanaging director of the joint venture which operated the giant Karachaganak field in Kazakhstan.Following that he was responsible for BG Group’s technical effect in the Mediterranean Basin andits African assets and thereafter was project director (Middle East) where he was responsible forthe development of new liquefied natural gas projects. Before joining BG Group, John spent thefirst 15 years of his career at Royal Dutch Shell where he held a variety of operational and

100


commercial roles in the UK, Malaysia and the Netherlands, including as an offshore installationmanager in the North Sea.

The Senior Managers

The Company’s current senior management team (the “Senior Managers”), in addition to theDirectors listed above, is as follows:

Peter Mann – Managing Director (age 38)

Peter Mann joined IGas Energy in 2013 to assist in the implementation of the company’s corestrategic aims. During his time at IGas Energy he was involved in acquisitions and businessdevelopment, heading up the restructuring of the company in 2015, asset development andmanagement and working with IGas Energy’s joint venture partners including Ineos, Total andEngie. Peter left IGas to join RockRose in 2017. Peter’s career prior to IGas Energy has includedvarious strategic management roles. Peter attended the Royal Military Academy Sandhurst,commissioning into the British Army in 2004, where he served for over six years leaving in 2009.Peter subsequently joined Cazenove Capital’s asset management team and in 2011 left toimplement and run a private family office in London.

Richard Slape – Chief Financial Officer (age 53)

Richard Slape has over three decades’ experience working with independent oil and gasexploration and production companies. For much of his career, he worked as an analyst forinvestment banks. Richard joined Rockhopper Exploration in 2012 as a Business DevelopmentManager. He then moved to Lansdowne Oil & Gas in 2014, where he was an executive director,before joining Zeus Capital Limited as an oil and gas research director. Richard joined RockRosein 2019. In 2017, Richard founded Hopton Petroleum, which provides corporate advisory, valuationand research services to clients in the oil and gas and financial sectors.

Stephen (Steve) Pawson – Finance Director (age 63)

Steve Pawson BA, ACMA, has over 40 years of experience in the oil and gas industry where hehas held a variety of financial roles. After a brief stint in the construction industry, Steve joinedPhillips Petroleum as an assistant accountant where he rapidly moved through various roles as hegained his accounting qualification leaving as assistant chief accountant after 10 years. He thenmoved to ARCO where he held a number of roles involving the treasury, commercial, explorationand tax areas of the business and also spent two years in Yemen setting up systems, controls andreporting procedures for a start-up venture. Steve then joined the small start-up onshore producerStar Energy as group financial controller and group finance manager where he was involved in aninitial public offering, various fund raises and acquisitions, a gas storage project and acquisition byPETRONAS. Subsequent to the break-up of the Star Energy Group in 2011, Steve remained withthe upstream business which was acquired by IGas Energy where he continued to be involved invarious refinancing projects, acquisitions and restructurings prior to joining RockRose. Mr Pawsonintends to retire as finance director in September 2019.

Strategic decisions

Process and responsibility

The Directors are responsible for carrying out the Company’s objectives, implementing itsbusiness strategy and conducting its overall supervision, acquisition, divestment and otherstrategic decisions will all be considered and determined by the Board in conjunction with theCompany’s external advisers. The Executive Team are charged with day-to-day responsibility forthe implementation of the Company’s acquisition strategy.

The Board will provide leadership within a framework of prudent and effective controls. The Boardwill establish the corporate governance values of the Company and will have overall responsibility

Annex I, 14.1

Annex III, 1.1

101


for setting the Company’s strategic aims, defining the business plan and strategy and managingthe financial and operational resources of the Company.

Unless required by law or other regulatory process, no Shareholder approval will be sought by theCompany in relation to the making of any further acquisition(s).

Frequency of meetings

The Board will schedule quarterly meetings and will hold additional meetings as and whenrequired. The expectation is that this will not result in more than four meetings of the Board eachyear.

Corporate governance

The Company will observe the requirements of the UK Corporate Governance Code (so far as itis practicable) given the composition of the Board. The Board have resolved not to comply with theprovisions relating to the division of responsibilities between the chairman and chief executive andexecutive compensation.

• The Company will hold Board meetings periodically as issues arise which require theattention of the Board. The Board will be responsible for the management of the business ofthe Company, setting the strategic direction of the Company, establishing the policies of theCompany and appraising the making of all material investments. It will be the Board’sresponsibility to oversee the financial position of the Company and monitor the business andaffairs of the Company on behalf of the Shareholders, to whom the Directors areaccountable. The primary duty of the Board will be to act in the best interests of theCompany at all times. The Board will also address issues relating to internal control and theCompany’s approach to risk management.

• The Company also has a remuneration committee (the “Remuneration Committee”), anaudit committee (the “Audit Committee”), a risk and disclosure committee (the “Risk and

Disclosure Committee”), a nomination committee (the “Nomination Committee”) and ahealth, safety, security and environmental committee (the “Health, Safety, Security and

Environmental Committee”), with formally delegated duties and responsibilities.

• The Remuneration Committee comprises only non-executive Directors, being John Morrowas chairman and Richard Benmore, and will meet normally not less than twice each year.The Remuneration Committee will be responsible for the review of and makingrecommendations to the Board on the scale and structure of remuneration for Directors andSenior Managers, including any bonus arrangements or the award of share options with dueregard to the interests of the Shareholders and other stakeholders.

• The Audit Committee comprises only non-executive Directors, being Richard Benmore aschairman and John Morrow, and will meet normally not less than twice each year. The AuditCommittee will be responsible for making recommendations to the Board on theappointment of auditors and the audit fee and for ensuring that the financial performance ofthe Company is properly monitored and reported. In addition, the Audit Committee willreceive and review reports from management and the auditors relating to the interim report,the annual report and accounts and the internal control systems of the Company.

• The Risk and Disclosure Committee will operate as part of the Audit Committee and willreview the operational risks that face the business and monitor and report upon theCompany’s obligations under the Disclosure Guidance and Transparency Rules regardingcontinuous disclosure.

• The Nomination Committee, which will comprise Andrew Austin as chairman and RichardBenmore and will meet as required during the year. The Nomination Committee is

Annex I, 16.3,

16.4

102


responsible for reviewing succession plans for the Directors, including the ExecutiveChairman and other senior executives.

• The Health, Safety, Security and Environmental Committee is chaired by John Morrow andits other members are Andrew Austin and Richard Benmore. The Health, Safety, Securityand Environmental Committee meets as required during the year and is responsible forensuring that employees are provided with a safe and secure place to work, ensuring thatthe Group is complying with the latest statutory requirements, ensuring that operators arecomplying with latest health, safety and environmental directives and ensuring that theCompany’s IT systems are secure and protected from cyber-attack. The operational head ofthe Health, Safety, Security and Environmental Committee reports directly to Andrew Austin.

• As at the date of this document, the Board has adopted the policies and procedures tocomply with applicable market abuse legislation, including a share dealing code (“Share

Dealing Code”) on the dealing in securities of the Company by Directors, Senior Managersand employees. The Board will be responsible for taking all proper and reasonable steps toensure compliance with the Share Dealing Code by the Directors, Senior Managers andemployees of the Company.

103


PART IX

UNAUDITED PRO FORMA FINANCIAL INFORMATION

FOR THE ENLARGED GROUP

Section A: Unaudited pro forma financial information

The unaudited consolidated pro forma statement of net assets and income statement of theEnlarged Group set out below in this section of this Part IX – Unaudited Pro Forma Financial

Information for the Enlarged Group of this document have been prepared in a manner consistentwith the accounting policies adopted by the Company in preparing the Group’s auditedconsolidated financial statements for the period ended 31 December 2018 on the basis set out inthe notes to the Pro Forma Financial Information and in accordance with Annex II to theProspectus Directive Regulation. The adjustments in the unaudited pro forma financial informationare expected to have a continuing impact on the Enlarged Group, unless stated otherwise.

The unaudited pro forma statement of net assets has been prepared based on the net assets ofthe Group as at 31 December 2018, which includes the consolidated financial position of Dyas,and has been prepared to illustrate the impact of the Marathon Acquisition, which completed on1 July 2019 on the net assets of the Group as if it had been completed on 31 December 2018.

The unaudited pro forma income statement has been prepared based on the consolidated incomestatement of the Group for the year ended 31 December 2018, which includes the post-acquisitionresults (from 1 October 2018 to 31 December 2018) of Dyas. The unaudited pro forma incomestatement has been prepared to illustrate the impact of the Dyas Acquisition and MarathonAcquisition, which completed on the 1 October 2018 and 1 July 2019 respectively, on theconsolidated income statement of the Group as if they had been completed on 1 January 2018.

The unaudited pro forma financial information has been prepared on the basis that the MarathonAcquisition will be accounted for under the acquisition method pursuant to IFRS 3 “BusinessCombinations”. Under the acquisition method, assets and liabilities are recorded at their fair valueson the date of purchase and any excess of the fair value of the total purchase price over the fairvalues of the tangible and intangible assets acquired and liabilities assumed is recorded asgoodwill. As of the date of this document, the valuation studies necessary to finalise the fair valuesof the purchase price, the assets acquired and the liabilities assumed have not been finalised.

Accordingly, the unaudited pro forma statement of net assets and income statement do not reflectany fair value adjustments to the acquired assets and liabilities of MOUK and MOWOS. A finaldetermination of these fair values will reflect, inter alia, consideration of the final purchase price,as well as the final valuation based on the actual net tangible and intangible assets, if any, thatexist as of the closing of the Marathon Acquisition. Any adjustments will change the allocation ofthe purchase price, which will affect the fair value assigned to the assets and liabilities and couldresult in a material change to the figures shown in the unaudited pro forma statement of net assetsand the unaudited pro forma income statement.

The unaudited pro forma financial information has been prepared for illustrative purposes only and,by its nature, addresses a hypothetical situation and, therefore, does not represent the Group’s orthe Enlarged Group’s actual financial position or results.

The unaudited pro forma financial information does not constitute financial statements within themeaning of Section 434 of the Companies Act. Shareholders should read the whole of thisdocument and not rely solely on the summarised financial information in this Part IX – Unaudited

Pro Forma Financial Information for the Enlarged Group of this document. PricewaterhouseCoopers LLP’s report on the unaudited pro forma financial information is set out in Section B ofthis Part IX – Unaudited Pro Forma Financial Information for the Enlarged Group of this document.

The unaudited pro forma financial information does not purport to represent what the Group’sfinancial position and results of operations actually would have been if the Dyas Acquisition and

Annex II, 7

Annex II, 1

104


the Marathon Acquisition had been completed on the dates indicated nor does it purport torepresent the results of operations for any future period or the financial condition at any future date.

1. Unaudited pro forma statement of net assets

Adjustments–––––––––––––––––––––––––––––––––––

Group at MOUK at MOWOS at Enlarged

31 December 31 December 31 December Acquisition Group at

2018 2018 2018 adjustments 31 December

(note 1) (note 2) (note 2) (note 3) 2018

US$m* US$m* US$m* US$m* US$m*

ASSETS

Non-current assets

Intangible assets 33 – – 20 53Property, plant andequipment 359 70 46 1 476Investment property – 1 – – 1Pension asset – 83 – – 83Deferred tax asset – 369 100 – 469 –––––––– –––––––– –––––––– –––––––– –––––––– 392 523 146 21 1,082 –––––––– –––––––– –––––––– –––––––– ––––––––Current assets

Inventory 5 11 – – 16Trade and otherreceivables 28 43 – – 71Tax receivable – – –Loan to groupundertaking – 163 157 (320) –Cash and cashequivalents 68 30 2 169 269Restricted cash 53 – – 50 103 –––––––– –––––––– –––––––– –––––––– –––––––– 154 247 159 (101) 459 –––––––– –––––––– –––––––– –––––––– ––––––––TOTAL ASSETS 546 770 305 (80) 1,541 –––––––– –––––––– –––––––– –––––––– ––––––––LIABILITIES

Current liabilities

Trade and otherpayables (57) (37) (10) – (104)Tax payable (23) – (17) – (40)Provisions for liabilitiesand other charges (5) (45) – – (50) –––––––– –––––––– –––––––– –––––––– –––––––– (85) (82) (27) – (194) –––––––– –––––––– –––––––– –––––––– ––––––––Non-current liabilities

Trade and otherpayables – (5) – – (5)Provisions for liabilitiesand other charges (365) (578) (250) – (1,193)Deferred tax liability (23) (39) (19) – (81) –––––––– –––––––– –––––––– –––––––– –––––––– (388) (622) (269) – (1,279) –––––––– –––––––– –––––––– –––––––– ––––––––TOTAL LIABILITIES (473) (704) (296) – (1,473) –––––––– –––––––– –––––––– –––––––– ––––––––NET ASSETS/

(LIABILITIES) 73 66 9 (80) 68 –––––––– –––––––– –––––––– –––––––– ––––––––*Rounded to nearest US$m

Annex II, 2, 3, 4,

5, 6

105


Notes:

1. The Group financial information as at 31 December 2018, which includes the consolidated financial position of Dyas,

has been extracted from the Group’s consolidated audited financial statements as at the 31 December 2018.

2. The MOUK and MOWOS financial information as at 31 December 2018 has been extracted from the Historic

Financial Information for MOUK and MOWOS as at 31 December 2018 as included in Part XII – Historical Financial

Information on MOUK and Part XIII – Historical Financial Information on MOWOS, respectively, of this document.

3. Adjustments attributable to the transaction

3(a): The unaudited pro forma statement of net assets has been prepared on the basis that the Marathon Acquisition

will be treated as an acquisition of a business in accordance with IFRS 3 “Business Combinations”. The pro forma

statement of net assets does not reflect the fair value adjustments to the acquired assets and liabilities of MOUK and

MOWOS, as the fair value measurement of these items are still being finalised. For the purposes of the pro forma

statement of net assets, the excess purchase consideration over the carrying amount of the net assets acquired, after

impairment reversals, has been attributed to intangible assets (goodwill).

US$m*

Consideration 96

Less carrying value of net assets/(liabilities) acquired:

– MOUK (66)

– MOWOS (9)

Impairment reversal MOUK 1––––––––

Goodwill 20

––––––––* Rounded to nearest US$m

3(b): Repayment of US$320m funds owed by a Marathon group company to MOUK and MOWOS, which were repaid

prior to completion of the Marathon Acquisition in accordance with the terms of the Marathon Acquisition Agreements.

3(c): Total increase in cash of US$169m arises due to a number of adjustments attributable to the Marathon

Acquisition, which consisted of the:

• receipt of US$320m funds previously held as a receivable from a Marathon group company as described in

note 3(b);

• net payment of cash consideration of US$96m for the Marathon Acquisition;

• payment of US$50m into trust in relation to a letter of credit to be provided in relation to the Defined Benefit

Scheme which is classified and shown separately as ‘restricted cash’ in the financial statements; and

• transaction costs arising from the Marathon Acquisition of US$5m.

106


2. Unaudited pro forma income statement

Adjustments (notes 8 to 9)––––––––––––––––––––––––––––––––––––––––––––––––

Dyas B.V.

Group year 9 months MOUK MOWOS Enlarged

ending ending year ending year ending Group year

31 December 30 September 31 December 31 December Acquisition ending

2018 2018 2018 2018 adjustments 31 December

US$m* US$m* US$m* US$m* US$m* 2018

(note 4) (note 5) (note 6) (note 6) (note 7) US$m*

Revenue 153 78 196 176 – 603Other Income – – – – – –Cost of sales (105) (42) (85) (101) – (333) –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Gross profit 48 36 111 75 – 270 –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Change in estimateof decommissioningprovisions 14 – 126 – – 140Foreign exchange ondecommissioningprovision – – – – – –Administrative costs (12) (2) (13) (3) (5) (35)Loss on derivatives (6) – – – – (6)Gain on acquisition – – – – – –Impairment ofgoodwill (19) – – – – (19) –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Operating profit/

(loss) 25 34 224 72 (5) 350 –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Finance income – 16 4 – 20Finance cost (15) (3) (8) (2) – (28)Foreign exchangegain/(loss) (2) – – – – (2)Profit/(loss) before

income tax 8 31 232 74 (5) 340 –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Taxation 31 (12) (99) (30) – (110) –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Profit/(loss) for the

year 39 19 133 44 (5) 230 –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––Adjusted EBITDA 77 49 103 93 (5) 317 –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––

* Rounded to nearest US$m

Notes:

4. The Group financial information for the year ended 31 December 2018, which includes the post-acquisition results

(from 1 October 2018 to 31 December 2018) of the Dyas Group, has been extracted or derived (for the purposes of

calculating the Adjusted EBITDA), from the Group’s consolidated audited financial statements for the year ended 31

December 2018.

5. The pre-acquisition Dyas financial information for the nine months ended 30 September 2018 has been extracted

from underlying books and records of Dyas which are the financial records that support the full year financial

statements of Dyas for the year ended 31 December 2018.

6. The MOUK and MOWOS financial information for the year ended 31 December 2018 has been extracted from the

MOUK and MOWOS Historic Financial Information for the year ended 31 December 2018 as included in Part XII –

Historical Financial Information on MOUK and Part XIII – Historical Financial Information on MOWOS, respectively,

of this document.

7. For the purposes of the unaudited pro forma income statement, transaction costs of US$5m incurred by the Company

in respect of the Marathon Acquisition have been reflected as an expense. These costs are not expected to be

incurred on an ongoing basis in the Enlarged Group.

In relation to finance income, there is a net nil adjustment as a result of:

a) the elimination of the interest income recognized by MOUK/MOWOS of US$20m which arose on the $320m

receivables from a Marathon group company, as set out in note 3(b); and

b) the inclusion of estimated interest income on the net cash funds received as a result of the Marathon Acquisition

of £169m as set out in note 3).

107


8. No additional depreciation and amortisation charge has been applied to reflect the impact of any fair value

adjustments that might arise under IFRS 3 “Business Combinations” in relation to intangible assets and property,

plant and equipment, for the Marathon Acquisition, as it is considered impractical to do so given the fair value

adjustments are still being calculated.

9. No adjustment has been made to reflect the financial results or the net assets of RockRose, Dyas, MOUK or MOWOS

since 31 December 2018.

108


Section B: Accountant’s report on the Unaudited Pro Forma Financial Information for the

Enlarged Group

The DirectorsRockRose Energy plcc/o Cooley Services LimitedDashwood69 Old Broad StreetLondon EC2M 1QS

19 July 2019

Dear Sirs

RockRose Energy plc (the “Company”)

We report on the unaudited pro forma financial information (the “Pro Forma Financial

Information”) set out in Section A of Part IX of the Company’s prospectus dated 19 July 2019 (the“Prospectus”) which has been prepared on the basis described in the notes to the Pro Forma

Financial Information, for illustrative purposes only, to provide information about how theacquisitions of the entire issued share capital of Marathon Oil U.K. LLC, including its subsidiaries,and the entire issued share capital of Marathon Oil West of Shetlands Limited might have affectedthe financial information presented on the basis of the accounting policies adopted by theCompany in preparing the financial statements for the year ended 31 December 2018. This reportis required by item 20.2 of Annex I to the PD Regulation and is given for the purpose of complyingwith that PD Regulation and for no other purpose.

Responsibilities

It is the responsibility of the directors of the Company to prepare the Pro Forma FinancialInformation in accordance with item 20.2 of Annex I to the PD Regulation.

It is our responsibility to form an opinion, as required by item 20.2 of Annex I to the PD Regulationas to the proper compilation of the Pro Forma Financial Information and to report our opinion toyou. In providing this opinion we are not updating or refreshing any reports or opinions previouslymade by us on any financial information used in the compilation of the Pro Forma FinancialInformation, nor do we accept responsibility for such reports or opinions beyond that owed to thoseto whom those reports or opinions were addressed by us at the dates of their issue.

Save for any responsibility which we may have to those persons to whom this report is expresslyaddressed and for any responsibility arising under item 5.5.3R(2)(f) of the Prospectus Rules to anyperson as and to the extent there provided, to the fullest extent permitted by law we do not assumeany responsibility and will not accept any liability to any other person for any loss suffered by anysuch other person as a result of, arising out of, or in connection with this report or our statement,required by and given solely for the purposes of complying with item 23.1 of Annex I to the PDRegulation, consenting to its inclusion in the Prospectus.

Annex I, 20.2,

20.4.3

Annex III, 10.2

Annex II, 1

109


PricewaterhouseCoopers LLP is a limited liability partnership registered in England with registered number OC303525. The registered office of PricewaterhouseCoopers LLP is 1 Embankment Place, London WC2N 6RH. PricewaterhouseCoopers LLP is authorised and regulated by the Financial Conduct Authority for designated investment business.

PricewaterhouseCoopers LLP, 1 Embankment Place, London, WC2N 6RHT: +44 (0) 2075 835 000, F: +44 (0) 2072 124 652, www.pwc.co.uk

Basis of opinion

We conducted our work in accordance with the Standards for Investment Reporting issued by theAuditing Practices Board in the United Kingdom. The work that we performed for the purpose ofmaking this report, which involved no independent examination of any of the underlying financialinformation, consisted primarily of comparing the unadjusted financial information with the sourcedocuments, considering the evidence supporting the adjustments and discussing the Pro Forma

Financial Information with the directors of the Company.

We planned and performed our work so as to obtain the information and explanations weconsidered necessary in order to provide us with reasonable assurance that the Pro Forma

Financial Information has been properly compiled on the basis stated and that such basis isconsistent with the accounting policies of the Company.

Opinion

In our opinion:

(a) the Pro Forma Financial Information has been properly compiled on the basis stated; and

(b) such basis is consistent with the accounting policies of the Company.

Declaration

For the purposes of Prospectus Rule 5.5.3 R(2)(f), we are responsible for this report as part of theProspectus and we declare that we have taken all reasonable care to ensure that the informationcontained in this report is, to the best of our knowledge, in accordance with the facts and containsno omission likely to affect its import. This declaration is included in the Prospectus in compliancewith item 1.2 of Annex I to the PD Regulation.

Yours faithfully

PricewaterhouseCoopers LLP

Chartered Accountants

110


PART X

SELECTED FINANCIAL INFORMATION ON THE

ENLARGED GROUP

The selected financial information set out below has been extracted without material

adjustment from the audited historical financial information of the Company for the

financial years ended 31 December 2018 and 31 December 2017, and the 18 month period

ended 31 December 2016, which are incorporated by reference in Part XXII – Documents

incorporated by reference of this document.

Selected Financial Information of the Group:




2018 2017** 2016*

US$000 US$000 US$000

Revenue 153,072 7,436 –Cost of sales (105,356) (7,604) –Gross profit/(loss) 47,716 (168) –Change in estimate of decommissioning provisions 14,302 – –Foreign exchange movements on decommissioningprovision – (223) –Administrative Costs (12,649) (5,617) (1,900)Loss on derivatives (6,399) – –Gain on acquisition – 87,825 –Impairment of goodwill (18,660) (7,974) – –––––––– –––––––– ––––––––Operating profit/(loss) 24,310 73,843 (1,900)Finance income 51 9 6Finance costs (14,996) (915) –Foreign exchange (loss)/gain (1,987) 1,137 – –––––––– –––––––– ––––––––Profit/(loss) before income tax 7,378 74,074 (1,894)Income tax credit 31,481 – – –––––––– –––––––– ––––––––Profit/(loss) for the year attributable to shareholders 38,859 74,074 (1,894)Comprehensive income to be reclassified to profit or

loss in subsequent years when specific conditions

are met:

Foreign currency translation loss – 140 (653) –––––––– –––––––– ––––––––Total comprehensive income for the year 38,859 74,214 (2,547) –––––––– –––––––– ––––––––Unadjusted basic earnings/(loss) per share (cents) 261 651 (34) –––––––– –––––––– ––––––––Unadjusted diluted earnings/(loss) per share (cents) 242 580 (34) –––––––– –––––––– ––––––––

* All balances for the 18 month period ended 31 December 2016 presented throughout these financial statements have

been restated in US$ following the change to the Group’s presentational currency in 2017.

** The income statement for the year ended 31 December 2017 has been presented in a format consistent with that

adopted in the year ended 31 December 2018 annual report and accounts and therefore some sub-totals are different

from those presented in the annual report and accounts for the year ended 31 December 2017. However, no financial

information has been restated.

Annex I,

3.1, 20.1,

20.4.3

111



As at As at As at


2018 2017 2016*

US$000 US$000 US$000

AssetsIntangible assets 32,287 1,723 –Property, plant and equipment 359,293 180,325 –Deferred tax – 36,472 – –––––––– –––––––– ––––––––Total non-current assets 391,580 218,520 – –––––––– –––––––– ––––––––Inventory 5,090 6,005 –Trade and other receivables 28,147 14,997 313Cash and cash equivalents 67,944 64,955 2,938Restricted cash 53,347 55,336 – –––––––– –––––––– ––––––––Total current assets 154,528 141,293 3,251 –––––––– –––––––– ––––––––Total assets 546,108 359,813 3,251 –––––––– –––––––– ––––––––EquityShare capital 3,549 4,269 2,890Share premium 129 9,902 3,222Other reserves 11,772 (75) (558)Retained earnings/(Accumulated losses) 58,007 71,228 (2,846) –––––––– –––––––– ––––––––Total equity 73,457 85,324 2,708 –––––––– –––––––– ––––––––LiabilitiesProvisions for liabilities and other charges 364,717 247,048 –Deferred tax liability 22,788 – – –––––––– –––––––– ––––––––Total non-current liabilities 387,505 247,048 – –––––––– –––––––– ––––––––Trade and other payables 57,015 21,882 543Tax payable 23,012 – –Provisions for liabilities and other charges 5,119 5,559 – –––––––– –––––––– ––––––––Total current liabilities 85,146 27,441 543 –––––––– –––––––– ––––––––Total liabilities 472,651 274,489 543 –––––––– –––––––– ––––––––Total equity and liabilities 546,108 359,813 3,251 –––––––– –––––––– ––––––––



112





2018 2017 2016*

US$000 US$000 US$000


Profit/(loss) before income tax 7,378 74,074 (1,894)Non-cash adjustment to reconcile (loss)/profit beforetax to net cash flows:Foreign exchange loss/(gains) on operating activities 1,987 (1,136) –Finance income (51) (9) (5)Finance costs 14,996 915** –Share based payments 291 242 95Impairment of goodwill 18,660 7,974 –Gain on acquisitions – (87,825) –Depreciation and amortisation 34,222 1,669 –Change in estimate of decommissioning provision (14,302) – –Foreign exchange movement on decommissioningprovision – 223 –Increase in provisions – 749 – –––––––– –––––––– ––––––––Operating cash flows before movements in workingcapital 63,181 (3,124) (1,804)Decrease in inventory 915 895 –(Increase)/decrease in trade and other receivables (13,149) 28,381 (301)Decrease/(increase) in restricted cash 1,988 (55,336) –Increase in trade and other payables 35,048 1,710 543Income tax paid (4,534) – – –––––––– –––––––– ––––––––Net cash generated from/(used in) operating activities 83,449 (27,474) (1,562) –––––––– –––––––– ––––––––Cash flows from investing activities

Acquisition of subsidiaries net of cash acquired (11,773) 82,311 –Utilisation of decommissioning liabilities (2,402) – –Additions of intangible assets (215) – –Additions of property, plant and equipment (10,414) (895) – –––––––– –––––––– ––––––––Net cash (used in)/generated from investing activities (24,804) 81,416 – –––––––– –––––––– ––––––––Cash flows from financing activities

Finance income 51 9 5Finance costs (3,711) – –Share issue costs – (2,183) (1,114)Shareholders distribution (30,360) – –Share buy-back (22,041) – –Proceeds from share issue 169 10,343 6,108 –––––––– –––––––– ––––––––Net cash (used in)/generated from financing activities (55,892) 8,169 4,999 –––––––– –––––––– ––––––––Net increase in cash and cash equivalent 2,753 62,111 3,437Cash and cash equivalents at 1 January 64,955 2,938 –Effect of foreign exchange 236 (94) (499) –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 67,944 64,955 2,938 –––––––– –––––––– ––––––––



** Finance costs for the year ended 31 December 2017 has been presented on the same basis as adopted in the year

ended 31 December 2018 annual report by combining unwind of discount on decommissioning provision and finance

expense.

113


• During the period covered by the audited historical financial information set out above, thesignificant changes to the Company’s financial conditions were:

• the receipt of net proceeds from the issue of Ordinary Shares in conjunction with the InitialAdmission;

• the receipt of net proceeds from the issue of Ordinary Shares in conjunction with thesubscription by Arunvill for 2,666,666 Ordinary Shares and the subscription by certain of theDirectors, certain of their spouses and certain third parties for 967,074 Ordinary Shares, andplacing of 1,699,594 Ordinary Shares, which completed on 6 July 2017;

• the completion of the Acquisitions;

• the completion of the Share Buy-back; and

• the completion of the Shareholder Distribution.

Since 31 December 2018 (being the end of the last financial period of the Company for whichfinancial information has been published), the significant change to the Company’s financialcondition and operating results was the completion of the Marathon Acquisition on 1 July 2019.

114


Selected Financial Information of MOUK

The selected financial information set out below has been extracted without material adjustmentfrom the audited historical financial information of MOUK for the financial years ended31 December 2018 and 31 December 2017, and the unaudited historical financial information forthe financial year ended 31 December 2016.




2018 2017 2016


US$000 US$000 US$000

Revenue 196,424 209,693 157,851Cost of sales (84,656) (180,312) (197,904) –––––––– –––––––– ––––––––Gross profit/(loss) 111,768 29,381 (40,053)Other operating income 125,550 423 281Administrative costs (13,345) (6,546) 350 –––––––– –––––––– ––––––––Operating profit/(loss) 223,973 23,258 (39,422)Finance income 16,399 11,775 11,011Finance costs (7,546) (7,773) (8,107) –––––––– –––––––– ––––––––Profit/(loss) before income tax 232,826 27,260 (36,518)Income tax (charge)/credit (98,929) 23,969 21,299 –––––––– –––––––– ––––––––Profit/(loss) for the year 133,897 51,229 (15,219) –––––––– –––––––– ––––––––Adjusted EBITDA 102,594 89,485 66,912 –––––––– –––––––– ––––––––Comprehensive income to be reclassified

to profit or loss in subsequent years when specific

conditions are met:

Foreign currency translation (loss)/gain (7,832) 7,915 (11,313)Comprehensive income that will not be reclassified to

profit or loss in subsequent years when specific

conditions are met:

Deferred tax relating to defined benefit pensionscheme (5) (6,395) 5,459Actuarial gains on defined benefit pension scheme 11 37,623 (32,109) –––––––– –––––––– ––––––––Other comprehensive income/(expense) for the year 6 31,228 (26,650) –––––––– –––––––– ––––––––Total comprehensive income/(expense) for the year 126,071 90,372 (53,182) –––––––– –––––––– ––––––––

115



As at As at As at


2018 2017 2016


US$000 US$000 US$000

AssetsProperty, plant and equipment 69,763 106,033 218,127Investment property 1,302 1,382 963Pension asset 82,512 70,993 12,307Deferred tax asset 368,642 471,525 332,079 –––––––– –––––––– ––––––––Total non-current assets 522,219 649,933 563,476 –––––––– –––––––– ––––––––Inventory 11,360 8,222 9,390Trade and other receivables 42,737 41,140 54,657Loans to the group undertakings 162,867 429,503 513,413Cash and cash equivalents 30,373 62,048 24,246 –––––––– –––––––– ––––––––Total current assets 247,337 540,913 601,706 –––––––– –––––––– ––––––––Total assets 769,556 1,190,846 1,165,182 –––––––– –––––––– ––––––––EquityCapital surplus 31,797 31,797 31,797Foreign currency translation reserve (11,230) (3,398) (11,313)Retained earnings 45,568 251,665 169,208 –––––––– –––––––– ––––––––Total equity 66,135 280,064 189,692 –––––––– –––––––– ––––––––LiabilitiesAccruals and deferred income 5,166 5,032 12,572Deferred tax liability 38,782 47,671 51,038Provisions for liabilities and other charges 577,718 777,845 849,221 –––––––– –––––––– ––––––––Total non-current liabilities 621,666 830,548 912,831 –––––––– –––––––– ––––––––Trade and other payables 36,574 42,324 28,096Tax payable – 2,315 2,335Provisions for liabilities and other charges 45,181 35,595 32,228 –––––––– –––––––– ––––––––Total current liabilities 81,755 80,234 62,659 –––––––– –––––––– ––––––––Total liabilities 703,421 910,782 975,490 –––––––– –––––––– ––––––––Total equity and liabilities 769,556 1,190,846 1,165,182 –––––––– –––––––– ––––––––

116





2018 2017 2016


US$000 US$000 US$000


Profit/(loss) for the year 133,897 51,229 (15,219)Non-cash adjustments to reconcile profit/(loss) forthe year to net cash flows:Foreign exchange (gain)/loss on operating activities (1,673) 1,931 (4,614)Revaluation of investment property – (212) –Finance costs (8,853) (4,002) (2,904)Share based payments (14,436) (16,796) (17,741)(Reversal of impairment)/impairment of property,plant and equipment (20) 1,418 –Tax on profit/(loss) on ordinary activities 98,929 (23,969) (21,299)Depreciation 4,171 66,650 105,125Profit on disposal of tangible assets – – (90)Change in estimate of decommissioning provision (124,674) – (14,770)Increase in provisions (24,848) (21,909) – –––––––– –––––––– ––––––––Operating cash flows before movements in workingcapital 62,493 54,340 28,488(Increase)/decrease in inventory (3,142) 1,169 5,514(Increase)/decrease in trade and other receivables (2,338) 65,773 (27,711)(Decrease)/increase in trade and other payables (5,569) 6,688 (16,492)Income tax paid (3,835) (124,501) (13,012) –––––––– –––––––– ––––––––Net cash generated from/(used in) operatingactivities 47,609 3,469 (23,213)Cash flows from investing activities

Loan repayment receipts 265,000 30,000 –Interest receivable and similar income 11,072 11,201 9,611(Additions)/disposals of property, plant andequipment (13,917) (5,642) 305 –––––––– –––––––– ––––––––Net cash generated from investing activities 262,155 35,559 9,916Cash flows from financing activities

Finance costs (2,559) (4,228) (3,841)Members distribution (340,000) – – –––––––– –––––––– ––––––––Net cash used in financing activities (342,559) (4,228) (3,841) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cashequivalents (32,795) 34,800 (17,138)Cash and cash equivalents at 1 January 62,048 24,246 44,757Effect of foreign exchange 1,120 3,002 (3,373) –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 30,373 62,048 24,246 –––––––– –––––––– ––––––––

For the years ended 31 December 2016, 31 December 2017 and 31 December 2018, certainsignificant changes to the financial condition and the operating results of MOUK occurred. Thesechanges are set out below:

• revenue increased by 32.84% from US$157,851,000 for the financial year ended31 December 2016 to US$209,693,000 for the financial year ended 31 December 2017 but

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decreased by 6.32% to US$196,424,000 for the financial year ended 31 December 2018.The decline was primarily due to the changes in production volumes and price;

• cost of sales decreased by 8.88% from US$197,904,000 for the financial year ended31 December 2016 to US$180,312,000 for the financial year ended 31 December 2017, andfurther decreased by 53% to US$84,656,000 for the financial year ended 31 December2018,due to the significant reduction in depreciation charges as the Brae assets movefurther towards ends of life, and one off increase in contractor costs in 2017 resulting fromgas bypass works and additional decommissioning spend in respect of Brae Bravo; and

• MOUK noted an operating loss of US$39,422,000 for the financial year ended 31 December2016. Operating profit increased to US$23,258,000 for the financial year ended31 December 2017, and substantially increased by 863% to US$223,973,000 for thefinancial year ended 31 December 2018. The 2018 financial year increase was primarilydriven by a reduction in the decommissioning provision (a consequence of changes in keyestimates) of US$125,550,000 (in excess of its net book value) within fixed assets,recognised in other income. The remainder of the increase is explained by the decrease incosts of sales, as mentioned above.

Since 31 December 2018 (being the end of the last financial period of MOUK for which financialinformation has been published), (i) MOHL entered into the MOUK Acquisition Agreement (asdefined below) and completed the Marathon Acquisition and (ii) MOUK’s wholly owned subsidiary,Marathon Oil Decommissioning Services LLC, transferred its trade and assets to MOUK.

MOUK was notified on 20 June 2019 by TAQA Bratani, a significant non-operator interest holderin those licences, following the approval of the proposals made by TAQA Bratani to other membersof the relevant operating committees on 5 June 2019, that it would be discharged as operator ofBlocks 16/7a, Licence no. P.108 (Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313(Block 16/3c) and TAQA Bratani appointed in its place. No reasons were given for the changes. Aprocess will follow involving OGA approval, which could result in MOUK losing operatorship ofthese licences in July 2020.

Save as set out above, there have been no significant changes in the financial condition andoperating results of MOUK during or after the period covered by the historical financial informationof MOUK set out in this document.

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Selected Financial Information of MOWOS:

The selected financial information set out below has been extracted without material adjustmentfrom the audited historical financial information of MOWOS for the financial years ended31 December 2018, 31 December 2017 and 31 December 2016.




2018 2017 2016


US$000 US$000 US$000

Revenue 176,023 93,981 126,035Cost of sales (100,740) (71,298) (85,947) –––––––– –––––––– ––––––––Gross profit 75,292 22,683 40,088Administrative costs (2,672) (3,198) (3,129) –––––––– –––––––– ––––––––Operating profit 72,620 19,485 36,959Finance income 4,274 2,040 799Finance costs (2,444) (1,438) (1,439) –––––––– –––––––– ––––––––Profit before income tax 74,450 20,087 36,319Income tax (charge)/credit (29,610) (8,402) (25,279) –––––––– –––––––– ––––––––Profit for the year attributable to members 44,840 11,685 11,040 –––––––– –––––––– ––––––––Adjusted EBITDA 92,976 39,669 70,617There were no other comprehensive income 2018,

2017 and 2016, respectively:

Total comprehensive income for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Unadjusted basic earnings per share (in cents) 179,360 47 44 –––––––– –––––––– ––––––––Unadjusted diluted earnings per share (in cents) 179,360 47 44 –––––––– –––––––– ––––––––

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As at As at As at


2018 2017 2016


US$000 US$000 US$000

AssetsProperty, plant and equipment 45,541 102,511 111,380Deferred tax asset 100,192 113,748 108,636 –––––––– –––––––– ––––––––Total non-current assets 145,733 216,259 220,016Inventory 56 458 4,051Trade and other receivables 35 13,951 9,063Loans to group undertakings 156,545 143,989 153,692Cash and cash equivalents 1,730 9,194 7,680 –––––––– –––––––– ––––––––Total current assets 158,366 167,592 174,486 –––––––– –––––––– ––––––––Total assets 304,099 383,851 394,502 –––––––– –––––––– ––––––––EquityShare capital 25 25,025 25,025Other reserves 109,591 84,591 84,591Accumulated losses (101,264) (61,104) (47,789) –––––––– –––––––– ––––––––Total equity 8,352 48,512 61,827 –––––––– –––––––– ––––––––LiabilitiesAccruals and deferred income – – –Deferred tax liability 18,515 40,329 43,385Provisions for liabilities and othercharges 250,481 284,313 271,590 –––––––– –––––––– ––––––––Total non-current liabilities 268,996 324,642 314,975 –––––––– –––––––– ––––––––Trade and other payables 10,007 10,056 10,642Tax payable 16,744 641 7,058 –––––––– –––––––– ––––––––Total current liabilities 26,751 10,697 17,700 –––––––– –––––––– ––––––––Total liabilities 295,747 335,339 332,675 –––––––– –––––––– ––––––––Total equity and liabilities 304,099 383,851 394,502 –––––––– –––––––– ––––––––

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2018 2017 2016


US$000 US$000 US$000


Profit before income tax 74,450 20,087 36,319Non-cash adjustments to reconcile profit before taxto net cash flows:Finance income (4,274) (2,040) (799)Finance costs 4 – 3Depreciation and amortisation 20,356 20,184 33,658Finance charge on decommissioning provisions 2,440 1,438 1,436 –––––––– –––––––– ––––––––Operating cash flows before movements in workingcapital 92,976 39,669 70,617Decrease in inventory 402 3,593 3,368Decrease/(increase) in trade and other receivables 13,916 (4,888) 16,020(Increase)/decrease in amounts owed by groupcompanies (12,623) 9,853 (55,748)Increase/(decrease) in trade and other payables 18 (736) (5,018)Income tax paid (21,765) (22,987) (23,310) –––––––– –––––––– ––––––––Net cash generated from/(used in) operating activities 72,924 24,504 5,929Cash flows from investing activities

Payments to acquire property, plant and equipment – (30) (1,430)Receipts from sales of property, plant and equipment 342 – –Finance income 4,274 2,040 799 –––––––– –––––––– ––––––––Net cash generated from/(used in) investing activities 4,616 2,010 (631)Cash flows from financing activities

Finance costs (4) – (3)Shareholder distribution (85,000) (25,000) – –––––––– –––––––– ––––––––Net cash used in financing activities (85,004) (25,000) (3) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cash equivalents (7,464) 1,514 5,295Cash and cash equivalents at 1 January 9,194 7,680 2,385 –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 1,730 9,194 7,680 –––––––– –––––––– ––––––––

For the years ended 31 December 2016, 31 December 2017 and 31 December 2018, certainsignificant changes to the financial condition and the operating results of MOWOS occurred. Thesechanges are set out below:

• revenue decreased by 25% from US$126,035,000 for the financial year ended 31 December2016 to US$93,981,000 for the financial year ended 31 December 2017 but increased by87% to US$176,032,000 for the financial year ended 31 December 2018. The increase wasprimarily due to the changes in production volumes and price;

• cost of sales decreased by 17% from US$85,947,000 for the financial year ended31 December 2016 to US$71,298,000 for the financial year ended 31 December 2017, andincreased by 41% to US$100,740,000 for the financial year ended 31 December 2018, inline with the fall in production during the same periods and a significant increase incontractor spend in 2018 driven in part from pump and compressor outages; and

• Operating profit decreased by 47% from US$36,959,000 for the financial year ended31 December 2016 to US$19,485,000 for the financial year ended 31 December 2017, and

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substantially increased by 272% to US$72,620,000 for the financial year ended31 December 2018.

Since 31 December 2018 (being the end of the last financial period of MOWOS for which financialinformation has been published), MIOH entered into the MOWOS Acquisition Agreement (asdefined below) and completed the Marathon Acquisition.

Save as set out above, there have been no significant changes in the financial condition andoperating results of MOWOS during or after the period covered by the historical financialinformation of MOWOS set out in this document.

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PART XI

HISTORICAL FINANCIAL INFORMATION OF THE COMPANY

The audited financial statements relating to the Company for the financial years ended31 December 2018, 31 December 2017 and the 18 month period ended 31 December 2016 areincorporated by reference into this document as described in Part XXII – Documents incorporated

by reference of this document.

Annex I, 20.1,

20.4.1, 20.5.1

Annex III, 10.2

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PART XII

HISTORICAL FINANCIAL INFORMATION ON MOUK

Section A: Accountant’s Report on the Historical Financial Information on MOUK

The DirectorsRockRose Energy plcc/o Cooley Services LimitedDashwood69 Old Broad StreetLondon EC2M 1QSUnited Kingdom

19 July 2019

Dear Sirs

Marathon Oil U.K. LLC and its subsidiaries (“MOUK”)

We report on the financial information on MOUK for the two years ended 31 December 2018 and31 December 2017 (the “MOUK HFI”). The MOUK HFI has been prepared for inclusion in theprospectus dated 19 July 2019 (the “Prospectus”) of RockRose Energy plc (the “Company”) onthe basis of the accounting policies set out in note 1 to the MOUK HFI. This report is required byitem 20.1 of Annex I to the PD Regulation and is given for the purpose of complying with that itemand for no other purpose.

We have not audited or reviewed the financial information for the year ended 31 December 2016which has been included for comparative purposes only, and accordingly do not express anopinion thereon.

Responsibilities

The Directors of the Company are responsible for preparing the MOUK HFI in accordance withInternational Financial Reporting Standards as adopted by the European Union.

It is our responsibility to form an opinion as to whether the MOUK HFI gives a true and fair view,for the purposes of the Prospectus and to report our opinion to you.

Save for any responsibility which we may have to those persons to whom this report is expresslyaddressed and for any responsibility arising under item 5.5.3R(2)(f) of the Prospectus Rules to anyperson as and to the extent there provided, to the fullest extent permitted by law we do not assumeany responsibility and will not accept any liability to any other person for any loss suffered by anysuch other person as a result of, arising out of, or in connection with this report or our statement,required by and given solely for the purposes of complying with item 23.1 of Annex I to the PDRegulation consenting to its inclusion in the Prospectus.

Annex I, 20.4.1

Annex I, 1.2

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Basis of opinion

We conducted our work in accordance with the Standards for Investment Reporting issued by theAuditing Practices Board in the United Kingdom. Our work included an assessment of evidencerelevant to the amounts and disclosures in the financial information. It also included anassessment of significant estimates and judgments made by those responsible for the preparationof the financial information and whether the accounting policies are appropriate to the MOUK’scircumstances, consistently applied and adequately disclosed.

We planned and performed our work so as to obtain all the information and explanations which weconsidered necessary in order to provide us with sufficient evidence to give reasonable assurancethat the financial information is free from material misstatement whether caused by fraud or otherirregularity or error.

Opinion

In our opinion, the MOUK HFI gives, for the purposes of the Prospectus, a true and fair view of thestate of affairs of MOUK as at 31 December 2018 and 31 December 2017 and of its profits, cashflows and changes in equity for the periods then ended in accordance with International FinancialReporting Standards as adopted by the European Union.

Declaration

For the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of theProspectus and declare that we have taken all reasonable care to ensure that the informationcontained in this report is, to the best of our knowledge, in accordance with the facts and containsno omission likely to affect its import. This declaration is included in the Prospectus in compliancewith item 1.2 of Annex I to the PD Regulation.

Yours faithfully



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Section B: Historical Financial Information on MOUK




2018 2017 2016


Note US$000 US$000 US$000

Revenue 4 196,424 209,693 157,851Cost of sales (84,656) (180,312) (197,904) –––––––– –––––––– ––––––––Gross profit/(loss) 111,768 29,381 (40,053)Other operating income 5 125,550 423 281Administrative costs (13,345) (6,546) 350 –––––––– –––––––– ––––––––Operating profit/(loss) 6 223,973 23,258 (39,422)Finance income 8 16,399 11,775 11,011Finance costs 9 (7,546) (7,773) (8,107) –––––––– –––––––– ––––––––Profit/(loss) before income tax 232,826 27,260 (36,518)Income tax (charge)/credit 10 (98,929) 23,969 21,299 –––––––– –––––––– ––––––––Profit/(loss) for the year 133,897 51,229 (15,219) –––––––– –––––––– ––––––––Adjusted EBITDA 25 102,594 89,485 66,912 –––––––– –––––––– ––––––––Comprehensive income to be reclassified

to profit or loss in subsequent years when

specific conditions are met:

Foreign currency translation (loss)/gain (7,832) 7,915 (11,313)

Comprehensive income that will not be

reclassified to profit or loss in subsequent

years when specific conditions are met:

Deferred tax relating to defined benefitpension scheme (5) (6,395) 5,459Actuarial gains/(losses) on defined benefitpension scheme 11 37,623 (32,109) –––––––– –––––––– ––––––––Other comprehensive income/(expense)for the year 6 31,228 (26,650) –––––––– –––––––– ––––––––Total comprehensive income/(expense)for the year 126,071 90,372 (53,182) –––––––– –––––––– ––––––––

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As at As at As at As at

31 December 31 December 31 December 1 January

2018 2017 2016 2016

Audited Audited Unaudited Unaudited

Note US$000 US$000 US$000 US$000

AssetsProperty, plant and equipment 11 69,763 106,033 218,127 378,131Investment property 12 1,302 1,382 963 1,004Pension asset 24 82,512 70,993 12,307 28,718Deferred tax asset 13 368,642 471,525 332,079 295,114 –––––––– –––––––– –––––––– ––––––––Total non-current assets 522,219 649,933 563,476 702,967Inventory 14 11,360 8,222 9,390 14,904Trade and other receivables 15 42,737 41,140 54,657 57,121Loans to group undertakings 15 162,867 429,503 513,413 478,165Cash and cash equivalents 16 30,373 62,048 24,246 44,757 –––––––– –––––––– –––––––– ––––––––Total current assets 247,337 540,913 601,706 594,947 –––––––– –––––––– –––––––– ––––––––Total assets 769,556 1,190,846 1,165,182 1,297,914 –––––––– –––––––– –––––––– ––––––––EquityCapital surplus 19 31,797 31,797 31,797 31,797Foreign currency translation reserve (11,230) (3,398) (11,313) –Retained earnings 45,568 251,665 169,208 211,077 –––––––– –––––––– –––––––– ––––––––Total equity 66,135 280,064 189,692 242,874 –––––––– –––––––– –––––––– ––––––––LiabilitiesAccruals and deferred income 5,166 5,032 12,572 –Deferred tax liability 13 38,782 47,671 51,038 45,634Provisions for liabilities andother charges 18 577,718 777,845 849,221 928,829 –––––––– –––––––– –––––––– ––––––––Total non-current liabilities 621,666 830,548 912,831 974.463 –––––––– –––––––– –––––––– ––––––––Trade and other payables 17 36,574 42,324 28,096 57,168Tax payable 17 – 2,315 2,335 6,240Provisions for liabilities andother charges 18 45,181 35,595 32,228 17,169 –––––––– –––––––– –––––––– ––––––––Total current liabilities 81,755 80,234 62,659 80,577 –––––––– –––––––– –––––––– ––––––––Total liabilities 703,421 910,782 975,490 1,055,040 –––––––– –––––––– –––––––– ––––––––Total equity and liabilities 769,556 1,190,846 1,165,182 1,297,914 –––––––– –––––––– –––––––– ––––––––

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Consolidated Statement of Changes in Equity

Foreign

currency

Capital translation Retained

surplus reserve earnings Total

US$000 US$000 US$000 US$000

Balance as at 31 December 2015 asoriginally presented (unaudited) 31,797 – 210,391 242,188IFRS transitional adjustments (note 2) – – 686 686 –––––––– –––––––– –––––––– ––––––––Balance as at 1 January 2016(unaudited) 31,797 – 211,077 242,874Loss for the year – – (15,219) (15,219)Other comprehensive expense – – (26,650) (26,650)Total currency translation loss – (11,313) – (11,313) –––––––– –––––––– –––––––– ––––––––Total comprehensive expense – (11,313) (41,869) (53,182) –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2016(unaudited) 31,797 (11,313) 169,208 189,692Profit for the year – – 51,229 51,229Other comprehensive income – – 31,228 31,228Foreign currency translation gain – 7,915 – 7,915 –––––––– –––––––– –––––––– ––––––––Total comprehensive income – 7,915 82,457 90,372 –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2017 31,797 (3,398) 251,665 280,064Profit for the year – – 133,897 133,897Other comprehensive expense – – 6 6 –––––––– –––––––– –––––––– ––––––––Foreign currency translation loss – (7,832) – (7,832) –––––––– –––––––– –––––––– ––––––––Total comprehensive income – (7,832) 133,903 126,071 –––––––– –––––––– –––––––– ––––––––Members distribution – – (340,000) (340,000) –––––––– –––––––– –––––––– ––––––––Total transactions with owners – – (340,000) (340,000) –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2018 31,797 (11,230) 45,568 66,135 –––––––– –––––––– –––––––– ––––––––

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2018 2017 2016


US$000 US$000 US$000


Profit/(loss) for the year 133,897 51,229 (15,219)Non-cash adjustments to reconcile profit/(loss)for the year to net cash flows:Foreign exchange (gain)/loss on operating activities (1,673) 1,931 (4,614)Revaluation of investment property – (212) –Finance costs (8,853) (4,002) (2,904)Share based payments (14,436) (16,796) (17,741)(Reversal of impairment)/impairment of property,plant and equipment (20) 1,418 –Tax on profit/(loss) on ordinary activities 98,929 (23,969) (21,299)Depreciation 4,171 66,650 105,125Profit on disposal of tangible assets – – (90)Change in estimate of decommissioning provision (124,674) – (14,770)Increase in provisions (24,848) (21,909) – –––––––– –––––––– ––––––––Operating cash flows before movements in workingcapital 62,493 54,340 28,488(Increase)/decrease in inventory (3,142) 1,169 5,514(Increase)/decrease in trade and other receivables (2,338) 65,773 (27,711)(Decrease)/increase in trade and other payables (5,569) 6,688 (16,492)Income tax paid (3,835) (124,501) (13,012) –––––––– –––––––– ––––––––Net cash generated from/(used in) operatingactivities 47,609 3,469 (23,213)Cash flows from investing activities

Loan repayment receipts 265,000 30,000 –Interest receivable and similar income 11,072 11,201 9,611(Additions)/disposals of property, plant andequipment (13,917) (5,642) 305 –––––––– –––––––– ––––––––Net cash generated from investing activities 262,155 35,559 9,916Cash flows from financing activities

Finance costs (2,559) (4,228) (3,841)Members distribution (340,000) – – –––––––– –––––––– ––––––––Net cash used in financing activities (342,559) (4,228) (3,841) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cashequivalents (32,795) 34,800 (17,138)Cash and cash equivalents at 1 January 62,048 24,246 44,757Effect of foreign exchange 1,120 3,002 (3,373) –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 30,373 62,048 24,246 –––––––– –––––––– ––––––––

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Notes

1. Principal accounting policies

General information

On 25 February 2019, RockRose entered into a sale and purchase agreement with Marathon OilHoldings UK Limited to acquire the entire membership in Marathon Oil U.K. LLC.

Marathon Oil U.K. LLC is a private limited liability company incorporated in Delaware, UnitedStates. The address of its registered office is Corporation Trust Center, 1209 Orange Street,Wilmington DE 19801, United States. The group and private limited liability company are domiciledin Aberdeen, Scotland.

MOUK’s principal activity is to explore for, develop, produce and market crude oil and natural gasin the United Kingdom, MOUK holds approximately 37% to 40% operated interests in fields in theGreater Brae Area (which are unitised fields).

Basis of preparation

The Historic Financial Information (referred to as the “HFI”) presented is a consolidation ofMarathon Oil U.K. LLC and its subsidiaries (for the purposes of these notes, together referred toas “MOUK”).

The principal activities of MOUK are as follows:

Ownership of capital

Name of Principal Country of Class or stock by MOUK

entity activity incorporation shares 2018 2017 2016

Marathon Oil U.K. LLC Operating US* Ordinary 100% 100% 100%Marathon OilDecommissioningServices LLC Decommissioning services US* Ordinary 100% 100% 100%Marathon Oil NorthSea (G.B.) Limited Exploration UK** Ordinary 100% 100% 100%Marathon Service (G.B.)Limited Management services UK** Ordinary 100% 100% 100%Marathon InternationalOil (G.B.) Limited Management services UK** Ordinary 100% 100% 100%

The registered offices of Marathon Oil U.K. LLC and its subsidiaries are as follows:

* Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801

** 91 Wimpole Street, London, England, W1G 0EF

The MOUK HFI, which has been prepared specifically for the purposes of this document, sets outthe balance sheet as at 31 December 2018, 31 December 2017 and 31 December 2016 and theresults of operations and cash flows for each of the three years then ended of MOUK and has beenprepared in accordance with the requirements of the Prospectus Directive regulations.

The MOUK HFI has been prepared in accordance with International Financial Reporting Standardsand the IFRS Interpretation Committee (IFRS IC) interpretations as adopted by the EuropeanUnion (“IFRS”). The principal accounting policies that have been applied to the MOUK HFI are setout below. These policies have been consistently applied to all years presented unless otherwisestated.

The MOUK HFI does not constitute statutory accounts and represents the first-time preparation offinancial information for MOUK under IFRS reporting standards.

MOUK has previously prepared and reported special purpose, non-statutory financial statements,in accordance with applicable standards in the United Kingdom (“Financial Reporting

Standard 102”). Consequently, the opening statement of financial position at the 1 January 2016has been included in the HFI together with IFRS 1 reconciliations between financial informationprepared under Financial Reporting Standard 102 and financial information prepared in

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accordance with IFRS, as required by IFRS 1 on transition to IFRS. The principle changes to thepresentation of the financial information as a result of adopting IFRS as at the 1 January 2016 aresent out in note 2 to this HFI. We have taken the exemption to reset the currency translationaccount to nil on transition.

The MOUK HFI has been prepared under the historical cost convention except for certain financialinstruments which are carried at fair value and is presented in US Dollars (“US$”), which is thecurrency of the primary economic environment in which MOUK operates, rounded to the nearestthousand.

Adoption of new standards and interpretations

New standards, amendments and interpretations

IFRS 1 “First-time adoption of IFRS”, requires that entities use the same accounting policiesthroughout their first IFRS financial statements and in their opening IFRS balance sheet, and thatthese accounting policies should be those complying with the accounting standards effective at theend of an entity’s first IFRS reporting period. As such the HFI has been prepared using the currentversion of IFRS throughout all the periods presented in the HFI.

New standards, amendments and interpretations not yet adopted

The following new and revised Standards and Interpretations have been published that are notmandatory for 31 December 2018 reporting periods and have not been early adopted by MOUK.

Standards Effective date Description

IFRS 16 1 January 2019 LeasesIFRIC Interpretation 23 1 January 2019 Uncertainty over Income Tax TreatmentsAmendments to IAS 28 1 January 2019 Long-term interest in Associates and Joint Ventures

Other than IFRS 16, there are no other standards that are not yet effective and that would beexpected to have a material impact on the entity in the current or future reporting periods. MOUK’sassessment of the impact of IFRS 16 is set out below:

Under the new standard all lease contracts, with limited exceptions, are recognised in financialstatements by way of right-of-use assets and corresponding lease liabilities. MOUK will apply themodified retrospective approach, which means that the cumulative effect of initially applying thestandard is recognised at the date of initial application. The right of use asset is measured at itscarrying amount as if IFRS 16 had always been applied from commencement of the lease.Compared with the existing accounting for operating leases, application of the standard will impacton the classification of expenditures with a portion of the lease costs presented as interest andconsequently the classification of operating lease cash flows from operating activities to financingactivities. It will also impact the timing of expenses recognised in the statement of income. Noimpact is expected in relation to lease contracts previously classified as finance leases. Theadoption of the new standard at January 1, 2019, is expected to have a negligible impact on theprofit/(loss) for future years; however, an increase of US$8.54 million to total assets andUS$8.73 million to total liabilities will occur following the recognition of right of use assets and leaseliabilities.

Basis of consolidation

Subsidiaries are all entities over which MOUK has control. MOUK controls an entity when MOUKis exposed to, or has rights to, variable returns from its involvement with the entity and has theability to affect those returns through its power over the entity. Subsidiaries are fully consolidatedfrom the date on which control is transferred to MOUK. They are deconsolidated from the date onwhich that control ceases.

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MOUK applies the acquisition method to account for business combinations. The considerationtransferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilitiesincurred to the former owners of the acquiree, and the equity interests issued by MOUK. Theconsideration transferred includes the fair value of any asset or liability resulting from a contingentconsideration arrangement. Identifiable assets acquired and liabilities and contingent liabilitiesassumed in a business combination are measured initially at their fair value at the acquisition date.MOUK recognises any non-controlling interest in the acquiree on an acquisition-by-acquisitionbasis, either at fair value or at the non-controlling interest’s proportionate share of the recognisedamounts of the acquiree’s identifiable net assets.

Acquisition related costs are expensed as incurred.

If the business combination is achieved in stages, the acquisition date carrying value of theacquirer’s previously held equity interest in the acquiree is remeasured to fair value at theacquisition date; any gains or losses arising from such remeasurement are recognised in profit orloss.

Any contingent consideration to be transferred by MOUK is recognised at fair value at theacquisition date. Subsequent changes to the fair value of the contingent consideration that isdeemed to be an asset or liability is recognised in accordance with IFRS 9, either in profit or lossor as a change to other comprehensive income.

Contingent consideration that is classified as equity is not remeasured, and its subsequentsettlement is accounted for within equity.

Inter-company transactions, balances and unrealised gains on transactions between MOUKcompanies are eliminated. Unrealised losses are also eliminated. Where necessary, amountsreported by subsidiaries have been adjusted to conform to MOUK’s accounting policies.

Segmental reporting

IFRS 8 requires operating segments to be identified on the basis of internal reports that areregularly reviewed by the chief operating decision maker, which in the case of MOUK is consideredto be the management of MOC Management, which is located in Houston, Texas. Managementconsider and review operating segments by reference to geographic location.

Revenue and other income

Sale of goods

Revenue from sales of oil, natural gas, and other products is recognised at the transaction pricewhich MOUK is entitled to, after deducting sales taxes, excise duties and similar levies. Forcontracts that contain separate performance obligations the transaction price is allocated to thoseseparate performance obligations by reference to their relative standalone selling prices.

Revenue is recognised when MOUK has transferred the significant control of ownership of theproducts to the customer which is when the title passes to the customer. For sales by IntegratedGas and Upstream operations, this generally occurs when the product is physically transferred intoa vessel, pipe or other delivery mechanism; and for sales of oil products, it is either at the point ofdelivery or the point of receipt, depending on contractual conditions.

Revenue resulting from hydrocarbon production from properties in which MOUK has an interestwith partners in joint arrangements is recognised on the basis of MOUK’s volumes lifted and sold.

Revenue excludes value added tax and represents the sales value of MOUK’s share of oil and gasproduction lifted during the year and includes tariff income.

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Sale of transportation and processing services

Transportation and processing services represent a separate performance obligation, and arerecognised separately from the sale of oil, natural gas, and other products, when the shipping andprocessing services have been provided. Shipment and processing revenues are recognised atthe contracted price as this reflects the stand-alone selling price.

Sale of services to other group companies

Revenue from the sale of services to other Marathon group companies is recognised as theservices are rendered. These are predominantly people costs which are recharged on a regularbasis driven by time booked to specific projects.

Financing income and costs

Financing costs comprise interest payable, finance charges on shares classified as liabilitiesand finance leases, unwinding of the discount on decommissioning provisions, and net foreignexchange losses that are recognised in the statement of comprehensive income (see foreigncurrency accounting policy). Financing income comprises interest receivable on funds invested,dividend income, and net foreign exchange gains.

Interest income and interest payable are recognised in profit or loss as they accrue, using theeffective interest method. Dividend income is recognised in the statement of comprehensiveincome on the date the entity’s right to receive payments is established.

Leases

Rentals under operating leases are charged to the statement of comprehensive income on astraight-line basis over the lease term.

Foreign currencies

Items included in the financial statements of each of MOUK’s entities are measured using thecurrency of the primary economic environment in which each entity operates (the “functional

currency”). Transactions in foreign currencies are translated to the entity’s functional currency atthe foreign exchange rates at the date of the transactions. Foreign exchange gains and lossesresulting from the settlement of monetary assets and liabilities denominated in foreign currenciesare recognised in the income statement. All UK entities in MOUK have a functional currency of USdollars apart from MSGB and Marathon International Oil G.B Limited which continue to have aGBP functional currency. The presentation currency for the financial statements is US dollars.

The results and financial position of all of MOUK entities (none of which has the currency of ahyper-inflationary economy) that have a functional currency different from the presentationcurrency are translated into the presentation currency as follows:

a) assets and liabilities for each balance sheet presented are translated at the closing rate atthe date of that balance sheet;

b) income and expenses for each income statement are translated at average exchange rates(unless this average is not a reasonable approximation of the cumulative effect of the ratesprevailing on the transaction dates, in which case income and expenses are translated at therate on the dates of each transaction); and

c) all resulting exchange differences are recognised in other comprehensive income.

Taxation

Tax on the profit/(loss) for the year comprises current and deferred tax. Tax is recognised in thestatement of comprehensive income except to the extent that it relates to items recognised directlyin equity, in which case it is recognised in equity.

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Current tax is the expected tax payable on the taxable income for the year, using tax rates enactedor substantively enacted at the statement of financial position date, and any adjustment to taxpayable in respect of previous years.

Deferred tax is provided on temporary differences between the carrying amounts of assets andliabilities for financial reporting purposes and the amounts used for taxation purposes. Thefollowing temporary differences are not provided for: the initial recognition of assets or liabilitiesthat affect neither accounting nor taxable profit other than in a business combination, anddifferences relating to investments in subsidiaries to the extent that they will probably not reversein the foreseeable future. The amount of deferred tax provided is based on the expected mannerof realisation or settlement of the carrying amount of assets and liabilities, using tax rates enactedor substantively enacted at the statement of financial position date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profitswill be available against which the temporary difference can be utilised.

Exploration, evaluation and producing assets

Pre-licence acquisition costs are recognised in the statement of comprehensive income whenincurred. Costs incurred after licences have been obtained, such as geological and geophysicalsurveys, drilling and commercial appraisal costs are capitalised as Exploration and Evaluation(“E&E”) assets as tangible or intangible depending on the nature of the asset. E&E assets withinintangible assets are not amortised.

MOUK applies the successful efforts method of accounting for exploration expenditure. E&Eassets shall no longer be classified as such when the technical feasibility and commercial viabilityof extracting oil and gas resources are demonstrable.

Once the technical feasibility and commercial viability has been demonstrated, then the carryingvalue of the E&E assets is reclassified as a Development and Production (“D&P”) asset andclassified as ‘oil and gas’ assets within Property, plant and equipment. The E&E assets shall beassessed annually for impairment using indicators in accordance with IFRS 6 ‘Exploration for andEvaluation of Mineral Resources’. If technically feasible or commercially viable reserves are notdiscovered, the impairment is recognised on E&E assets in the statement of comprehensive income.

The assets transferred to D&P assets are depreciated once the asset commences production.D&P assets are depreciated using the unit of production method based on the proved andprobable reserves of those fields. Changes in these estimates are dealt with prospectively.

General and administration costs are expensed as incurred.

Depletion and Amortisation on producing oil and gas assets

All expenditure carried within each Oil and Gas (“O&G”) asset is amortised from thecommencement of production on a unit of production basis, which is the ratio of oil and gasproduction in the year to the estimated quantities of commercial reserves at the end of the yearplus the production in the year, generally on a field-by-field basis. Costs used in the unit ofproduction calculation comprise the net book value of capitalised costs plus the estimated futurefield development costs, audited in the annual reserves report by ERC Equipoise.

Changes in the estimates of commercial reserves or future field development costs are dealt withprospectively.

Administrative assets

MOUK acquired various administrative assets including fixtures and fittings, computer equipmentand leasehold improvements. These assets are recorded in the statement of the financial positionat cost less accumulated depreciation. Depreciation is provided to write off the cost less theestimated residual value of the tangible fixed asset.

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Depreciation is provided at the following annual rates on a straight-line basis:

Fixtures and fittings 3 to 5 yearsComputer equipment 3 to 5 yearsLeasehold improvements Period of lease

Impairments of producing and development assets

The carrying amounts of MOUK’s assets are reviewed at each statement of financial position dateto determine whether there is any indication of impairment; an asset is considered to be impairedif objective evidence indicates that one or more events have had a negative effect on the estimatedfuture cash flows of that asset. If any such indication exists, the asset’s recoverable amount isestimated. An impairment loss is recognised whenever the carrying amounts of an asset or its cashgenerating unit exceed its recoverable amount. Impairment losses are recognised in the statementof comprehensive income. The recoverable amount of assets is determined by the higher of fairvalue less cost to dispose and value in use. Fair value less cost to dispose is determined as theamount of estimated risk adjusted and discounted future cash flows. For this purpose, assets aregrouped into Cash Generating Units (“CGUs”) based on separately identifiable and largelyindependent cash inflows. Estimates of future cash flows used in the evaluation of impairment ofassets are made using management forecasts including assumptions for commodity prices,market supply and demand, and in the case of oil and gas properties, expected productionvolumes. The latter takes into account assessments of field and reservoir performance andincludes expectations about proved and probable volumes, which are risk-weighted utilisinggeological, production, recovery and economic projections. Cash flow estimates are risk adjustedto reflect market conditions as appropriate and discounted at a rate that reflects a market returnand the risks of the cash generating units.

Investment property

Investment property is carried at fair value which is reviewed annually. Changes in fair value arerecognised in the statement of comprehensive income.

Crude oil under and over lift

Crude oil under/over lift is classified under debtors or creditors as appropriate and valued at theyear-end oil price. Liabilities arising from lifting more than MOUK’s share of the joint venture’spetroleum production (over lifting) are valued at the market price and booked under ‘Currentliabilities’. Under lifting is valued at the market price and booked under ‘Current assets’.

Inventory

Inventories are stated at the lower of cost and net realisable value. The net realisable value ofcrude oil is based on the estimated selling price in the ordinary course of business which is spotprice on the date of statement of financial position.

Restricted Stock Awards (“RSAs”)

Restricted stock award programme

Under this arrangement certain MOUK employees were awarded grants based on theirperformance within certain guidelines and for retention purposes. Each of these grants vest in one-third increments, contingent on the recipient’s continued employment. There are no performanceaccelerators for early vesting of these awards. Awards under the RSA are classified as an equityaward and recorded at the grant date fair value and the compensation expense is recognised overthe expected life of the award. A charge is recorded to the statement of comprehensive income asan employee benefit expense, within wages and salaries, for the fair value at grant date of theshare awards expected to vest, accrued over the vesting period. The corresponding credit is aMOC group recharge in respect of the share based payment expense.

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Cash and cash equivalents comprise cash in hand and bank balances. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash, which aresubject to an insignificant risk of changes in value and have a maturity of three months or less.

Share capital and capital surplus

MOUK is a limited liability company, and therefore does not issue share capital. MOUK’sownership is represented by a membership interest and is shown as capital surplus on the balancesheet.

Dividends

Dividends and other distributions to MOUK’s members are recognised as a liability in the financialstatements in the period in which the dividends and other distributions are approved by MOUK’smembers. These amounts are recognised in the Statement of changes in equity. Interim dividendsare recognised when paid. Dividend income is recognised when the right to receive payment isestablished.

Non-derivative financial instruments

Financial assets

Financial assets are classified at initial recognition and subsequently measured at amortised cost,fair value through other comprehensive income or fair value through profit or loss. Theclassification of financial assets is determined by the contractual cash flows and where applicablethe business model for managing the financial assets.

A financial asset is measured at amortised cost, if the objective of the business model is to holdthe financial asset in order to collect contractual cash flows and the contractual terms give rise tocash flows that are solely payments of principal and interest. It is initially recognised at fair valueplus or minus transaction costs that are directly attributable to the acquisition or issue of thefinancial asset. Subsequently the financial asset is measured using the effective interest methodless any impairment. Gains and losses are recognised in profit or loss when the asset isderecognised, modified or impaired.

All equity instruments and other debt instruments are recognised at fair value. For equityinstruments, on initial recognition, an irrevocable election (on an instrument-by-instrument basis)can be made to designate these as at fair value through other comprehensive income instead offair value through profit and loss.

The expected credit loss model is applied for recognition and measurement of impairments infinancial assets measured at amortised cost or at fair value through other comprehensive income.The expected credit loss model also is applied for financial guarantee contracts to which IFRS 9applies and are not accounted for at fair value through profit or loss. The loss allowance for thefinancial asset is measured at an amount equal to the 12-month expected credit losses. If the creditrisk on the financial asset has increased significantly since initial recognition, the loss allowancefor the financial asset is measured at an amount equal to the lifetime expected credit losses.Changes in loss allowances are recognised in profit and loss. For trade receivables, a simplifiedimpairment approach is applied recognising expected lifetime losses from initial recognition.

MOUK’s financial assets include cash and trade and other receivables.

Trade and other receivables

Trade and other receivables that are created by MOUK by way of providing goods directly to adebtor are carried at the original invoice amount. Trade and other receivables are recognisedinitially at fair value less any expected credit losses.

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MOUK has reviewed its trade receivables at the balance sheet date and considers that the creditrisk is not material as all amounts are due within 30 days.

Financial liabilities

Financial liabilities are measured at amortised cost. Debt and trade payables are recognisedinitially at fair value based on amounts exchanged, net of transaction costs, and subsequently atamortised cost. Interest expense on debt is accounted for using the effective interest method, andis recognised in income.

MOUK determines the classification of its financial liabilities at initial recognition.

MOUK’s financial liabilities include trade and other payables and loans and borrowings.

The subsequent measurement of financial liabilities depends on their classification. Tradepayables that are created by MOUK are carried at the original invoice amount.

Trade and other payables

Trade and other payables are recognised at fair value and subsequently measured at amortised cost.

Loans and borrowings

Loans and borrowings are recognised initially at fair value plus any directly attributable transactioncosts. Subsequent to initial recognition, these financial liabilities are measured at amortised costusing the effective interest rate method.

Provisions

Provisions are recognised when MOUK has present obligation (legal and constructive) as a resultof a past event, it is probable that MOUK will be required to settle that obligation and a reliableestimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settlethe present obligation at the statement of financial position date, taking into account the risks anduncertainties surrounding the obligation. Where a provision is measured using the cash flowsestimated to settle the present obligation, its carrying values amount is the present value of thosecash flows.

Specific provisions recognition policies are listed below:

Decommissioning and restoration provision

Provisions (referred to as “Asset Retirement Obligations” or “ARO”) are recognised for the futuredecommissioning and restoration of hydrocarbon production facilities and pipelines at the end oftheir economic lives. The estimated cost is recognised initially as part of Property, plant &equipment and depreciated over the life of the proved and probable reserves on a unit-of-production basis. Any changes in the estimates of costs to be incurred on proved and probablereserves or in the rate of production will therefore impact net income, over the remaining economiclife of the oil and gas assets.

Estimates of the amounts of provisions recognised are based on current legal and constructiverequirements, technology and price levels. Because actual outflows can differ from estimates dueto changes in laws, regulations, public expectations, technology, prices and conditions, and cantake place many years in the future, the carrying amounts of provisions are regularly reviewed andadjusted to take account of such changes.

All decommissioning and restoration provisions are denominated in GBP or EUR which arerevalued to USD based on the latest spot rates on an annual basis. Any resulting forex exchangemovements are recognised within the related property, plant and equipment decommissioningasset balance, unless the decommissioning assets have previously been impaired and forexexchange movements would therefore be recognised in the statement of comprehensive income.

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Significant accounting judgements and key sources of estimation uncertainty

In the application of MOUK’s accounting policies, the Directors are required to make judgements,estimates and assumptions about the carrying amounts of assets and liabilities that are not readilyapparent from other sources.

The estimates and associated assumptions are based on historical experience and other factorsthat are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an annual basis. Revisions toaccounting estimates are recognised in the year in which the estimate is revised. The following arethe critical judgements and estimates that the Directors have made in the process of applyingMOUK’s accounting policies and that have the most effect on the amounts recognised in the HFI.

Impairment of tangible assets

MOUK has significant investments in property, plant and equipment. Long-lived assets in use areassessed for impairment whenever changes in facts and circumstances indicate that the carryingvalue of the assets may not be recoverable. Changes in the circumstances or expectations offuture performance of an asset may not be recoverable. Changes in the circumstances orexpectations of future performance of an asset may be an indicator that the asset is impaired,requiring the asset to be written down to its recoverable amount. Evaluating whether an asset isimpaired requires a high degree of judgement and may to a large extent depend on often volatileeconomic factors such as future market prices, proved and probable volume of reserves, currencyexchange rates, future output, discount rates and political risk among others.

Provisions

MOUK has legal, regulatory and contractual obligations to remove and dismantle long-lived assetsand to restore land or seabed at the end of oil and gas production operations at the end of theireconomic life, with most of these activities expected to take place many years in the future.Estimates of retirement costs are developed based on numerous factors, such as the scope of thedismantlement, timing of settlement, interpretation of legal, regulatory and contractualrequirements, type of production and processing structures, depth of water, reservoircharacteristics, market demand for equipment and consultations with construction and engineeringprofessionals.

The decommissioning provisions as at 31 December 2018, 31 December 2017 and 31 December2016 respectively have been estimated using existing technology, at estimated current prices anddiscounted to the present values using real rates ranging from: 0.20% to 1.09%, 0.068% to 0.61%and 0% to 0.837% in 2018, 2017 and 2016 respectively over the expected life of expenditure byyear. These costs are being incurred at present and are expected to continue until 2034. It isreasonably possible on the basis of existing knowledge that outcomes within the next financial yearthat are different from the assumptions made could require a material adjustment to the carryingamount

Discount rates applied reflect the real risk free rate of appropriate United States Treasury bondsthat match the timing of the expected future cash flows for decommissioning.

Recoverability of deferred tax assets

Deferred tax assets are recognised to the extent that it is probable that they will be recoveredagainst the reversal of deferred tax liabilities or other future taxable profits. In the case of balancesrelated to decommissioning, the probability of recovery is assessed in light of the enacted losscarry-back rules and MOUK’s tax history. Deferred tax assets are reviewed at each reporting dateand are reduced to the extent that it is no longer probable that the related tax benefit will berealised.

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Presumption of going concern

The Directors have a reasonable expectation that MOUK has adequate resources to continue inoperational existence for the foreseeable future and, accordingly, have adopted the going concernbasis in preparing the HFI.

2. Adoption of IFRS and changes in accounting policies

MOUK has previously prepared and reported special purpose, non-statutory financial statements,in accordance with applicable standards in the United Kingdom (Financial ReportingStandard 102). Consequently, the opening statement of financial position at 1 January 2016 hasbeen included in the HFI together with IFRS 1 reconciliations between financial informationprepared under Financial Reporting Standard 102 and financial information prepared inaccordance with IFRS, as required by IFRS 1 on transition to IFRS.

Exemptions applied

IFRS 1 First-Time Adoption of International Financial Reporting Standards allows first-timeadopters certain exemptions from the retrospective application of certain IFRS.

Estimates

The estimates used as at 31 December 2016, 31 December 2017 and 31 December 2018 areconsistent with those made for the same dates in accordance with Financial ReportingStandard 102 (after adjustments to reflect any differences in accounting policies).

Change in accounting policies

In order to align with the policies of RockRose, MOUK has now calculated its crude oil under/overlift debtor or creditor at market price instead of at the lower of cost or net realisable value.

Management have reviewed the impact of this change in accounting policy and have made thefollowing adjustment to the HFI:



2018 2017 2016

US$000 US$000 US$000

Consolidated statement of comprehensive incomeDecrease/(increase) to cost of sales 7,575 (10,503) 578Decrease/(increase) to income tax charge (3,030) 4,201 (231) –––––––– –––––––– ––––––––Increase/(decrease) to total comprehensive incomefor the year 4,545 (6,302) 347 –––––––– –––––––– ––––––––Consolidated statement of financial position(Decrease)/increase to property, plant and equipment (51) (1,919) 885(Decrease)/increase to trade and other receivables (50) 3,086 148 –––––––– –––––––– ––––––––(Decrease)/increase to total assets (101) 1,167 1,033 –––––––– –––––––– ––––––––Increase to trade and other payables 623 6,436 –(Decrease)/increase to retained earnings at start ofthe year (5,269) 1,033 686Increase/(decrease) to total comprehensive incomefor the year 4,545 (6,302) 347 –––––––– –––––––– ––––––––(Decrease)/increase to total equity and liabilities (101) 1,167 1,033 –––––––– –––––––– ––––––––

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3. Operating segments

MOUK’s activity consists of one main class of business relating to the acquisition, exploration,development and production of oil and gas reserves and related activities in a single geographicalarea presently being the UK North Sea. This is considered to be the only reportable segment ofMOUK as it makes up more than 90% of MOUK’s activities. The majority of revenues, expenses,corporate activities and non-current assets are attributable to the UK North Sea and can beassigned to this reportable segment, accordingly no additional segment analysis is disclosed.

4. Revenue

MOUK derives revenue from the transfer of goods to external customers and the transfer ofservices to MOC companies. MOUK’s product lines are:



2018 2017 2016

US$000 US$000 US$000

Sale of crude oil 109,408 105,948 64,976Sale of gas 42,800 54,998 45,615Transportation and processing services 31,458 34,063 25,932Provision of services to:Other Marathon group companies 11,996 13,613 19,337Third parties 762 1,071 1,991 –––––––– –––––––– ––––––––Total revenues 196,424 209,693 157,851 –––––––– –––––––– ––––––––

Analysis of turnover by geography: Year ended Year ended Year ended


2018 2017 2016

US$000 US$000 US$000

United Kingdom 185,915 198,267 140,655Rest of World 10,509 11,426 17,196 –––––––– –––––––– ––––––––Total revenues 196,424 209,693 157,851 –––––––– –––––––– ––––––––

5. Other Operating Income

Reductions in the decommissioning provision are credited against fixed assets, where the fixedasset net book value is nil, the excess is taken to other operating income. In the financial yearended 31 December 2018 this resulted in a credit to other operating income of US$125,550,000.

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6. Operating profit/(loss)

Included in the statement of comprehensive income are the following:



2018 2017 2016

US$000 US$000 US$000

Operating profit/(loss) is stated aftercharging/(crediting):Depreciation on oil and gas assets 4,013 66,134 104,071Depreciation on administrative assets 158 516 1,054Contractor costs 12,212 50,937 19,473Operating leases 2,007 2,494 4,649Inventory recognised as an expense 8,542 9,797 9,122Foreign exchange movement 5,503 (633) (6,335)Fees payable to MOUK’s auditors:

Audit related assurance services 505 570 80 –––––––– –––––––– ––––––––

7. Directors and employees



2018 2017 2016

US$000 US$000 US$000

Wages and salaries 51,640 45,717 53,882Social security costs 5,430 4,952 5,169Other pension costs 7,983 4,788 6,209 –––––––– –––––––– ––––––––Total employee costs 65,053 55,457 65,260 –––––––– –––––––– ––––––––

The average monthly number of employees employed by MOUK, including directors in the yearare as follows:



2018 2017 2016

No No No

Onshore personnel 188 199 213Offshore personnel 139 130 136 –––––––– –––––––– –––––––– 327 329 349 –––––––– –––––––– ––––––––

Directors’ remuneration

Total remuneration of US$1.76 million, US$2.10 million and US$1.46 million, in 2018, 2017 and2016 respectively, relates to three directors who provided qualifying services to MOUK during theyear. The highest paid director’s remuneration amounts to US$405,000 in 2018; US$294,000 in2017; and US$294,000 in 2016. See note 23 for the breakdown of compensation of keymanagement personnel.

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8. Finance income



2018 2017 2016

US$000 US$000 US$000

Interest income – bank 28 39 53Interest income – loans 12,098 9,389 8,900Other interest receivable 2,300 1,773 658Net interest income on post-employment benefits 1,973 574 1,400 –––––––– –––––––– ––––––––Total finance income 16,399 11,775 11,011 –––––––– –––––––– ––––––––

9. Finance costs



2018 2017 2016

US$000 US$000 US$000

Unwind of discount on decommissioning provision (4,987) (3,545) (4,266)Other interest (2,559) (4,228) (3,841) –––––––– –––––––– ––––––––Total finance costs (7,546) (7,773) (8,107) –––––––– –––––––– ––––––––

10. Income tax charge/(credit)

Total tax charge of US$98.9 million, tax credit of U$24.0 million and tax credit of US$21.3 millionin 2018, 2017 and 2016 respectively, has been recognised in the consolidated statement ofcomprehensive income during the year.



2018 2017 2016

US$000 US$000 US$000

Current tax:

Current tax (credit)/charge (2,589) 19,610 3,924Adjustments in respect of prior years 6,716 106,223 (2,657) –––––––– –––––––– ––––––––Total current tax charge 4,127 125,833 1,267 –––––––– –––––––– ––––––––Deferred tax:

Adjustment in respect of prior years 16,142 (136,819) 36,965Relating to the origination and reversal oftemporary differences 78,660 (12,983) (59,531)Relating to the movement due to the tax ratechanges – – – –––––––– –––––––– ––––––––Total deferred tax charge/(credit) 94,802 (149,802) (22,566) –––––––– –––––––– ––––––––Total tax charge/(credit) 98,929 (23,969) (21,299) –––––––– –––––––– ––––––––

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A reconciliation between tax income and the product of accounting profit multiplied by thecombined UK ring fence corporation tax and supplementary charge rate of 40%, 40% and 40% in2018, 2017 and 2016 respectively and non-ring fence tax rate of 19%, 20% and 20% in 2018, 2017and 2016 respectively is as follows:



2018 2017 2016

US$000 US$000 US$000

Accounting profit/(loss)t before income tax 232,826 27,260 (36,518)A combined UK ring fence corporation tax andsupplementary charge rate of 40% in 2018,2017 and 2016 respectively and non-ring fencetax rate of 19%, 20% and 20% in 2018, 2017and 2016 respectively 93,130 10,904 (14,607)Expenses not deductible for tax purposes (9,841) (6,675) 1,230Income taxed at mainstream corporation tax rate (6,001) (5,060) (8,168)Currency remeasurements (4,816) 294 1,274Prior year adjustment 9,689 (13,291) 3,726Petroleum revenue tax 16,768 (7,491) (4,754)Interest – (2,650) – –––––––– –––––––– ––––––––Total tax charge/(credit) for the year 98,929 (23,969) (21,299) –––––––– –––––––– ––––––––

During 2017, a decision was received from the First-tier Tribunal regarding the timing ofdeductibility for decommissioning activities which are covered by the agreement mentioned in note18. The capital allowances claim which MOUK had made in respect of the expenditure in questionwas rejected.

In the first quarter of 2019 MOUK withdrew its appeal on this matter. The resulting revisions tocurrent and deferred tax liabilities, along with reversal of unrecognised tax benefits, are expectedto have no cumulative adverse impact on MOUK’s net income

11. Property, plant and equipment

Oil and gas Administrative

assets assets Total

US$000 US$000 US$000

CostAt 1 January 2016 4,526,854 58,932 4,585,786Transfers – (310) (310)Disposals (161) (32,721) (32,882)ARO revisions (53,920) – (53,920)Foreign exchange translation adjustment – (9,606) (9,606) ––––––––– ––––––––– –––––––––At 31 December 2016 4,472,773 16,295 4,489,068Additions 5,570 73 5,643Transfers – (963) (963)Impairment (1,418) – (1,418)Disposals – (8,167) (8,167)ARO revisions (49,646) – (49,646)Foreign exchange translation adjustment – 1,547 1,547 ––––––––– ––––––––– –––––––––

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Oil and gas Administrative

assets assets Total

US$000 US$000 US$000

At 31 December 2017 4,427,279 8,785 4,436,064Additions 13,813 104 13,917Impairment 20 – 20ARO revisions (170,681) – (170,681)Transfer excess ARO revision to other income 124,674 – 124,674Foreign exchange translation adjustment – (507) (507) ––––––––– ––––––––– –––––––––At 31 December 2018 4,395,105 8,382 4,403,487Accumulated depreciation and impairmentAt 1 January 2016 4,151,718 55,937 4,207,655Disposals – (32,721) (32,721)Charge for the year 104,071 1,054 105,125Foreign exchange translation adjustment – (9,118) (9,118) ––––––––– ––––––––– –––––––––At 31 December 2016 4,255,789 15,152 4,270,941Charge for the year 66,134 516 66,650Disposals – (8,167) (8,167)Transfers – (857) (857)Foreign exchange translation adjustment – 1,464 1,464 ––––––––– ––––––––– –––––––––At 31 December 2017 4,321,923 8,108 4,330,031Charge for the year 4,013 158 4,171Foreign exchange translation adjustment – (478) (478) ––––––––– ––––––––– –––––––––At 31 December 2018 4,325,936 7,788 4,333,724 ––––––––– ––––––––– –––––––––Net book valueAt 31 December 2018 69,169 594 69,763 ––––––––– ––––––––– –––––––––At 31 December 2017 105,356 677 106,033 ––––––––– ––––––––– –––––––––At 31 December 2016 216,984 1,143 218,127 ––––––––– ––––––––– –––––––––

The oil and gas assets consist of producing and development assets and decommissioning assetsin accordance with IAS 16 ‘Property, Plant and Equipment’.

The administrative assets consist of freehold property, fixtures and fittings, computer equipmentand leasehold improvements.

ARO revisions made as a result of updates to the estimations in respect of abandonment costs.

In assessing whether any impairment is required to the carrying value of assets, their carryingvalue is compared with their recoverable amount. The CGU assessed for impairment is generallythe field, or group of fields where these are economically dependent. The recoverable amount isthe higher of the asset’s fair value less costs to sell or value in use. See note 1 for further detailsof the accounting policy on impairment. An impairment to oil and gas assets was required in 2016with a reversal of the impairment in 2017 due to the oil price in those years.

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12. Investment property

Total

US$000

ValuationAt 1 January 2016 1,004Additions at cost 122Foreign exchange movement (163) ––––––––At 31 December 2016 963Additions at cost 328Foreign exchange movement 91 ––––––––At 31 December 2017 1,382Additions at cost –Foreign exchange movement (80) ––––––––At 31 December 2018 1,302 ––––––––

The fair value of the investment property is based on the valuation performed by a firm ofindependent registered surveyors, Savills UK Limited. The basis of the valuation is market valueas defined by the Royal Institute of Chartered Surveyors.

There are no restrictions on the realisability of investment property or the remittance of incomefrom the current lease which expires on 6 January 2022.

The lessee of the property has contractual obligations for repairs and maintenance throughout theterm of the lease.

13. Deferred tax assets and liabilities



2018 2017 2016

US$000 US$000 US$000

Pension (14,024) (12,068) (2,092)Accelerated capital allowances – Corporation Tax (24,758) (35,603) (48,946)Decommissioning provision 367,754 468,875 332,079Tax losses 888 2,650 – –––––––– –––––––– ––––––––Net deferred tax asset 329,860 423,854 281,041 –––––––– –––––––– ––––––––Deferred tax asset 368,642 471,525 332,079Deferred tax liability (38,782) (47,671) (51,038) –––––––– –––––––– ––––––––Net deferred tax asset 329,860 423,854 281,041 –––––––– –––––––– ––––––––

Deferred tax assets have been recognised in respect of tax losses and other temporary differenceswhere the Directors believe it is probable that these assets will be recovered in the near future.

The unrecognised losses may affect future tax charges should certain subsidiaries in MOUKproduce taxable trading profits in future periods where there is currently uncertainty of the timingof future taxable profits.

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Movements in the net deferred tax asset are the result of origination and reversal of timingdifferences and have been accounted for as follows:

Accelerated

capital Decommissioning Tax

Pension allowances provision losses Total

US$000 US$000 US$000 US$000 US$000

At 1 January 2016 (5,170) (40,464) 295,114 – 249,480(Charged)/credited to loss (2,308) (7,908) 32,782 – 22,566Foreign exchangedifferences (charged)/credited to loss (73) (574) 4,183 – 3,536Credited to othercomprehensiveexpense 5,459 – – – 5,459 –––––––– –––––––– –––––––– –––––––– ––––––––At 31 December 2016 (2,092) (48,946) 332,079 – 281,041(Charged)/credited toprofit (3,586) 13,241 137,491 2,656 149,802Foreign exchangedifferences (charged)/credited to profit 5 102 (695) (6) (594)Charged to othercomprehensive income (6,395) – – – (6,395) –––––––– –––––––– –––––––– –––––––– ––––––––At 31 December 2017 (12,068) (35,603) 468,875 2,650 423,854(Charged)/credited toprofit (1,928) 10,913 (102,020) (1,767) (94,802)Foreign exchangedifferences (charged)/credited to profit (23) (68) 899 5 813Charged to othercomprehensiveexpense (5) – – – (5) –––––––– –––––––– –––––––– –––––––– ––––––––At 31 December 2018 (14,024) (24,758) 367,754 888 329,860 –––––––– –––––––– –––––––– –––––––– ––––––––

14. Inventory



2018 2017 2016

US$000 US$000 US$000

Raw materials and consumables 8,496 5,358 6,526Linefill 2,864 2,864 2,864 –––––––– –––––––– ––––––––Total inventory 11,360 8,222 9,390 –––––––– –––––––– ––––––––

The carrying value of MOUK’s inventories as stated above is based on the net realisable value inaccordance with the accounting policies.

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15. Trade and other receivables



2018 2017 2016

US$000 US$000 US$000

Trade receivables 28,780 31,945 32,244Under lift asset – – 3,499Prepayments and accrued income 11,939 4,029 8,410Corporation tax 1,093 3,421 5,076Other tax receivable 418 887 670Other debtors 507 858 4,758 –––––––– –––––––– ––––––––Total current trade and other receivables 42,737 41,140 54,657 –––––––– –––––––– ––––––––Amounts owed from other Marathon groupundertakings 162,867 429,503 513,413 –––––––– –––––––– ––––––––

All trade and other receivables are due within one year from the statement of financial positiondate.

The carrying value of MOUK’s trade and other receivables as stated above is considered to be areasonable approximation of the fair value. None of the above trade receivables were consideredpast due or impaired as of 31 December 2018, 31 December 2017 or 31 December 2016.

Included in amounts owed by other Marathon group undertakings is US$60,320,000,US$314,437,000 and US$344,473,000 as at 31 December 2018, 31 December 2017 and31 December 2016 respectively which has been loaned to Marathon Oil Investment LLC. The loanis interest-bearing at 3.7850%, 2.8290% and 2.5767% in 2018, 2017 and 2016 respectively and isrepayable on MOUK’s demand. Also included in amounts owed by other Marathon groupundertakings is US$90,086,000, US$80,877,000 and US$133,762,000 as at 31 December 2018,2017 and 2016 respectively which has been loaned to Marathon Oil Investment LLC. The loan isinterest-bearing at LIBOR +0.1% and is repayable on MOUK’s demand. The remainder representsamounts owed by other Marathon group undertakings and these are unsecured, interest-free,repayable on demand and have no set repayment date.

The nature of MOUK’s external and intercompany receivables, being a mix of due within 30 daysand repayable on demand, means that the credit loss exposure is negligible, and as such noprovision for expected credit losses have been made.

16. Cash and cash equivalents



2018 2017 2016

US$000 US$000 US$000

Available cash at bank and in hand 30,373 62,048 24,246 –––––––– –––––––– ––––––––

The fair values of cash and cash equivalents are the same as the above book values.

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17. Trade and other payables



2018 2017 2016

US$000 US$000 US$000

Trade payables 8,832 5,332 7,778Over lift liability 1,603 10,841 –Accruals 24,422 23,291 17,711Provisions for liabilities and other charges 45,181 35,595 32,228Other creditors 1,717 1,258 1,412Tax payable – 2,315 2,335 –––––––– –––––––– ––––––––Total current trade and other payables 81,755 78,632 61,464 –––––––– –––––––– ––––––––Amount owed to other Marathon groupundertakings – 1,602 1,195 –––––––– –––––––– ––––––––

All current trade and other payables are due within one year from the statement of financialposition date including non-interest bearing intercompany balances. The carrying value of thetrade and other payables as stated above is considered to be a reasonable approximation of thefair value. All trade and other payables are settled within three months of invoice date.

18. Provisions for liabilities and other charges

Decommissioning Other Total

provision provision Provisions

US$000 US$000 US$000

At 1 January 2016 944,950 1,048 945,998Utilisation (14,301) (594) (14,895)Changes in estimates (53,920) – (53,920)Finance charge 4,266 – 4,266 –––––––– –––––––– ––––––––At 31 December 2016 880,995 454 881,449Utilisation (21,454) (454) (21,908)Changes in estimates (49,646) – (49,646)Finance charge 3,545 – 3,54 –––––––– –––––––– ––––––––At 31 December 2017 813,440 – 813,440 –––––––– –––––––– ––––––––Utilisation (24,950) – (24,950)Changes in estimates (170,681) 103 (170,578)Finance charge 4,987 – 4,987 –––––––– –––––––– ––––––––At 31 December 2018 622,796 103 622,899 –––––––– –––––––– ––––––––

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Decommissioning provision



2018 2017 2016

US$000 US$000 US$000

Less amounts included in current liabilities (note 17) 45,181 35,595 32,228Amounts included in non-current liabilities 577,615 777,845 848,767Total decommissioning provision 622,796 813,440 880,995 –––––––– –––––––– ––––––––Other provisionAmounts included in current liabilities (note 17) – – – –––––––– –––––––– ––––––––Amounts included in non-current liabilities 103 – 454 –––––––– –––––––– ––––––––Total other provision 103 – 454 –––––––– –––––––– ––––––––Total provisionsAmounts included in current liabilities (note 17) 45,181 35,595 32,228 –––––––– –––––––– ––––––––Amounts included in non-current liabilities 577,718 777,845 849,221 –––––––– –––––––– ––––––––Total provisions 622,899 813,440 881,449 –––––––– –––––––– ––––––––

The estimated cost of decommissioning at the end of the producing lives of the fields is reviewedannually and engineering estimates and reports are updated periodically. Provision is made for theestimated cost of decommissioning at the statement of financial position date for MOUK’s share ofthe overall costs. Cost estimates have been discounted at an average discount rate of 1.035%,0.525% and 0.66%, in 2018, 2017 and 2016 respectively.

The timing of spend is based on the economic cut off point for the producing assets. Provisionsacquired in business combinations have been calculated based on the latest operator costestimates. The payment dates are uncertain and are currently anticipated to be between 2019 and2032 for the relevant producing fields. It is anticipated that MOUK will obtain full tax relief on itsdecommissioning liabilities in the UK.

The other provision in MOUK balance sheet relates to a dilapidation provision for office premises.The unwind for this provision is immaterial.

The total provision for decommissioning includes: US$45,181,000, US$35,595,000 andUS$32,228,000 in 2018, 2017 and 2016 respectively which relate to short term provisions and assuch are included in current liabilities in the balance sheet.

19. Capital surplus

MOUK is a limited liability company, and therefore does not issue share capital. MOUK’sownership is represented by a membership interest which is shown as capital surplus on thebalance sheet.

20. Restricted stock awards

The MOC 2016 Incentive Compensation Plan, which was approved by our stockholders in May2017 and authorizes the Compensation Committee of the Board of Directors to grant restrictedstock awards to employees. Restricted stock awards are granted to certain non-officer employeesbased on their performance within certain guidelines and for retention purposes. The restrictedstock awards to non-officers generally vest ratably over a three-year period, contingent on therecipient’s continued employment. Prior to vesting, all restricted stock recipients have the right tovote on such stock and receive dividends thereon. The non-vested shares of restricted stock arenot transferable and are held by MOC’s transfer agent.

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Total stock-based compensation expense – Total employee stock-based compensation expensewas US$7.48 million, US$7.13 million and US$7.12 million in 2018, 2017 and 2016 respectively.

Restricted stock awards – The following is a summary of restricted stock award activity:

Weighted

average grant

Awards date fair value

Unvested at 1 January 2016 392,994 US$31.28Granted 601,596 US$8.67Vested and exercised (177,592) US$31.66Cancelled (56,353) US$17.10 ––––––––Unvested at 31 December 2016 760,645 US$14.36Granted 383,429 US$16.22Vested and exercised (305,156) US$17.48Cancelled (46,128) US$14.34 ––––––––Unvested at 31 December 2017 792,790 US$14.06Granted 485,307 US$14.53Vested and exercised (360,756) US$15.09Cancelled (62,150) US$14.64 ––––––––Unvested at 31 December 2018 855,191 US$13.87

The vesting date fair value of restricted stock awards which vested during 2018, 2017 and 2016respectively was US$5.72 million, US$4.81 million and US$2.30 million. The weighted averagegrant date fair value of restricted stock awards was US$13.87, US$12.64 and US$8.72 for awardsunvested at 31 December, 2018, 31 December 2017 and 31 December 2016 respectively.

The total amount of unrecognized compensation cost related to restricted stock awards which isexpected to be recognised over a weighted average period of one year was US$7.48 million,US$7.13 million and US$7.12 million at 31 December, 2018, 31 December 2017 and 31 December2016 respectively.

21. Financial instruments

MOUK’s financial instruments comprise trade and other receivables, trade and other payables, andcash and cash equivalents.

Financial risk factors and capital risk management

The fair values of MOUK’s financial instruments are materially the same as their carrying amounts.MOUK’s financial instruments expose it to a variety of financial risks: market risk, credit risk,interest risk and liquidity risk.

(a) Market risk

Commodity price riskMOUK held no financial instruments as at 31 December 2018, 31 December 2017 and31 December 2016 that were affected by commodity price, but MOUK is nonethelessexposed to movements in oil and gas prices.

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The table below illustrates the impact on profit before tax of changes of commodity prices.The impact on equity is the same.



2018 2017 2016

Crude oil sales during the year (US$000s) 109,409 105,948 64,976Gas sales during the year (US$000s) 42,799 54,998 45,451Average crude oil price (US$) per bbl 71.98 54.52 44.95Average gas price (US$) per boe 48.33 36.32 28.72Impact of decrease of crude oil prices byUS$1 (US$000s) 1,479 1,847 1,446Impact of decrease of crude oil prices by10% (US$000s) 10,903 10,506 (13,712)Impact of decrease of gas prices byUS$1 (US$000s) 866 1,514 1,583Impact of decrease of gas prices by10% (US$000s) 4,280 5,500 4,545

Foreign exchange riskMOUK is exposed to foreign exchange risk arising from currency exposures, primarily withrespect to GBP. Foreign exchange risk arises when future commercial transactions orrecognised assets or liabilities are denominated in a currency that is not the entity’sfunctional currency.

The following foreign exchange rates were applied:

2018 2017 2016

As at 31 December (US$ to GBP) 1.27 1.35 1.23Average for the year (US$ to GBP) 1.34 1.29 1.36

As at 31 December 2018, 31 December 2017 and 31 December 2016 various statements offinancial position line items were denominated in foreign currencies and the impact due toforeign exchange movement of an increase or decrease in exchange rate is shown below.

MOUK’s exposure to foreign currency risk was as follows, based on the following nominalamounts:

2018 2017 2016

£000 US$000 €000 £000 US$000 €000 £000 US$000 €000

Cash at bank 13,872 2 – 19,542 1,291 – 6,013 1,038 –Working capitalaccruals 4,640 6,080 – 5,247 5,377 19 3,778 4,811 807Trade receivables 18,114 12,075 – 20,081 8,653 – 24,045 11,747 –Trade payables 7,219 10,781 – 6,747 183,533 17 7,059 184,361 –

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(b) Credit risk

Credit risk arises from cash and cash equivalents, as well as credit exposures on trade andother receivables. The credit risk of MOUK’s trade and other receivables is assessedthrough the credit ratings of relevant customers.

See listing below:

Recoverable

Recoverable period

period Within

2018 0-30 days one year

Customers US$000 US$000 US$000

BP Exploration Co. Ltd 354 354 –BP Oil International Ltd 1,275 1,275 –CNR International UK Ltd 183 183 –John Lawrie Group 751 751 –JX Nippon Expl & Prod (UK) Ltd 1,038 1,038 –Repsol Sinopec North Sea Ltd 678 678 –Spirit Energy Resources Ltd 1,320 1,320 –Suncor Energy Int. Trading Ltd 9,047 9,047 –TAQA Group 8,825 8,456 369Others 5,309 5,298 11 –––––––– –––––––– ––––––––Total 28,780 28,400 380 –––––––– –––––––– ––––––––

MOUK only trades with recognised creditworthy third parties. The exposure risk arises fromdefault of the counter party, with a maximum exposure equal to the carrying amount as atthe statement of financial position date.

(c) Interest rate risk

Liquidity risk is the risk that MOUK will not be able to meet its financial obligations as theyfall due.

Management monitors MOUK’s liquidity reserve (comprising cash and cash equivalents)through comparison to expected cash flow and budgets.

The following are the contractual maturities of financial liabilities including estimated interestpayments for loans from MOC group undertakings:

2018 2017 2016

1 year 1 year 2 year 1 year 1 year 2 year 1 year 1 year 2 year

Total or less <2years <5years Total or less <2years <5years Total or less <2years <5years

US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000

Non-derivative

financial

liabilities:

Trade and other

payables 80,152 80,152 – – 69,393 69,393 – – 62,659 62,659 – –

Over lift liability 1,603 1,603 – – 10,841 10,841 – – – – – –

Total financial

liabilities 81,755 81,755 – – 80,234 80,234 – – 62,659 62,659 – ––––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––

Capital risk managementMOUK’s objectives when managing capital are to safeguard MOUK’s ability to continue asa going concern in order to provide returns for members.

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22. Commitments and contingent liabilities

Capital commitments

In respect of its interest in joint operating agreements, MOUK has committed Capital expenditureof US$46,151,000, US$47,821,000 and US$nil as at 31 December 2018, 31 December 2017 and31 December 2016 respectively.

Operating lease commitments



2018 2017 2016

US$000 US$000 US$000

Office premise and vessel leases:Payments under operating leases due withinone-year 1,972 2,082 1,923Payments under operating leases due betweentwo to five-years 3,069 4,560 84Payments under operating leases due later thanfive-years 186 992 – –––––––– –––––––– ––––––––Total operating lease commitments 5,227 7,634 2,007 –––––––– –––––––– ––––––––

Lease payments of US$2,007,000, US$2,494,000 and US$4,649,000, in 2018, 2017 and 2016respectively, were recognised in the statement of comprehensive income.

Contingent liabilities/assets

No contingent liabilities or assets existed as at 31 December 2018, 31 December 2017 and31 December 2016.

23. Related parties

(a) Controlling Parties

MOUK is controlled by the following entities:

Principal place Ownership interest

Name Type of business 2018 2017 2016

Parent 100% 100% 100%

Ultimate parent 100% 100% 100%

(b) Key management personnel compensation

Key management personnel compensation is set out in the following table.

2018 2017 2016

US$000 US$000 US$000

Salary/fees 1,106 1,588 1,079Taxable benefits 7 12 8Bonus 589 499 370Payments in Lieu of Pension 56 – –Total 1,758 2,099 1,457

5555 San FelipeStreet, Houston,Texas, TX 77056-2723, USA

MarathonInternational OilHoldings LLC


Marathon OilCorporation

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The above amounts have been calculated by translating the GBP amounts to USD at theaverage rate for the year of US$1.34, US$1.29 and US$1.36, in 2018, 2017 and 2016respectively.

(c) Directors

The Directors’ emoluments are disclosed in note 7.

(d) Transactions with other related parties

The following transactions occurred with related parties:

2018 2017 2016

US$000 US$000 US$000

Recharge of services to MOC undertakings 11,996 13,613 19,337Management service charge from parent 1,438 1,775 810Interest received from MOC undertakings 12,098 9,389 8,900Dividend revenue 40,000 – –

24. Pensions

For certain employees, MOUK operates a defined benefit pension scheme with assets held in aseparately administered fund. This scheme was closed to new entrants on 1 April 2010 and wasclosed to future benefit accrual on 31 December 2015. The scheme provided retirement benefitson the basis of members’ final salary. The scheme is administered by trustees, who areresponsible for ensuring that the plan is sufficiently funded to meet current and future obligations.MOUK agreed a funding plan with the trustees whereby annual contributions of £13,000,000 willbe made until 31 December 2020.

Present value Fair value of

of obligation plan assets Net amount

US$000 US$000 US$000

Present at 1 January 2016 579,565 (608,283) (28,718)Interest expense/(income) 19,903 (21,303) (1,400)Loss on changes/introductions 879 – 879 –––––––– –––––––– ––––––––Total amount recognised in profit or loss 20,782 (21,303) (521)Remeasurements:

Return on plan assets – (110,208) (110,208)Loss from change in demographic assumptions 142,317 – 142,317 –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome 142,317 (110,208) 32,109Exchange differences (105,198) 108,641 3,443Contributions:Employers – (18,620) (18,620)Plan participants – – –Benefit payments (52,070) 52,070 – –––––––– –––––––– ––––––––At 31 December 2016 585,396 (597,703) (12,307) –––––––– –––––––– ––––––––At 31 December 2016 (from previous table) 585,396 (597,703) (12,307)Interest expense/(income) 15,926 (16,500) (574) –––––––– –––––––– ––––––––Total amount recognised in profit or loss 15,926 (16,500) (574) –––––––– –––––––– ––––––––

154




US$000 US$000 US$000

Remeasurements:

Return on plan assets – (30,354) (30,354)Gain from change in demographic assumptions (7,269) – (7,269) –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome (7,269) (30,354) (37,623)Exchange differences 53,927 (57,620) (3,693)Contributions:Employers – (16,796) (16,796)Plan participants – – –Benefit payments (46,115) 46,115 – –––––––– –––––––– ––––––––At 31 December 2017 601,865 (672,858) (70,993)Interest expense/(income) 14,406 (16,379) (1,973) –––––––– –––––––– ––––––––Total amount recognised in profit or loss 14,406 (16,379) (1,973)Remeasurements:

Return on plan assets – 37,598 37,598Gain from change in demographic assumptions (34,670) – (34,670) –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome (34,670) 37,598 (2,928)Exchange differences (32,145) 37,046 4,901Contributions:Employers – (17,375) (17,375)Plan participants – – –Benefit payments (38,047) 38,047 – –––––––– –––––––– ––––––––At 31 December 2018 511,409 (593,921) (82,512) –––––––– –––––––– ––––––––

On 1 April 2010, MOUK established a defined contribution scheme to provide benefits to newemployees. On 1 January 2016 all employees were transferred to the defined contribution scheme.

Total contributions to the defined benefit scheme and defined contribution scheme was US$7.98million, US$4.79 million and US$6.21 million in 2018, 2017 and 2016 respectively.

A comprehensive actuarial valuation of the MOUK pension scheme, using the projected unit basiswas carried out at 31 March 2016 by Mercer Limited, independent consulting actuaries.Adjustments to the valuation at that date have been made based on the following assumptions.

Principal actuarial assumptions at the statement of financial position date (expressed as weightedaverages):

2018 2017 2016

Discount rate 2.9% 2.5% 2.7%Future salary increases 0.0% 0.0% 0.0%Future pension increases 3.1% 3.0% 3.2%Inflation assumption 2.2% 2.2% 2.3%Mortality rates

– for a male aged 65 now 22.4 22.5 22.6– at 65 for a male aged 45 now 23.7 23.8 24.9– for a female aged 65 now 24.5 24.6 24.2– at 65 for a female aged 45 now 26.2 26.3 27.0 –––––––– –––––––– ––––––––

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The fair value of the scheme assets for defined benefit scheme were:

2018 2017 2016

$’000 $’000 $’000

Cash and cash equivalents 6,198 3,430 6,799Equity instruments 190,651 266,084 360,529Debt instruments 306,836 301,932 230,375Diversified growth funds 90,236 101,412 – –––––––– –––––––– ––––––––Total scheme assets 593,921 672,858 597,703 –––––––– –––––––– ––––––––

25. Adjusted EBITDA

Presented is the Earnings Before Interest, Tax, Depreciation and Amortisation (referred to asEBITDA) adjusted for the one-off non-cash adjustments in respect of the Asset RetirementObligation provision included within other income.

2018 2017 2016


Profit/(loss) before income tax less: 232,826 27,260 (36,518)Finance costs 9 7,546 7,773 8,107Finance income 8 (16,399) (11,775) (9,611)Other income 5 (125,550) (423) (191)Depreciation charge 11 4,171 66,650 105,125 –––––––– –––––––– ––––––––Adjusted EBITDA 102,594 89,485 66,912 –––––––– –––––––– ––––––––

EBITDA is considered a useful proxy for cash flow.

26. Events after the reporting date

On the 25 February 2019, RockRose entered into a sale and purchase agreement with MOHL toacquire the entire membership in MOUK. The transaction has an effective date of 1 January 2019and is expected to complete, subject to certain contractual requirements, in the second half of2019 (which is the IFRS 3 effective date).

As part of the sale and purchase agreement MOHL agreed to repay all intercompany balancesreceivable by MOUK on the completion date.

Effective 31 March 2019, MOUK’s wholly owned subsidiary, Marathon Oil DecommissioningServices LLC, transferred its trade and assets to MOUK. The agreement between the twocompanies for the provision of decommissioning services ceased to have effect from that date.MOUK expects to record a net gain in its 2019 financial statements in relation to these events. Theexpected net gain reflects the elimination of Petroleum Revenue Tax temporary differences. Therewere no adjustments recorded in the 2018 HFI in respect of this as it is a post balance sheet event.

On 20 June 2019 MOUK was notified by TAQA Bratani Limited (“TAQA Bratani”), a significantnon-operator interest holder in the Greater Brae Area licences, following the approval of proposalsmade by TAQA Bratani to the other members of the relevant operating committees on 5 June 2019,that MOUK would be discharged as operator of Blocks 16/7a. Licence no. P.108 (Block 16/3a),Licence no. P313 (Block 16/3b), Licence no. P313 (Block 16/3c) and East Brae and TAQA Brataniappointed in its place. No reasons were given for the changes. A process will follow, involving OGAapproval, which could result in MOUK losing operatorship of these licences in July 2020. Shouldthis occur MOUK will no longer be an operator, but will retain its interests in the field.

There were no adjustments recorded in the 2018 HFI in respect of these events as they occurredafter the reporting date.

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PART XIII

HISTORICAL FINANCIAL INFORMATION ON MOWOS

Section A: Accountant’s Report on the Historical Financial Information on MOWOS

The DirectorsRockRose Energy plcc/o Cooley Services LimitedDashwood69 Old Broad StreetLondon EC2M 1QSUnited Kingdom

19 July 2019

Dear Sirs

Marathon Oil West of Shetlands Limited (“MOWOS”)

We report on the financial information on MOWOS for the three years ended 31 December 2018,31 December 2017 and 31 December 2016 (the “MOWOS HFI”). The MOWOS HFI has beenprepared for inclusion in the prospectus dated 19 July 2019 (the “Prospectus”) of RockRoseEnergy plc (the “Company”) on the basis of the accounting policies set out in note 1 to theMOWOS HFI. This report is required by item 20.1 of Annex I to the PD Regulation and is given forthe purpose of complying with that item and for no other purpose.

Responsibilities

The Directors of the Company are responsible for preparing the MOWOS HFI in accordance withInternational Financial Reporting Standards as adopted by the European Union.

It is our responsibility to form an opinion as to whether the MOWOS HFI gives a true and fair view,for the purposes of the Prospectus and to report our opinion to you.

Save for any responsibility which we may have to those persons to whom this report is expresslyaddressed and for any responsibility arising under item 5.5.3R(2)(f) of the Prospectus Rules to anyperson as and to the extent there provided, to the fullest extent permitted by law we do not assumeany responsibility and will not accept any liability to any other person for any loss suffered by anysuch other person as a result of, arising out of, or in connection with this report or our statement,required by and given solely for the purposes of complying with item 23.1 of Annex I to the PDRegulation consenting to its inclusion in the Prospectus.

Annex I, 20.4.1

Annex I, 1.2

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Basis of opinion

We conducted our work in accordance with the Standards for Investment Reporting issued by theAuditing Practices Board in the United Kingdom. Our work included an assessment of evidencerelevant to the amounts and disclosures in the financial information. It also included anassessment of significant estimates and judgments made by those responsible for the preparationof the financial information and whether the accounting policies are appropriate to the MOWOS’scircumstances, consistently applied and adequately disclosed.

We planned and performed our work so as to obtain all the information and explanations which weconsidered necessary in order to provide us with sufficient evidence to give reasonable assurancethat the financial information is free from material misstatement whether caused by fraud or otherirregularity or error.

Opinion

In our opinion, the MOWOS HFI gives, for the purposes of the Prospectus, a true and fair view ofthe state of affairs of MOWOS as at the dates stated and of its profits, cash flows and changes inequity for the periods then ended in accordance with International Financial Reporting Standardsas adopted by the European Union.

Declaration

For the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of theProspectus and declare that we have taken all reasonable care to ensure that the informationcontained in this report is, to the best of our knowledge, in accordance with the facts and containsno omission likely to affect its import. This declaration is included in the Prospectus in compliancewith item 1.2 of Annex I to the PD Regulation.

Yours faithfully



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Section B: Historical Financial Information on MOWOS




2018 2017 2016



Revenue 4 176,032 93,981 126,035Cost of sales (100,740) (71,298) (85,947) –––––––– –––––––– ––––––––Gross profit 75,292 22,683 40,088Administrative costs (2,672) (3,198) (3,129) –––––––– –––––––– ––––––––Operating profit 5 72,620 19,485 36,959Finance income 7 4,274 2,040 799Finance costs 8 (2,444) (1,438) (1,439) –––––––– –––––––– ––––––––Profit before income tax 74,450 20,087 36,319Income tax charge 9 (29,610) (8,402) (25,279) –––––––– –––––––– ––––––––Profit for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Adjusted EBITDA 24 92,976 39,669 70,617 –––––––– –––––––– ––––––––There was no other comprehensive

income 2018, 2017 and 2016 respectively.

Total comprehensive income for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Unadjusted basic earnings per share(in cents) 10 179,360 47 44 –––––––– –––––––– ––––––––Unadjusted diluted earnings per share(in cents) 10 179,360 47 44 –––––––– –––––––– ––––––––

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As at As at As at As at

31 December 31 December 31 December 1 January

2018 2017 2016 2016

Audited Audited Audited Unaudited

Note US$000 US$000 US$000 US$000

AssetsProperty, plant and equipment 11 45,541 102,511 111,380 195,194Deferred tax asset 12 100,192 113,748 108,636 64,575 –––––––– –––––––– –––––––– ––––––––Total non-current assets 145,733 216,259 220,016 259,769 –––––––– –––––––– –––––––– ––––––––Inventory 13 56 458 4,051 7,419Trade and other receivables 14 35 13,951 9,063 25,082Loans to group undertakings 14 156,545 143,989 153,692 108,499Cash and cash equivalents 15 1,730 9,194 7,680 2,385 –––––––– –––––––– –––––––– ––––––––Total current assets 158,366 167,592 174,486 143,385 –––––––– –––––––– –––––––– ––––––––Total assets 304,099 383,851 394,502 403,154 –––––––– –––––––– –––––––– ––––––––EquityShare capital 18 25 25,025 25,025 25,025Other reserves 19 109,591 84,591 84,591 84,591Accumulated losses (101,264) (61,104) (47,789) (58,829) –––––––– –––––––– –––––––– ––––––––Total equity 8,352 48,512 61,827 50,787 –––––––– –––––––– –––––––– ––––––––LiabilitiesAccruals and deferred income – – – 10,388Deferred tax liability 12 18,515 40,329 43,385 –Provisions for liabilities andother charges 17 250,481 284,313 271,590 321,739 –––––––– –––––––– –––––––– ––––––––Total non-current liabilities 268,996 324,642 314,975 332,127 –––––––– –––––––– –––––––– ––––––––Trade and other payables 16 10,007 10,056 10,642 15,827Tax payable 16 16,744 641 7,058 4,413 –––––––– –––––––– –––––––– ––––––––Total current liabilities 26,751 10,697 17,700 20,240 –––––––– –––––––– –––––––– ––––––––Total liabilities 295,747 335,339 332,675 352,367 –––––––– –––––––– –––––––– ––––––––Total equity and liabilities 304,099 383,851 394,502 403,154 –––––––– –––––––– –––––––– ––––––––

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Consolidated Statement of Changes in Equity

Other Accumulated

Share capital reserves losses Total

US$000 US$000 US$000 US$000

Balance as at 31 December 2015as originally presented (unaudited) 25,025 84,591 (58,983) 50,633IFRS transitional adjustments (note 2) – – 154 154 –––––––– –––––––– –––––––– ––––––––Balance as at 1 January 2016(unaudited) 25,025 84,591 (58,829) 50,787Profit for the year – – 11,040 11,040Other comprehensive income – – – – –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2016 25,025 84,591 (47,789) 61,827Profit for the year – – 11,685 11,685Other comprehensive income – – – –Shareholder distribution – – (25,000) (25,000) –––––––– –––––––– –––––––– ––––––––Total transactions with owners – – (25,000) (25,000) –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2017 25,025 84,591 (61,104) 48,512Profit for the year – – 44,840 44,840Other comprehensive income – – – –Shareholder distribution – – (85,000) (85,000)Capital reduction (25,000) 25,000 – – –––––––– –––––––– –––––––– ––––––––Total transactions with owners (25,000) 25,000 (85,000) (85,000) –––––––– –––––––– –––––––– ––––––––Balance as at 31 December 2018 25 109,591 (101,264) 8,352 –––––––– –––––––– –––––––– ––––––––

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2018 2017 2016

US$000 $’000 $’000


Profit before income tax 74,450 20,087 36,319Non-cash adjustments to reconcile profit beforetax to net cash flows:Finance income (4,274) (2,040) (799)Finance costs 4 – 3Depreciation and amortisation 20,356 20,184 33,658Finance charge on decommissioning provision 2,440 1,438 1,436 –––––––– –––––––– ––––––––Operating cash flows before movements inworking capital 92,976 39,669 70,617Decrease in inventory 402 3,593 3,368Decrease/(increase) in trade and other receivables 13,916 (4,888) 16,020(Increase)/decrease in amounts owed by groupcompanies (12,623) 9,853 (55,748)Increase/(decrease) in trade and other payables 18 (736) (5,018)Income tax paid (21,765) (22,987) (23,310) –––––––– –––––––– ––––––––Net cash generated from operating activities 72,924 24,504 5,929Cash flows from investing activities

Payments to acquire property, plant and equipment – (30) (1,430)Receipts from sales of property, plant andequipment 342 – –Finance income 4,274 2,040 799 –––––––– –––––––– ––––––––Net cash generated from/(used in) investingactivities 4,616 2,010 (631)Cash flows from financing activities

Finance costs (4) – (3)Shareholder distribution (85,000) (25,000) – –––––––– –––––––– ––––––––Net cash used in financing activities (85,004) (25,000) (3) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cashequivalents (7,464) 1,514 5,295Cash and cash equivalents at 1 January 9,194 7,680 2,385 –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 1,730 9,194 7,680 –––––––– –––––––– ––––––––

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Notes

1. Principal accounting policies

General information

On the 25 February 2019, RockRose entered into a sale and purchase agreement with MarathonInternational Oil Holdings LLC (“MIOH”) to acquire the entire issued share capital of Marathon OilWest of Shetlands Limited (“MOWOS”).

MOWOS is a company incorporated in England and Wales. The address of its registered office is91 Wimpole Street, London, England, W1G 0EF. The company is domiciled in Aberdeen, Scotland.

MOWOS’s principal activity is the development and production of oil and gas from the Foinavenarea in the United Kingdom (UK) Atlantic Margin. MOWOS has a 28% interest in the BP operatedFoinaven area complex in UK blocks 204/19 and 204/24a, located directly west of the ShetlandIslands.

Basis of preparation

The MOWOS Historical Financial Information (referred to as the “HFI”), which has been preparedspecifically for the purposes of this document, sets out the balance sheet as at 31 December 2018,2017 and 2016 and the results of operations and cash flows for each of the three years then endedof MOWOS and has been prepared in accordance with the requirements of the ProspectusDirective regulations.

The MOWOS HFI has been prepared in accordance with International Financial ReportingStandards and the IFRS Interpretation Committee (IFRS IC) interpretations as adopted by theEuropean Union (“IFRS”). The principal accounting policies that have been applied to the MOWOSHFI are set out below. These policies have been consistently applied to all years presented unlessotherwise stated.

The MOWOS HFI does not constitute statutory accounts and represents the first-time preparationof financial information for MOWOS under IFRS reporting standards.

MOWOS has previously prepared and reported statutory financial statements, in accordance withapplicable standards in the United Kingdom (“Financial Reporting Standard 102”).Consequently, the opening statement of financial position at the 1 January 2016 has been includedin the HFI together with IFRS 1 reconciliations between financial information prepared underFinancial Reporting Standard 102 and financial information prepared in accordance with IFRS, asrequired by IFRS 1 on transition to IFRS. The principle changes to the presentation of the financialinformation as a result of adopting IFRS as at the 1 January 2016 are sent out in note 2 to this HFI.

The statutory accounts for the years ended 31 December 2018, 31 December 2017 and31 December 2016 were prepared for the purposes of English company law and under FinancialReporting Standard 102. The reports of the auditors for those years were unqualified and did notinclude a reference to any matters to which the auditors drew attention by way of emphasis withoutqualifying their report. The statutory accounts for the years ended 31 December 2018,31 December 2017 and 31 December 2016 were filed at Companies House.

The MOWOS HFI has been prepared under the historical cost convention except for certainfinancial instruments which are carried at fair value and is presented in US Dollars (“US$”), whichis the currency of the primary economic environment in which MOWOS operates, rounded to thenearest thousand.

Adoption of new standards and interpretations

New standards, amendments and interpretations

IFRS 1 “First-time adoption of IFRS”, requires that entities use the same accounting policiesthroughout their first IFRS financial statements and in their opening IFRS balance sheet, and thatthese accounting policies should be those complying with the accounting standards effective at the

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end of an entity’s first IFRS reporting period. As such the HFI has been prepared using the currentversion of IFRS throughout all the periods presented in the HFI.

New standards, amendments and interpretations not yet adopted

The following new and revised Standards and Interpretations have been published that are notmandatory for 31 December 2018 reporting periods and have not been early adopted by MOWOS.

Standards Effective date Description

IFRS 16 1 January 2019 LeasesIFRIC Interpretation 23 1 January 2019 Uncertainty over Income Tax TreatmentsAmendments to IAS 28 1 January 2019 Long-term interest in Associates and Joint Ventures

Other than IFRS 16, there are no other standards that are not yet effective and that would have animpact on the entity in the current or future reporting periods. Adoption of IFRS 16 will not have amaterial impact as the recharge of costs to MOWOS relating to leases held by the operator are notwithin the scope of IFRS 16.

Segmental reporting

IFRS 8 requires operating segments to be identified on the basis of internal reports that areregularly reviewed by the chief operating decision maker, which in the case of MOWOS isconsidered to be management of Marathon Oil Corporation, which is located in Houston, Texas.Management consider and review operating segments by reference to geographic location.

Revenue and other income

Revenue from sales of oil, natural gas, and other products is recognised at the transaction pricewhich MOWOS is entitled to, after deducting sales taxes, excise duties and similar levies. Forcontracts that contain separate performance obligations the transaction price is allocated to thoseseparate performance obligations by reference to their relative standalone selling prices.

Revenue is recognised when MOWOS has transferred the significant control of ownership of theproducts to the customer which is when the title passes to the customer. Revenue associated withsales of crude oil and petroleum products including natural gas is recorded when title passes tothe customer. Revenue from production of natural gas and oil in which MOWOS has interest withother joint venture parties is recognised based on MOWOS’s working interest and the terms of therelevant petroleum production licences. In all cases, this is deemed to be on a lifting basis. All otherrevenue is recognised when title passes to the customers.

Financing income and costs

Financing costs comprise interest payable, finance charges on shares classified as liabilitiesand finance leases, unwinding of the discount on decommissioning provisions, and net foreignexchange losses that are recognised in the statement of comprehensive income (see foreigncurrency accounting policy). Financing income comprises interest receivable on funds invested,dividend income, and net foreign exchange gains.

Interest income and interest payable are recognised in profit or loss as they accrue, using theeffective interest method. Dividend income is recognised in the statement of comprehensiveincome on the date the entity’s right to receive payments is established.

Leases

Rentals under operating leases are charged to the statement of comprehensive income on astraight-line basis over the lease term.

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Foreign currencies

Items included in the financial statements of MOWOS are measured using the currency of theprimary economic environment in which the entity operates (the “functional currency”).Transactions in foreign currencies are translated to the entity’s functional currency at the foreignexchange rates at the date of the transactions. Foreign exchange gains and losses resulting fromthe settlement of monetary assets and liabilities denominated in foreign currencies are recognisedin the income statement, except when deferred in other comprehensive income as qualifying cashflow hedges and qualifying net investment hedges. MOWOS has a functional currency of USD.The presentation currency for the financial statements is USD.

Taxation

Tax on the profit/(loss) for the year comprises current and deferred tax. Tax is recognised in thestatement of comprehensive income except to the extent that it relates to items recognised directlyin equity, in which case it is recognised in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enactedor substantively enacted at the statement of financial position date, and any adjustment to taxpayable in respect of previous years.

Deferred tax is provided on temporary differences between the carrying amounts of assets andliabilities for financial reporting purposes and the amounts used for taxation purposes. Thefollowing temporary differences are not provided for: the initial recognition of assets or liabilitiesthat affect neither accounting nor taxable profit other than in a business combination, anddifferences relating to investments in subsidiaries to the extent that they will probably not reversein the foreseeable future. The amount of deferred tax provided is based on the expected mannerof realisation or settlement of the carrying amount of assets and liabilities, using tax rates enactedor substantively enacted at the statement of financial position date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profitswill be available against which the temporary difference can be utilised.

Exploration, evaluation and producing assets

Pre-licence acquisition costs are recognised in the statement of comprehensive income whenincurred. Costs incurred after licences have been obtained, such as geological and geophysicalsurveys, drilling and commercial appraisal costs are capitalised as Exploration and Evaluation(“E&E”) assets as tangible or intangible depending on the nature of the asset. E&E assets withinintangible assets are not amortised.

MOWOS applies the successful efforts method of accounting for exploration expenditure. E&Eassets shall no longer be classified as such when the technical feasibility and commercial viabilityof extracting oil and gas resources are demonstrable.

Once the technical feasibility and commercial viability has been demonstrated, then the carryingvalue of the E&E assets is reclassified as a Development and Production (“D&P”) asset andclassified as ‘oil and gas’ assets within property, plant and equipment. The E&E assets shall beassessed annually for impairment using indicators in accordance with IFRS 6 ‘Exploration for andEvaluation of Mineral Resources’. If technically feasible or commercially viable reserves are notdiscovered, the impairment is recognised on E&E assets in the statement of comprehensiveincome.

The assets transferred to D&P assets are depreciated once the asset commences production.D&P assets are depreciated using the unit of production method based on the proved andprobable reserves of those fields. Changes in these estimates are dealt with prospectively.

General and administration costs are expensed as incurred.

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Depletion and Amortisation on producing oil and gas assets

All expenditure carried within each O&G asset is amortised from the commencement of productionon a unit of production basis, which is the ratio of oil and gas production in the year to the estimatedquantities of commercial reserves at the end of the year plus the production in the year, generallyon a field-by-field basis. Costs used in the unit of production calculation comprise the net bookvalue of capitalised costs plus the estimated future field development costs, audited in the annualreserves report by ERC Equipoise. Changes in the estimates of commercial reserves or future fielddevelopment costs are dealt with prospectively.

Impairments of producing and development assets

The carrying amounts of MOWOS’s assets are reviewed at each statement of financial positiondate to determine whether there is any indication of impairment; an asset is considered to beimpaired if objective evidence indicates that one or more events have had a negative effect on theestimated future cash flows of that asset. If any such indication exists, the asset’s recoverableamount is estimated. An impairment loss is recognised whenever the carrying amounts of an assetor its cash generating unit exceed its recoverable amount. Impairment losses are recognised in thestatement of comprehensive income. The recoverable amount of assets is determined by thehigher of fair value less cost to dispose and value in use. Fair value less cost to dispose isdetermined as the amount of estimated risk adjusted and discounted future cash flows. For thispurpose, assets are grouped into cash generating units (“CGUs”) based on separately identifiableand largely independent cash inflows. Estimates of future cash flows used in the evaluation ofimpairment of assets are made using management forecasts including assumptions for commodityprices, market supply and demand, and in the case of oil and gas properties, expected productionvolumes. The latter takes into account assessments of field and reservoir performance andincludes expectations about proved and probable volumes, which are risk-weighted utilisinggeological, production, recovery and economic projections. Cash flow estimates are risk adjustedto reflect market conditions as appropriate and discounted at a rate that reflects a market returnand the risks of the cash generating units.

Crude oil under and over lift

Crude oil under/over lift is classified under debtors or creditors as appropriate and valued at theyear-end oil price. Liabilities arising from lifting more than MOWOS’s share of the joint venture’spetroleum production (over lifting) are valued at the market price and booked under ‘Currentliabilities’. Under lifting is valued at the market price and booked under ‘Current assets’.

Restricted Stock Awards (“RSAs”)

Restricted stock award programme

Under this arrangement certain MOWOS employees were awarded grants based on theirperformance within certain guidelines and for retention purposes. Each of these grants vest in one-third increments, contingent on the recipient’s continued employment. There are no performanceaccelerators for early vesting of these awards. Awards under the RSA are classified as an equityaward and recorded at the grant date fair value and the compensation expense is recognised overthe expected life of the award. A charge is recorded to the statement of comprehensive income asan employee benefit expense, within wages and salaries, for the fair value at grant date of theshare awards expected to vest, accrued over the vesting period. The corresponding credit is aMarathon Oil Corporation group recharge in respect of the share based payment expense.

Inventory

Inventories are stated at the lower of cost and net realisable value. The net realisable value ofcrude oil is based on the estimated selling price in the ordinary course of business which is spotprice on the date of statement of financial position.

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Cash and cash equivalents comprise cash in hand and bank balances. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash, which aresubject to an insignificant risk of changes in value and have a maturity of three months or less.

Share capital

Ordinary shares are classified as equity. MOWOS’s share capital currently consists of ordinaryshares. Any transaction costs associated with the issuing of shares are deducted from equity tothe extent they are incremental costs directly attributable to the equity transaction.

Dividends

Dividends and other distributions to MOWOS’s shareholder are recognised as a liability in thefinancial statements in the year in which the dividends and other distributions are approved byMOWOS’s shareholder. These amounts are recognised in the statement of changes in equity.Interim dividends are recognised when paid.

Non-derivative financial instruments

Financial assets (from 1 January 2018)



All equity instruments and other debt instruments are recognised at fair value. For equityinstruments, on initial recognition, an irrevocable election (on an instrument-by-instrument basis)can be made to designate these as at fair value through other comprehensive income instead offair value through profit and loss. Dividends received on equity instruments are recognised asother income in profit or loss when the right of payment has been established, except whenMOWOS benefits from such proceeds as a recovery of part of the cost of the financial asset, inwhich case, such gains are recorded in other comprehensive income.


Financial assets


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All equity instruments and other debt instruments are recognised at fair value. For equityinstruments, on initial recognition, an irrevocable election (on an instrument-by-instrument basis)can be made to designate these as at fair value through other comprehensive income instead offair value through profit and loss.


MOWOS’s financial assets include cash and trade and other receivables.

Trade and other receivables

Trade and other receivables that are created by MOWOS by way of providing goods directly to adebtor are carried at the original invoice amount. Trade and other receivables are recognisedinitially at fair value less any expected credit losses.

MOWOS has reviewed its trade receivables at the balance sheet date and considers that the creditrisk is not material as all amounts are due within 30 days.

Financial liabilities

Financial liabilities are measured at amortised cost. Debt and trade payables are recognisedinitially at fair value based on amounts exchanged, net of transaction costs, and subsequently atamortised cost. Interest expense on debt is accounted for using the effective interest method andis recognised in income.

MOWOS determines the classification of its financial liabilities at initial recognition.

MOWOS’s financial liabilities include trade and other payables and loans and borrowings.

The subsequent measurement of financial liabilities depends on their classification. Tradepayables that are created by MOWOS are carried at the original invoice amount.

MOWOS determines the classification of its financial liabilities at initial recognition.

MOWOS’s financial liabilities include trade and other payables and loans and borrowings.

The subsequent measurement of financial liabilities depends on their classification. Tradepayables that are created by MOWOS are carried at the original invoice amount.

Trade and other payables

Trade and other payables are recognised at fair value and subsequently measured at amortisedcost.

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Loans and borrowings

Loans and borrowings are recognised initially at fair value plus any directly attributable transactioncosts. Subsequent to initial recognition, these financial liabilities are measured at amortised costusing the effective interest rate method.

Provisions

Provisions are recognised when MOWOS has present obligation (legal and constructive) as aresult of a past event, it is probable that MOWOS will be required to settle that obligation and areliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settlethe present obligation at the statement of financial position date, taking into account the risks anduncertainties surrounding the obligation. Where a provision is measured using the cash flowsestimated to settle the present obligation, its carrying values amount is the present value of thosecash flows.

Specific provisions recognition policies are listed below:

Decommissioning and restoration provision

Provisions (referred to as “Asset Retirement Obligations” or “ARO”) are recognised for the futuredecommissioning and restoration of hydrocarbon production facilities and pipelines at the end oftheir economic lives. The estimated cost is recognised initially as part of property, plant &equipment and depreciated over the life of the proved and probable reserves on a unit-of-production basis. Any changes in the estimates of costs to be incurred on proved and probablereserves or in the rate of production will therefore impact net income, over the remaining economiclife of the oil and gas assets.

Estimates of the amounts of provisions recognised are based on current legal and constructiverequirements, technology and price levels. Because actual outflows can differ from estimates dueto changes in laws, regulations, public expectations, technology, prices and conditions, and cantake place many years in the future, the carrying amounts of provisions are regularly reviewed andadjusted to take account of such changes.

All decommissioning and restoration provisions are denominated in GBP or EUR which arerevalued to USD based on the latest spot rates on an annual basis. Any resulting forex exchangemovements are recognised within the related property, plant and equipment decommissioningasset balance, unless the decommissioning assets have previously been impaired and forexexchange movements would therefore be recognised in the statement of comprehensive income.

Significant accounting judgements and key sources of estimation uncertainty

In the application of MOWOS’s accounting policies, the Directors are required to makejudgements, estimates and assumptions about the carrying amounts of assets and liabilities thatare not readily apparent from other sources.

The estimates and associated assumptions are based on historical experience and other factorsthat are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an annual basis. Revisions toaccounting estimates are recognised in the year in which the estimate is. The following are thecritical judgements and estimates that the Directors have made in the process of applyingMOWOS’s accounting policies and that have the most effect on the amounts recognised in thefinancial statements.

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Impairment review of carrying value of assets

MOWOS has significant investments in plant, property and equipment. Long-lived assets in useare assessed for impairment whenever changes in facts and circumstances indicate that thecarrying value of the assets may not be recoverable. Changes in the circumstances orexpectations of future performance of an assets may be an indicator that the asset is impaired,requiring the asset to be written down to its recoverable amount. Evaluating whether an asset isimpaired requires a high degree of judgement and may to a large extent depend on often volatileeconomic factors such as future market prices, proved and probable volumes of reserves,currency exchange rates, future output, discount rates and political risk among others. There wasno indication of impairment in each of the years presented.

Decommissioning liability

MOWOS has legal, regulatory and contractual obligations to remove and dismantle long-livedassets and to restore land or seabed at the end of oil and gas production operations at the end oftheir economic life, with most of these activities expected to take place many years in the future.Estimates of retirement cost are developed based on numerous factors, such as the scope of thedismantlement, timing of settlement, interpretation of legal, regulatory and contractualrequirements, type of production and processing structures, depth of water, reservoircharacteristics, market demand for equipment and consultations with construction and engineeringprofessionals.

It is reasonably possible on the basis of existing knowledge that outcomes within the next financialyear that are different from the assumptions made could require a material adjustment to thecarrying amount.

Recoverability of deferred tax assets

Deferred tax assets are recognised to the extent that it is probable that they will be recoveredagainst the reversal of deferred tax liabilities or other future taxable profits. In the case of balancesrelated to decommissioning, the probability of recovery is assessed in light of the enacted losscarry-back rules and MOWOS’s tax history. Deferred tax assets are reviewed at each reportingdate and are reduced to the extent that it is no longer probable that the related tax benefit will berealised.

Presumption of going concern

The Directors have a reasonable expectation that MOWOS has adequate resources to continue inoperational existence for the foreseeable future and, accordingly, have adopted the going concernbasis in preparing the HFI.

2. Adoption of IFRS and changes in accounting policies

MOWOS has previously prepared and reported statutory financial statements, in accordance withapplicable standards in the United Kingdom (Financial Reporting Standard 102). Consequently,the opening statement of financial position at 1 January 2016 has been included in the HFItogether with IFRS 1 reconciliations between financial information prepared under FinancialReporting Standard 102 and financial information prepared in accordance with IFRS, as requiredby IFRS 1 on transition to IFRS.

Exemptions applied

IFRS 1 First-Time Adoption of International Financial Reporting Standards allows first-timeadopters certain exemptions from the retrospective application of certain IFRS.

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Estimates

The estimates used as at 31 December 2016, 31 December 2017 and 31 December 2018 areconsistent with those made for the same dates in accordance with Financial Reporting Standard102 (after adjustments to reflect any differences in accounting policies).

Change in accounting policies

In order to align with the policies of RockRose, MOWOS has now calculated its crude oilunder/over lift asset or liability at market price instead of at the lower of cost or net realisable value.

Management have reviewed the impact of this change in accounting policy and have made thefollowing adjustments to the HFI:

Consolidated statement of comprehensive income



2018 2017 2016

US$000 US$000 US$000

(Increase)/decrease to cost of sales (8,851) 4,169 3,939Decrease/(increase) to income tax charge 3,540 (1,667) (1,576) –––––––– –––––––– ––––––––Increase/(decrease) to total comprehensive incomefor the year (5,311) 2,502 2,363 –––––––– –––––––– ––––––––Consolidated statement of financial position(Decrease)/increase to property, plant andequipment (69) 1,588 1,658Increase to trade and other receivables – 4,072 2,588 –––––––– –––––––– ––––––––(Decrease)/increase to total assets (69) 5,660 4,246 –––––––– –––––––– ––––––––Increase to trade and other payables 367 – –(Decrease)/increase to tax payable (144) 641 1,729Decrease to accumulated losses at start of the year 5,019 2,517 154Increase/(decrease) to total comprehensive incomefor the year (5,311) 2,502 2,363 –––––––– –––––––– ––––––––(Decrease)/increase to total equity and liabilities (69) 5,660 4,246 –––––––– –––––––– ––––––––

3. Operating segments

MOWOS’s activity consists of one class of business relating to the acquisition, exploration,development and production of oil and gas reserves and related activities in a single geographicalarea presently being the UK North Sea. This is considered to be the only reportable segment ofMOWOS. All revenues, expenses, corporate activities and non-current assets are attributable tothe UK North Sea and can be assigned to this reportable segment, accordingly no additionalsegment analysis is disclosed.

4. Revenue

MOWOS derives revenue from the transfer of goods to external customers which is recognised ata point in time. MOWOS’s product lines are:



2018 2017 2016

US$000 US$000 US$000

Crude oil 173,221 88,236 117,706Gas 2,811 5,745 8,329 –––––––– –––––––– ––––––––Total revenues 176,032 93,981 126,035 –––––––– –––––––– ––––––––

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Analysis of turnover by country of destination:

2018 2017 2016

US$000 US$000 US$000

United Kingdom 2,811 34,131 79,602Rest of Europe 173,221 59,850 46,433 –––––––– –––––––– ––––––––Total revenues 176,032 93,981 126,035 –––––––– –––––––– ––––––––

5. Operating profit

Included in the statement of comprehensive income are the following:



2018 2017 2016

US$000 US$000 US$000

Operating profit is stated after charging/(crediting):Directors’ remuneration 274 96 70Depreciation charge for oil and gas assets 20,356 20,184 33,658Contractor costs 81,058 47,957 52,271Inventory recognised as an expense 317 3,389 3,361Foreign exchange movement (991) (232) (3,343)Fees payable to MOWOS’s auditors:

Audit related assurance services 85 88 92 –––––––– –––––––– ––––––––

6. Directors and employees

MOWOS had no employees in 2018, 2017 or 2016. Directors are employed by other Marathongroup companies. Administrative and technical services to support MOWOS’s operations are alsoprovided by another Marathon group company.

No directors exercised share options during 2018, 2017 or 2016.

Directors who received shares under a long-term incentive plan were four, three and three during2018, 2017 and 2016.

The highest paid Director’s remuneration amounts to US$263,000, US$48,000 and US$48,000during 2018, 2017 and 2016 and awards granted to the directors.

7. Finance income



2018 2017 2016

US$000 US$000 US$000

Interest income – loans 4,274 2,040 799 –––––––– –––––––– ––––––––Total finance income 4,274 2,040 799 –––––––– –––––––– ––––––––

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8. Finance costs



2018 2017 2016

US$000 US$000 US$000

Finance charge on provisions 2,440 1,438 1,436Other interest payable 4 – 3 –––––––– –––––––– ––––––––Total finance costs 2,444 1,438 1,439 –––––––– –––––––– ––––––––

9. Income tax charge

Total tax charge of US$29.6 million, US$8.4 million and US$25.3 million in 2018, 2017 and 2016respectively has been recognised in the statement of comprehensive income during the year.



2018 2017 2016

US$000 US$000 US$000

Current tax:

Current tax charge 27,613 12,992 19,941Supplementary tax charge 10,256 3,578 6,014 –––––––– –––––––– ––––––––Total current tax charge 37,869 16,570 25,955 –––––––– –––––––– ––––––––Deferred tax:

Relating to the origination and reversal of temporarydifferences (8,259) (8,168) (15,888)Relating to the movement due to the tax rate changes – – 15,212 –––––––– –––––––– ––––––––Total deferred tax credit (8,259) (8,168) (676) –––––––– –––––––– ––––––––Total tax charge 29,610 8,402 25,279 –––––––– –––––––– ––––––––

A reconciliation between tax income and the product of accounting profit multiplied by thecombined UK ring fence corporation tax and supplementary charge rate of 40%, 40% and 40% in2018, 2017 and 2016 respectively and non-ring fence tax rate of 19%, 20% and 20% in 2018, 2017and 2016 respectively is as follows:



2018 2017 2016

US$000 US$000 US$000

Accounting profit before income tax 74,450 20,087 36,319A combined UK ring fence corporation tax andsupplementary charge rate of 40% in 2018,2017 and 2016 and non-ring fence tax rate of 19%,20% and 20% in 2018, 2017 and 2016 respectively 29,780 8,034 14,528Impact of supplementary charge tax rate change – – 12,915Expenses not deductible for tax purposes (191) 370 (2,071)Small field and investment allowances 21 (2) (93) –––––––– –––––––– ––––––––Total tax charge 29,610 8,402 25,279 –––––––– –––––––– ––––––––

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10. Earnings per share

Basic earnings per share amounts are calculated by dividing the profit for the year by the weightedaverage number of shares outstanding during the year. The basic and diluted earnings per shareare the same as there are no instruments that have a dilutive effect on earnings. There have beenno transactions involving ordinary shares or potential ordinary shares between the reporting dateand the date of authorisation of these financial statements other than those detailed in note 25.



2018 2017 2016

Earnings attributable to the shareholders (in US$000) 44,840 11,685 11,040Weighted average basic number of shares 25,000 25,025,000 25,025,000Weighted average diluted number of shares 25,000 25,025,000 25,025,000 –––––––––– –––––––––– ––––––––––Unadjusted basic earnings per share (in cents) 179,360 47 44Unadjusted diluted earnings per share (in cents) 179,360 47 44

11. Property, plant and equipment

Oil and gas assets

US$000

CostAt 1 January 2016 1,072,398Additions 1,430ARO revisions (51,586) –––––––––At 31 December 2016 1,022,242Additions 30ARO Revisions 11,285 –––––––––At 31 December 2017 1,033,557Additions –ARO revisions (36,272)Disposals (342) –––––––––At 31 December 2018 996,943Accumulated depreciation and impairmentAt 1 January 2016 877,204Depreciation charge 33,658 –––––––––At 31 December 2016 910,862Depreciation charge 20,184 –––––––––At 31 December 2017 931,046Depreciation charge 20,356 –––––––––At 31 December 2018 951,402 –––––––––Net book valueAt 31 December 2018 45,541 –––––––––At 31 December 2017 102,511 –––––––––At 31 December 2016 111,380 –––––––––

The oil and gas assets consist of producing and development assets and decommissioning assetsin accordance with IAS 16 ‘Property, Plant and Equipment’.

In assessing whether any impairment is required to the carrying value of assets, their carryingvalue is compared with their recoverable amount. The CGU assessed for impairment is generallythe field, or group of fields where these are economically dependent. The recoverable amount is

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the higher of the asset’s fair value less costs to dispose or value in use. See note 1 for furtherdetails of the accounting policy on impairment. No indicators of impairment were identified for theMOWOS’s oil & gas assets in each of the years present.

12. Deferred tax assets and liabilities



2018 2017 2016

US$000 US$000 US$000

Accelerated capital allowances – Corporation Tax (18,515) (40,329) (43,385)Decommissioning provision 100,192 113,748 108,636Tax losses – – – –––––––– –––––––– ––––––––Net deferred tax asset 81,677 73,419 65,251 –––––––– –––––––– ––––––––Deferred tax asset 100,192 113,748 108,636Deferred tax liability (18,515) (40,329) (43,385) –––––––– –––––––– ––––––––Net deferred tax asset 81,677 73,419 65,251 –––––––– –––––––– ––––––––

Deferred tax assets have been recognised in respect of tax losses and other temporary differenceswhere the Directors believe it is probable that these assets will be recovered in the near future.

13. Inventory



2018 2017 2016

US$000 US$000 US$000

Raw materials and consumables 56 458 4,051 –––––––– –––––––– ––––––––Total inventory 56 458 4,051 –––––––– –––––––– ––––––––

The carrying value of MOWOS’s inventories as stated above is based on the net realisable valuein accordance with the accounting policies.

14. Trade and other receivables



2018 2017 2016

US$000 US$000 US$000

Trade receivables 35 932 3,242Under lift asset – 13,019 4,825Prepayments and accrued income – – 996 –––––––– –––––––– ––––––––Total current trade and other receivables 35 13,951 9,063 –––––––– –––––––– ––––––––Amount owed from other Marathon groupundertakings 156,545 143,989 153,692 –––––––– –––––––– ––––––––

All trade and other receivables are due within one year from the statement of financial positiondate.

The carrying value of MOWOS’s trade and other receivables as stated above is considered to bea reasonable approximation of the fair value. None of the above trade receivables were consideredpast due or impaired as of 31 December 2018, 31 December 2017 or 31 December 2016.

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Included in amounts owed by group undertakings at 31 December is US$156,056,176,US$143,756,266, and US$153,582,030 for 2018, 2017 and 2016 which has been loaned toMarathon Oil Investment LLC. The loan is interest-bearing (one-month LIBOR + 0.1%) and isrepayable to MOWOS on demand. The remainder of amounts owed from other Marathon groupentities are unsecured, interest free and repayable on demand.

The nature of MOWOS’s external and internal intercompany receivables, being a mix of due within30 days and repayable on demand, means that the credit loss exposure is negligible, and as suchno provision for expected credit losses have been made.

15. Cash and cash equivalents



2018 2017 2016

US$000 US$’000 US$000

Available cash at bank and in hand 1,730 9,194 7,680 –––––––– –––––––– ––––––––

The fair values of cash and cash equivalents are the same as the above book values.

16. Trade and other payables



2018 2017 2016

US$000 US$000 US$000

Trade payables 6,817 5,918 7,107Over lift liability 860 – –Accruals 1,999 3,740 3,287 –––––––– –––––––– ––––––––Tax payable 16,744 641 7,058 –––––––– –––––––– ––––––––Total current trade and other payables 26,420 10,299 17,452 –––––––– –––––––– ––––––––Amounts owed to other Marathon group undertakings 331 398 248 –––––––– –––––––– ––––––––All current trade and other payables are due within one year from the statement of financialposition date including non-interest bearing intercompany balances. The carrying value of thetrade and other payables as stated above is considered to be a reasonable approximation of thefair value. All trade and other payables are settled within three months of invoice date.

17. Provisions for liabilities and other charges

Decommissioning

provision

$’000

At 1 January 2016 321,739Changes in estimates (51,585)Finance charge 1,436 ––––––––At 31 December 2016 271,590 ––––––––Changes in estimates 11,285Finance charge 1,438 ––––––––At 31 December 2017 284,313 ––––––––Changes in estimates (36,272)Finance charge 2,440 ––––––––At 31 December 2018 250,481 ––––––––

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The estimated cost of decommissioning at the end of the producing lives of the fields is reviewedannually and engineering estimates and reports are updated periodically. Provision is made for theestimated cost of decommissioning at the statement of financial position date for MOWOS’s shareof the overall costs. Cost estimates have been discounted at an average discount rate of 1.31%,0.51% and 0.53% (Foinaven Complex) and 1.42%, 0.53% and 0.69% (Pipeline) in 2018, 2017 and2016. These costs are expected to be incurred between 2025 and 2032.

The timing of spend is based on the economic cut off point for the producing assets. Provisionsacquired in business combinations have been calculated based on the latest operator costestimates. The payment dates are uncertain and are currently anticipated to be between 2025 and2032 for the relevant producing fields. It is anticipated that MOWOS will obtain full tax relief on itsdecommissioning liabilities in the UK.

The other provision in MOWOS’s balance sheet relates to a dilapidation provision for officepremises. The unwind for this provision is immaterial

18. Share capital

Shares Share capital Total

Allotted Number US$000 US$000

Issued at 31 December 2016 and 2017 25,025,000 25,025 25,025Capital reduction (25,000,000) (25,000) (25,000) –––––––––– –––––––––– ––––––––––At 31 December 2018 25,000 25 25 –––––––––– –––––––––– ––––––––––

In November 2018, MOWOS reduced its share capital by US$25,000,000 to US$25,000 inaccordance with the solvency statement procedure for private limited companies set out insections 641 to 644 of the Companies Act 2006.

Shares Share capital Total

Authorised Number US$000 US$000

At 31 December 2016, 2017 and 2018 1,000,000,000 1,000,000 1,000,000 –––––––––––– –––––––– ––––––––

There is a single class of ordinary shares. There are no restrictions on the distribution of dividendsand the repayment of capital.

19. Reserves

Other reserves

Other reserves were originally created following a capital reduction on 30 November 2000. The netof the other and the accumulated loss reserves are distributable reserves and are consideredtogether for the purposes of dividend distribution.

During 2018, there was an increase in distributable reserves of $25,000,000 as a result of a capitalreduction by MOWOS.

20. Restricted Stock Awards

Restricted stock – The MOC 2016 Incentive Compensation Plan, which was approved by ourstockholders in May 2017 and authorizes the Compensation Committee of the Board of Directorsto grant restricted stock awards to employees. Restricted stock awards are granted to certain non-officer employees based on their performance within certain guidelines and for retention purposes.The restricted stock awards to non-officers generally vest ratably over a three-year period,contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipientshave the right to vote on such stock and receive dividends thereon. The non-vested shares ofrestricted stock are not transferable and are held by MOC’s transfer agent.

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Total stock-based compensation expense – Total employee stock-based compensation expensewas US$0.96 million, US$0.41 million and US$0.43 million in 2018, 2017 and 2016 respectively.

Restricted stock awards – The following is a summary of restricted stock award activity:

Weighted

average grant

Awards date fair value

Unvested at 1 January 2016 21,084 $31.81Granted 35,946 $7.96Vested and exercised (8,892) $32.26Cancelled – $0.00 ––––––––Unvested at 31 December 2016 48,138 $13.92Granted 29,994 $14.28Vested and exercised (15,497) $13.69Cancelled (25,224) $14.50 ––––––––Unvested at 31 December 2017 37,411 $13.91Granted 69,101 $14.53Vested and exercised (14,426) $14.62Cancelled – $0.00 ––––––––Unvested at 31 December 2018 92,086 $14.26

The vesting date fair value of restricted stock awards which vested during 2018, 2017 and 2016respectively was US$0.28 million, US$0.25 million and US$0.11 million. The weighted averagegrant date fair value of restricted stock awards was US$14.26, US$13.91 and US$13.92 forawards unvested at 31 December, 2018, 2017 and 2016 respectively.

The total amount of unrecognized compensation cost related to restricted stock awards which isexpected to be recognized over a weighted average period of one year was US$0.96 million,US$0.41 million and US$0.43 million at 31 December, 2018, 31 December 2017 and 31 December2016 respectively.

21. Financial instruments

MOWOS’s financial instruments comprise trade and other receivables, trade and other payables,and cash and cash equivalents.

Financial risk factors and capital risk management

The fair values of the MOWOS’s financial instruments are materially the same as their carryingamounts.

MOWOS’s financial instruments expose it to a variety of financial risks: market risk, credit risk,interest risk and liquidity risk.

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(a) Market risk

Commodity price risk

MOWOS held no financial instruments as at 31 December 2018, 31 December 2017 and 31December 2016 that are affected by commodity price, but the MOWOS is nonethelessexposed to movements in oil and gas prices.

The table below illustrates the impact on profit before tax of changes of commodity prices.The impact on equity is the same.



2018 2017 2016

Crude oil sales during the year (US$000s) 173,221 88,236 117,716Gas sales during the year (US$000s) 2,811 5,745 8,329Average crude oil price (US$) per bbl 75.91 54.49 42.65Average gas price (US$) per boe 46.32 53.19 29.34Impact of decrease of crude oil prices byUS$1 (US$000s) 2,282 1,619 2,760Impact of decrease of crude oil prices by10% (US$000s) 17,322 8,824 11,772Impact of decrease of gas prices byUS$1 (US$000s) 61 108 284Impact of decrease of gas prices by 10%(US$000s) 281 575 833

Foreign exchange risk

MOWOS is exposed to foreign exchange risk arising from currency exposures, primarily withrespect to GBP. Foreign exchange risk arises when future commercial transactions orrecognised assets or liabilities are denominated in a currency that is not the entity’sfunctional currency.

The following foreign exchange rates were applied:



2018 2017 2016

US$000 US$000 US$000

As at 31 December (US$ to GBP) 1.27 1.35 1.23Average for the year (US$ to GBP) 1.34 1.29 1.36

As at 31 December 2018, 31 December 2017 and 31 December 2016 various statements offinancial position line items were denominated in foreign currencies and the impact due toforeign exchange movement of an increase or decrease in exchange rate is shown below.

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MOWOS’s exposure to foreign currency risk was as follows based, on the following nominalamounts:

2018 2017 2016

£000 US$000 £000 US$000 £000 US$000

Cash at bank 1,323 45 4,754 2,770 5,854 456Working capitalaccruals – 1,831 – 5,097 – 4,644Trade receivables 28 12 692 6,222 1,341 3,843Trade payables 6,563 (1,206) 5,125 (688) 6,879 (1,151) –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––

(b) Credit risk

Credit risk arises from cash and cash equivalents, as well as credit exposures on trade andother receivables. The credit risk of MOWOS’s trade and other receivables is assessedthrough the credit ratings of relevant customers. The balances at year end are minimal andtherefore MOWOS is not exposed to a high level of credit risk.

MOWOS only trades with recognised creditworthy third parties. The exposure risk arisesfrom default of the counter party, with a maximum exposure equal to the carrying amount asat the statement of financial position date. The maximum exposure to credit risk wasUS$35,000, US$932,000 and US$3,242,000 as at 31 December 2018, 31 December 2017and 31 December 2016 respectively.

(c) Interest rate risk

Liquidity risk is the risk that MOWOS will not be able to meet its financial obligations as theyfall due.

Management monitors MOWOS’s liquidity reserve (comprising cash and cash equivalents)through comparison to expected cash flow and budgets.

The following are the contractual maturities of financial liabilities including estimated interestpayments for loans from other Marathon group undertakings:

2018 2017 2016

1 year 1 year 2 year 1 year 1 year 2 year 1 year 1 year 2 year

Total or less <2years <5years Total or less <2years <5years Total or less <2years <5years

US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000 US$000

Non-derivative

financial

liabilities

Trade and other

payables 25,894 25,894 – – 10,697 10,697 – – 17,700 17,700 – –

Over lift liability 860 860 – – – – – – – – – ––––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––

Total financial

liabilities 26,754 26,754 – – 10,697 10,697 – – 17,700 17,700 – ––––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– –––––––– ––––––––

Capital risk management

MOWOS’s objectives when managing capital are to safeguard MOWOS’s ability to continueas a going concern in order to provide returns for shareholders as described in the StrategicReport.

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22. Commitments and contingent liabilities

Operating lease commitments



2018 2017 2016

US$000 US$000 US$000

Other leases:Payments under operating leases due withinone-year 22,410 18,290 18,290Payments under operating leases due betweentwo to five-years 10,409 8,547 8,547 –––––––– –––––––– ––––––––Total operating lease commitments 32,819 26,837 26,837 –––––––– –––––––– ––––––––

Lease payments of US$18,290,000, US$18,290,000 and US$18,290,000, in 2018, 2017 and 2016respectively, were recognised in the statement of comprehensive income.

Contingent liabilities/assets

No contingent liabilities and assets existed as at 31 December 2018, 31 December 2017 and31 December 2016 respectively.

Petrojarl Foinaven FPSO

On 6 December 2018, Golar-Nor (UK) Limited (“Golar”) issued proceedings in the CommercialCourt against all the joint venture partners in Foinaven (including MOWOS (now RockRoseUKCS10)) in connection with the FPSO contract dated 17 November 1994, as amended. Theclaim alleges that a solids management issue affected the FPSO gas compression system,resulting in shutdowns and a requirement for the replacement of certain parts, and causing a lossof revenue and maintenance costs for the replacement of parts. MOWOS’s exposure for the claimis quantified at £78.3 million (plus interest), together with declaratory relief in relation to revenueshortfall and maintenance costs for the period 6 December 2012 to 31 December 2013 and inrelation to any future losses or damages relating to the same issue (plus interest).

The risk to MOWOS will be proportional to its 28% working interest. The Foinaven joint venturepartners instructed a Queen’s Counsel to advise on the claim as they considered it to be spuriousdue to the exclusion of consequential loss in certain contractual arrangements. A defence was filedon 13 February 2019. The Foinaven joint venture partners have requested further particulars of theclaim and reserved their right to plead further to the claim as properly particularised (including theright to submit further defences or a counterclaim). The parties agreed to a stay of proceedingsuntil end of September 2019, with a case management conference to be scheduled no sooner than25 November 2019. On the basis of the aforementioned spurious nature of the claim, it ismanagement’s view that no liability, contingent or otherwise, should be recognised as at the31 December 2018.

181


23. Related parties

(a) Controlled parties

MOWOS is controlled by the following entities:

Principal place Ownership interest

Name Type of business 2018 2017 2016

Parent 100% 100% 100%

Ultimate parent 100% 100% 100%

(b) Key management personnel compensation

Key management personnel compensation is set out in the following table.



2018 2017 2016

US$000 US$000 US$’000

Salary/fees 162 91 65Taxable benefits 1 1 1Bonus 75 36 43Payments in Lieu of Pension – – – –––––––– –––––––– ––––––––Total 238 128 109 –––––––– –––––––– ––––––––

The above amounts have been calculated by translating the GBP amounts to USD at theaverage rate for the year of US$1.34, US$1.29 and US$1.36 in 2018, 2017 and 2016.

(c) Directors

The Directors’ emoluments are disclosed in note 6.

(d) Transactions with other related parties

The following transactions occurred with related parties:



2018 2017 2016

US$000 US$000 US$000

Recharge of services from MOCundertakings 229 230 131Management service charge from parent 670 674 842Interest received from MOC undertakings 4,274 2,040 799

MarathonInternational OilHoldings LLC


Marathon OilCorporation


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24. Adjusted EBITDA

Presented is the Earnings Before Interest, Tax, Depreciation and Amortisation (referred to asEBITDA).



2018 2017 2016


Profit before income tax less: 74,450 20,087 36,319Finance costs 8 2,444 1,438 1,439Finance income 7 (4,274) (2,040) (799)Depreciation charge 11 20,356 20,184 33,658 –––––––– –––––––– ––––––––Adjusted EBITDA 92,976 39,669 70,617 –––––––– –––––––– ––––––––

EBITDA is considered a useful proxy for cash flow.

25. Events after the reporting date

On the 25 February 2019, RockRose entered into a sale and purchase agreement with MIOH toacquire the entire share capital in MOWOS. The transaction has an effective date of 1 January2019 and is expected to complete, subject to certain contractual requirements, in the second halfof 2019 (which is the IFRS 3 effective date).

As part of the sale and purchase agreement, MIOH agreed to repay all intercompany balancesreceivable by MOWOS on the completion date.

There were no adjustments recorded in the 2018 HFI in respect of these events as they occurredafter the reporting date.

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PART XIV

OPERATING AND FINANCIAL REVIEW OF THE GROUP (INCLUDING

LIQUIDITY AND CAPITAL RESOURCES AND CAPITALISATION AND

INDEBTEDNESS FOR THE ENLARGED GROUP)

The following operating and financial review contains financial information that has been extracted

or derived without material adjustment from the Group’s financial information for the financial years

ended 31 December 2018, 31 December 2017 and the 18 month period ended 31 December 2016,

which are incorporated by reference in Part XXII – Documents incorporated by reference of this

document prepared in accordance with IFRS.

This discussion contains forward-looking statements, which, although based on assumptions that

the Directors consider reasonable, are subject to risks and uncertainties which could cause actual

events or conditions to differ materially from those expressed or implied by the forward-looking

statements. Investors should read the notice in relation to forward-looking statements contained on

pages 45 and 46 of this document.

The key risks and uncertainties, include, but are not limited to those described in Part II – Risk

Factors of this document.

Overview

The Company was incorporated on 1 July 2015 as an investment vehicle to identify and completean acquisition of a company or business in the services sector which requires further funding forexpansion in conjunction with a public quotation for its Ordinary Shares which would provebeneficial to the existing Shareholders, management, employees and shareholders of thebusiness being acquired.

The Company completed the Dyas Acquisition on 1 October 2018 for a cash consideration ofEUR 107 million. For accounting purposes, the effective date of the transaction was determined as1 October 2018. Dyas and Dyas Infrastructure B.V. were subsequently renamed RockRose (NL)CS1 B.V. and RockRose (NL) Infrastructure B.V., respectively.

Since the end of that period on 31 December 2018, the Company completed the MarathonAcquisition on 1 July 2019. The Company has no material liabilities other than in respect of theMarathon Acquisition and the Acquisitions.

The Directors are using their experience of actively working on the acquired equity assets toinstigate activity and unlock the identified additional value in each prospect.

As at 31 December 2018, the Group had a total committed operating expenditure of £89.2 million(2017: US$nil million; 2016: US$nil), committed capital expenditure of US$83 million (2017:US$6 million; 2016: US$nil) and planned decommissioning postings of US$5 million (2017:US$7 million; 2016: US$nil), all of which are included in agreed operator budgets or have beennotified to the Group by the relevant field operators. For the assets it evaluated, ERC Equipoisehas estimated the Group’s net operating expenditure for the 21 months to 31 December 2020 as£254.3 million for the Group’s UK assets and EUR 42.2 million for its Dutch assets; its estimatedcapital expenditure for the same period is £173.8 million for the UK assets and EUR 4.7 million forthe Dutch assets. In respect of abandonment and decommissioning costs, ERC Equipoiseestimates that for the 21 months to 31 December 2020 such amount will equate to £37 million forthe UK assets and EUR 600,000 for the Dutch assets. These ERC Equipoise estimates are notfully committed, but have been included within our working capital models.

Annex I, 7.1, 9.1,

9.2.1, 9.2.2,

9.2.3, 10.4

ESMA update

paras 27-32

184


Key performance indicators

The Directors are of the opinion that the following constitutes the Company’s key performanceindicators:

• Revenue;

• Lifting cost per barrel of oil;

• Barrels of oil equivalent produced per day (boepd);

• Booked reserves; and

• Date and amount of decommissioning.

The lifting cost per barrel includes direct operating costs, tariffs and insurances and excludesdepreciation, depletion and amortisation of oil and gas assets. For the financial year ended 31December 2018, the lifting cost per boe was US$35 (2017: US$38; 2016: US$nil) and the liftingcosts per boe for oil were US$36.43 (2017: US$38.0; 2016: US$nil) and gas were US$21.62(2017: US$nil; 2016: US$nil).




2018 2017** 2016*

US$000 US$000 US$000

Revenue 153,072 7,436 –Cost of sales (105,356) (7,604) –Gross profit/(loss) 47,716 (168) –Change in estimate of decommissioning provisions 14,302 – –Foreign exchange movements on decommissioningprovision – (223) –Administrative Costs (12,649) (5,617) (1,900)Loss on derivatives (6,399) – –Gain on acquisition – 87,825 –Impairment of goodwill (18,660) (7,974) – –––––––– –––––––– ––––––––Operating profit/(loss) 24,310 73,843 (1,900)Finance income 51 9 6Finance costs (14,996) (915) –Foreign exchange (loss)/gain (1,987) 1,137 – –––––––– –––––––– ––––––––Profit/(loss) before income tax 7,378 74,074 (1,894)Income tax credit 31,481 – – –––––––– –––––––– ––––––––Profit/(loss) for the year attributable to shareholders 38,859 74,074 (1,894) –––––––– –––––––– ––––––––Comprehensive income to be reclassified to profit

or loss in subsequent years when specific conditions

are met:

Foreign currency translation loss – 140 (653) –––––––– –––––––– ––––––––Total comprehensive income for the year 38,859 74,214 (2,547) –––––––– –––––––– ––––––––

*All balances for the 18 month period ended 31 December 2016 presented throughout these financial statements have


**The income statement for the year ended 31 December 2017 has been presented in a format consistent with that

adopted in the year ended 31 December 2018 annual report and accounts and therefore some sub-totals are different

from those presented in the annual report and accounts for the year ended 31 December 2017. However, no financial

information has been restated.

Annex I, 9.2.1

ESMA update

para 30

185


The Group’s revenue increased to US$7,436,000 in the financial year ended 31 December 2017from US$nil for the 18 month period ended 31 December 2016 and subsequently increased toUS$153,072,000 in the financial year ended 31 December 2018. The increase was predominantlydue to an increase in the sale combined sale of crude oil and gas of US$151,499,000 (up fromUS$7,436,000 in the financial year ended 31 December 2017 and US$nil for the 18 month periodended 31 December 2016).

The Group’s operating profit decreased by 67% to US$24,310,000 in the financial year ended31 December 2018 from US$73,843,000 for the financial year ended 31 December 2017. Thisdecrease was primarily as a result of increased costs attributed to depreciation, depletion andamortisation of oil and gas assets of US$33,913,000 for the financial year ended 31 December2018 compared to US$1,655,000 for the financial year ended 31 December 2017. For the financial18 month period ended 31 December 2016, the Group’s operating loss was US$1,900,000 due toadministrative costs and no revenue generated.

The Group’s sale of crude oil increased substantially to US$124,866,000 for the financial yearended 31 December 2018 from US$7,436,000 for the financial year ended 31 December 2017 andUS$nil for the 18 month period ended 31 December 2016, realising and average oil price ofUS$72.95, US$66.1 and US$nil respectively. The Group’s results are sensitive to crude oil andnatural gas prices which are dependent on a number of factors including world supply anddemand.

Acquisitions

Dyas Acquisition

The Group completed the Dyas Acquisition on 1 October 2018 for a cash consideration ofEUR107 million.

Total fair value

US$000

Intangible assets: exploration costs 30,349Property, plant and equipment: oil & gas assets 190,606Property, plant and equipment: decommissioning assets 19,250Deferred tax liability (98,831)Inventory 1,060Trade and other receivables 33,027Cash and cash equivalents 90,572Trade and other payables (28,049)Decommissioning provisions (130,329) ––––––––Net identifiable assets acquired at fair value 107,655 ––––––––Total consideration paid (124,115) ––––––––Goodwill 16,460 ––––––––Total cash outflow on the acquisition is as follows:Cash paid (102,344)Net cash acquired with the subsidiary 90,571 ––––––––Net consolidated cash flow (11,773) ––––––––Goodwill arose on the Dyas Acquisition and is the difference between the fair value of the purchaseconsideration given and the fair value of the net assets acquired, and liabilities assumed. It will notbe deductible for tax purposes.

The directors assessed the carrying value of the goodwill and specifically note:

• the acquired business operates in a single country, the Netherlands;

186


• the group’s operations relate in whole to exploration for and the appraisal and developmentof oil and gas assets;

• both oil and gas are commodity products that trade in an active market that, particularly inthe case of oil, is international;

• and oil and gas assets are valued based on the quantity of oil or gas that it is estimated canbe economically recovered.

The fair value of the trade receivables is US$33 million. The gross contractual amount for tradereceivables due is US$33 million, the full value is expected to be collected.

Acquisition-related expenses of US$1 million are included in administrative expenses in the profitand in the operating cashflow in the statement of cashflow.

The acquired business contributed revenues of US$23.5 million and profit after tax ofUS$8.9 million to the Group for the period 1 October to 31 December 2018.

If the Dyas Acquisition had occurred on 1 January 2018, consolidated pro forma revenue and profitbefore tax for the year ended 31 December 2018 would have been US$231 million andUS$39 million respectively.

Arran Acquisition

The Group completed the acquisition of 30.43% stake in the Shell operated Arran field on10 October 2018 for the nominal consideration of US$1. This is a development asset.

Provision for liabilities and other charges

Decommissioning Other Total

provision provision provisions

US$000 US$000 US$000

Group

At 1 January 2017 – – –Acquired through business combinations 251,943 54 251,997Utilisation (398) – (398)Foreign exchange movements (420) – (420)Changes in estimates 516 – 516Unwinding of discount 912 – 912 –––––––– –––––––– ––––––––At 31 December 2017 252,553 54 252,607 –––––––– –––––––– ––––––––Company

At 1 January 2017 – – –Arising from acquisition of subsidiaries – 7,173 7,173 –––––––– –––––––– ––––––––At 31 December 2017 – 7,173 7,173 –––––––– –––––––– ––––––––Group

At 1 January 2018 252,553 54 252,607Acquired through business combinations 128,689 – 128,689Utilisation (2,402) – (2,402)Changes in estimates (20,343) – (20,343)Unwinding of discount 11,285 – 11,285 –––––––– –––––––– ––––––––At 31 December 2018 369,782 54 369,836 –––––––– –––––––– ––––––––CompanyAt 1 January 2018 – 7,173 7,173Change in estimate – 105 105 –––––––– –––––––– ––––––––At 31 December 2018 – 7,278 7,278 –––––––– –––––––– ––––––––

187


The estimated cost of decommissioning at the end of the producing lives of the fields is reviewedannually and engineering estimates and reports are updated periodically.

Provision is made for the estimated cost of decommissioning at the statement of financial positiondate for the Company’s share of the overall costs. Cost estimates have been discounted at anaverage discount rate of 4.0% (2017: 3.9%; 2016: nil).

The timing of spend is based on the economic cut off point for the producing assets. Provisionsacquired in business combinations have been calculated based on the latest operator costestimates. The payment dates are uncertain and are currently anticipated to be between 2019 and2040 for the relevant producing fields.

It is anticipated that the Group will obtain full tax relief on its decommissioning liabilities in the UK.The above decommissioning provision of US$370 million includes US$5.1 million classified withincurrent liabilities.

RockRose, as part of its stewardship of its interest in the licence fields, has become party tovarious decommissioning security agreements, which has resulted in restricted cash balancesbeing placed with the trustees and letter of credit providers under the terms of these agreements.The amounts placed in restricted cash will continue to vary over the time they are in place, whichwill depend on certain assumptions, for example the oil price and anticipated dates of cessation ofproduction. In the financial year ended 31 December 2018, the Group’s restricted cash balancetotalled US$53.3 million and US$55.3 million for the financial year ended 31 December 2016. TheGroup did not hold restricted cash in the 18 month period ended 31 December 2016.

Restricted cash balances are amounts deposited with trustees or banks issuing Letters of Credit,under the terms of various decommissioning security agreements in place on certain fields inwhich the Group has an interest.

Capital resources

The Company’s capital resources comprise its share capital and reserves.

In the financial year ended 31 December 2018, being the period covered by the most recentlypublished audited financial information, net cash generated from operating activities totalledUS$83,449,000. For the financial year ended 31 December 2017, the net cash used in operatingactivities totalled US$27,474,000 compared to US$1,562,000 for the 18 month period ended31 December 2016. The net cash used in investing activities amounted to US$24,804,000. For thefinancial year ended 31 December 2017, the net cash generated from investing activities totalledUS$81,416,000 compared to US$nil for the 18 month period ended 31 December 2016. The netcash used in financing activities amounted to US$55,892,000. For the financial year ended31 December 2017, the net cash generated from financing activities totalled US$8,169,000compared to US$4,999,000 for the 18 month period ended 31 December 2016. No dividends onOrdinary Shares or other cash flows arose during the period, however in February 2018 theCompany made a shareholder distribution of £1.50 per share via a “B” Share Scheme followingthe approval at an general meeting of the Shareholders on 14 February 2018. Additionally, theCompany made a Share buy-back of just under 20% of issue shared capital for cash ofUS$22 million (£16.4 million (£5.60 per Ordinary Share)) in November 2018.

The Company does not forecast any restrictions on its ability to meet financial commitments asthey fall due and anticipates that all planned operational costs, capital expenditure anddecommissioning obligations will be met out of revenues with respect to all of the licence interests.

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Capitalisation and indebtedness

The following tables show the Group’s capitalisation as at 31 December 2018 (being the last datein respect of which the Group has published financial information) and the Enlarged Group’sindebtedness as at 1 July 2019 (distinguishing between guaranteed and unguaranteed, securedand unsecured indebtedness).

As at

31 December 2018

US$000

Total current debt

Guaranteed –Secured –Unguaranteed/unsecured –Total non-current debt (excluding current portion of non-current debt)

Guarantee –Secured –Unguaranteed/unsecured –Shareholder’s equity

Share capital 3,549Share premium 129Legal reserve –Other reserves 11,772 ––––––––Total capitalisation 15,450 ––––––––Shareholders’ equity does not include the profit and loss account reserve. The information abovehas been extracted without material adjustment from the audited financial results of the Group forthe financial year ended 31 December 2018. There has been no material change in the Group’scapitalisation from 31 December 2018 to the date of this document.

The following table shows the Enlarged Group’s net indebtedness as at 1 July 2019:

As at 1 July 2019

US$000

Cash and cash equivalent 373,734Restricted cash3 (90,867)Liquidity 282,867Current financial debt –Net current financial indebtedness 282,867 ––––––––Non-current financial indebtedness – ––––––––Net financial indebtedness 282,867 ––––––––The Enlarged Group had no indirect or contingent indebtedness as at 1 July 2019.

The cash balance as at 1 July 2019 was US$282.9 million and there were as at that date noborrowings.

Hedging arrangements and risk management

The Company may use forward contracts, options, swaps, caps, collars and floors or otherstrategies or forms of derivative instruments to limit its exposure to changes in the relative valuesof investments that may result from market developments, including changes in prevailing interest

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3 Restricted cash balances are amounts deposited with trustees under the terms of various decommissioning security

agreements amount to US$40,527,000 and US$50,340,000 posted in respect of the letter of credit for the DB

Scheme. As these amounts are adjusted for on an annual basis or utilised as decommissioning occurs, they are not

readily convertible and are therefore classed as restricted.

rates and currency exchange rates, as previously described. It is expected that the extent of riskmanagement activities by the Company will vary based on the level of exposure and considerationof risk across the business.

The success of any hedging or other derivative transaction generally will depend on theCompany’s ability to correctly predict market changes. As a result, while the Company may enterinto such a transaction to reduce exposure to market risks, unanticipated market changes mayresult in poorer overall investment performance than if the transaction had not been executed. Inaddition, the degree of correlation between price movements of the instruments used in connectionwith hedging activities and price movements in a position being hedged may vary. Moreover, for avariety of reasons, the Company may not seek, or be successful in establishing, an exactcorrelation between the instruments used in a hedging or other derivative transactions and theposition being hedged and could create new risks of loss. In addition, it may not be possible to fullyor perfectly limit the Company’s exposure against all changes in the values of its assets, becausethe values of its assets are likely to fluctuate as a result of a number of factors, some of which willbe beyond the Company’s control. In April 2019 the Company entered into a hedging agreementby hedging 3,000 boepd of its oil production at US$69 for a period of 13 months effective from May2019.

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PART XV

OPERATING AND FINANCIAL REVIEW OF MOUK


or derived without material adjustment from MOUK’s financial information for the financial years

ended 31 December 2018, 31 December 2017 and 31 December 2016, which are detailed in

Part XII – Historical Financial Information on MOUK prepared in accordance with IFRS.








Overview

MOUK is a private limited liability company incorporated in Delaware, United States. The addressof its registered office is Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801,United States. MOUK’s principal activity is to explore for, develop, produce and market crude oiland natural gas in the United Kingdom. Its subsidiary companies provide employee and otherservices to MOUK and other Marathon group companies.

For MOUK’s assets, ERC Equipoise has estimated the net operating expenditure for the21 months to 31 December 2020 as £93.5 million; its estimated capital expenditure for the sameperiod is £34.5 million. In respect of abandonment and decommissioning costs, ERC Equipoiseestimates that for the 21 months to 31 December 2020 such amount will equate to £30.9 million.These ERC Equipoise estimates are not fully committed, but have been included within ourworking capital models.

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RESULTS OF OPERATIONS FOR THE FINANCIAL YEARS ENDED 31 DECEMBER 2018,

31 DECEMBER 2017 AND 31 DECEMBER 2016

The following table sets forth MOUK’s results of operations for the financial year ended31 December 2018, 31 December 2017 and 31 December 2016.



2018 2017 2016


US$000 US$000 US$000

Revenue 196,424 209,693 157,851Cost of sales (84,656) (180,312) (197,904) –––––––– –––––––– ––––––––Gross profit/(loss) 111,768 29,381 (40,053)Other operating income 125,550 423 281Administrative costs (13,345) (6,546) 350 –––––––– –––––––– ––––––––Operating profit 223,973 23,258 (39,422)Finance income 16,399 11,775 11,011Finance costs (7,546) (7,773) (8,107) –––––––– –––––––– ––––––––Profit before income tax 232,826 27,260 (36,518)Income tax (charge)/credit (98,929) 23,969 21,299 –––––––– –––––––– ––––––––Profit for the year attributable to members 133,897 51,229 (15,219) –––––––– –––––––– ––––––––Adjusted EBITDA 102,594 89,485 66,912 –––––––– –––––––– ––––––––Comprehensive income to be reclassified to profit or

loss in subsequent years when specific conditions

are met:

Foreign currency translation (loss)/gain (7,832) 7,915 (11,313) –––––––– –––––––– ––––––––Comprehensive income that will not be reclassified

to profit or loss in subsequent years when specific

conditions are met:

Deferred tax relating to defined benefit pension scheme (5) (6,395) 5,459Actuarial gains on defined benefit pension scheme 11 37,623 (32,109)Other comprehensive income/(expense) for the year 6 31,228 (26,650) –––––––– –––––––– ––––––––Total comprehensive income for the year 126,071 90,372 (53,182) –––––––– –––––––– ––––––––Revenue

MOUK’s revenue increased by 32.84% to US$209,693,000 in the financial year ended31 December 2017 from US$157,851,000 for the financial year ended 31 December 2016 butsubsequently decreased to US$196,424,000 in the financial year ended 31 December 2018,representing a decrease of 6.32%. The decrease was predominantly due to a decrease in thecombined sale of crude oil and gas of US$152,208,000 (down from US$160,946,000 in thefinancial year ended 31 December 2017 and US$110,591,000 in the financial year ended31 December 2016) and representing a decrease of 5.43%, and a decrease in revenue generatedfrom transportation and processing services of US$31,458,000 (down from US$34,063,000 in thefinancial year ended 31 December 2017 and up from US$25,932,000 in the financial year ended31 December 2016) and representing a decrease of 7.64% and an increase of 21.3% respectively.

Costs of sales

Cost of sales decreased by 8.88% from US$197,904,000 for the financial year ended31 December 2016 to US$180,312,000 for the financial year ended 31 December 2017, andfurther decreased by 53% to US$84,656,000 for the financial year ended 31 December 2018 due

Annex I, 20.4.2

192


to the significant reduction in depreciation charges as the Brae assets move further towards endof life, and one off increase in contractor costs in 2017 resulting from gas bypass works andadditional decommissioning spend in respect of Brae Bravo.

Operating profit/(loss)

MOUK noted an operating loss of US$39,422,000 for the financial year ended 31 December 2016.Operating profit increased to US$23,258,000 for the financial year ended 31 December 2017, andsubstantially increased by US$200,715,000 to US$223,973,000 for the financial year ended31 December 2018. The 2018 financial year increase, was primarily driven by a reduction in thedecommissioning provision (a consequence of changes in the key estimates) of US$125,555,000in excess of its net book value within fixed assets, recognised in other income. The remainder ofthe increase is explained by the decrease in costs of sales as mentioned above.

Administrative Costs

MOUK’s administrative costs increased to US$13,345,000 in the financial year ended31 December 2018 from US$6,546,000 in the financial year ended 31 December 2017,representing an increase of 103%. MOUK did experience a loss as a result of administrative costsin the financial year ended 31 December 2016.

Taxation

MOUK’s tax expense increased to US$98,929,000 for the financial year ended 31 December 2018compared to the US$23,969,000 tax credit for the financial year ended 31 December 2017 and thetax credit of US$21,299,000 tax credit for the financial year ended 31 December 2016.

The table below sets forth a breakdown of corporate income tax for the financial years ended31 December 2018, 31 December 2017 and 31 December 2016.



2018 2017 2016


US$000 US$000 US$000

Current tax:

Current tax (credit)/charge (2,589) 19,610 3,924Adjustments in respect of prior years 6,716 106,223 (2,657) –––––––– –––––––– ––––––––Total current tax charge 4,127 125,833 1,267 –––––––– –––––––– ––––––––Deferred tax:

Adjustment in respect of prior years 16,142 (136,819) 36,965Relating to the origination and reversal oftemporary differences 78,660 (12,983) (59,531)Relating to the movement due to the tax rate changes – – – –––––––– –––––––– ––––––––Total deferred tax charge/(credit) 94,802 (149,802) (22,566) –––––––– –––––––– ––––––––Total tax charge/(credit) 98,929 (23,969) (21,299) –––––––– –––––––– ––––––––

193


A reconciliation between tax income and the product of accounting profit multiplied by thecombined UK ring fence corporation tax and supplementary charge rate of 40% in 2018, 2017 and2016 and non-ring fence tax rate of 19%, 20% and 20% in 2018, 2017 and 2016, respectively isas follows:



2018 2017 2016


US$000 US$000 US$000

Accounting profit before income tax 232,826 27,260 (36,518)A combined UK ring fence corporation tax andsupplementary charge rate of 40% in 2018,2017 and 2016 respectively and non-ring fencetax rate of 19%, 20% and 20% in 2018, 2017and 2016 respectively 93,130 10,904 (14,607)Expenses not deductible for tax purposes (9,841) (6,675) 1,230Income taxed at mainstream corporation tax rate (6,001) (5,060) (8,168)Currency remeasurements (4,816) 294 1,274Prior year adjustment 9,689 (13,291) 3,726Petroleum revenue tax 16,768 (7,491) (4,754)Interest – (2,650) – –––––––– –––––––– ––––––––Total tax charge/(credit) for the year 98,929 (23,969) (21,299) –––––––– –––––––– ––––––––Cash Flow Analysis

The following table presents MOUK’s cash flow summary for the financial years ended31 December 2018, 31 December 2017 and 31 December 2016:



2018 2017 2016


US$000 US$000 US$000


Profit/(loss) for the year 133,897 51,229 (15,219)Non-cash adjustments to reconcile profit/(loss)for the year to net cash flows:Foreign exchange (gain)/loss on operating activities (1,673) 1,931 (4,614)Revaluation of investment property – (212) –Finance costs (8,853) (4,002) (2,904)Share based payments (14,436) (16,796) (17,741)(Reversal of impairment)/impairment of property,plant and equipment (20) 1,418 –Tax on profit/(loss) on ordinary activities 98,929 (23,969) (21,299)Depreciation 4,171 66,650 105,125Profit on disposal of tangible assets – – (90)Change in estimate of decommissioning provision (124,674) – (14,770)Increase in provisions (24,848) (21,909) – –––––––– –––––––– ––––––––

194




2018 2017 2016


US$000 US$000 US$000

Operating cash flows before movements in workingcapital 62,493 54,340 28,488(Increase)/decrease in inventory (3,142) 1,169 5,514(Increase)/decrease in trade and other receivables (2,338) 65,773 (27,711)(Decrease)/increase in trade and other payables (5,569) 6,688 (16,492)Income tax paid (3,835) (124,501) (13,012) –––––––– –––––––– ––––––––Net cash generated from/(used in) operating activities 47,609 3,469 (23,213)Cash flows from investing activities

Loan repayment receipts 265,000 30,000 –Interest receivable and similar income 11,072 11,201 9,611(Additions)/disposals of property, plant and equipment (13,917) (5,642) 305 –––––––– –––––––– ––––––––Net cash generated from investing activities 262,155 35,559 9,916Cash flows from financing activities

Finance costs (2,559) (4,228) (3,841)Members distribution (340,000) – – –––––––– –––––––– ––––––––Net cash used in financing activities (342,559) (4,228) (3,841) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cash equivalents (32,795) 34,800 (17,138)Cash and cash equivalents at 1 January 62,048 24,246 44,757Effect of foreign exchange 1,120 3,002 (3,373) –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 30,373 62,048 24,246 –––––––– –––––––– ––––––––

Net cash flows from investing activities

For the financial year ended 31 December 2018, MOUK’s net cash generated from investingactivities was US$262,155,000 compared to US$35,559,000 for the financial year ended31 December 2017 and US$9,916,000 for the financial year ended 31 December 2016. The cashused in investing activities is mainly attributable to receipt of loan repayments of US$265,000,000in the financial year ended 31 December 2018 (up from US$30,000,000 in the financial year ended31 December 2017 and US$nil in the financial year ended 31 December 2016).

Net cash flows used in financing activities

For the financial year ended 31 December 2018, MOUK’s net cash used in financing activities wasUS$342,559,000 compared to US$4,228,000 for the financial year ended 31 December 2017 andUS$3,841,000 for the financial year ended 31 December 2016. Cash was used to make dividendpayments of US$340,000,000 to shareholders and interest payments of US$2,559,000 for thefinancial year ended 31 December 2018.

Pension

MOUK’s subsidiary, MSGB, operates a DC Scheme for its employees. A DC Scheme is a pensionscheme under which a company pays fixed contributions into a separate entity. Once thecontributions have been paid, the company has no further payment obligations.

The contributions are recognised as an expense in the statement of comprehensive income whenthey fall due. Amounts not paid are shown in accruals as a liability at the balance sheet date. Theassets of the scheme are held separately from the company in independently administered funds.

The DC Scheme was closed to future benefit accrual on 31 December 2015. A DB Scheme definesthe pension benefit that the employee will receive on retirement, usually dependent upon several

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factors including but not limited to age, length of service and remuneration. A DB Scheme is apension scheme which is not a DC Scheme.

The surplus recognised on the balance sheet in respect of the defined benefit scheme is thepresent value of the defined benefit obligation at the balance sheet date less the fair value ofscheme assets at the balance sheet date out of which the obligations are to be settled.

The defined benefit obligation is calculated using the projected unit credit method. TrienniallyMOUK engages independent actuaries to calculate the obligation. The last valuation was carriedout as at 31 March 2016.

The present value is determined by discounting the estimated future payments using market yieldson high quality corporate bonds that are denominated in sterling and that have termsapproximating the estimated period of the future payments.

Actuarial gains and losses arising from experience adjustments and changes in actuarialassumptions are charged or credited to other comprehensive income.

The cost of the DB Scheme, recognised in the statement of comprehensive income as employeecosts, except where included in the cost of an asset, comprises the cost of the schemeintroductions, benefit changes, curtailments and settlements.

The net interest cost is calculated by applying the discount rate to the net balance of the definedbenefit obligation and the fair value of the scheme assets. This cost is recognised in the statementof comprehensive income as interest payable.

The scheme is administered by trustees, who are responsible for ensuring that the plan issufficiently funded to meet current and future obligations. As part of the last full triennial valuation,a funding plan was agreed with the DB Scheme trustees which provides for annual contributionsof £13,000,000 until 31 December 2020.

On 1 April 2010, the Group established a DC Scheme to provide benefits to new employees.

On 1 January 2016 all employees were transferred to the DC Scheme.

Total contributions to the DB Scheme and DC Scheme were US$7.98 million, US$4.79 million andUS$6.21 million in 2018, 2017 and 2016 respectively.



US$000 US$000 US$000

Present at 1 January 2016 579,565 (608,283) (28,718)Interest expense/(income) 19,903 (21,303) (1,400)Loss on changes/introductions 879 – 879 –––––––– –––––––– ––––––––Total amount recognised in profit or loss 20,782 (21,303) (521)Remeasurements:

Return on plan assets – (110,208) (110,208)Loss from change in demographic assumptions 142,317 – 142,317 –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome 142,317 (110,208) 32,109 –––––––– –––––––– ––––––––Exchange differences (105,198) 108,641 3,443Contributions:Employers – (18,620) (18,620)Plan participants – – –Benefit payments (52,070) 52,070 – –––––––– –––––––– ––––––––At 31 December 2016 585,396 (597,703) (12,307)Interest expense/(income) 15,926 (16,500) (574) –––––––– –––––––– ––––––––Total amount recognised in profit or loss 15,926 (16,500) (574)

196




US$000 US$000 US$000

Remeasurements:

Return on plan assets – (30,354) (30,354)Gain from change in demographic assumptions (7,269) – (7,269) –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome (7,269) (30,354) (37,623) –––––––– –––––––– ––––––––Exchange differences 53,927 (57,620) (3,693)Contributions:Employers – (16,796) (16,796)Plan participants – – –Benefit payments (46,115) 46,115 – –––––––– –––––––– ––––––––At 31 December 2017 601,865 (672,858) (70,993)Interest expense/(income) 14,406 (16,379) (1,973) –––––––– –––––––– ––––––––Total amount recognised in profit or loss 14,406 (16,379) (1,973)Remeasurements:

Return on plan assets – 37,598 37,598Gain from change in demographic assumptions (34,670) – (34,670) –––––––– –––––––– ––––––––Total amount recognised in other comprehensiveincome (34,670) 37,598 (2,928) –––––––– –––––––– ––––––––Exchange differences (32,145) 37,046 4,901Contributions:Employers – (17,375) (17,375)Plan participants – – –Benefit payments (38,047) 38,047 – –––––––– –––––––– ––––––––At 31 December 2018 511,409 (593,921) (82,512) –––––––– –––––––– ––––––––Foreign currencies

Items included in the financial statements of each of MOUK’s entities are measured using thecurrency of the primary economic environment in which each entity operates (‘the functionalcurrency’).

Transactions in foreign currencies are translated to the entity’s functional currency at the foreignexchange rates at the date of the transactions. Foreign exchange gains and losses resulting fromthe settlement of monetary assets and liabilities denominated in foreign currencies are recognisedin the income statement. All UK entities in MOUK have a functional currency of US dollars apartfrom MSGB and Marathon International Oil G.B Limited which continue to have a GBP functionalcurrency. The presentation currency for the financial statements is US dollars.

The results and financial position of all of MOUK entities (none of which has the currency of ahyper-inflationary economy) that have a functional currency different from the presentationcurrency are translated into the presentation currency as follows:

a) assets and liabilities for each balance sheet presented are translated at the closing rate atthe date of that balance sheet;

b) income and expenses for each income statement are translated at average exchange rates(unless this average is not a reasonable approximation of the cumulative effect of the ratesprevailing on the transaction dates, in which case income and expenses are translated at therate on the dates of each transaction); and

c) all resulting exchange differences are recognised in other comprehensive income.

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PART XVI

OPERATING AND FINANCIAL REVIEW OF MOWOS


or derived without material adjustment from MOWOS’s financial information for the financial years

ended 31 December 2018, 31 December 2017 and 31 December 2016, which are detailed in

Part XIII – Historical Financial Information on MOWOS prepared in accordance with IFRS.








Overview

MOWOS’s principal activity is the development and production of oil and gas from the Foinavenarea in the United Kingdom (UK) Atlantic Margin. MOWOS has a 28% interest in the BP operatedFoinaven area complex in UK blocks 204/19 and 204/24a, located directly west of the ShetlandIslands, some 190km north west of Orkney.

MOWOS has a 28% interest in the main Foinaven field, a 47% interest in East Foinaven and a20% interest in the T25 and T35 accumulations. The Foinaven development utilises an FPSOvessel, linked by flexible production risers to a subsea system and remote wells on the seabed.

The 240m long Petrojarl Foinaven FPSO has an oil storage capacity of approximately 300,000barrels. Product is normally lifted in approximately 600,000 barrel parcels through dedicatedshuttle tanker operations. MOWOS’s main source of revenue is the sale of crude oil on theinternational market from its entitlement at the FPSO.

From 2002, Foinaven gas has been exported via the West of Shetlands gas pipeline system to theEnquest operated (previously BP) Magnus platform for use as an injection gas. Foinaven isprimarily an oil field, but the sale of the associated gas provides a useful secondary revenuestream.

MOWOS’s net share of sales from the Foinaven fields averaged 6 thousand barrels per day(mbpd) of liquid hydrocarbons and 1 million cubic feet per day (mmcfd) of natural gas in 2018,compared with 5 mbpd and 2 mmcfd in 2017. The Company’s revenue and profitability is impactedby changes in the crude oil price.

For MOWOS’s assets, ERC Equipoise has estimated the net operating expenditure for the21 months to 31 December 2020 as £81.3 million; its estimated capital expenditure for the sameperiod is £42.1 million. In respect of abandonment and decommissioning costs, ERC Equipoiseestimates that for the 21 months to 31 December 2020 such amount will equate to nil. These ERCEquipoise estimates are not fully committed, but have been included within our working capitalmodels.

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RESULTS OF OPERATIONS FOR THE FINANCIAL YEAR ENDED 31 DECEMBER 2018,

31 DECEMBER 2017 and 31 DECEMBER 2016

The following table sets forth the MOWOS’ results of operations for the financial year ended31 December 2018, 31 December 2017 and 31 December 2016.



2018 2017 2016


US$000 US$000 US$000

Revenue 176,032 93,981 126,035Cost of sales (100,740) (71,298) (85,947) –––––––– –––––––– ––––––––Gross profit 75,292 22,683 40,088Administrative costs (2,672) (3,198) (3,129) –––––––– –––––––– ––––––––Operating profit 72,620 19,485 36,959Finance income 4,274 2,040 799Finance costs (2,444) (1,438) (1,439) –––––––– –––––––– ––––––––Profit before income tax 74,450 20,087 36,319Income tax charge (29,610) (8,402) (25,279) –––––––– –––––––– ––––––––Profit for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Adjusted EBITDA 92,976 39,669 70,617 –––––––– –––––––– ––––––––There was no other comprehensive income

in 2018, 2017 and 2016 respectively.

Total comprehensive income for the year 44,840 11,685 11,040 –––––––– –––––––– ––––––––Revenue

MOWOS’s revenue decreased by 25% to US$93,981,000 in the financial year ended 31 December2017 from US$126,035,000 for the financial year ended 31 December 2016 but subsequentlyincreased to US$176,032,000 in the financial year ended 31 December 2018, representing anincrease of 87.3% from the financial year ended 31 December 2017. The increase waspredominantly due to an increase in the sales of crude oil of US$173,221,000 for the financial yearended 31 December 2018 (up from US$88,236,000 in the financial year ended 31 December 2017and US$117,706,000 for the financial year ended 31 December 2016) and representing anincrease of 96.3% and 47.1% respectively.

Costs of Sales

Cost of sales decreased by 17% from US$85,947,000 for the financial year ended 31 December2016 to US$71,298,000 for the financial year ended 31 December 2017, and increased by 41% toUS$100,740,000 for the financial year ended 31 December 2018,in line with the fall in productionduring the same periods and a significant increase in contractor spend in 2018 driven in part frompump and compressor outages.

Operating profit

Operating profit decreased by 47% from US$36,959,000 for the financial year ended 31 December2016 to US$19,485,000 for the financial year ended 31 December 2017, and substantiallyincreased by 272% to US$72,620,000 for the financial year ended 31 December 2018, driven bythe aforementioned increase in sales and reductions to costs of sales.

Annex I, 20.4.2

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Administrative Costs

MOWOS’s administrative expenses decreased to US$2,672,000 in the financial year ended31 December 2018 from US$3,198,000 in the financial year ended 31 December 2017,representing a decrease of 16.4%. MOWOS’s administrative expenses were marginally lower inthe year ended 31 December 2016 at US$3,129,000 compared to the financial year ended31 December 2017.

Taxation

MOWOS’s tax expense increased to US$29,610,000 for the financial year ended 31 December2018 compared to US$8,402,000 for the financial year ended 31 December 2017 andUS$25,279,000 for the financial year ended 31 December 2016.

The table below sets forth a breakdown of corporate income tax for the financial year ended31 December 2018, 31 December 2017 and 31 December 2016:



2018 2017 2016


US$000 US$000 US$000

Current tax:

Current tax charge 27,613 12,992 19,941Supplementary tax charge 10,256 3,578 6,014 –––––––– –––––––– ––––––––Total current tax charge 37,869 16,570 25,955 –––––––– –––––––– ––––––––Deferred tax:

Relating to the origination and reversal of temporary differences (8,259) (8,168) (15,888)Relating to the movement due to the tax rate changes – – 15,212 –––––––– –––––––– ––––––––Total deferred tax credit (8,259) (8,168) (676) –––––––– –––––––– ––––––––Total tax charge 29,610 8,402 25,279 –––––––– –––––––– ––––––––A reconciliation between tax income and the product of accounting profit multiplied by thecombined UK ring fence corporation tax and supplementary charge rate of 40% in 2018, 2017 and2016 and non-ring fence tax rate of 19%, 20% and 20% in 2018, 2017 and 2016 respectively is asfollows:



2018 2017 2016


US$000 US$000 US$000

Accounting profit before income tax 74,450 20,087 36,319A combined UK ring fence corporation tax and supplementary charge rate of 40%, 40% and40% in 2018, 2017 and 2016 respectively and non-ring fence tax rate of 19%, 20% and 20% in 2018, 2017 and 2016 respectively 29,780 8,034 14,528Impact of supplementary charge on tax change – – 12,915Expenses not deductible for tax purposes (191) 370 (2,071)Small field and investment allowances 21 (2) (93) –––––––– –––––––– ––––––––Total tax credit for the year 29,610 8,402 25,279 –––––––– –––––––– ––––––––

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Cash Flow Analysis

The following table presents MOWOS’s cash flow summary for the financial years ended31 December 2018, 31 December 2017 and 31 December 2016:



2018 2017 2016


US$000 US$000 US$000


Profit before income tax 74,450 20,087 36,319Non-cash adjustments to reconcile profit before tax to net cash flows:Finance income (4,274) (2,040) (799)Finance costs 4 – 3Depreciation and amortisation 20,356 20,184 33,658Finance charge on decommissioning provision 2,440 1,438 1,436 –––––––– –––––––– ––––––––Operating cash flows before movements in working capital 92,976 39,669 70,617Decrease in inventory 402 3,593 3,368Decrease/(increase) in trade and other receivables 13,916 (4,888) 16,020(Increase)/decrease in amounts owed by group companies (12,623) 9,853 (55,748)Increase/(decrease) in trade and other payables 18 (736) (5,018)Income tax paid (21,765) (22,987) (23,310) –––––––– –––––––– ––––––––Net cash generated from operating activities 72,924 24,504 5,929Cash flows from investing activities

Payments to acquire property, plant and equipment – (30) (1,430)Receipts from sales of property, plant and equipment 342 – –Finance income 4,274 2,040 799 –––––––– –––––––– ––––––––Net cash generated from/(used in) investing activities 4,616 2,010 (631)Cash flows from financing activities

Finance costs (4) – (3)Shareholder distribution (85,000) (25,000) – –––––––– –––––––– ––––––––Net cash used in financing activities (85,004) (25,000) (3) –––––––– –––––––– ––––––––Net (decrease)/increase in cash and cash equivalents (7,464) 1,514 5,295Cash and cash equivalents at 1 January 9,194 7,680 2,385 –––––––– –––––––– ––––––––Cash and cash equivalents at 31 December 1,730 9,194 7,680 –––––––– –––––––– ––––––––

Net cash flows from investing activities

For the financial year ended 31 December 2018, MOWOS’s net cash generated from investingactivities was US$4,616,000 compared to the financial year ended 31 December 2017 where netcash of US$2,010,000 was used in investing activities. For the financial year ended 31 December2016 the net cash MOWOS used US$631,000 in investing activities The cash generated frominvesting activities is attributable to receipt of cash from the disposal of certain property, plant andequipment of US$342,000 in the financial year ended 31 December 2018 (up from US$nil in thefinancial year ended 31 December 2017 and the financial year ended 31 December 2016), andfinance income of US$4,274,000 in the financial year ended 31 December 2018 (up from

Annex I, 10.2

ESMA

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US$2,040,000 in the financial year ended 31 December 2017 and US$799,000 in the financial yearended 31 December 2016).

Net cash flows used in financing activities

For the financial year ended 31 December 2018, MOWOS’s net cash used in financing activitieswas US$85,004,000 compared to US$25,000,000 for the financial year ended 31 December 2017and US$3,000 for the financial year ended 31 December 2016. Cash was used to makeshareholder distributions of US$85,000,000 to shareholders and pay interest of US$4,000 for thefinancial year ended 31 December 2018.

Financial risk management

Price risk

MOWOS is exposed to commodity price risk as a result of its operation. The markets for crude oil andnatural gas have been volatile and are likely to continue to be volatile in the future, causing prices tofluctuate widely. No derivative transactions were entered into by MOWOS during the financial yearended 31 December 2018 or the comparative financial year ended 31 December 2017.

Credit risk

Credit risk arises from cash and cash equivalents, as well as credit exposures on trade and otherreceivables. The credit risk of MOWOS’s trade and other receivables is assessed through thecredit ratings of relevant customers. The balances at year end are minimal and therefore MOWOSis not exposed to a high level of credit risk.

MOWOS only trades with recognised creditworthy third parties. The exposure risk arises fromdefault of the counter party, with a maximum exposure equal to the carrying amount as at thestatement of financial position date. The maximum exposure to credit risk was US$35,000,US$932,000 and US$3,242,000 as at 31 December 2018, 31 December 2017 and 31 December2016 respectively.

Foreign exchange risk

MOWOS is exposed to foreign exchange risk arising from currency exposures, primarily withrespect to GBP. Foreign exchange risk arises when future commercial transactions or recognisedassets or liabilities are denominated in a currency that is not the entity’s functional currency.

As at 31 December 2018, 31 December 2017 and 31 December 2016 various statements offinancial position line items were denominated in foreign currencies and the impact due to foreignexchange movement of an increase or decrease in exchange rate is shown below.

MOWOS’s exposure to foreign currency risk was as follows based, on the following nominalamounts:

2018 2017 2016

£000 US$000 £000 US$000 £000 US$000

Cash at bank 1,323 45 4,754 2,770 5,854 456Working capital accruals – 1,831 – 5,097 – 4,644Trade receivables 28 12 692 6,222 1,341 3,843Trade payables 6,563 (1,206) 5,125 (688) 6,879 (1,151)

Liquidity risk

Liquidity risk is the risk that MOWOS will not be able to meet its financial obligations as they falldue.

MOWOS maintains sufficient available funds for operations and has profitable operations whichfund their continued investment. Management considers MOWOS’s exposure to liquidity risk asminimal.

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PART XVII

TAXATION

The following summary is intended only as a general guide and relates solely to UK tax. It is basedon current UK law and published practice of HMRC as at the date of this document, each of whichmay be subject to change, possibly with retrospective effect.

The following paragraphs are not intended to be exhaustive and relate only to certain limitedaspects of the UK taxation consequences of acquiring, holding and disposing of the OrdinaryShares and do not constitute legal or tax advice. Except to the extent expressly stated, they applyonly to holders of Ordinary Shares who are resident, and in the case of individuals, domiciled,solely in the United Kingdom for UK tax purposes, and who are the absolute beneficial owners oftheir Ordinary Shares and who do not hold their Ordinary Shares through an individual savingsaccount or a self-invested personal pension (“UK Holders”). The information may not apply tocertain classes of UK Holders such as tax exempt entities, collective investment schemes, pensionschemes, insurance companies, financial institutions, dealers, professional investors, persons whohold Ordinary Shares in connection with a trade, profession or vocation, persons connected withthe company and persons who have acquired (or been deemed to have acquired) their OrdinaryShares by reason of their (or another person’s) office or employment, to whom special rules mayapply.

IT IS RECOMMENDED THAT ALL PROSPECTIVE HOLDERS OF ORDINARY SHARES

OBTAIN ADVICE AS TO THE CONSEQUENCES OF THE ACQUISITION, OWNERSHIP AND

DISPOSAL OF THE ORDINARY SHARES IN THEIR OWN SPECIFIC CIRCUMSTANCES FROM

THEIR OWN TAX ADVISORS. IN PARTICULAR, PROSPECTIVE SHAREHOLDERS WHO MAY

BE SUBJECT TO TAX IN A JURISDICTION OTHER THAN THE UNITED KINGDOM ARE

ADVISED TO CONSIDER THE POTENTIAL IMPACT OF ANY RELEVANT DOUBLE TAXATION

AGREEMENTS.

Dividends

Withholding Tax

Dividends paid by the company will not be subject to any withholding or deduction for or onaccount of UK tax, irrespective of the residence or particular circumstances of the holders ofOrdinary Shares.

Income Tax

An individual UK Holder may, depending on their particular circumstances, be subject to UK tax ondividends received from the company.

All dividends received by an individual UK Holder from the company (or from other sources, exceptto the extent within an individual savings account, self-invested pension plan or other regime whichexempts dividends from tax) will form part of that UK Holder’s total income for income tax purposesand will constitute the top slice of that income. A nil rate of income tax will apply to the first £2,000of taxable dividend income received by the individual UK Holder in a tax year. Income within thisnil-rate band will be taken into account in determining whether income in excess of the £2,000 nil-rate band falls within the basic rate, higher rate or additional rate tax bands. Dividend income inexcess of the nil-rate band will (subject to the availability of any income tax personal allowance)be taxed at 7.5% to the extent that the excess amount falls within the basic rate tax band, 32.5%to the extent that the excess amount falls within the higher rate tax band and 38.1% to the extentthat the excess amount falls within the additional rate tax band.

An individual holder of Ordinary Shares who is not resident for tax purposes in the United Kingdomshould not be chargeable to UK income tax on dividends received from the company unless he or

Annex III, 4.11

203


she carries on (whether solely or in partnership) a trade, profession or vocation in the UnitedKingdom through a branch or agency to which the Ordinary Shares are attributable. There arecertain exceptions for trading in the United Kingdom through independent agents, such as somebrokers and investment managers.

Corporation Tax

Corporate UK Holders should not be subject to UK corporation tax on any dividend received fromthe company so long as the dividends qualify for exemption, which should generally be the case,provided certain conditions (including under anti-avoidance rules) are met. If the conditions for theexemption are not satisfied, or such UK Holder elects for an otherwise exempt dividend to betaxable, UK corporation tax will be chargeable on the amount of any dividends (currently at the rateof 19%, reducing to 17% from 1 April 2020).

A corporate holder of Ordinary Shares who is not resident for tax purposes in the United Kingdomshould not be within the scope of UK corporation tax in respect of dividends received from thecompany unless it carries on (whether solely or in partnership) a trade in the United Kingdomthrough a permanent establishment to which the Ordinary Shares are attributable.

Chargeable Gains

If a UK Holder disposes (or is treated as disposing) of some or all of its Ordinary Shares, a liabilityto tax on chargeable gains may arise, depending on the UK Holder’s circumstances and anyexemptions or reliefs which may be available.

Individual UK Holders

For an individual UK Holder, a disposal (or deemed disposal) of Ordinary Shares may give rise toa chargeable gain or allowable loss for the purposes of UK capital gains tax. For an individual UKHolder who is subject to UK income tax at either the higher or the additional rate, the currentapplicable rate of capital gains tax is 20%. For an individual UK Holder who is subject to UKincome tax at the basic rate, the current applicable rate would be 10%, save to the extent that anycapital gains when aggregated with the UK Holder’s other taxable income and gains in the relevanttax year exceed the unused basic rate tax band. In that case, the rate currently applicable to theexcess would be 20%. An individual UK Holder is entitled to realise an annual exempt amount ofgains (currently £12,000) without being liable to UK capital gains tax.

Corporate UK Holders

For a UK Holder within the charge to UK corporation tax, a disposal (or deemed disposal) ofOrdinary Shares may give rise to a chargeable gain or to an allowable loss for the purposes of UKcorporation tax. The current rate of UK corporation tax is 19%, and will reduce to 17% from 1 April2020. Indexation allowance is not available in respect of disposals of Ordinary Shares acquired onor after 1 January 2018 (and only covers the movement in the retail prices index up until31 December 2017, in respect of assets acquired prior to that date).

Shareholders who are not UK Resident

A holder of Ordinary Shares who is not resident for tax purposes in the United Kingdom should notnormally be liable to UK capital gains tax or corporation tax on chargeable gains on a disposal (ordeemed disposal) of Ordinary Shares unless (i) the person is carrying on (whether solely or inpartnership) a trade, profession or vocation in the United Kingdom through a branch or agency (or,in the case of a corporate holder of Ordinary Shares, through a permanent establishment) to whichthe Ordinary Shares are attributable or (ii) in respect of disposals made on or after 6 April 2019,the company directly or indirectly derives 75% or more of its qualifying asset value from UK land,in which case a holder may, depending on its circumstances, be liable for non-resident capitalgains tax. However, an individual holder of Ordinary Shares who has ceased to be resident for taxpurposes in the United Kingdom (including where an individual is treated as resident outside the

204


United Kingdom for the purposes of a double tax treaty) for a period of five years or less and whodisposes of Ordinary Shares during that period may be liable on his or her return to the UnitedKingdom to UK tax on any capital gain realised (subject to any available exemption or relief).

Stamp Duty and Stamp Duty Reserve Tax

The discussion below relates to holders of Ordinary Shares, wherever resident. However, specialrules may apply where Ordinary Shares are issued or transferred to, or to a nominee or agent for,a depositary receipt issuer or clearance service provider, which are briefly summarised below, orpersons such as market makers, brokers, dealers or intermediaries.

Issue of Shares

No UK stamp duty or stamp duty reserve tax (“SDRT”) should ordinarily be payable on an issue ofOrdinary Shares.

Transfers of certificated Ordinary Shares

Stamp duty at the rate of 0.5% (rounded up to the next multiple of £5) of the amount or value ofthe consideration given is generally payable on an instrument transferring Ordinary Shares. Anexemption from stamp duty is available on an instrument transferring Ordinary Shares where theamount or value of the consideration is £1,000 or less, and it is certificated on the instrument thatthe transaction effected by the instrument does not form part of a larger transaction or series oftransactions for which the aggregate consideration exceeds £1,000. A charge to SDRT will alsoarise on an unconditional agreement to transfer Ordinary Shares (at the rate of 0.5% of the amountor value of the consideration payable). However, if within six years of the date of the agreementbecoming unconditional an instrument of transfer is executed pursuant to the agreement, andstamp duty is paid on that instrument, or the instrument is otherwise exempt, any SDRT alreadypaid will be refunded (generally, but not necessarily, with interest) provided that a claim forrepayment is made, and any outstanding liability to SDRT will be cancelled. The purchaser ortransferee of Ordinary Shares will generally be accountable for the SDRT. In the absence ofcontractual agreement no party is legally responsible for the payment of stamp duty as it is not anassessable tax, however, in practice the purchaser or transferee will usually pay stamp duty toensure that the company’s register of members can be updated by the registrar to show the newownership.

Ordinary Shares transferred through paperless means including CREST

Paperless transfers of Ordinary Shares, such as those occurring within CREST, are generallyliable to SDRT rather than stamp duty, at the rate of 0.5% of the amount or value of theconsideration. CREST is obliged to collect SDRT on relevant transactions settled within the systemand to pay this to HMRC. The SDRT charge is generally borne by the purchaser. Under theCREST System, no stamp duty or SDRT will arise on a transfer of Ordinary Shares into the CRESTSystem unless such a transfer is made for consideration in money or money’s worth, in which casea liability to SDRT (usually at a rate of 0.5%) will arise.

Ordinary Shares held through Clearance Systems or Depositary Receipt Arrangements

Special rules apply where Ordinary Shares are issued or transferred to, or to a nominee or agentfor, either a person whose business is or includes issuing depositary receipts within Section 67 orSection 93 of the Finance Act 1986 or a person providing a clearance service within Section 70 orSection 96 of the Finance Act 1986, under which SDRT or stamp duty may be charged at a rateof 1.5% Following litigation, HMRC confirmed that they will no longer seek to apply the 1.5% SDRTcharge on an issue of shares into a clearance service or depositary receipt arrangement on thebasis that the charge is not compatible with EU law. It was announced on 22 November 2017 thatthe government will not seek to reintroduce this charge following the departure of the UK from theEuropean Union.

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Based on current published HMRC practice and recent case law, no SDRT is generally payablewhere the transfer of shares to a clearance service or depositary receipt system is an integral partof an issue of share capital. Any liability for stamp duty or SDRT in respect of such a transfer thatis not integral to an issue of share capital will generally be accountable by the clearance serviceor depositary receipt system operator or their nominee, as the case may be, but will, in practice,be payable by the participants in the clearance service or depositary receipt system.

Transfers of Ordinary Shares within a depositary receipt system or a clearance service that hasnot made and maintained an election under section 97A of the Finance Act 1986 (a “section 97A

election”) will be exempt from SDRT and, provided no instrument of transfer is entered into, willnot be subject to stamp duty.

Where a clearance service has made and maintained a section 97A election the 1.5% charge willnot apply. Rather, stamp duty or SDRT will be charged at the normal rate of 0.5% on the transferof existing shares into and within the clearance service.

Accordingly, specific professional advice should be sought before incurring a 1.5% stamp

duty or stamp duty reserve tax charge in any circumstances.

Inheritance tax

The Ordinary Shares will be assets situated in the UK for the purposes of UK inheritance tax. A giftof such assets by, or the death of, an individual holder of such assets may (subject to certainexemptions and reliefs) give rise to a liability to UK inheritance tax even if the holder is neitherdomiciled in the UK nor deemed to be domiciled there under certain rules relating to long residenceor previous domicile. For inheritance tax purposes, a transfer of assets at less than full marketvalue may be treated as a gift and particular rules apply to gifts where the donor reserves or retainssome benefit.

Special rules also apply to close companies and to trustees of settlements who hold OrdinaryShares, bringing them within the charge to inheritance tax. Shareholders should consult anappropriate tax adviser if they make a gift or transfer at less than market value or intend to holdany Ordinary Shares through trust arrangements. They should also seek professional advice in asituation where there is potential for a double charge to UK inheritance tax and an equivalent taxin another country or if they are in any doubt about their UK inheritance tax position.

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PART XVIII

CONSEQUENCES OF A STANDARD LISTING

As the Marathon Acquisition is classified as a Reverse Takeover, upon completion of the MarathonAcquisition, the Standard Listing of the Ordinary Shares was cancelled and an application will bemade for the immediate admission of the Ordinary Shares to Standard Listing (pursuant to Chapter14 of the Listing Rules) and to trading on the Main Market of the London Stock Exchange. TheCompany intends to comply with the Listing Principles set out in Chapter 7 of the Listing Rules atListing Rule 7.2.1 which apply to all companies with their securities admitted to the Official List. Inaddition, the Company also intends to comply with the Listing Principles at Listing Rule 7.2.1Anotwithstanding that they only apply to companies which obtain a Premium Listing. With regard tothe Listing Principles at 7.2.1A, the Company is not, however, formally subject to such ListingPrinciples and will not be required to comply with them by the FCA.

While the Company has a Standard Listing, it is not required to comply with the provisions of, inter

alia:

• Chapter 8 of the Listing Rules regarding the appointment of a sponsor to guide the Companyin understanding and meeting its responsibilities under the Listing Rules in connection withcertain matters. The Company has not and does not intend to appoint such a sponsor inconnection with Admission;

• Chapter 9 of the Listing Rules relating to the ongoing obligations for companies admitted tothe Premium List and therefore does not apply to the Company;

• Chapter 10 of the Listing Rules relating to significant transactions. It should be notedtherefore that the Marathon Acquisition did not require Shareholder consent;

• Chapter 11 of the Listing Rules regarding related party transactions. Nevertheless, theCompany will not enter into any transaction which would constitute a ‘related partytransaction’ as defined in Chapter 11 of the Listing Rules without the specific prior approvalof the Directors;

• Chapter 12 of the Listing Rules regarding purchases by the Company of its Ordinary Shares.In particular, the Company has not adopted a policy consistent with the provisions of ListingRules 12.4.1 and 12.4.2; and

• Chapter 13 of the Listing Rules regarding the form and content of circulars to be sent toShareholders.

It should be noted that the FCA will not have the authority to (and will not) monitor the

Company’s compliance with any of the Listing Rules which the Company has indicated

herein that it intends to comply with on a voluntary basis, nor to impose sanctions in

respect of any failure by the Company so to comply. However, the FCA would be able to

impose sanctions for non-compliance where the statements regarding compliance in this

document are themselves misleading, false or deceptive.

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PART XIX

ADDITIONAL INFORMATION

1. Responsibility

The Company and the Directors, whose names appear on page 51 of this document, acceptresponsibility for the information contained in this document. To the best of the knowledge of theCompany and the Directors (each of whom has taken all reasonable care to ensure that such isthe case), the information contained in this document is in accordance with the facts and does notomit anything likely to affect the import of such information.

2. The Company

2.1 The Company was incorporated on 1 July 2015 as a public company with limited liabilityunder the Companies Act.

2.2 The Company is not regulated by the FCA or any financial services or other regulator. Witheffect from Admission, the Company will be subject to the Listing Rules and the DisclosureGuidance and Transparency Rules (and the resulting jurisdiction of the FCA), to the extentsuch rules apply to companies with a Standard Listing pursuant to Chapter 14 of the ListingRules.

2.3 The principal legislation under which the Company operates and conforms, and pursuant towhich the Ordinary Shares have been created, is the Companies Act and the regulationsmade thereunder. The Company operates in conformity with its constitution.

2.4 The Company’s registered office is at c/o Cooley Services Limited, Dashwood, 69 Old BroadStreet, London EC2M 1QS. The Company’s telephone number is +44 (0) 20 7556 4261.

2.5 On incorporation of the Company, Andrew Austin subscribed for 1,200,000 ordinary sharesof 5 pence in the Company at a price of 12.5 pence each (equivalent to 300,000 shares ata price of 50 pence each on a consolidated basis).

2.6 On 5 August 2015 a special resolution was passed to consolidate every four ordinary sharesof 5 pence each into an ordinary share of 20 pence.

2.7 By a special resolution of the founder shareholder passed by a written resolution of the soleshareholder of the Company on 5 November 2015, the Articles were adopted with effect fromAdmission in substitution for and to the exclusion of the Company’s then existing articles ofassociation.

2.8 On 18 December 2015 Andrew Austin subscribed for 900,000 ordinary shares of nominalvalue 20 pence in the Company at a price of 50 pence each.

2.9 Pursuant to written resolution of the sole shareholder passed on 6 January 2016 theDirectors were authorised in accordance with section 551 of the Companies Act to exerciseall the powers of the Company to allot up to 29,000,000 Ordinary Shares, provided that suchauthority, unless renewed, varied or revoked by the Company, shall expire on 28 February2016, but so that the Company may, before such expiry, make an offer or agreement whichwould or might require Ordinary Shares to be allotted and the Directors may allot shares inpursuance of such offer of agreement notwithstanding that the authority conferred by thisresolution has expired.

2.10 On 12 January 2016, the Company issued 10,000,000 Ordinary Shares, of which 8,800,000Ordinary Shares were placed with certain investors in connection with a placing at a price of50 pence per Ordinary Share.

Annex III, 1.1,

1.2, 4.2

Annex I, 5.1.1,

5.1.2, 5.1.3, 5.1.4

LR 2.2.1(1), (2)

LR 2.2.2(1), (3)

Annex I, 21.1.7

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2.11 On 6 July 2017, the Company issued 5,333,334 Ordinary Shares to placees and subscribersin connection with a fundraise at a price of 150 pence per Ordinary Share.

2.12 On 14 February 2018, the Company issued 15,333,334 B Shares at a price of 150 penceper B Share in connection with a share redemption which occurred on the same date.

2.13 On 14 February 2018, Andrew Austin exercised an option to acquire 1,533,333 OrdinaryShares on terms of his option award dated 22 December 2015.

2.14 On 14 February 2018, the Company granted Peter Mann 212,600 options and StevePawson 159,450 options, each at an exercise price of 127 pence per Ordinary Share.

2.15 On 20 April 2018, the Company issued 15,941 Ordinary Shares at a price of 352 pence perOrdinary Share.

2.16 On 24 May 2018, the Company issued 1,386 Ordinary Shares at a price of 371 pence perOrdinary Share.

2.17 On 25 May 2018, the Company granted Richard Benmore 107,817 options over OrdinaryShares at an exercise price of 371 pence per Ordinary Share.

2.18 On 21 June 2018, the Company issued 1,419 Ordinary Shares at a price of 355 pence perOrdinary Share.

2.19 On 25 July 2018, the Company issued 1,488 Ordinary Shares at a price of 345 pence perOrdinary Share.

2.20 On 21 August 2018, the Company issued 1,386 Ordinary Shares at a price of 363 pence perOrdinary Share.

2.21 On 21 September 2018, the Company issued 1,356 Ordinary Shares at a price of 409 penceper Ordinary Share.

2.22 On 23 October 2018, the Company issued 1,200 Ordinary Shares at a price of 528 penceper Ordinary Share.

2.23 Pursuant to resolutions of the Shareholders passed on 14 November 2018 the Companywas authorised under section 701 of the Companies Act to make one or more marketpurchases of its Ordinary Shares of a nominal amount of 20 pence each in the capital of theCompany, of up to 3,072,062 Ordinary Shares of the Company through the Tender Offer,which represents a 20% premium to the 60-day volume weighted average price (VWAP) perOrdinary Share.

2.24 On 23 November 2018, the Company bought back 2,923,240 Ordinary Shares pursuant tothe Tender Offer, which were also cancelled on the same date.

2.25 On 20 February 2019, the Company issued 3,381 Ordinary Shares at a price of 570 penceper Ordinary Share.

2.26 On 2 May 2019, the Company issued 6,288 Ordinary Shares at a price of 633 pence perOrdinary Share.

2.27 Pursuant to resolutions of the Shareholders passed on 4 June 2019:

(a) the Directors were authorised in accordance with section 551 of the Companies Act toexercise all the powers of the Company to allot relevant securities up to an aggregatenominal amount of £1,679,841 representing the aggregate nominal value of two thirdsof the Ordinary Shares, provided that in relation to any allotment of relevant securitiesin excess of £839,920, representing the aggregate nominal value of one third of theOrdinary Shares, such authority shall only be used if the relevant securities are equitysecurities (as defined in Section 560(1) of the Companies Act) and they are allotted in

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209


connection with a rights issue or other pre-emptive issues of equity shares whichsatisfies the conditions and may be subject to all or any of the exclusions specified in2.25(b), provided that the Company may before such expiry, variation or revocationmake an offer or agreement which would or might require such relevant or equitysecurities to be allotted after such expiry, variation or revocation and the directors mayallot relevant or equity securities pursuant to such an offer or agreement as if theauthority conferred hereby had not expired or been varied or revoked;

(b) the Directors were empowered in accordance with section 570 of the Companies Actto allot equity securities (as defined in section 560 of the Companies Act) of theCompany for cash pursuant to the general authorities conferred on them by thisresolution as if section 561(1) of the Companies Act did not apply to any suchallotment, provided that such power;

(c) shall, subject to the continuance of the authority conferred by 2.25(a), expire15 months after the passing of this resolution or at the conclusion of the next annualgeneral meeting of the Company following the passing of this resolution, whicheveroccurs first, but may be previously revoked or varied from time to time by specialresolution but so that the Company may before such expiry, revocation or variationmake an offer or agreement which would or might require equity securities to beallotted after such expiry, revocation or variation and the directors of the Companymay allot equity securities in pursuance of such offer or agreement as if such powerhad not expired or been revoked or varied; and

(d) shall be limited to:

(i) the allotment of equity securities of up to an aggregate nominal amount of£839,920 pursuant to a rights issue, open offer, scrip dividend scheme or otherpre-emptive offer or scheme which is in each case in favour of holders ofOrdinary Shares and any other persons who are entitled to participate in suchissue, offer or scheme where the equity securities offered to each such holderand other person are proportionate (as nearly as may be) to the respectivenumbers of Ordinary Shares held or deemed to be held by them for thepurposes of their inclusion in such issue, offer or scheme on the record dateapplicable thereto, but subject to such exclusions or other arrangements as thedirectors of the Company may deem fit or expedient to deal with fractionalentitlements, legal or practical problems under the laws of any overseasterritory, the requirements of any regulatory body or stock exchange in anyterritory, shares being represented by depositary receipts, directions from anyholders of shares or other persons to deal in some other manner with theirrespective entitlements or any other matter whatsoever which the directors ofthe Company consider to require such exclusions or other arrangements withthe ability for the directors of the Company to allot equity securities and sellrelevant shares not taken up to any person as they may think fit; and

(ii) the allotment of equity securities for cash otherwise than pursuant to sub-paragraph (b)(i) up to an aggregate maximum nominal amount of £504,002.

(e) the Directors were authorised for the purposes of section 701 of the Companies Act tomake one or more market purchases (as defined in section 693(4) of the CompaniesAct) of its Ordinary Shares provided that:

(i) the maximum number of Ordinary Shares hereby authorised to be purchased is1,260,007;

(ii) the minimum price (exclusive of expenses) which may be paid for each OrdinaryShare is 20 pence; and

210


(iii) the maximum price (exclusive of expenses) which may be paid for eachOrdinary Share is the highest of:

(iv) an amount equal to 5% above the average market value of an Ordinary Sharefor the five business days immediately preceding the day on which that OrdinaryShare is contracted to be purchased; and

(v) the higher of the price of the last independent trade and the highest currentindependent bid on the trading venues where the purchase carried out at therelevant,

such authority to apply until the end of next annual general meeting (or, if earlier,15 months after the passing of this resolution) but during this period the Company mayenter into a contract to purchase Ordinary Shares, which would, or might becompleted or executed wholly or partly after the authority ends and the Company maypurchase Ordinary Shares pursuant to any such contract as if the authority had notended.

2.28 On 25 June 2019, the Company granted Andrew Austin 73,620 options over OrdinaryShares at an exercise price of 815 pence per Ordinary Share.

2.29 On 25 June 2019, the Company granted Peter Mann 30,675 options over Ordinary Sharesat an exercise price of 815 pence per Ordinary Share.

2.30 On 25 June 2019, Richard Benmore, Peter Mann and Steve Pawson exercised their optionsto acquire 107,817 Ordinary Shares, 212,600 Ordinary Shares and 159,450 OrdinaryShares respectively on terms of their option awards.

2.31 As at 18 July 2019, being the latest practicable date prior to publication of this document, theCompany had the following wholly owned subsidiaries all of which are incorporated inEngland and Wales.

Company’s percentage ownership in

the issued share capital of the

Name of Group company: relevant Group company:

RockRose (UKCS1) Limited(1)(3) 100%RockRose (UKCS2) Limited(1) 100%RockRose (UKCS3) Limited(1) 100%RockRose UKCS4 Limited(1) 100%RockRose UKCS5 Limited(2)(3) 100%RockRose UKCS6 Limited(2)(3) 100%RockRose UKCS7 Limited(2)(3) 100%RockRose UKCS8 LLC(1) 100%RockRose UKCS9 Limited(4) 100%RockRose UKCS10 Limited(1) 100%RockRose UKCS11 Limited(4) 100%RockRose UKCS12 Limited(4) 100%RockRose UKCS13 LLC(4) 100%RockRose Energy (NL) B.V.(1) 100%RockRose (NL) CS1 B.V.(5) 100%RockRose (NL) Infrastructure B.V.(5) 100%

(1) The Company holds a 100% direct ownership interest in this entity.

(2) The Company holds a 100% direct ownership interest in RockRose UKCS4 Limited, which in turn holds a

100% direct ownership stake in this entity.

(3) This entity is dormant.

(4) The Company holds a 100% direct ownership interest in RockRose UKCS8 LLC, which in turn holds a 100%

direct ownership stake in this entity.

Annex I, 7.2, 25

211


(5) The Company holds a 100% direct ownership interest in RockRose Energy (NL) B.V., which in turn holds a

100% direct ownership stake in this entity.

3. Share capital

The following table shows the issued and fully paid shares of the Company at the date of thisdocument and Admission:

Class of share Number Amount paid

Ordinary 13,090,595 £106,668,349

3.1 Save as disclosed in this document:

(a) no share or loan capital of the Company has been issued or is proposed to be issued;

(b) no person has any preferential subscription rights for any shares of the Company;

(c) no share or loan capital of the Company is unconditionally to be put under option; or

(d) no commissions, discounts, brokerages or other special terms have been granted bythe Company since its incorporation in connection with the issue or sale of any shareor loan capital of the Company.

3.2 All Ordinary Shares in the capital of the Company are in registered form.

3.3 The Ordinary Shares will have a Standard Listing and be traded on the Main Market of theLondon Stock Exchange. The Ordinary Shares are not listed or traded on, and no applicationhas been or is being made for the admission of the Ordinary Shares to listing or trading onany other stock exchange or securities market.

4. Articles

4.1 The Articles were adopted (with effect from Initial Admission) by a special resolution of theFounder Shareholder passed at a general meeting of the Company (held on short notice) on5 November 2015. A summary of the terms of the Articles is set out below. The summarybelow is not a complete copy of the terms of the Articles.

4.2 The Articles contain no specific restrictions on the Company’s objects and therefore, byvirtue of section 31(1) of the Companies Act, the Company’s objects are unrestricted.

4.3 The Articles contain, inter alia, provisions to the following effect:

(a) Share Capital

The Company’s share capital currently consists of Ordinary Shares. The Companymay issue shares with such rights or restrictions as may be determined by ordinaryresolution, including shares which are to be redeemed, or are liable to be redeemedat the option of the Company or the holder of such shares.

(b) Voting

The Shareholders have the right to receive notice of, and to vote at, general meetingsof the Company. Each Shareholder who is present in person (or, being a corporation,by representative) at a general meeting on a show of hands has one vote and, on apoll, every such holder who is present in person (or, being a corporation, byrepresentative) or by proxy has one vote in respect of every share held by him.

LR 2.2.4(2)

Annex I, 21.1.1,

21.1.6, 21.2.3

Annex III, 4.3,

4.5, 6.2

Annex I, 21.2.1

LR 2.2.2(2)

212


(c) Variation of rights

Whenever the share capital of the Company is divided into different classes of shares,the special rights attached to any class may be varied or abrogated either with theconsent in writing of the holders of three-fourths in nominal value of the issued sharesof that class or with the sanction of a special resolution passed at a general meetingof the holders of the shares of that class and may be so varied and abrogated whilstthe Company is a going concern or during or in contemplation of a winding up.

(d) Dividends

The Company may, subject to the provisions of the Companies Act and the Articles,by ordinary resolution from time to time declare dividends to be paid to members notexceeding the amount recommended by the Directors. Subject to the provisions of theCompanies Act in so far as, in the Directors’ opinions, the Company’s profits justifysuch payments, the Directors may pay interim dividends on any class of shares.

Any dividend unclaimed after a period of 12 years from the date such dividend wasdeclared or became payable shall, if the Directors resolve, be forfeited and shall revertto the Company. No dividend or other moneys payable on or in respect of a share shallbear interest as against the Company.

(e) Transfer of Ordinary Shares

Each member may transfer all or any of his shares which are in certificated form bymeans of an instrument of transfer in any usual form or in any other form which theDirectors may approve. Each member may transfer all or any of his shares which arein uncertificated form by means of a ‘relevant system’ (i.e., CREST) in such mannerprovided for, and subject as provided in, the CREST Regulations.

The Board may, in its absolute discretion, refuse to register a transfer of certificatedshares unless:

(i) it is for a share which is fully paid up;

(ii) it is for a share upon which the Company has no lien;

(iii) it is only for one class of share;

(iv) it is in favour of a single transferee or no more than four joint transferees;

(v) it is duly stamped or is duly certificated or otherwise shown to the satisfaction ofthe Board to be exempt from stamp duty; and

(vi) it is delivered for registration to the registered office of the Company (or suchother place as the Board may determine), accompanied (except in the case ofa transfer by a person to whom the Company is not required by law to issue acertificate and to whom a certificate has not been issued or in the case of arenunciation) by the certificate for the shares to which it relates and such otherevidence as the Board may reasonably require to prove the title of the transferor(or person renouncing) and the due execution of the transfer or renunciation byhim or, if the transfer or renunciation is executed by some other person on hisbehalf, the authority of that person to do so.

The Directors may refuse to register a transfer of uncertificated shares in anycircumstances that are allowed or required by the CREST Regulations and CREST.

Annex I, 20.7

Annex III, 4.3,

4.8

LR 2.2.4(1)

Annex I, 21.2.3,

21.2.4

213


(f) Allotment of shares and pre-emption rights

Subject to the Companies Act and to any rights attached to existing shares, any sharemay be issued with or have attached to it such rights and restrictions as the Companymay by ordinary resolution determine, or if no ordinary resolution has been passed orso far as the resolution does not make specific provision, as the Directors maydetermine (including shares which are to be redeemed, or are liable to be redeemedat the option of the Company or the holder of such shares).

(g) Alteration of share capital

The Company may by ordinary resolution consolidate or divide all of its share capitalinto shares of larger nominal value than its existing shares, or cancel any shareswhich, at the date of the ordinary resolution, have not been taken or agreed to betaken by any person and diminish the amount of its share capital by the nominalamount of shares so cancelled or sub-divide its shares, or any of them, into shares ofsmaller nominal value.

The Company may, in accordance with the Companies Act, reduce or cancel its sharecapital or any capital redemption reserve or share premium account in any mannerand with and subject to any conditions, authorities and consents required by law.

(h) Directors

Unless otherwise determined by the Company by ordinary resolution, the number ofDirectors (other than any alternate Directors) shall not be less than two, but there shallbe no maximum number of Directors.

Subject to the Articles and the Companies Act, the Company may by ordinaryresolution appoint a person who is willing to act as a Director and the Board shall havepower at any time to appoint any person who is willing to act as a Director, in bothcases either to fill a vacancy or as an addition to the existing Board.

At every annual general meeting any director who:

(i) has been appointed by the Directors since the last annual general meeting; or

(ii) was not appointed or re-appointed at one of the preceding two annual generalmeetings must retire from office and may offer themselves for reappointment bythe Shareholders by ordinary resolution.

Subject to the provisions of the Articles, the Board may regulate their proceedings asthey think fit. A Director may, and the secretary at the request of a Director shall, calla meeting of the Directors.

The quorum for a Directors’ meeting shall be fixed from time to time by a decision ofthe Directors, but it must never be less than two and unless otherwise fixed, it is two.

Questions and matters requiring resolution arising at a meeting shall be decided by amajority of votes of the participating Directors, with each director having one vote. Inthe case of an equality of votes, the chairman will only have a casting vote or secondvote when an acquisition has been completed. The entering into any furtheracquisition requires the consent of 75% of the Directors present and entitled to vote.

The Directors shall be entitled to receive such remuneration as the Directors shalldetermine for their services to the Company as directors and for any other servicewhich they undertake for the Company provided that the aggregate fees payable tothe Directors must not exceed £200,000 per annum. The Directors shall also beentitled to be paid all reasonable expenses properly incurred by them in connectionwith their attendance at meetings of Shareholders or class meetings, board or

Annex I, 21.2.8

Annex III, 4.5

Annex III, 4.5

214


committee meetings or otherwise in connection with the exercise of their powers andthe discharge of their responsibilities in relation to the Company.

The Board may, in accordance with the requirements in the Articles, authorise anymatter proposed to them by any Director which would, if not authorised, involve aDirector breaching his duty under the Companies Act to avoid conflicts of interests.

A Director seeking authorisation in respect of such conflict shall declare to the Boardthe nature and extent of his interest in a conflict as soon as is reasonably practicable.The Director shall provide the Board with such details of the matter as are necessaryfor the Board to decide how to address the conflict together with such additionalinformation as may be requested by the Board.

Any authorisation by the Board will be effective only if:

(i) to the extent permitted by the Companies Act, the matter in question shall havebeen proposed by any Director for consideration in the same way that any othermatter may be proposed to the Directors under the provisions of the Articles;

(ii) any requirement as to the quorum for consideration of the relevant matter is metwithout counting the conflicted Director and any other conflicted Director; and

(iii) the matter is agreed to without the conflicted Director voting or would be agreedto if the conflicted Director’s and any other interested Director’s vote is notcounted.

Subject to the provisions of the Companies Act, every Director, secretary or other officerof the Company (other than an auditor) is entitled to be indemnified against all costs,charges, losses, damages and liabilities incurred by him in the actual purported exerciseor discharge of his duties or exercise of his powers or otherwise in relation to them.

(i) General Meetings

The Company must convene and hold annual general meetings in accordance withthe Companies Act.

No business shall be transacted at any general meeting unless a quorum is presentwhen the meeting proceeds to business, but the absence of a quorum shall notpreclude the choice or appointment of a chairman of the meeting which shall not betreated as part of the business of the meeting. Save as otherwise provided by thearticles, two Shareholders present in person or by proxy and entitled to vote shall bea quorum for all purposes.

(j) Borrowing Powers

Subject to the Articles and the Companies Act, the Board may exercise all of thepowers of the Company to:

(i) borrow money;

(ii) indemnify and guarantee;

(iii) mortgage or charge;

(iv) create and issue debentures and other securities; and

(v) give security either outright or as collateral security for any debt, liability orobligation of the Company or of any third party.

Annex I, 21.2.2

Annex I, 10.3

215


(k) Capitalisation of profits

The Directors may, if they are so authorised by an ordinary resolution of theShareholders, decide to capitalise any undivided profits of the Company (whether ornot they are available for distribution), or any sum standing to the credit of theCompany’s share premium account or capital redemption reserve. The Directors mayalso, subject to the aforementioned ordinary resolution, appropriate any sum whichthey so decide to capitalise to the persons who would have been entitled to it if it weredistributed by way of dividend and in the same proportions.

(l) Uncertificated Shares

Subject to the Companies Act, the Directors may permit title to shares of any class tobe issued or held otherwise than by a certificate and to be transferred by means of a‘relevant system’ (i.e., CREST) without a certificate.

The Directors may take such steps as it sees fit in relation to the evidencing of andtransfer of title to uncertificated shares, any records relating to the holding ofuncertificated shares and the conversion of uncertificated shares to certificatedshares, or vice-versa.

The Company may by notice to the holder of an uncertificated share, require thatshare to be converted into certificated form.

The Board may take such other action that the Board considers appropriate to achievethe sale, transfer, disposal, forfeiture, re-allotment or surrender of an uncertified shareor otherwise to enforce a lien in respect of it.

5. Other Relevant Laws and Regulations

5.1 Mandatory bid

(a) The Takeover Code applies to the Company. Under the Takeover Code, where:

(i) any person acquires, whether by a series of transactions over a period of time or not,an interest in shares which (taken together with shares in which he is alreadyinterested, and in which persons acting in concert with him are interested) carry 30%or more of the voting rights of a company; or

(ii) any person who, together with persons acting in concert with him, is interested inshares which in the aggregate carry not less than 30% of the voting rights of acompany but does not hold shares carrying more than 50% of such voting rights andsuch person, or any person acting in concert with him, acquires an interest in any othershares which increases the percentage of shares carrying voting rights in which he isinterested;

such person shall, except in limited circumstances, be obliged to extend offers, on the basisset out in Rules 9.3, 9.4 and 9.5 of the Takeover Code, to the holders of any class of equityshare capital whether voting or non-voting and also to the holders of any other class oftransferable securities carrying voting rights. Offers for different classes of equity sharecapital must be comparable; the Takeover Panel should be consulted in advance in suchcases.

(b) An offer under Rule 9 of the Takeover Code must be in cash and at the highest price paidfor any interest in the shares by the person required to make an offer or any person actingin concert with him during the 12 months prior to the announcement of the offer.

(c) Under the Takeover Code, a ‘concert party’ arises where persons acting together pursuantto an agreement or understanding (whether formal or informal and whether or not in writing)actively co-operate, through the acquisition by them of an interest in shares in a company,

Annex III, 4.9

Annex III, 4.5

216


to obtain or consolidate control of the company. ‘Control’ means holding, or aggregateholdings, of an interest in shares carrying 30% or more of the voting rights of the company,irrespective of whether the holding or holdings give de facto control.

(d) There have been no public takeover bids by third parties in respect of the Company’s equityin the current financial year or the previous financial year.

5.2 Squeeze-out

(a) Under sections 979 to 982 of the Companies Act, if an offeror were to acquire 90% of theOrdinary Shares it could then compulsorily acquire the remaining 10%. It would do so bysending a notice to outstanding Shareholders telling them that it will compulsorily acquiretheir shares, provided that no such notice may be served after the end of: (a) the period ofthree months beginning with the day after the last day on which the offer can be accepted;or (b) if earlier, and the offer is not one to which section 943(1) of the Companies Act applies,the period of six months beginning with the date of the offer.

(b) Six weeks following service of the notice, the offeror must send a copy of it to the Companytogether with the consideration for the Ordinary Shares to which the notice relates, and aninstrument of transfer executed on behalf of the outstanding Shareholder(s) by a personappointed by the offeror.

(c) The Company will hold the consideration on trust for the outstanding Shareholders.

5.3 Sell-out

(a) Sections 983 to 985 of the Companies Act also give minority Shareholders in the Companya right to be bought out in certain circumstances by an offeror who has made a takeoveroffer. If a takeover offer relating to all the Ordinary Shares is made at any time before theend of the period within which the offer could be accepted and the offeror held or had agreedto acquire not less than 90% of the Ordinary Shares, any holder of shares to which the offerrelated who had not accepted the offer could by a written communication to the offerorrequire it to acquire those shares. The offeror is required to give any Shareholder notice ofhis right to be bought out within one month of that right arising. The offeror may impose atime limit on the rights of minority Shareholders to be bought out, but that period cannot endless than three months after the end of the acceptance period, or, if longer a period of threemonths from the date of the notice.

(b) If a Shareholder exercises his/her rights, the offeror is bound to acquire those shares on theterms of the offer or on such other terms as may be agreed.

5.4 Shareholder notification and disclosure requirements

(a) Shareholders are obliged to comply with the shareholding notification and disclosurerequirements set out in Chapter 5 of the DTRs. A Shareholder is required pursuant to Rule 5of the DTRs to notify the Company if, as a result of an acquisition or disposal of shares orfinancial instruments, the Shareholder’s percentage of voting rights of the Companyreaches, exceeds or falls below, 3% of the nominal value of the Company’s share capital orany 1% threshold above that.

(b) The DTRs can be accessed and downloaded from the FCA’s website athttp://fshandbook.info/FS/html/FCA/DTR. Shareholders are urged to consider theirnotification and disclosure obligations carefully as a failure to make a required disclosure tothe Company may result in disenfranchisement.

Annex III, 4.9

217


6. Directors’ and Senior Managers’ and Other Interests

6.1 Save as disclosed below, no Director nor Senior Manager nor any member of theirimmediate families has at the date of this document or will have on Admission any interests(beneficial or non-beneficial) in the Ordinary Shares of the Company:

Name No. of Ordinary Shares

Andrew Austin(1) 3,563,234Richard Benmore(2) 320,729John Morrow 212,808Peter Mann 281,203Steve Pawson 205,363

(1) Of the 3,563,234 Ordinary Shares held by Mr. Austin, 2,843,234 Ordinary Shares are held by him legally and

beneficially, the balance of 720,000 Ordinary Shares are held in his SIPP, administered by Rowanmoor

Trustees.

(2) Mr. Benmore’s Ordinary Shares are held in the name of his wife, Judith Helen Benmore.

6.2 In addition to their directorships of the Group, the Directors and Senior Managers are, orhave been, members of the administrative, management or supervisory bodies or partnersof the following companies or partnerships, at any time in the five years prior to the date ofthis document:

Name Current directorships/partnerships Previous directorships/partnerships

Andrew Austin Artisan Ginyard Ltd IGas Energy plcIGas Energy Enterprise LimitedIGas Energy Production LimitedIGas Exploration UK LimitedIGas Energy DevelopmentIsland Gas LimitedStar Energy Group Limited StarEnergy LimitedStar Energy (East Midlands)LimitedStar Energy Weald Basin LimitedStar Energy Oil & Gas LimitedStar Energy Oil UK LimitedIsland Gas (Singleton) LimitedIGas Exploration UK LimitedIsland Gas Operations LimitedDart Energy (Europe) LtdDart Energy (Carbon Storage)LimitedDart Energy (East England) LimitedDart Energy (Lothian) LimitedDart Energy (West England)LimitedGreenpark Energy TransportationLimitedDart Energy SPV No1 Pty LtdDart Energy SPV No 2 Pty LtdDart Energy (Bruxner) Pty LtdDart Energy (Overseas) Pty LtdDart Energy (China) Pty LtdApollo Gas LimitedDart Energy (Apollo) Pty Ltd

Annex I, 17.2

Annex I, 14.1

218


Name Current directorships/partnerships Previous directorships/partnerships

Andrew Austin Artisan Ginyard Ltd Dart Energy Global CBM Pty LtdDart Energy (India) Pty LtdDart Energy International LtdDart Energy Europe Pte LtdDart Energy (Vietnam) HoldingsPte. LtdDart Energy (Hanoi Basin CBM)Pte. LtdDart Energy (China) Holdings Pte.LtdDart Energy (Dajing) Pte. LtdDart Energy Asia Holdings Pte LtdDart Energy (India) Holdings Pte.LtdDart Energy (AS) Pte. LtdDart Energy (ST) Pte. LtdDart Energy India (CMM) Pte. LtdDart Energy (CIL) Pte. LtdDart Energy (MG) Pte. LtdDart Energy (India) Pte. LtdDart Energy (Indonesia) HoldingsPte. LtdDart Energy (Tanjung Enim) Pte.LtdDart Energy (Muralim) Pte. LtdDart Energy (Bontang Bengalon)Pte. LtdDart Energy (Sangatta West) Pte.LtdDart Energy (CBM PowerIndonesia) Pte. Ltd.PT Dart Energy IndonesiaPT Coal Bed Methane PowerIndonesiaUK Onshore Oil and Gas

– –Richard

Benmore

John Morrow JACM Consultants Limited Sand Geophysics Limited

Peter Mann – Mann & Co LtdStrae Capital Limited

Richard Slape Hopton Petroleum Limited Lansdowne Oil & Gas plcLansdowne Celtic Sea Limited

Steve Pawson SHP Accounting LtdLythe Hill Park ManagementCompany LimitedLythe Hill Park Limited

–

219


6.3 At the date of this document, none of the Directors or Senior Managers has at any timewithin the last five years:

(a) had any convictions in relation to fraudulent offences for at least the previous fiveyears;

(b) been associated with any bankruptcy, receivership or liquidation while acting in thecapacity of a member of the administrative, management or supervisory body or ofsenior manager of any company for at least the previous five years; or

(c) has been subject to any official public incrimination and/or sanction of him by anystatutory or regulatory authority (including any designated professional bodies) or hasever been disqualified by a court from acting as a director of a company or from actingas a member of the administrative, management or supervisory bodies of an issuer orfrom acting in the management or conduct of the affairs of any issuer for at least theprevious five years,

6.4 None of the Directors or Senior Managers has any potential conflicts of interest betweentheir duties to the Company and their private interests or other duties they may also have.

6.5 There are no family relationships between any Directors or Senior Managers.

6.6 There are no outstanding loans granted by the Company to the Directors or SeniorManagers or any guarantees provided by the Company for the benefit of the Directors orSenior Managers.

6.7 Save as set out in paragraph 11 of this Part XIX – Additional Information of this Document,there are no service contracts or consultancy agreements between any of the Directors orSenior Managers and the Company or any of its subsidiaries and no such contract has beenentered into or amended or replaced within the six months preceding the date of thisdocument and no such contracts are proposed.

6.8 Save as set out in paragraph 11 of this Part XIX – Additional Information of this Document,the Directors and Senior Managers receive no Ordinary Shares or options over OrdinaryShares in lieu of remuneration or as any form of compensation.

6.9 Other than as disclosed in paragraph 11 of this Part XIX – Additional Information of thisDocument, the Company is not party to any service contract with any of the Directors orSenior Managers which provides for benefits on the termination of any such contract.

6.10 No Director or Senior Manager has any accrued pension or retirement benefits, other thanstatutory pension entitlements.

6.11 There is no arrangement under which any Director or Senior Manager has waived or agreedto waive future emoluments.

6.12 In the year ended 31 December 2018, the total aggregate remuneration paid, and benefits-in- kind granted, to the Directors was US$1,686,000.

Annex I, 14.2

220


6.13 Save as set out below, the Directors are not aware of any person who, directly or indirectly,had an interest in 3% or more of the voting rights of the Company as at the date ofpublication of this document and Admission:

Percentage

of issued

No. of Ordinary Ordinary Share

Shares at the capital at the

date of this date of this

document and document and

Shareholder Admission Admission

Andrew Austin(1) 3,563,234 27.21%Cavendish Asset Management Limited 1,816,800 13.87%Macquarie Capital (Europe) Limited 747,588 5.71%

(1) Of the 3,563,234 Ordinary Shares held by Mr. Austin, 2,843,234 Ordinary Shares are held by him legally and

beneficially, the balance of 720,000 Ordinary Shares are held in his SIPP which is administered by

Rowanmoor Trustees.

6.14 As at 18 July 2019 (being the latest practicable date prior to the publication of thisdocument), the Company was not aware of any person or persons who, directly or indirectly,jointly or severally, exercise or could exercise control over the Company nor is it aware ofany arrangements, the operation of which may at a subsequent date result in a change incontrol of the Company.

6.15 There have been no public takeover bids by third parties in respect of the Company’s equityin the current financial year or the previous financial year.

6.16 Those interested, directly or indirectly, in 3% or more of the issued Ordinary Shares of theCompany (as set out in paragraph 6.13 of this Part XIX – Additional Information of thisDocument) do not now, and, following Admission, will not, have different voting rights fromother holders of Ordinary Shares.

7. Working Capital

The Company is of the opinion that the working capital available to the Enlarged Group (which forthe avoidance of doubt includes the Marathon Group) is sufficient for the present requirements ofthe Enlarged Group, that is, for at least the next 12 months following the date of this document.

8. Significant Change

Since 31 December 2018 (being the end of the last financial period of the entities making up theEnlarged Group for which financial information has been published), the only significant changesin the financial or trading position of the Enlarged Group were:

• the completion of the Marathon Acquisition by the Company; and

• MOUK (now RockRose UKCS8) being notified on 20 June 2019 by TAQA Bratani, asignificant non-operator interest holder in those licences,following the approval of theproposals made by TAQA Bratani to the other members of the relevant operating committeeson 5 June 2019, that it would be discharged as operator of Blocks 16/7a, Licence no. P.108(Block 16/3a), Licence no. P.313 (Block 16/3b), Licence no. P.313 (Block 16/3c) and TAQABratani appointed in its place. No reasons were given for the changes. A process will followinvolving OGA approval, which could result in the Enlarged Group losing operatorship ofthese licences in July 2020.

Annex I, 18.2

Annex III, 3.1

Annex I, 21.2.6

Annex I, 18.1,

18.3, 18.4

221


9. Litigation and Disputes

Petrojarl Foinaven FPSO

On 6 December 2018, Golar-Nor (UK) Limited (“Golar”) issued proceedings in the CommercialCourt against all the joint venture partners in Foinaven (including MOWOS (now RockRoseUKCS10)) in connection with the FPSO contract dated 17 November 1994, as amended. Theclaim alleges that a solids management issue affected the FPSO gas compression system,resulting in shutdowns and a requirement for the replacement of certain parts, and causing a lossof revenue and maintenance costs for the replacement of parts. MOWOS’s exposure for the claimis quantified at £78.3 million (plus interest), together with declaratory relief in relation to revenueshortfall and maintenance costs for the period 6 December 2012 to 31 December 2013 and inrelation to any future losses or damages relating to the same issue (plus interest).

The risk to MOWOS will be proportional to its 28% working interest. The Foinaven joint venturepartners instructed a Queen’s Counsel to advise on the claim as they considered it to be spuriousdue to the exclusion of consequential loss in certain contractual arrangements. A defence was filedon 13 February 2019. The Foinaven joint venture partners have requested further particulars of theclaim and reserved their right to plead further to the claim as properly particularised (including theright to submit further defences or a counterclaim). The parties agreed to a stay of proceedingsuntil end of September 2019, with a case management conference to be scheduled no sooner than25 November 2019.

UK – Brae – Offshore Investigation of Brae A Installation

MOUK (now RockRose UKCS8) was investigated by the HSE for a release of gas from the BraeAlpha platform. The Aberdeen Sherriff Court heard that on 26 December 2015, an eight-inchdiameter high pressure pipework in Module 14 of the platform suffered a catastrophic rupture as aresult of ‘Corrosion under Insulation’, allowing over two tonnes of high-pressure methane gas tobe released almost instantaneously. The incident did not result in any injuries, only significantdamage to the pipework within Module 14. An investigation by HSE found that MOUK had failedto undertake any suitable and sufficient inspection of the pipework that would have allowed thecompany to identify the risk and prevent the hazard from materialising. MOUK pleaded guilty tobreaching regulation 4(1) of the Offshore Installations (Prevention of Fire and Explosion, andEmergency Response) Regulations 1995 and section 33(1) of the Health and Safety at Work Act1974, at Aberdeen Sheriff Court. On 20 May 2019, MOUK was fined £1,160,000.

Save as set out above, there have been no governmental, legal or arbitration proceedings and theCompany is not aware of any governmental legal or arbitration proceedings pending or threatened,nor of any such proceedings having been pending or threatened during the 12 months prior to thedate of this document which may have, or have had in the recent past, a significant effect on thefinancial position or profitability of the Enlarged Group.

10. Material Contracts

The following are all of the contracts (not being contracts entered into in the ordinary course ofbusiness) that have been entered into by the Company since the Company’s incorporation which;(i) are, or may be, material to the Company or the Group; or (ii) contain obligations or entitlementswhich are, or may be, material to the Company as at the date of this document.

10.1 Idemitsu UK Acquisition Agreement

The Idemitsu UK Acquisition Agreement was entered into on 17 October 2017 and wasconditional upon the OGA confirming that it had no objection to the change of control ofIdemitsu UK and the release of Idemitsu Group and its affiliates from any guarantee givento a bank in respect of any DSAs to which Idemitsu UK was a party. As noted above, theCompany received a letter from the OGA on 30 November 2017 confirming that it currentlyhas no objection to the change of control of Idemitsu UK and the remaining condition wasalso satisfied.

Annex I, 22

Annex I, 20.8

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The consideration for the Idemitsu UK Acquisition was US$29.7 million, effective, foreconomic purposes as at 1 July 2017. The Idemitsu UK Acquisition was subject to certainadjustments recorded in the Idemitsu UK Acquisition Agreement relating to certain taxrefunds and proceeds of an insurance claim, the effect of which was to increase theconsideration payable to Idemitsu Group by US$652,000. At completion, the Companyacquired Idemitsu UK with cash at bank of US$139.7million.

The Idemitsu UK Acquisition Agreement contained customary warranties andrepresentations relating to Idemitsu Group’s interests in Idemitsu UK, which were given tothe Company by Idemitsu Group on the one hand, and by the Company to Idemitsu Groupon the other hand, as at the date of signing of the Idemitsu UK Acquisition Agreement; eachsuch representation and warranty was repeated on the date of completion of the IdemitsuUK Acquisition (i.e., 8 December 2017).

Claims under the Idemitsu UK Acquisition Agreement were subject to certain financial, timeand other limitations that are customary in agreements of this type. Idemitsu Group will notbe liable in respect of a claim under the Idemitsu UK Acquisition Agreement unless theliability under such claim exceeds £10,000. The overall cap and aggregate liability ofIdemitsu Group in respect of claims under the Idemitsu UK Acquisition Agreement was£50,000. The limitation period in respect of a claim under the Idemitsu UK AcquisitionAgreement expires 12 months following completion of the Idemitsu UK Acquisition (i.e.,8 December 2018). Pursuant to the terms of the Idemitsu UK Acquisition Agreement, theCompany agreed to indemnify Idemitsu Group and its affiliates against, and agreed toassume full responsibility for, any and all environmental liabilities (including but not limited toclaims, demands, actions, proceedings and costs) in relation to the licences to whichIdemitsu UK was a party, provided that the Company shall not be responsible for, and shallnot be required to make, any payment in respect of amounts actually paid by Idemitsu Groupand its affiliates prior to 1 July 2017.

The Idemitsu UK Acquisition Agreement was governed by the laws of England and Walesand the parties irrevocably agreed to the exclusive jurisdiction of the courts of England andWales in relation to any action or proceeding arising out of the Idemitsu UK AcquisitionAgreement.

10.2 Arran Acquisition Agreement

The Arran Acquisition Agreement was entered into on 8 August 2018. The Company paidnominal consideration of US$1 in connection with the Arran Acquisition.

The transaction was conditional on, inter alia, consent of the OGA to the transfer by the ArranSeller to RockRose UKCS4 Limited of the licence interests, the receipt of all necessarywritten consents, approvals or waiver, as the case may be, by the co-venturers in relation tothe Arran Acquisition and RockRose UKCS4 Limited being appointed as an appointedoperator or licence administrator (subject to the consent of the OGA and any relevant thirdparty) in respect of certain licence interests. The consent from the OGA was granted prior tocompletion of the Arran Acquisition.

The Arran Acquisition Agreement contained customary warranties, which were given to theArran Seller by RockRose UKCS4 Limited on the one hand, and by the Arran Seller toRockRose UKCS4 Limited on the other hand, as at the date of signing of the ArranAcquisition Agreement; each warranty was repeated on the date of completion of the ArranAcquisition (i.e., 10 October 2018).

Claims under the Arran Acquisition Agreement were subject to certain financial, time andother limitations that are customary in agreements of this type. The Arran Seller is not beliable in respect of a claim under the Arran Acquisition Agreement unless the liability undersuch claim exceeds US$150,000. The overall cap and aggregate liability of Idemitsu Group

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in respect of claims under the Arran Acquisition Agreement was US$350,000. The limitationperiod in respect of a claim under the Arran Acquisition Agreement expires 12 monthsfollowing completion of the Arran Acquisition (i.e., 9 October 2019). Pursuant to the terms ofthe Arran Acquisition Agreement, RockRose UKCS4 Limited agreed to indemnify the ArranSeller and its affiliates against, and agreed to assume full responsibility for, any and alldecommissioning liabilities, safety liabilities and/or environmental liabilities (including but notlimited to claims, demands, actions, proceedings and costs) in relation to the licenceswhether before or after completion and regardless or who was a licensee under the relevantlicence or a party to the joint operating agreements or owned or leased the relevant propertyand regardless of whether such losses and expenses arise as a consequence of negligenceor breach of any environmental law or other applicable law on the part of the Arran Seller orany of its affiliates.

The Arran Acquisition Agreement was governed by the laws of England and Wales and theparties irrevocably agreed to the exclusive jurisdiction of the courts of England and Wales inrelation to any action or proceeding arising out of the Arran Acquisition Agreement.

10.3 Dyas Acquisition Agreement

The Dyas Acquisition Agreement was entered into on 23 May 2018. The consideration paidby the Company in connection with the Dyas Acquisition was approximately EUR 107 million(US$124 million).

The transaction was conditional on, inter alia, obtaining a consent to an indirect change ofcontrol and the withdrawal of guarantees issued by Dyas in relation to some of its Danishlicences. These conditions were satisfied prior to the completion of the Dyas Acquisition.

Claims under the Dyas Acquisition Agreement were subject to certain financial, time andother limitations that are customary in agreements of this type. The threshold to be exceededin respect of the aggregate amount of all warranty claims was EUR 2,000,000 in which casethe Dyas Seller shall be liable for the whole amount claimed and not only the excess. Thelimitation period in respect of warranty and indemnity claims under the Dyas AcquisitionAgreement expires three years following completion of the Dyas Acquisition in the case ofthe general warranties and in the case of a claim under the tax warranties or the taxindemnities the earlier of (i) the date of conclusion of any tax audit, enquiry or similar processcarried out by a tax authority in respect of the Dutch State profit share returns of Dyas for(or incorporating) the fiscal year 2018 or (ii) 1 January 2021. The overall cap and aggregateliability of the Dyas Seller in respect of claims under the Dyas Acquisition Agreement will notexceed 80% of the purchase price (EUR 86,000,000).

The Dyas Acquisition Agreement was governed by the laws of the Netherlands and theparties irrevocably submitted to the exclusive jurisdiction of the courts of the Netherlands inrelation to any action or proceeding arising out of the Dyas Acquisition Agreement.

10.4 Repurchase Agreement with Cantor Fitzgerald

The Company and Cantor Fitzgerald Europe (“Cantor Fitzgerald”) entered into arepurchase agreement on 23 October 2018 pursuant to which the Company has agreed topurchase from Cantor Fitzgerald, on market, such number of Ordinary Shares as CantorFitzgerald purchased pursuant to the Tender Offer, at an aggregate price equal to theamount paid by Cantor Fitzgerald for the Ordinary Shares (the “Repurchase Agreement”).

Under the terms of the Repurchase Agreement, the Company agreed that, immediatelyfollowing the purchase by Cantor Fitzgerald of all Ordinary Shares which it agreed topurchase under the terms of the Repurchase Agreement, the Company would purchasefrom Cantor Fitzgerald such Ordinary Shares (less any on-sale Ordinary Shares) at the priceof 560 pence.

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The Repurchase Agreement contained certain representations, warranties and undertakingsfrom Cantor Fitzgerald in favour of the Company concerning its authority to enter into theRepurchase Agreement and to make the purchase of Ordinary Shares pursuant thereto. TheRepurchase Agreement also contained representations and warranties from the Companyin favour of Cantor Fitzgerald and incorporated an indemnity in favour of Cantor Fitzgeraldin respect of any liability which it suffered in relation to its performance under the TenderOffer. The Company has no continuing unperformed obligations under the RepurchaseAgreement.

10.5 Marathon Acquisition Agreements

The Marathon Acquisition Agreements were entered into on 24 February 2019. Theconsideration payable by the Company in connection with the Marathon Acquisition is circaUS$140 million (subject to adjustments).

MOUK Acquisition Agreement

The transaction was conditional on, inter alia, (1) the receipt by the Company of writtenconfirmation from the Secretary of State for Business, Energy and Industrial Strategy in theUnited Kingdom that he does not intend, as a consequence of the transaction, to (i) revokeany licences held directly or indirectly by MOHL or any member of its group or (ii) require achange of control of any member of MOHL’s group under the terms of the licences helddirectly or indirectly by the same; (2) the Company providing written evidence that it hasprocured, at its own cost, pension trustees liability insurance cover for the trustees of thedefined benefit pension held by MSGB (now RockRose UKCS9); and (3) the replacementby the Company, from completion, of all insurance required to support the membership ofMOUK (now RockRose UKCS8) in the Offshore Pollution Liability Association Ltd scheme,which cover shall be in full force and effect from completion. These conditions were satisfiedprior to the completion of the Marathon Acquisition. On 26 June 2019, the Company receiveda letter from the OGA confirming that it currently has no objection to the change of control ofthe Marathon Group, and the Marathon Acquisition completed on 1 July 2019.

The MOUK Acquisition Agreement contained customary warranties and certain indemnities,which were given to MOHL by the Company on the one hand, and by MOHL to the Companyon the other hand.

Claims under the MOUK Acquisition Agreement were subject to certain financial, time andother limitations that are customary in agreements of this type. MOHL will not be liable inrespect of a claim under the MOUK Acquisition Agreement unless the liability under suchclaim exceeds US$350,000 in which case MOHL shall be liable for the whole amountclaimed and not only the excess. The overall cap and aggregate liability of MOHL in respectof general claims under the MOUK Acquisition Agreement was US$10,000,000, althoughthis amount rises to US$150,000,000 in respect of certain accounts date warranties andUS$120,000,000 in respect of certain tax warranties and tax covenants. The limitation periodin respect of a claim under the MOUK Acquisition Agreement expires 12 months followingcompletion of the Marathon Acquisition in respect of non-tax claims and five years followingthe completion of the Marathon Acquisition for certain tax claims. The MOUK AcquisitionAgreement also contains customary indemnities in respect of all decommissioning liabilitiesand/or environmental obligation in relation to the licences resulting from any acts oromissions, negligence or breach of duty, conduct or statements of any indemnified person.

The MOUK Acquisition Agreement was governed by the laws of England and Wales and theparties irrevocably agreed to the exclusive jurisdiction of the London Court of InternationalArbitration in relation to any action or proceeding arising out of the MOUK AcquisitionAgreement.

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MOWOS Acquisition Agreement

The transaction was conditional on, inter alia, the receipt by the Company of writtenconfirmation from the Secretary of State for Business, Energy and Industrial Strategy in theUnited Kingdom that he does not intend, as a consequence of the transaction, to (i) revokeany licences held directly or indirectly by MIOH or any member of its group or (ii) require achange of control of any member of MIOH’s group under the terms of the licences helddirectly or indirectly by the same. These conditions were satisfied/waived prior to thecompletion of the Marathon Acquisition. On 26 June 2019, the Company received a letterfrom the OGA confirming that it currently has no objection to the change of control of theMarathon Group, and the Marathon Acquisition completed on 1 July 2019.

The MOWOS Acquisition Agreement contained customary warranties and certainindemnities, which were given to MIOH by the Company on the one hand, and by MIOH tothe Company on the other hand.

Claims under the MOWOS Acquisition Agreement were subject to certain financial, time andother limitations that are customary in agreements of this type. MIOH will not be liable inrespect of a claim under the MOWOS Acquisition Agreement unless the liability under suchclaim exceeds US$3,150,000 in which case MIOH shall be liable for the whole amountclaimed and not only the excess. The overall cap and aggregate liability of MIOH in respectof general claims under the MOWOS Acquisition Agreement was US$90,000,000, althoughthis amount rises to US$150,000,000 in respect of certain accounts date warranties andUS$30,000,000 in respect of certain tax warranties and tax covenants. The limitation periodin respect of a claim under the MOWOS Acquisition Agreement expires 12 months followingcompletion of the Marathon Acquisition in respect of non-tax claims and five years followingthe completion of the Marathon Acquisition for certain tax claims. The MOWOS AcquisitionAgreement also contains customary indemnities in respect of all decommissioning liabilitiesand/or environmental obligation in relation to the licences resulting from any acts oromissions, negligence or breach of duty, conduct or statements of any indemnified person.

The MOWOS Acquisition Agreement was governed by the laws of England and Wales andthe parties irrevocably agreed to the exclusive jurisdiction of the London Court ofInternational Arbitration in relation to any action or proceeding arising out of the MOWOSAcquisition Agreement.

10.6 Registrar Agreement

The Company and the Registrar have entered into the registrar agreement dated 8 January2016 (the “Registrar Agreement”) pursuant to which the Registrar has agreed to act asregistrar to the Company and to provide transfer agency services and certain otheradministrative services to the Company in relation to its business and affairs.

The Registrar is entitled to receive the annual fee for creation and maintenance of the shareregister will be £1.25 per holder of ordinary shares appearing on the register during the feeyear, with a minimum charge per annum of £2,500 for the provision of its services under theRegistrar Agreement.

In addition to the annual fee, the Registrar is entitled to reimbursement for all out-of-pocketexpenses incurred by it in the performance of its services.

The Registrar Agreement shall continue for an initial period of three years and thereafter willautomatically renew for successive periods of 12 months unless and until terminated uponwritten notice by either party, by giving not less than six months’ written notice. In addition,the agreement may be terminated as soon as reasonably practicable if either party (i)commits a material breach of the agreement which has not been remedied within 45 days ofa notice requesting the same; (ii) goes into liquidation (except voluntary) or becomesbankrupt or insolvent.

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11. Related Party Transactions

11.1 Non-Executive Directors’ letters of appointment

Each of Richard Benmore and John Morrow entered into a Director’s non-executive letter ofappointment dated 22 December 2015 with the Company in respect of his appointment asa Director of the Company.

Under the terms of the appointment letters, Richard Benmore is entitled to a fee of £50,000per annum and John Morrow is entitled to a fee of £50,000 per annum. Fees will accrue ona daily basis and will be payable in equal monthly instalments in arrears on the last BusinessDay of each month (or as otherwise agreed).

Each of the Directors appointments as a non-executive director of the Company, shall(subject to limited exceptions) be subject to termination by either party on six months’ writtennotice, under which they are not entitled to any pension, benefits or bonuses. Benefitsprovided to Richard Benmore are the provision of medical insurance for himself and his wife.

11.2 Service Agreement of Andrew Austin

Andrew Austin entered into a service agreement with the Company dated 22 December2015 with respect to his appointment as executive chairman of the Company and directorresponsible for implementation of the acquisition strategy. Mr. Austin’s is a full-timeemployee of the Company. Mr. Austin’s service agreement is capable of termination by eitherparty giving 12 months’ notice in writing. Mr. Austin is currently entitled to a salary of£475,000 per annum. Benefits provided to Andrew Austin are the provision of medicalinsurance for himself and his family.

At the discretion of the Remuneration Committee, Andrew Austin was paid a bonus ofUS$804,000 in recognition of progress made by the Group during 2018 and the fact that nobonus had been paid for 18 months, representing a bonus of 156% of base salary and 104%of bonus entitlement. Mr. Austin also received US$34,000 in lieu of pension in 2018.

11.3 Senior Managers’ Service Agreements

Each of Peter Mann, Steve Pawson and Richard Slape have entered into Senior Managers’service agreements dated 3 August 2017, 24 July 2017 and 10 April 2019, respectively, withthe Company in respect of their roles as managing director, finance director and chieffinancial officer, respectively. Peter Mann, Stephen Pawson and Richard Slape are entitledto an aggregated fee of £650,000 per annum. Fees will accrue on a daily basis and will bepayable in equally monthly instalments in arrears on the last Business Day of each month(or as otherwise agreed). Each of the Senior Managers’ appointments as senior managersof the Company, shall (subject to limited exceptions) be subject to termination by either partyon three months’ written notice.

11.4 Unapproved Share Option Plan

The Company believes that the incentive arrangements for the Directors and the SeniorManagers should be focused on significant long-term value creation through the delivery ofShareholder returns in order to closely align the interests of Directors and the SeniorManagers with those of Shareholders. Under the terms of the non-tax advantaged shareoption plan (the “Share Option Plan”), the Board may issue options over shares up to 15%of the issued share capital of the Company from time to time.

To recognise the changing requirements of the business over time and to support growthobjectives over the medium to long term, a long-term incentive structure has been put inplace for Directors and the Senior Managers in the form of a non-tax advantaged shareoption plan. The structure of the Share Option Plan is designed such that participants will

Annex I, 15.1,

16.1, 16.2, 19

Annex I, 17.3

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only benefit if significant value is delivered to Shareholders. Its implementation serves toensure that:

• Directors and Senior Managers, who are critical to executing the business strategyand driving value for shareholders, are appropriately attracted, retained andmotivated;

• the reward structure supports a growth strategy and is heavily weighted towardsshareholder value creation over the longer term;

• the interests of Directors and Senior Managers are closely aligned with those ofShareholders; and

• Directors and Senior Managers are provided with an appropriate opportunity to earnlevels of reward provided significant returns are delivered to Shareholders.

On 14 February 2018, Andrew Austin exercised an option to acquire 1,533,333 OrdinaryShares on terms of his option award dated 22 December 2015.

The Company granted Peter Mann and Steve Pawson 212,600 options and 159,450 optionsrespectively over Ordinary Shares at an exercise price of 127 pence on 14 February 2018.On 25 May 2018, Richard Benmore was also granted 107,817 options over Ordinary Shares.These options were to vest and become exercisable in three equal tranches on the first,second and third anniversaries of the dates of grant. On 25 June 2019, and in accordancewith the terms of the Share Option Plan, the Board waived the exercise conditions attachingto the options such that the options vested and became exercisable in full. On 25 June 2019,Mr. Benmore, Mr. Mann and Mr. Pawson exercised their respective options to acquireOrdinary Shares at the exercise price of 371 pence, 127 pence and 127 pence respectively.

On 25 June 2019 the Board, following a recommendation of the Remuneration Committee,made the following awards under the Share Option Plan:

Exercise Vesting

No. of options Price Conditions

Andrew Austin 73,620 815 pence Vests and exercisablePeter Mann 30,675 815 pence on completion of Marathon Acquisition

No payment has been made for the grant of any of the options.

The main features of the Share Option Plan are summarised below.

Eligibility

All executive directors and employees of the Company and any of its subsidiaries are eligibleto participate in the Share Option Plan. The Remuneration Committee selects the individualsto whom options are to be granted from time to time.

Grant of options

Options may be granted at such time or times as the Remuneration Committee (or theBoard, excluding any interested director, until a Remuneration Committee is formallyestablished) determines.

Exercise price and adjustments to options

While the Ordinary Shares are admitted to trading on the Official List, the exercise price perOrdinary Share may not be less than the average of the middle market quotations for anOrdinary Share for the five dealing days immediately prior to the date of grant. While the

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Ordinary Shares are not admitted to trading on the Official List, the exercise price will be theamount specified by the Remuneration Committee. If the Ordinary Shares are newly issuedthe exercise price may not, in any event, be less than the nominal value of an OrdinaryShare.

In the event of any variation in the share capital of the Company the exercise price and/orthe number of Ordinary Shares comprised in each option may be adjusted as theRemuneration Committee determines. No adjustment may be made which will reduce theexercise price below the nominal value of an Ordinary Share.

Rights and restrictions

An option granted under the Share Option Plan is not transferable. The option certificate willspecify when the option will lapse and such date may not be later than the tenth anniversaryof its date of grant. Except in the circumstances referred to below, an option will only beexercisable on or after the date which is three years after the date of grant.

If the participant ceases to be employed by the Company by reason of injury, disability, ill-health or redundancy; or because the business or company that employs him is transferredout of the ultimate ownership of the Company, his option may be exercised within 6 monthsafter such cessation or transfer. In the event of the death of a participant, the personalrepresentatives of a participant may exercise his option within 6 months after the date ofdeath. The extent to which an option may be exercised in these circumstances will bedetermined by reference to any exercise conditions and time vesting provisions set out in theoption certificate unless the Remuneration Committee decides otherwise and is satisfied thatany waiver of such provisions does not constitute a reward for failure.

On cessation of employment for any other reason (or when a participant serves or has beenserved with, notice of termination of such employment), the option will lapse unless theRemuneration Committee exercises its discretion to allow the exercise of the option for aperiod not exceeding six months from the date of such cessation or notice. In suchcircumstances and where exercise is permitted, the extent to which an option may beexercised will be determined by reference to any exercise conditions and time vestingprovisions set out in the option certificate unless the Remuneration Committee decidesotherwise and is satisfied that any waiver of such provisions does not constitute a reward forfailure.

Corporate events

Options, to the extent not already exercisable, will become exercisable immediately prior toa change in control of the Company, in the event of a takeover of the Company, in the eventthat an offeror becomes entitled or bound to acquire Ordinary Shares or in the event that thecourt sanctions a compromise or arrangement for the reconstruction of the Company or itsamalgamation with any other company. In such event, all options may be exercised for alimited period and will lapse to the extent not exercised.

Options, to the extent not already exercisable, will become exercisable in the event that theCompany is proposed to be voluntarily wound up and all options may be exercised within alimited period in connection with the winding up, failing which they will lapse.

In such circumstances and where exercise is permitted, the extent to which an option maybe exercised will be determined by reference to any exercise conditions set out in the optioncertificate unless the Remuneration Committee decides otherwise and is satisfied that anywaiver of such provisions does not constitute a reward for failure.

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Performance conditions

The exercise of options may be subject to the satisfaction of such performance conditions,if any, as may be specified and subsequently varied and/or waived by the RemunerationCommittee.

Issuance of Ordinary Shares

The Ordinary Shares issued upon the exercise of options granted under the Share OptionPlan will rank pari passu with the Company’s issued Ordinary Shares on the date ofexercise, save as regards any rights arising by reference to a record date prior to the dateof such exercise.

Plan limit

Options may not be granted under the Share Option Plan if such grant would result in thetotal number of “Dilutive Shares” exceeding 15% of the issued share capital of the Companyfrom time to time. “Dilutive Shares” means, on any date, all shares of the Company which(a) have been issued, or transferred out of treasury, on the exercise of options granted, orin satisfaction of any other awards made, under any share incentive scheme (including theShare Option Plan) in the shorter of the five years ending on (and including) that date andthe period since Admission; and (b) remain capable of issue, or transfer out of treasury,under any subsisting options granted by the Company.

Alternative settlement on exercise

Instead of delivering the number of Ordinary Shares specified in the exercise notice, theRemuneration Committee may make a cash payment with the option holder’s consent ordeliver Ordinary Shares equal to the value of the Ordinary Shares over which the option isexercised less the relevant exercise price, or may deliver a combination of the two.

Alteration

The Remuneration Committee may alter the Share Option Plan except that (apart from minoramendments to benefit the administration of the Share Option Plan, to correct typographicalor other errors, to take account of a change in legislation or to obtain or maintain favourabletax, exchange control or regulatory treatment for participants or the Company) no alterationto the advantage of participants or to the Share Option Plan limit described above can bemade without the prior approval of Shareholders in general meeting.

No amendment may have a materially adverse effect on options granted before theamendment without the relevant optionholder’s consent.

Termination and Plan period

The Remuneration Committee may terminate or suspend the operation of the Share OptionPlan at any time, whereupon no further options shall be granted but in all other respects theprovisions of the Share Option Plan shall remain in force. In any event, no options may begranted after the date which is five years after the date the Share Option Plan is adopted.

11.5 Pensions

The Group currently operates a DB Scheme and DC Scheme. In March 2010, the DBScheme was closed to new entrants and was further closed to future accrual on a definedbenefit basis in December 2015. On 1 April 2010, MOUK established the DC Scheme toprovide benefits to new employees and, on 1 January 2016 all former DB Scheme memberswere transferred to the DC Scheme. The most recent full triennial valuation of the DBScheme was carried out as at 31 March 2016. As part of that valuation, a funding plan wasagreed with the DB Scheme trustees which provides for annual contributions of £13,000,000until 31 December 2020.

Annex I, 15.2

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On completion of the Marathon Acquisition on 1 July 2019 RockRose delivered a cash-backed letter of credit to the trustees of the DB Scheme in the sum of £39,000,000 (coveringthe Group and its partners’ anticipated contributions to the DB Scheme for a period of threeyears). As funding obligations become due under the DB Scheme a significant proportion arerecharged to the partners on licences; these payment obligations of the partners wereaffirmed by the Court of Appeal in a judgment delivered on 17 January 2019 (which was notappealed by the partners). Pursuant to the Marathon Acquisition, RockRose has undertakento use all reasonable commercial efforts to procure the release of the current MOC parentalguarantee in respect of the obligations of the DB Scheme, and to this end has also deliveredits own parental guarantee to the trustees of the DB Scheme.

The DB Scheme will shortly commence its next formal triennial review, the statutory deadlinefor completion of such review being 30 June 2020. RockRose intends tabling proposals fora formal buy-out of the DB Scheme as part of that process, which involve an insurancecompany assuming all of the obligations and liabilities of the DB Scheme. These costs havebeen factored into the Enlarged Group’s working capital statement and the Company canconfirm that the working capital available to the Enlarged Group (which for the avoidance ofdoubt includes the Marathon Group) is sufficient for the present requirements of theEnlarged Group, that is, for at least 12 months following the date of this document.

RockRose and MOC remain in active discussions with the trustees of the DB Scheme andthe Pension Regulator concerning the future funding and current obligations of the DBScheme.

11.6 Property

The Company has a lease in respect of its London office at 5th floor, Halton House,20-23 Holborn, London EC1N 2JD, which commenced on 19 July 2018 and has an annualrent of £156,544 (exc. VAT and service charge). MSGB has a lease in respect of its office inAberdeen at Charter Building, Rubislaw Hill, Anderson Drive, Aberdeen AB15 6FZ, whichcommenced on 26 March 2017 and has an annual rent of £744,198 (exc. VAT and servicecharge) and another lease in respect of a facility at the Dales Industrial Estate, Peterhead,Aberdeenshire, AB42 3GZ, which commenced on 26 March 2017 and has an annual rent of£744,198 (excluding VAT and service charge). MSGB also owns the freehold propertieslocated at Peterhead Shore Base, South View, Peterhead, Aberdeenshire AB42 3GZ and 70Rubislaw Den South, Aberdeen AB15 4AY.

11.7 Related party transactions

Details of related party transactions entered into by members of the Group are set out in theaudited financial statements relating to the Group for the financial years ended 31 December2018, 31 December 2017 and the 18 month period ended 31 December 2016. See alsoparagraphs 11.1-11.5 of this Part XIX – Additional Information of this document.

Save as set out above, there were no other related parties transactions during the periodcovered by the audited financial statements relating to the Group for the financial yearsended 31 December 2018, 31 December 2017 and the 18 month period ended31 December 2016 and up to and including the date of this document.

12. Accounts

It is expected that the Company will continue to make public its annual report and accounts withinfour months of each financial year end (or earlier if possible) and that copies of the annual reportand accounts will be sent to Shareholders within six months of each financial year end (or earlierif possible). It is expected that the Company will continue to prepare its unaudited interim reportfor each six month period ending 30 June thereafter. It is expected that the Company will makepublic its unaudited interim reports within two months of the end of each interim period.

Annex I, 8.1

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13. General

13.1 By a resolution of the Shareholders passed on 4 June 2019, PricewaterhouseCoopers LLPwhose address is 1 Embankment Place, London WC2N 6RH, were reappointed as theauditor of the Company. PricewaterhouseCoopers LLP is registered to carry out audit workby the Institute of Chartered Accountants in England and Wales and the Financial ReportingCouncil.

13.2 The Group currently has 309 employees, as at the date of this document.

13.3 The total expenses incurred (or to be incurred) by the Company in connection with theAdmission are anticipated to be approximately £4,000,000, which comprise: pensionsadvice of £254,000, corporate finance advisory fees of £754,000, specialist accountancyservices of £164,000; reporting accountants costs of £500,000, legal fees of £1,130,000,competent persons costs of £330,000, printing and production costs of £120,000 and otherthird party consultancy fees of £748,000.

13.4 The Company is not dependent on patents, industrial, commercial or financial contracts ornew manufacturing processes which are material to the Company’s business or profitability.

13.5 The information in this document which has sourced from third parties has been accuratelyreproduced and so far as the Company is aware and is able to ascertain from informationpublished by such third parties, no facts have been omitted which would render thereproduced information inaccurate or misleading.

13.6 There have been no interruptions in the business of the Company, which may have or havehad in the 12 months preceding the publication of this document a significant effect on thefinancial position of the Company or which are likely to have a material effect on theprospects of the Company for the next 12 months.

13.7 The Directors are not aware of any trends, uncertainties, demands, commitments or eventsthat are reasonably likely to have a material effect on the Company’s prospects in the currentfinancial year.

13.8 The Company confirms that the Competent Person’s Report is dated within six months ofthe date of this document and that no material changes have occurred since the date of theCompetent Person’s Report the omission of which would make the Competent Person’sReport misleading.

13.9 The Group confirms that no material changes have occurred since 31 March 2019 being theeffective date to which the competent person’s reports set out in Part XXIII – Competent

Person’s Report of this document has been prepared regarding the mineral assets coveredby those reports the omission of which would make those competent person’s reportsmisleading.

14. Consents

14.1 ERC Equipoise is responsible for the report contained in Part XXIII – Competent Person’s

Report of this document and the estimates of mineral reserves and resources containedtherein, as well as references to them, and statements and information attributed to them orextracted from the report, which ERC Equipoise has given and not withdrawn consent forinclusion in this document, in the form and context in which they appear for the purposes ofRule 5.5.3R(2)(f) of the Prospectus Rules. To the best of the knowledge of ERC Equipoise(who have taken all reasonable care to ensure that such is the case), the information in thereport, estimates of mineral reserves and resources contained therein, as well as referencesto them, and statements and information attributed to them or extracted from their report arein accordance with the facts and contain no omission likely to affect the import of suchinformation.

Annex I, 17.1

Annex I, 23.1

Annex III, 10.3

LR 2.2.2(3)

Annex I, 2.1

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14.2 PricewaterhouseCoopers LLP has given and not withdrawn its written consent to theinclusion in this document of its reports set out in Section A of Part XII – Historical Financial

Information on MOUK, Section A of Part XIII – Historical Financial Information on MOWOS

and Section B of Part IX – Unaudited Pro Forma Financial Information for the Enlarged

Group in the form and context in which they appear, and has authorised the contents of itsreports for the purpose of Rule 5.5.3R(2)(f) of the Prospectus Rules.

14.3 Hannam has given and not withdrawn its written consent to the issue of this document withthe inclusion of the references herein to its name in the form and context in which theyappear.

14.4 Cantor Fitzgerald has given and not withdrawn its written consent to the issue of thisdocument with the inclusion of the references herein to its name in the form and context inwhich they appear.

14.5 Whitman Howard has given and not withdrawn its written consent to the issue of thisdocument with the inclusion of the references herein to its name in the form and context inwhich they appear.

15. Documents available for inspection

15.1 Copies of the following documents may be inspected at the registered office of the Companyat Cooley (UK) LLP, Dashwood, 69 Old Broad Street, London EC2M 1QS during usualbusiness hours on any day (except Saturdays, Sundays and public holidays) for a period of12 months following Admission:

(a) the Memorandum and Articles of the Company;

(b) the consent letters referred to in “Consents” in paragraph 14 of this Part XIX –

Additional Information of this document;

(c) the report of PricewaterhouseCoopers LLP, which is set out in Section B of Part IX –

Unaudited Pro Forma Financial Information for the Enlarged Group of this document;

(d) the report of PricewaterhouseCoopers LLP, which is set out in Section A of Part XII –

Historical Financial Information on MOUK of this document;

(e) the report of PricewaterhouseCoopers LLP, which is set out in Section A of Part XIII –

Historical Financial Information on MOWOS of this document;

(f) the documents referred to in Part XXII - Documents incorporated by reference; and

(g) this document.

15.2 In addition, this document will be published in electronic form and be available on theCompany’s website at www.rockroseenergy.com, subject to certain access restrictionsapplicable to persons located or resident outside the United Kingdom.

Date: 19 July 2019

Annex I, 24

LR 2.2.10(2)(a)

233


PART XX

GLOSSARY

“1P” Proved.

“2P” Proved + Probable.

“3P” Proved + Probable + Possible

“ABEX” abandonment expenditure.

“bbl” when referenced to water = to 1 barrel.

“bbl” per barrel

when referenced to oil in Nelson, this is a pipeline barrel perday in Nelson assumed at 0.953 stb/pipeline bbl

“bbl/d” when referenced to water = to 1 barrel per day

when referenced to oil in Nelson, this is a pipeline barrel perday in Nelson assumed at 0.953 stb/pipeline bbl

“bcm” billion cubic meters

“bd” barrel per day

“boe” barrels of oil equivalent

“Bscf” thousands of millions of standard cubic feet

“CAPEX” capital expenditure

“CoP” cessation of production

“CPI” computer processed interpretation log#

“DCA” decline curve analysis

“Eg” gas expansion factor

“ESP” electric submersible pumps

“FDP” field development plan

“FLE” field life extension

“FPS” forties pipeline system

“FPSO” floating production and storage unit

“GIIP” gas initially in place

“GOR” means gas oil ratio

“km” means kilometres

“LNG” liquefied natural gas

“M” or “MM” thousands and millions respectively

“m3/yr” cubic meter per year

234


“mb/d” million barrels per day

“ftTVDSS” feet subsea

“mTVDSS” metres subsea

“NPV” net present value

“OPEX” operating cost

“rb” reservoir barrels

“rcf” cubic feet at reservoir conditions

“scf” means standard cubic feet measured at 14.7 pounds persquare inch and 60 degrees fahrenheit

“scf/d” standard cubic feet per day

“ss” sub-sea

“stb” 42 US gallons measured at 14.7 pounds per square inch and60 degrees fahrenheit

“stb/d” stock tank barrels per day

“STOIIP” stock tank oil initially in place

“STOIIP” means stock tank oil initially in place

“TD” total depth

“TVD” true vertical depth

“TVDSS” means true vertical depth sub-sea

“V Model” 2D simulation model

“WGR” water gas ratio

“WOR” water oil ratio

235


PART XXI

DEFINITIONS

The following definitions apply throughout this document (unless the context requires otherwise):

“Acquisitions” the Sojitz Acquisition, the Egerton Acquisition and theIdemitsu UK Acquisition.

“Admission” admission of the Ordinary Shares to Standard Listing and totrading on the Main Market of the London Stock Exchangebecoming effective.

“AIM” AIM, the market of that name operated by the London StockExchange.

“Arran Acquisition” the acquisition of 30.43% of interest in blocks, 23/11a, 23/16band 23/16c, which contain the Arran field in the UK CentralNorth Sea, pursuant to the terms of the Arran AcquisitionAgreement.

“Arran Acquisition Agreement” the sale and purchase agreement between RockRoseUKCS4 Limited and the Arran Seller dated 8 August 2018relating to the Arran Acquisition.

“Arran Seller” Dana Petroleum (E&P) Limited, a company incorporated inEngland and Wales with registered number 02294746.

“Arunvill” Arunvill Capital Limited.

“Articles” the articles of association of the Company in force from timeto time.

“Audit Committee” a committee of directors of the Company, details of whichappear in Part VIII – The Board, the Senior Managers and

Corporate Governance of this document.

“Board” the board of directors of the Company.

“BP” British Petroleum Exploration Operating Company Ltd

“Business Day” days (not being a Saturday, Sunday or public holiday) onwhich the banks are generally open for business in London,UK.

“Cantor Fitzgerald” Cantor Fitzgerald Europe.

in relation to a share, warrant or other security, a share,warrant or other security, title to which is recorded in therelevant register of the share, warrant or other securityconcerned as being held in certificated form (that is, not inCREST).

“change of control” the acquisition of Control of the Company by any person orparty (or by any group of persons or parties who are acting inconcert).

“Companies Act” the UK Companies Act 2006.

“certificated” or “in certificated

form”

Annex I, 5.1.2

236


“Company” or “RockRose” RockRose Energy plc, a company incorporated in Englandand Wales with registered number 09665181.

“Competent Person’s Report” the report prepared by ERC Equipoise.

“Control” (i) the power (whether by way of ownership of shares, proxy,contract, agency or otherwise) to: (a) cast, or control thecasting of, more than 50%, of the maximum number of votesthat might be cast at a general meeting of the Company; or(b) appoint or remove all, or the majority, of the Directors orother equivalent officers of the Company; or (c) givedirections with respect to the operating and financial policiesof the Company with which the Directors or other equivalentofficers of the Company are obliged to comply; and/or (ii) theholding beneficially of more than 50%, of the issued shares ofthe Company (excluding any issued shares that carry no rightto participate beyond a specified amount in a distribution ofeither profits or capital), but excluding in the case of each of(i) and (ii) above any such power or holding that arises as aresult of the issue of Ordinary Shares by the Company inconnection with further acquisitions.

“CREST” the paperless settlement system operated by Euroclearenabling securities to be evidenced otherwise than bycertificates and transferred otherwise than by writteninstruments.

“CREST Regulations” the Uncertificated Securities Regulations 2001 (SI 2001

No. 3755).

“DB Scheme” the defined benefit pension scheme operated by the Groupfor former employees of the Marathon Group.

“DC Scheme” the defined contribution pension scheme operated by theGroup for employees and former employees.

“Directors” or “Board” the directors of the Company, whose names appear inPart VIII – The Board, the Senior Managers and Corporate

Governance of this document, or the board of directors fromtime to time of the Company, as the context requires, and“Director” is to be construed accordingly.

the disclosure guidance and transparency rules of the FCAmade in accordance with section 73A of FSMA.

“DRD” decommissioning relief deeds.

“DSA” decommissioning security agreement.

“Dyas” Dyas B.V., a private limited company duly incorporated andvalidly existing under the laws of the Netherlands registeredin the trade register under number 30108055.

“Dyas Acquisition” the acquisition of the entire issued share capital of the DyasGroup by RockRose Energy (NL) B.V. from the Dyas Sellerpursuant to the terms of the Dyas Acquisition Agreement.

“Disclosure Guidance and

Transparency Rules” or “DTRs”

237


“Dyas Acquisition Agreement” the sale and purchase agreement between RockRoseEnergy (NL) B.V., the Company and the Dyas Seller dated24 May 2018 relating to the Dyas Acquisition.

“Dyas Group” Dyas and its subsidiary Dyas Infrastructure B.V.

“Dyas Seller” SHV Nederland B.V., a private limited company dulyincorporated and validly existing under the laws of theNetherlands registered in the trade register undernumber 30048815.

“EBN” Energie Beheer Nederland.

the EU, Iceland, Norway and Liechtenstein.

“EEA States” the member states of the EU and the European EconomicArea, and each, an “EEA State”.

“Egerton” Egerton Energy Ventures Limited, a company incorporated inEngland and Wales with company number 08724360.

“Egerton Acquisition” the acquisition of the entire issued share capital of Egerton bythe Company from the Egerton Sellers.

“Egerton Sellers” Arunvill and John McKeown.

“EHS” environmental and health and safety.

“Enlarged Group” the enlarged group following the completion of the MarathonAcquisition, comprising the Group and the Marathon Group.

“ERC Equipoise” or “ERCE” ERC Equipoise Limited.

“EU” the Member States of the European Union.

“Euroclear” Euroclear UK & Ireland Limited.

“Executive Team” Andrew Austin and the Senior Managers.

“Existing Issued Share Capital” the current Ordinary Shares.

“FCA” the United Kingdom Financial Conduct Authority.

Hannam, acting in its capacity as financial adviser and jointbroker to the Company.

“FLE” field life extension.

“FSMA” the UK Financial Services and Markets Act 2000.

“general meeting” a meeting of the Shareholders of the Company or a class ofShareholders of the Company (as the context requires).

“Golar” Golar-Nor (UK) Limited.

“Group” the Company and its subsidiaries, from time to time.

“Hannam” H&P Advisory Limited.

a committee of directors of the Company, details of whichappear in Part VIII – The Board, the Senior Managers and


“EEA” or “European Economic

Area”

“Financial Adviser and Joint

Broker”

“Health, Safety, Security and

Environmental Committee”

238


“HSE” the Health & Safety Executive.

“IASB” International Accounting Standards Board.

“Idemitsu Group” Idemitsu Kosen Co., Limited.

“Idemitsu UK” Idemitsu Petroleum UK Limited.

“Idemitsu UK Acquisition” the Company’s acquisition of the entire issued share capitalof Idemitsu UK from Idemitsu Group pursuant to the terms ofthe Idemitsu UK Acquisition Agreement.

the sale and purchase agreement between the Company,and Idemitsu Group dated 17 October 2017 relating to theIdemitsu UK Acquisition.

“IEA” International Energy Agency.

“IFRS” International Financial Reporting Standards, as adopted inthe EU.

“Initial Admission” admission of the Ordinary Shares to Standard Listing and totrading on the Main Market of the London Stock Exchange on13 January 2016.

“ISA” individual savings account.

“ISIN” International Securities Identification Number.

“Joint Brokers” Whitman Howard and Cantor Fitzgerald, acting in theirrespective capacities as joint brokers to the Company.

“Listing Rules” the listing rules made by the FCA under section 73A of FSMA.

“London Stock Exchange” London Stock Exchange plc.

“Main Market” the main market for listed securities for the London StockExchange.

“Marathon” Marathon Oil Corporation, MOHL and MIOH.

“Marathon Acquisition” the Company’s acquisition of (i) the entire membershipinterest in MOUK from MOHL and (ii) the entire issued sharecapital of MOWOS from MIOH pursuant to the terms of theMOUK Acquisition Agreement and the MOWOS AcquisitionAgreement, respectively, which completed on 1 July 2019.

the MOUK Acquisition Agreement and the MOWOSAcquisition Agreement.

“Marathon Group” MOUK, MOWOS and their respective subsidiaries.

“Market Abuse Regulation” the Market Abuse Regulation (EU 596/2014).

“MEA” the Dutch Ministry of Economic Affairs.

“Memorandum” the memorandum of association of the Company in forcefrom time to time.

“MER UK Strategy” the UK Government’s “Maximising Economic Strategy for theUK”.

“Idemitsu UK Acquisition

Agreement”

“Marathon Acquisition

Agreement”

239


“MIOH” Marathon International Oil Holdings LLC, a companyincorporated in Delaware, United States with registerednumber 3735610.

“Mining Act” the Mining Act 2003.

“MOHL” Marathon Oil Holdings UK Limited, a company incorporatedin England and Wales with registered number 07450346.

“MOUK” Marathon Oil U.K. LLC, a company incorporated in Delaware,United States with registered number 0822875 (nowRockRose UKCS8 LLC).

“MOWOS” Marathon Oil West of Shetlands Limited, a companyincorporated in England and Wales with registered number04105025 (now RockRose UKCS10 Limited).

“MSGB” Marathon Service (G.B.) Limited, a company incorporated inEngland and Wales with registered number 1293052 (nowRockRose UKCS9 Limited).

“Nomination Committee” a committee of directors of the Company, details of whichappear in Part VIII – The Board, the Senior Managers and


“NTS” National Transmission System.

“Official List” the official list maintained by the FCA.

“OGA” the UK Oil and Gas Authority.

“Ordinary Shares” the ordinary shares of nominal value of 20 pence each in thecapital of the Company.

“Overseas Shareholders” Shareholders residing in, or subject to, any jurisdictionoutside the UK.

“partners” designated operator on behalf of interest holders.

“Premium Listing” a listing on the premium listing segment of the Official Listunder Chapter 6 of the Listing Rules.

“Prospectus Directive” Directive 2003/71/EC of the European Parliament and of theCouncil on the prospectus to be published when securitiesare offered to the public or admitted to trading.

EU Prospectus Directive Regulation (2004/809/EC).

“Prospectus Rules” the prospectus rules of the FCA made in accordance withsection 73A of FSMA.

“PRT” Petroleum Revenue Tax.

“Registrar” Link Asset Services or any other registrar appointed by theCompany from time to time.

“Registrar Agreement” the registrar agreement dated 8 January 2016 between theCompany and the Registrar details of which are set out inPart XIX – Additional Information of this document.

“Regulation S” Regulation S promulgated under the US Securities Act.

“Prospectus Directive

Regulation” or “PD Regulation

240


“Remuneration Committee” a committee of directors of the Company, details of whichappear in Part VIII – The Board, the Senior Managers and


“Repurchase Agreement” the repurchase agreement entered into between theCompany and Cantor Fitzgerald on 23 October 2018 detailsof which are set out in Part XIX – Additional Information ofthis document.

“Reverse Takeover” a reverse takeover as defined in the Listing Rules.

“RFCT” Ring Fence Corporation Tax.

a committee of directors of the Company, details of whichappear in Part VIII – The Board, the Senior Managers and


“RockRose UKCS8” RockRose UKCS8 LLC, a company incorporated inDelaware, United States with registered number 0822875,which was referred to as MOUK prior to the completion of theMarathon Acquisition.

“RockRose UKCS9” RockRose UKCS9 Ltd, a company incorporated in Englandand Wales with registered number 1293052, which wasreferred to as MSGB prior to the completion of the MarathonAcquisition.

“RockRose UKCS10” RockRose UKCS10 Ltd, a company incorporated in Englandand Wales with registered number 04105025, which wasreferred to as MOWOS prior to the completion of theMarathon Acquisition.

“SC” Supplementary Charge.

“SEGAL” Shell Esso Gas and Associated Liquids.

“SDRT” Stamp Duty Reserve Tax.

“Secondary Field Interests” the Balmoral, Stirling, Beauly and Burghley fields.

“Securities Act” the US Securities Act of 1933.

“SEDOL” Stock Exchange Daily Official List.

“Senior Managers” the senior management team of the Company, whose namesappear in Part VIII – The Board, the Senior Managers and

Corporate Governance of this document, and “Senior

Manager” is to be construed accordingly.

“Share Buy-back” the Company’s share buy-back of 2,923,240 Ordinary Sharesfor a cash payment of US$22 million (£16.4 million) on22 November 2018 following the Tender Offer.

“Share Dealing Code” the Company’s policy on directors’, senior managers’ andemployees’ dealings in securities.

“Shareholder” a holder of Ordinary Shares.

“Shareholder Distribution” the shareholder distribution of £1.50 per B Share on16 February 2018 following the redemption of the B Shares at£1.50 on 15 February 2018.

“Risk and Disclosure

Committee”

241


“Share Option Plan” the Company’s non-tax advantaged share option plan.

“SIPP” Self-Invested Personal Pension.

“Sojitz” Sojitz Energy Project Limited, a company incorporated inEngland and Wales with company number 04620801.

“Sojitz Acquisition” the acquisition of the entire issued share capital of Sojitz bythe Company.

“Sojitz Sellers” Sojitz Corporation and Sojitz Europe plc.

“SPS” the State Profit Share.

“SSM” the State Supervision of Mines.

“Standard Listing” a standard listing under Chapter 14 of the Listing Rules.

“TAQA Bratani” TAQA Bratani Limited.

“Takeover Code” the City Code on Takeovers and Mergers.

“Takeover Panel” the UK Panel on Takeovers and Mergers.

“Tender Offer” the Company’s proposal to purchase up to 3,072,062Ordinary Shares of the Company through a tender offer at aprice of 560 pence per Ordinary Share.

“TIDM” Tradeable Instrument Display Mnemonic.

the UK Corporate Governance Code issued by the UKFinancial Reporting Council.

“UK Holders” holders of Ordinary Shares who are resident, and in the caseof individuals, domiciled, solely in the United Kingdom for UKtax purposes.

in relation to a share or other security, a share or othersecurity, title to which is recorded in the relevant register ofthe share or other security concerned as being held inuncertificated form (that is, in CREST) and title to which maybe transferred by using CREST.

“United Kingdom” or “UK” the United Kingdom of Great Britain and Northern Ireland.

“United States” or “US” the United States of America.

“Whitman Howard” Whitman Howard Limited.

References to a “company” in this document shall be construed so as to include any company,corporation or other body corporate, wherever and however incorporated or established.

All references to legislation in this document are to the legislation of England and Wales unless thecontrary is indicated. Any reference to any provision of any legislation shall include anyamendment, modification, re-enactment or extension thereof. Words importing the singular shallinclude the plural and vice versa, and words importing the masculine gender shall include thefeminine or neutral gender.

For the purpose of this document, “subsidiary” and “subsidiary undertaking” have the meaningsgiven by the Companies Act.

“UK Corporate Governance

Code”

“uncertificated” or“uncertificated form”

242


PART XXII

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s annual report and accounts for the period from financial years ended31 December 2018, 31 December 2017 and for the 18 month period ended 31 December 2016and unaudited interim reports for the periods ended 30 June 2018, 30 June 2017 and 30 June2016 contain information which is relevant to Admission. These documents are available on theCompany’s website at https://www.rockroseenergy.com/investor-relations/reports/.

The table below sets out the various sections of the documents which are incorporated byreference into this document so as to provide the information required under the Prospectus Rulesand to ensure that Shareholders and others are aware of all information which, according to theparticular nature of Company and of the Ordinary Shares, is necessary to enable Shareholdersand others to make an informed assessment of the assets and liabilities, financial position, profitand losses and prospects of the Company.

Any non-incorporated parts of the documents are either not relevant for the purposes of Admissionor the relevant information is included elsewhere in this document. Any documents themselvesincorporated by reference or referred or cross-referred to in the documents referred to below shallnot form part of this document.

Page Section in this

Document Section numbers document

Strategic Report and Remuneration Report 2-8 Directors’ Report 9-11 Independent Auditors’ Report 12-13 Consolidated income statement and

statement of comprehensive income 14 Consolidated statement of financial position 15 Company statement of financial position 16 Consolidated statement of changes in equity 17 Company statement of changes in equity 18 Consolidated statement of cash flows 19 Company statement of cash flows 20 Notes to the financial statements 21-34

Chairman’s statement 1 Condensed consolidated interim statement of comprehensive income 5 Condensed consolidated interim statement of financial position 6

Condensed consolidated interim statement of changes in equity 7 Condensed consolidated interim statement of cash flows 7-8 Notes to the condensed consolidated interim financial statements 8-13

Annual Report for

the period ended

31 December 2018

Part XI –

Historical

Financial

Information of

the Company

Interim Report for

the six months

ended 30 June 2018

243


Page Section in this

Document Section numbers document

Strategic Report 3 Remuneration Report 6 Directors’ Report 12 Independent Auditors’ Report 19

Consolidated income statement and statement of comprehensive income 25 Consolidated statement of financial position 26 Company statement of financial position 27 Consolidated statement of changes in equity 28 Company statement of changes in equity 29 Consolidated statement of cash flows 30 Company statement of cash flows 31 Notes to the financial statements 32

Chairman’s statement 1

2

3

4

5

6-10

Strategic Report 3 Remuneration Report 8 Directors’ Report 15

20

Independent Auditors’ Report 21

27

Consolidated statement of financial position 28 Company statement of financial position 29 Consolidated statement of changes in equity 30 Company statement of changes in equity 31 Consolidated statement of cash flows 32 Company statement of cash flows 34 Notes to the financial statements 35

Chairman’s statement 2

4

4-5

5-6

Condensed interim statement of cash flows 6

7-12

Interim Report for

the six months

ended 30 June 2017

Condensed consolidated interimstatement of comprehensive income

Condensed consolidated interimstatement of financial position

Condensed consolidated interimstatement of changes in equity

Condensed consolidated interimstatement of cash flows

Notes to the condensed consolidatedinterim financial statements

Annual Report for

the 18 month period

ended 31 December

2016 Statement of Directors’ Responsibilitiesin respect of the Financial Statements

Consolidated income statement andstatement of comprehensive income

Interim Report for

the six months

ended 30 June 2016

Condensed interim statement ofcomprehensive income

Condensed interim statement of financialposition

Condensed interim statement of changesin equity

Notes to the consolidated interimfinancial statements

Annual Report for

the period ended

31 December 2017

244


245

PART XXIII

COMPETENT PERSON’S REPORT

The Marathon Acquisition constitutes a Reverse Takeover. Consequently, the Company is requiredto produce a prospectus in connection with Admission and by paragraphs 131 to 133 of theEuropean Securities and Markets Authority (ESMA) update of the Committee of EuropeanSecurities Regulators (CESR) recommendations in respect of the consistent implementation ofCommission Regulation (EC) No 809/2004 implementing the Prospectus Directive to include anindependent mineral expert report in this document on the licence interests of the Group along witha glossary of the technical terms used in the mineral expert’s report. The Company commissionedERC Equipoise to prepare the independent expert report (referred to as the Competent Person’sReport), which is set out in full below.

ERC Equipoise report .............................................................................................................. T-1

ESMA update

para 133

Annex I, 23.1

Annex III, 10.3

1. Independent Petroleum Consultant’s Consent

T-13

2. Introduction

T-14

Data Provided

T-16

Work Completed

Summary of Results

Reserves and Resources

T-17

3. Nelson & Howe Asset

Asset Summaries

Nelson Field Development History

T-19

Howe Field Development History

T-21

Reserves Forecasting

Nelson Field Reserves Forecasting

T-22

Howe Field Reserves Forecasting

T-24

OPEX and CAPEX Forecasts

CAPEX Assumptions

OPEX Assumptions

T-25

4. Blake Field

Drilling and Development History

T-26


T-29


DRILLEX Assumptions

CAPEX Assumptions

OPEX Assumptions

T-31

5. Ross Field

Drilling and Development History

T-32


T-33

OPEX, CAPEX and ABEX Forecasts

CAPEX Assumptions

OPEX Assumptions

T-34

6. B-Block: Balmoral, Beauly, Burghley, Stirling Fields

Asset Summary

T-35


Beauly Burghley

Balmoral Stirling

T-36


CAPEX Assumptions

OPEX Assumptions

Beauly Burghley

StirlingBalmoral

T-37

7. Tors: Kilmar & Garrow Fields

Asset Summary


T-38


CAPEX Assumptions

OPEX Assumptions

T-40

8. Grove

Asset Summary

T-41


Well Name

Last Known Estimates SITHP FTHP THP Gas Rate

psia psia psia MMscf/d G5 G2 G3x G6z

T-43


CAPEX Assumptions

OPEX Assumptions

T-44

9. Arran

Asset Summary

Geology and Geophysics

T-45

Reservoir Modelling, GIIP and Recoverable Gas

T-46


Low Mid High Low Mid High Low Mid High Low Mid High Low Mid High Low Mid High

GRV (MMm3) N/G Porosity Sh GEF RF

P90 P50 P10 P90 P50 P10

GIIP (Bscf) EUR (Bscf)

T-48


T-49

10. Brae Complex

Complex Overview

T-50

Brae Alpha Platform Fields

T-52

Central Brae

Asset Summary

T-53


T-54

C03

Company: On Stream: 01/12/1989Field: Central BraeCurrent Status: Flowing

Gp: 14942 MMscfNp: 12326.004 MstbWp: 124.343 MstbQcond: 0.000 Mstb

9000

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

8000

8500

Op

Oil Rate (stb

/d)

180000 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 16000 16500 17000 17500

Cumulative Oil Production (Mstb)

T-55


10.2.1.3.1. CAPEX Assumptions

10.2.1.3.2. OPEX Assumptions

T-56

West Brae

Asset Summary

T-57


Reservoir Modelling, STOIIP and GIIP

T-58


T-62




T-64

South Brae

Asset Summary

T-65


T-66




T-69

East Brae Platform Fields

Braemar

Asset Summary

T-70


T-71

BRA_01

Company: On Stream: 01/09/2003Field: BraemarCurrent Status: Flowing

Gp: 175179 MMscfNp: 0.000 MstbWp: 169.880 MstbQcond: 10421.454 Mstb

80000

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

55000

60000

65000

70000

75000

Op Gas

Rate (M

scfd)

150

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

CGR

(bbl

/MMsc

f)(C

+NGL)GR

(bbl

/MMsc

f)

110

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

105

WGR (bbl/M

Mscf)

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

T-72



T-73


East Brae

Asset Summary

T-74


T-75




T-78

11. Foinaven

Asset Summary

T-79


T-80


CAPEX Assumptions

T-84

OPEX Assumptions

T-85

12. Hanze Oil Field

Asset Summary

T-86



CAPEX Assumptions

OPEX Assumptions

T-88

13. P15/P18 Rijn Field

Asset Summary

T-89


T-90


T-91

14. A&B Fields

Asset Summary

T-92


T-93

Petrophysics and Gas Water Contacts

T-94

GIIP and EUR

AB Fields EUR and Recovery Factors

Field GIIP Sub-Unit Operator GIIP Estimate (nBCM)

Total GIIP (nBCM)

Low Mid High Low Mid High

Low Mid High Low Mid High

Low Mid High Low Mid HighRecovery Factor

Recovery Factor

A18 GIIP (nBCM)

EUR (nBCM)

EUR (nBCM) Recovery Factor

B13 GIIP (nBCM)

EUR (nBCM)

A12 GIIP (nBCM)

T-96


CAPEX Assumptions

T-97

OPEX Assumptions

T-98

15. Bergen, Groet & Schermer Fields

Asset Summary


T-99

Bergen - Rotliegend

Schermer – Platten dolomite

T-100

Groet

T-101

West Beemster


CAPEX Assumptions

OPEX Assumptions

T-102

16. K4/K5 Fields

Asset Summary

T-103


T-104

Working Interest, OPEX and CAPEX Forecasts

Area Working Interest Determination

T-105

CAPEX Assumptions

OPEX Assumptions

T-106

17. P/Q Blocks Asset (excluding Q1-B)

Asset Summary

P Block Asset Summary

T-107

Q Block Asset Summary

T-109


P6-AB Fields Forecasting

T-110

P6-D Field Forecasting

P9-AB, P6-S, P12 Fields Forecasting

T-111

Q4-A Field Forecasting

Q4-B Field Forecasting

T-112


T-113

18. Abandonment and Decommissioning

Methodology

All Assets Excluding the Brae Complex and Foinaven

T-114

Brae Decommissioning

Foinaven Decommissioning

T-115

Results

T-116

19. Economic Assumptions

Assumed Oil and Gas Price

Base Case ERCE Brent Assumptions ($/bbl Full Year Average)

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2028E+

Real (Constant $, 2019) 68 68 68 69 71 71 71 71 71 71 71Nominal ($ of the day) 69 70 71 74 77 79 81 82 84 85 +2.0% pa

ERCE Dutch TTF Base Case 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2028E+Real (Constant EUR/MW, 2019) 21 22 22 22 22 22 22 22 22 22 22Nominal (EUR of the day) 21 22 23 23 24 24 25 25 26 26 +2.0% pa

ERCE UK NBP Gas Price 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028E+Real (Constant p/therm, 2019) 45 44 46 51 53 53 53 53 53 53Nominal (p/therm of the day) 45 45 48 54 57 58 60 61 62 2% p.a.

Asset GHV (MJ/Nm3)A&B Blocks 39.7Bergen 39.9Hanze Oil 50.5K4/K5 40.3P15/P18 Rijn Oil 38.9PQ (excl. Q1B) 40.1

T-118

Inflation and Cost Escalation

Exchange Rates and other assumptions

Fiscal Terms

T-119

20. Calculation of Reserves

1P 2P 3PA&B Blocks 2027 2028 2030Bergen 2026 2029 2030Hanze Oil 2031 2039 2039K4K5 2036 2036 2040P15 P18 Rijn Oil 2021 2021 2022Total PQ Exlcuding Q1B 2021 2021 2022

AssetELT Year

1P 2P 3P2025 2028 20332019 2019 20192019 2019 20202019 2019 20192019 2019 20192029 2029 2029

AssetELT Year

T-120

21. Certificate of Qualification

T-122

22. Appendix 1: Summary of the PRMS

T-124

2)

A.

B.

T-131

23. Appendix 2: Nomenclature

T-150

24. Appendix 3: Production and Cost Forecasts

T-154

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

- -

102.2

- -

-20

20 -

- -

-18

5.1

- -

-20

21 -

3,09

73,30

574

.12.7

-29

.4 -

2022

-1,17

81,95

243

.7 -

-17

.9 -

2023

-55

61,17

726

.3 -

-14

.0 -

2024

-28

066

914

.9 -

-11

.6 -

2025

-18

345

310

.1 -

-11

.7 -

2026

-71

192

4.3

- -

12.5

-20

27 -

- -

- -

- -

23.4

2028

- -

- -

- -

-23

.420

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMst

b /

Bscf

/ £M

M)

-2.0

2.8

63.3

290.0

-97

.246

.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NG

L Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-155

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

- -

102.2

- -

-20

20 -

- -

-18

5.1

- -

-20

21 -

3,80

93,87

686

.92.7

-33

.0 -

2022

-2,05

02,98

566

.9 -

-25

.9 -

2023

-1,30

22,40

853

.7 -

-25

.0 -

2024

-89

21,93

343

.1 -

-25

.8 -

2025

-65

41,55

334

.6 -

-29

.2 -

2026

-48

61,21

327

.1 -

-38

.4 -

2027

-38

597

621

.8 -

-36

.9 -

2028

-27

869

915

.6 -

-38

.0 -

2029

-17

444

39.9

- -

32.6

-20

30 -

142

360

8.1

- -

50.8

-20

31 -

125

318

7.1

- -

50.4

-20

32 -

- -

- -

- -

23.4

2033

- -

- -

- -

-23

.420

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

-3.8

6.1

136.8

290.0

-38

5.8

46.8

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-156

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

- -

102.2

- -

-20

20 -

- -

-18

5.1

- -

-20

21 -

4,71

84,31

196

.82.7

-38

.4 -

2022

-3,00

93,74

684

.1 -

-33

.9 -

2023

-2,06

73,26

172

.8 -

-34

.7 -

2024

-1,57

82,93

365

.4 -

-39

.6 -

2025

-1,24

42,59

457

.9 -

-44

.1 -

2026

-1,02

32,26

050

.5 -

-54

.7 -

2027

-90

32,06

646

.0 -

-57

.7 -

2028

-78

11,83

340

.9 -

-62

.1 -

2029

-62

21,49

133

.2 -

-56

.4 -

2030

-54

31,30

029

.0 -

-61

.9 -

2031

-50

81,16

225

.9 -

-60

.6 -

2032

-46

31,02

122

.8 -

-66

.7 -

2033

-41

590

420

.1 -

-57

.9 -

2034

-38

282

118

.4 -

-58

.3 -

2035

-35

575

516

.8 -

-58

.4 -

2036

-32

668

015

.2 -

-60

.8 -

2037

-30

262

614

.0 -

-56

.3 -

2038

-28

458

613

.1 -

-56

.6 -

2039

-26

454

612

.2 -

-54

.4 -

2040

-23

648

810

.9 -

-59

.8 -

2041

-20

943

39.6

- -

54.8

-20

42 -

185

384

8.6

- -

52.5

-20

43 -

164

340

7.6

- -

52.9

-20

44 -

- -

- -

- -

23.4

2045

- -

- -

- -

-23

.420

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

-7.5

12.6

281.8

290.0

-1,23

3.7

46.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-157

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

192

- -

- -

-8.2

19.7

2020

219

- -

- -

-10

.930

2021

48 -

- -

- -

2.7

2520

22 -

- -

- -

- -

6120

23 -

- -

- -

- -

6720

24 -

- -

- -

- -

4520

25 -

- -

- -

- -

320

26 -

- -

- -

- -

2620

27 -

- -

- -

- -

120

28 -

- -

- -

- -

120

29 -

- -

- -

- -

120

30 -

- -

- -

- -

120

31 -

- -

- -

- -

120

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-21

.927

9.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-158

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

218

- -

- -

-8.2

19.7

2020

263

- -

- -

-10

.930

.020

2161

- -

- -

-2.7

24.6

2022

- -

- -

- -

-61

.020

23 -

- -

- -

- -

67.2

2024

- -

- -

- -

-44

.620

25 -

- -

- -

- -

3.0

2026

- -

- -

- -

-26

.020

27 -

- -

- -

- -

0.6

2028

- -

- -

- -

-0.6

2029

- -

- -

- -

-0.6

2030

- -

- -

- -

-0.6

2031

- -

- -

- -

-0.6

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-21

.927

9.1

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-159

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

244

- -

- -

-8.2

19.7

2020

303

- -

- -

-10

.930

2021

72 -

- -

- -

2.7

2520

22 -

- -

- -

- -

6120

23 -

- -

- -

- -

6720

24 -

- -

- -

- -

4520

25 -

- -

- -

- -

320

26 -

- -

- -

- -

2620

27 -

- -

- -

- -

120

28 -

- -

- -

- -

120

29 -

- -

- -

- -

120

30 -

- -

- -

- -

120

31 -

- -

- -

- -

120

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-21

.927

9.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-160

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

476

- -

- -

-6.1

0.6

2020

404

- -

- -

-8.2

220

2188

- -

- -

-2.0

120

22 -

- -

- -

- -

920

23 -

- -

- -

- -

720

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bscf

/ £M

M)

0.3

- -

- -

-16

.319

.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-161

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

492

- -

- -

-6.1

0.6

2020

441

- -

- -

-8.2

220

2110

0 -

- -

- -

2.0

120

22 -

- -

- -

- -

920

23 -

- -

- -

- -

720

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bscf

/ £M

M)

0.3

- -

- -

-16

.319

.8

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-162

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

505

- -

- -

-6.1

0.6

2020

469

- -

- -

-8.2

1.8

2021

109

- -

- -

-2.0

1.1

2022

- -

- -

- -

-9.5

2023

- -

- -

- -

-6.8

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb /

Bscf

/ £M

M)

0.4

- -

- -

-16

.319

.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-163

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

898

- -

- -

-12

.72.1

2020

658

- -

- -

-16

.92

2021

133

- -

- -

-4.2

120

22 -

- -

- -

- -

920

23 -

- -

- -

- -

920

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bscf

/ £M

M)

0.5

- -

- -

-33

.922

.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-164

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

933

- -

- -

-12

.72.1

2020

758

- -

- -

-16

.91.9

2021

162

- -

- -

-4.2

1.0

2022

- -

- -

- -

-8.7

2023

- -

- -

- -

-9.3

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.6

- -

- -

-33

.922

.9

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-165

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

969

- -

- -

-12

.72.1

2020

857

- -

- -

-16

.91.9

2021

192

- -

- -

-4.2

1.0

2022

- -

- -

- -

-8.7

2023

- -

- -

- -

-9.3

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.7

- -

- -

-33

.922

.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-166

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

210

- -

- -

-4.6

5.7

2020

155

- -

- -

-6.1

5.3

2021

29 -

- -

- -

1.5

0.9

2022

- -

- -

- -

-6.6

2023

- -

- -

- -

-1.8

2024

- -

- -

- -

-7.8

2025

- -

- -

- -

-4.1

2026

- -

- -

- -

-4.2

2027

- -

- -

- -

-3.6

2028

- -

- -

- -

-0.1

2029

- -

- -

- -

-0.1

2030

- -

- -

- -

-0.1

2031

- -

- -

- -

-0.1

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.1

- -

- -

-12

.340

.6

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-167

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

230

- -

- -

-4.6

5.7

2020

205

- -

- -

-6.1

5.3

2021

46 -

- -

- -

1.5

0.9

2022

- -

- -

- -

-6.6

2023

- -

- -

- -

-1.8

2024

- -

- -

- -

-7.8

2025

- -

- -

- -

-4.1

2026

- -

- -

- -

-4.2

2027

- -

- -

- -

-3.6

2028

- -

- -

- -

-0.1

2029

- -

- -

- -

-0.1

2030

- -

- -

- -

-0.1

2031

- -

- -

- -

-0.1

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-12

.340

.6

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-168

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

239

- -

- -

-4.6

5.7

2020

226

- -

- -

-6.1

5.3

2021

53 -

- -

- -

1.5

0.9

2022

- -

- -

- -

-6.6

2023

- -

- -

- -

-1.8

2024

- -

- -

- -

-7.8

2025

- -

- -

- -

-4.1

2026

- -

- -

- -

-4.2

2027

- -

- -

- -

-3.6

2028

- -

- -

- -

-0.1

2029

- -

- -

- -

-0.1

2030

- -

- -

- -

-0.1

2031

- -

- -

- -

-0.1

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-12

.340

.6

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-169

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

8,56

6 -

- -

55.7

0.32

56.0

-20

207,76

8 -

- -

82.8

0.25

72.8

-20

218,01

4 -

- -

21.0

0.16

82.7

-20

227,76

6 -

- -

20.3

0.16

76.6

-20

236,91

8 -

- -

30.8

1.95

74.7

-20

245,86

2 -

- -

9.9

0.95

71.3

-20

255,46

6 -

- -

30.8

0.50

73.9

-20

265,13

5 -

- -

8.9

0.30

76.4

-20

274,85

4 -

- -

0.3

0.21

71.6

4.0

2028

4,60

5 -

- -

-0.15

733.2

2029

4,91

1 -

- -

-0.12

733.2

2030

- -

- -

- -

-17

.220

31 -

- -

- -

- -

30.4

2032

- -

- -

- -

-75

.220

33 -

- -

- -

- -

30.4

2034

- -

- -

- -

-2.5

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

24.7

- -

-26

0.4

5.1

801.4

166.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-170

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

11,211

- -

-55

.70.46

57.9

-20

2011

,239

- -

-82

.80.41

75.0

-20

2112

,825

- -

-21

.00.29

84.6

-20

2210

,977

- -

-20

.30.30

78.7

-20

239,21

0 -

- -

30.8

3.14

76.7

-20

247,56

1 -

- -

9.9

1.83

73.1

-20

256,87

5 -

- -

30.8

0.96

74.3

-20

266,89

0 -

- -

8.9

0.54

77.0

-20

276,58

6 -

- -

0.3

0.35

72.3

4.0

2028

6,24

7 -

- -

-0.24

733.2

2029

6,32

1 -

- -

-0.17

733.2

2030

- -

- -

- -

-17

.220

31 -

- -

- -

- -

30.4

2032

- -

- -

- -

-75

.220

33 -

- -

- -

- -

30.4

2034

- -

- -

- -

-2.5

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

34.0

- -

-26

0.4

8.7

816.0

166.1

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-171

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

16,939

- -

-55

.70.56

62.3

-20

2016

,014

- -

-82

.80.52

79.5

-20

2118

,943

- -

-21

.00.39

88.8

-20

2215

,760

- -

-20

.30.43

82.8

-20

2312

,812

- -

-30

.84.00

80.3

-20

2410

,498

- -

-9.9

3.07

76.4

-20

259,37

1 -

- -

30.8

1.94

75.1

-20

268,50

1 -

- -

8.9

1.24

77.6

-20

277,88

7 -

- -

0.3

0.84

72.7

420

287,36

4 -

- -

-0.57

743

2029

6,93

3 -

- -

-0.39

733

2030

- -

- -

- -

-17

2031

- -

- -

- -

-30

2032

- -

- -

- -

-75

2033

- -

- -

- -

-30

2034

- -

- -

- -

-2

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

46.3

- -

-26

0.4

14.0

842.5

166.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-172

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

195

- -

- -

-1.9

-20

2018

0 -

- -

- -

2.5

-20

2110

9 -

- -

- -

2.4

-20

2269

- -

- -

-2.4

-20

2336

- -

- -

-2.3

-20

2421

- -

- -

-2.3

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

620

28 -

- -

- -

- -

520

29 -

- -

- -

- -

520

30 -

- -

- -

- -

2620

31 -

- -

- -

- -

4620

32 -

- -

- -

- -

113

2033

- -

- -

- -

-46

2034

- -

- -

- -

-4

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.2

- -

- -

-13

.824

9.1

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-173

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

265

- -

- -

-2.0

-20

2038

5 -

- -

- -

2.8

-20

2130

4 -

- -

- -

2.7

-20

2224

5 -

- -

- -

2.6

-20

2320

1 -

- -

- -

2.5

-20

2416

8 -

- -

- -

2.5

-20

2514

2 -

- -

- -

2.5

-20

2612

3 -

- -

- -

2.4

-20

2710

6 -

- -

- -

2.4

6.0

2028

80 -

- -

- -

24.8

2029

64 -

- -

- -

24.8

2030

- -

- -

- -

-25

.820

31 -

- -

- -

- -

45.6

2032

- -

- -

- -

-11

2.8

2033

- -

- -

- -

-45

.620

34 -

- -

- -

- -

3.7

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.7

- -

- -

-27

.124

9.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-174

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

320

- -

- -

-2.0

-20

2049

0 -

- -

- -

2.9

-20

2142

1 -

- -

- -

2.8

-20

2236

4 -

- -

- -

2.7

-20

2331

6 -

- -

- -

2.7

-20

2427

7 -

- -

- -

2.6

-20

2524

4 -

- -

- -

2.6

-20

2621

6 -

- -

- -

2.6

-20

2719

3 -

- -

- -

2.5

6.0

2028

174

- -

- -

-3

4.8

2029

157

- -

- -

-2

4.8

2030

- -

- -

- -

-25

.820

31 -

- -

- -

- -

45.6

2032

- -

- -

- -

-11

2.8

2033

- -

- -

- -

-45

.620

34 -

- -

- -

- -

3.7

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

1.1

- -

- -

-28

.524

9.1

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-175

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

4,61

6 -

- -

5.50

-52

.45

-20

205,36

5 -

- -

4.7

-80

.41

-20

216,28

1 -

- -

- -

73.68

-20

224,89

7 -

- -

- -

81.14

-20

235,16

2 -

- -

- -

79.35

-20

244,02

9 -

- -

- -

74.10

-20

254,12

6 -

- -

- -

70.06

-20

263,11

3 -

- -

- -

68.18

-20

273,27

7 -

- -

- -

65.91

-20

282,55

3 -

- -

- -

64.74

-20

292,68

6 -

- -

- -

63.01

-20

302,09

2 -

- -

- -

62.04

-20

312,20

2 -

- -

- -

60.52

-20

321,71

5 -

- -

- -

59.59

-20

331,80

5 -

- -

- -

58.20

-20

341,40

5 -

- -

- -

57.29

-20

351,48

0 -

- -

- -

56.00

-20

361,15

3 -

- -

- -

55.11

-20

371,21

3 -

- -

- -

53.91

-20

38 -

- -

- -

- -

5.4

2039

- -

- -

- -

-16

.820

40 -

- -

- -

- -

37.2

2041

- -

- -

- -

-47

.420

42 -

- -

- -

- -

68.8

2043

- -

- -

- -

-3.6

2044

- -

- -

- -

-3.6

2045

- -

- -

- -

-36

.120

46 -

- -

- -

- -

8.6

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

21.2

- -

-10

.2 -

1,23

5.7

227.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-176

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

7,57

9 -

- -

5.5

-52

.48

-20

206,63

4 -

- -

4.7

-79

.39

-20

216,99

3 -

- -

- -

72.79

-20

225,47

0 -

- -

- -

74.37

-20

235,79

7 -

- -

- -

78.00

-20

244,55

8 -

- -

- -

77.55

-20

254,85

0 -

- -

- -

75.65

-20

263,76

8 -

- -

- -

70.62

-20

273,84

4 -

- -

- -

66.71

-20

283,04

0 -

- -

- -

64.88

-20

293,25

3 -

- -

- -

62.68

-20

302,54

6 -

- -

- -

61.65

-20

312,68

8 -

- -

- -

60.11

-20

322,12

7 -

- -

- -

59.28

-20

332,29

1 -

- -

- -

57.80

-20

341,83

0 -

- -

- -

56.93

-20

351,97

7 -

- -

- -

55.57

-20

361,58

2 -

- -

- -

54.73

-20

371,71

2 -

- -

- -

53.47

-20

38 -

- -

- -

- -

5.4

2039

- -

- -

- -

-16

.820

40 -

- -

- -

- -

37.2

2041

- -

- -

- -

-47

.420

42 -

- -

- -

- -

68.8

2043

- -

- -

- -

-3.6

2044

- -

- -

- -

-3.6

2045

- -

- -

- -

-36

.120

46 -

- -

- -

- -

8.6

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

25.8

- -

-10

.2 -

1,23

4.7

227.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-177

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

7,99

1 -

- -

5.5

-52

.59

-20

207,17

5 -

- -

4.7

-78

.91

-20

217,65

0 -

- -

- -

71.40

-20

226,04

9 -

- -

- -

72.82

-20

236,47

7 -

- -

- -

72.23

-20

245,14

1 -

- -

- -

76.14

-20

255,51

9 -

- -

- -

74.06

-20

264,39

4 -

- -

- -

73.78

-20

274,73

5 -

- -

- -

71.87

-20

283,78

2 -

- -

- -

71.47

-20

293,83

2 -

- -

- -

69.86

-20

303,05

7 -

- -

- -

64.86

-20

313,26

6 -

- -

- -

61.02

-20

322,59

2 -

- -

- -

59.33

-20

332,80

6 -

- -

- -

57.27

-20

342,25

1 -

- -

- -

56.37

-20

352,44

4 -

- -

- -

54.84

-20

361,96

6 -

- -

- -

54.12

-20

372,13

7 -

- -

- -

52.79

-20

38 -

- -

- -

- -

5.4

2039

- -

- -

- -

-16

.820

40 -

- -

- -

- -

37.2

2041

- -

- -

- -

-47

.420

42 -

- -

- -

- -

68.8

2043

- -

- -

- -

-3.6

2044

- -

- -

- -

-3.6

2045

- -

- -

- -

-36

.120

46 -

- -

- -

- -

8.6

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

29.7

- -

-10

.2 -

1,24

5.7

227.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-178

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

707

- -

0.2

- -

2.25

-20

2031

9 -

-1.1

3 -

2.31

-20

2171

9 -

-4.2

- -

3.70

-20

22 -

- -

- -

- -

0.4

2023

- -

- -

- -

-1.3

2024

- -

- -

- -

-2.9

2025

- -

- -

- -

-3.7

2026

- -

- -

- -

-5.4

2027

- -

- -

- -

-4.5

2028

- -

- -

- -

-4.4

2029

- -

- -

- -

-4.3

2030

- -

- -

- -

-2.6

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.6

- -

2.0

3.0

-8.3

29.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-179

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

1,38

1 -

-2.1

- -

3.43

-20

201,28

8 -

-5.0

3 -

4.74

-20

211,46

7 -

-7.3

- -

5.57

-20

2250

2 -

-0.5

- -

2.65

-20

23 -

- -

- -

- -

0.4

2024

- -

- -

- -

-1.3

2025

- -

- -

- -

-2.9

2026

- -

- -

- -

-3.7

2027

- -

- -

- -

-5.4

2028

- -

- -

- -

-4.5

2029

- -

- -

- -

-4.4

2030

- -

- -

- -

-4.3

2031

- -

- -

- -

-2.6

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

1.6

- -

5.3

3.0

-16

.429

.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-180

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

1,38

1 -

- -

-0.00

3.20

-20

201,73

2 -

-2.4

30.00

5.21

-20

212,53

4 -

-6.3

-0.00

7.48

-20

221,65

4 -

-6.8

-0.00

5.78

-20

2398

2 -

-7.3

-0.00

4.51

-20

24 -

- -

- -

0.00

-0.4

2025

- -

- -

-0.00

-1.3

2026

- -

- -

-0.00

-2.9

2027

- -

- -

-0.00

-3.7

2028

- -

- -

- -

-5.4

2029

- -

- -

- -

-4.5

2030

- -

- -

- -

-4.4

2031

- -

- -

- -

-4.3

2032

- -

- -

- -

-2.6

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

2.9

- -

8.3

3.0

-26

.229

.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-181

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-59

-8.8

- -

7.47

-20

20 -

44 -

6.5

- -

8.55

-20

21 -

30 -

4.4

- -

7.25

0.3

2022

-22

-3.3

- -

6.24

5.9

2023

-16

-2.4

- -

5.68

26.4

2024

-12

-1.8

- -

4.83

15.8

2025

- -

- -

- -

-1.2

2026

- -

- -

- -

-0.1

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

-0.1

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.1

-9.1

- -

40.0

49.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-182

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-61

-9.2

- -

7.60

-20

20 -

50 -

7.5

- -

9.76

-20

21 -

40 -

6.0

- -

9.31

0.3

2022

-32

-4.8

- -

8.71

5.9

2023

-26

-3.9

- -

8.28

26.4

2024

-22

-3.3

- -

6.85

15.8

2025

- -

- -

- -

-1.2

2026

- -

- -

- -

-0.1

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.1

-11

.8 -

-50

.549

.7

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-183

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-64

-9.6

- -

7.99

-20

20 -

54 -

8.1

- -

10.03

-20

21 -

45 -

6.7

- -

9.33

0.3

2022

-39

-5.8

- -

8.56

5.9

2023

-34

-5.1

- -

7.76

26.4

2024

-31

-4.6

- -

5.52

15.8

2025

- -

- -

- -

-1.2

2026

- -

- -

- -

-0.1

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

-0.1

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.1

-13

.7 -

-49

.249

.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-184

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

-11

.91.0

-5.53

-20

20 -

- -

9.9

- -

6.92

-20

21 -

- -

7.9

- -

6.56

-20

22 -

- -

6.4

- -

6.28

-20

23 -

- -

5.2

- -

6.05

-20

24 -

- -

4.3

- -

5.87

-20

25 -

- -

3.5

- -

5.73

-20

26 -

- -

2.9

- -

5.61

9.8

2027

- -

- -

- -

-23

.020

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

- -

-17

.91.0

-48

.532

.8

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-185

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

-13

.51.0

-5.88

-20

20 -

- -

11.9

- -

7.46

-20

21 -

- -

10.2

- -

7.13

-20

22 -

- -

8.8

- -

6.88

-20

23 -

- -

7.7

- -

6.66

-20

24 -

- -

6.8

- -

6.48

-20

25 -

- -

6.0

- -

6.32

-20

26 -

- -

5.4

- -

6.19

9.8

2027

- -

- -

- -

-23

.020

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

- -

-24

.41.0

-53

.032

.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-186

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

- -

-15

.41.0

-6.29

-20

20 -

- -

14.0

- -

8.02

-20

21 -

- -

12.5

- -

7.69

-20

22 -

- -

11.2

- -

7.43

-20

23 -

- -

10.1

- -

7.20

-20

24 -

- -

9.2

- -

7.01

-20

25 -

- -

8.4

- -

6.84

9.8

2026

- -

-7.7

- -

6.69

23.0

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

- -

-31

.01.0

-57

.232

.8

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-187

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

9,28

6 -

-1.4

4.9

-10

1.42

-20

2013

,532

- -

1.4

17.2

-13

1.11

-20

2111

,012

- -

1.4

19.3

-13

4.50

-20

2211

,589

- -

1.4

2.0

-12

9.90

-20

239,23

2 -

-1.4

- -

129.41

-20

249,77

3 -

-1.4

- -

129.05

-20

259,03

2 -

-1.4

- -

121.35

1320

26 -

- -

- -

- -

127

2027

- -

- -

- -

-17

720

28 -

- -

- -

- -

177

2029

- -

- -

- -

-13

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb /

Bscf

/ £M

M)

26.0

- -

3.3

43.4

-87

6.7

507

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-188

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

9,67

4 -

-1.4

4.9

-10

1.82

-20

2014

,785

- -

1.4

17.1

-13

2.36

-20

2112

,293

- -

1.4

19.1

-13

5.34

-20

2213

,257

- -

1.4

1.9

-13

0.90

-20

2310

,893

- -

1.4

- -

130.19

-20

2411

,752

- -

1.4

- -

129.96

-20

2511

,024

- -

1.4

- -

122.23

1320

26 -

- -

- -

- -

127

2027

- -

- -

- -

-17

720

28 -

- -

- -

- -

177

2029

- -

- -

- -

-13

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb /

Bscf

/ £M

M)

29.7

- -

3.5

43.1

-88

2.8

507

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-189

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

10,072

- -

1.5

4.9

-10

2.89

-20

2016

,068

- -

1.5

17.1

-13

4.64

-20

2113

,652

- -

1.5

19.1

-13

7.85

-20

2215

,046

- -

1.5

1.9

-13

3.87

-20

2312

,616

- -

1.5

- -

133.17

-20

2413

,968

- -

1.5

- -

133.46

-20

2513

,467

- -

1.5

- -

125.96

1320

26 -

- -

- -

- -

127

2027

- -

- -

- -

-17

720

28 -

- -

- -

- -

177

2029

- -

- -

- -

-13

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb /

Bscf

/ £M

M)

33.8

- -

3.7

43.1

-90

1.8

507

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-190

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

920

- -

-0.5

-10

.05

-20

201,20

0 -

- -

1.5

-11

.51

-20

2193

5 -

- -

1.6

-11

.42

-20

2296

5 -

- -

0.2

-10

.82

-20

2375

3 -

- -

- -

10.56

-20

2478

1 -

- -

- -

10.33

-20

2570

7 -

- -

- -

9.52

220

26 -

- -

- -

- -

1820

27 -

- -

- -

- -

2520

28 -

- -

- -

- -

2520

29 -

- -

- -

- -

220

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

2.2

- -

-3.8

-74

.271

.4

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-191

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

972

- -

-0.5

-10

.35

-20

201,34

7 -

- -

1.6

-12

.11

-20

211,09

8 -

- -

1.7

-12

.34

-20

221,18

2 -

- -

0.2

-11

.97

-20

2396

7 -

- -

- -

11.92

-20

241,03

7 -

- -

- -

11.90

-20

2596

6 -

- -

- -

11.18

220

26 -

- -

- -

- -

1820

27 -

- -

- -

- -

2520

28 -

- -

- -

- -

2520

29 -

- -

- -

- -

220

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

2.7

- -

-4.0

-81

.871

.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-192

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

1,02

4 -

- -

0.5

-10

.34

-20

201,48

4 -

- -

1.6

-12

.16

-20

211,24

4 -

- -

1.7

-12

.31

-20

221,37

6 -

- -

0.2

-11

.93

-20

231,15

5 -

- -

- -

11.82

-20

241,27

9 -

- -

- -

11.79

-20

251,23

2 -

- -

- -

11.05

220

26 -

- -

- -

- -

1820

27 -

- -

- -

- -

2520

28 -

- -

- -

- -

2520

29 -

- -

- -

- -

220

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

3.1

- -

-4.0

-81

.471

.6

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-193

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

633

- -

-0.3

-6.95

-20

2081

6 -

- -

1.0

-7.90

-20

2163

0 -

- -

1.1

-7.78

-20

2264

6 -

- -

0.1

-7.34

-20

2350

2 -

- -

- -

7.16

-20

2452

1 -

- -

- -

6.99

-20

2547

1 -

- -

- -

6.44

120

26 -

- -

- -

- -

820

27 -

- -

- -

- -

1120

28 -

- -

- -

- -

1120

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

1.5

- -

-2.6

-50

.630

.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-194

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

667

- -

-0.3

-7.12

-20

2090

1 -

- -

1.0

-8.14

-20

2171

5 -

- -

1.1

-8.09

-20

2275

3 -

- -

0.1

-7.68

-20

2360

5 -

- -

- -

7.49

-20

2463

8 -

- -

- -

7.33

-20

2558

6 -

- -

- -

6.76

120

26 -

- -

- -

- -

820

27 -

- -

- -

- -

1120

28 -

- -

- -

- -

1120

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

1.7

- -

-2.6

-52

.630

.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-195

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

704

- -

-0.3

-7.13

-20

2099

9 -

- -

1.0

-8.19

-20

2181

7 -

- -

1.1

-8.10

-20

2288

3 -

- -

0.1

-7.69

-20

2372

6 -

- -

- -

7.49

-20

2478

9 -

- -

- -

7.35

-20

2574

6 -

- -

- -

6.80

120

26 -

- -

- -

- -

820

27 -

- -

- -

- -

1120

28 -

- -

- -

- -

1120

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

2.0

- -

-2.6

-52

.730

.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-196

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

429

- -

-0.2

-4.64

-20

2055

7 -

- -

0.7

-5.27

-20

2143

3 -

- -

0.8

-5.19

-20

2244

6 -

- -

0.1

-4.90

-20

2334

7 -

- -

- -

4.77

-20

2436

0 -

- -

- -

4.66

-20

2532

5 -

- -

- -

4.29

120

26 -

- -

- -

- -

520

27 -

- -

- -

- -

720

28 -

- -

- -

- -

720

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

1.0

- -

-1.8

-33

.720

.3

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-197

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

451

- -

-0.2

-4.75

-20

2061

4 -

- -

0.7

-5.43

-20

2149

0 -

- -

0.8

-5.40

-20

2251

7 -

- -

0.1

-5.12

-20

2341

6 -

- -

- -

4.99

-20

2444

0 -

- -

- -

4.89

-20

2540

4 -

- -

- -

4.50

120

26 -

- -

- -

- -

520

27 -

- -

- -

- -

720

28 -

- -

- -

- -

720

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

1.2

- -

-1.8

-35

.120

.3

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-198

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

470

- -

-0.2

-4.75

-20

2066

7 -

- -

0.7

-5.46

-20

2154

6 -

- -

0.8

-5.40

-20

2259

0 -

- -

0.1

-5.13

-20

2348

5 -

- -

- -

4.99

-20

2452

6 -

- -

- -

4.90

-20

2549

7 -

- -

- -

4.53

120

26 -

- -

- -

- -

520

27 -

- -

- -

- -

720

28 -

- -

- -

- -

720

29 -

- -

- -

- -

120

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

1.3

- -

-1.8

-35

.220

.3

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

ABEX

Cos

t (R

eal)

T-199

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-20

244

512

.0 -

-4.36

-20

20 -

164

353

9.6

- -

3.93

-20

21 -

- -

- -

- -

257

2022

- -

- -

- -

- -

2023

- -

- -

- -

- -

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

-To

tal (MMstb

/ Bs

cf / £M

M)

-0.1

0.3

6.8

- -

8.3

257.0

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-200

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-25

356

915

.4 -

-4.77

-20

20 -

216

479

13.0

- -

4.51

-20

21 -

- -

- -

- -

257

2022

- -

- -

- -

- -

2023

- -

- -

- -

- -

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.1

0.3

9.0

- -

9.3

257.0

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-201

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-29

667

418

.2 -

-5.07

-20

20 -

265

596

16.2

- -

5.02

-20

21 -

- -

- -

- -

257

2022

- -

- -

- -

- -

2023

- -

- -

- -

- -

2024

- -

- -

- -

- -

2025

- -

- -

- -

- -

2026

- -

- -

- -

- -

2027

- -

- -

- -

- -

2028

- -

- -

- -

- -

2029

- -

- -

- -

- -

2030

- -

- -

- -

- -

2031

- -

- -

- -

- -

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.2

0.4

10.9

- -

10.1

257.0

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-202

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-76

253

715

.2 -

-4.49

-20

20 -

698

510

14.5

- -

6.32

-20

21 -

648

493

13.9

- -

9.29

-20

22 -

- -

- -

- -

3920

23 -

- -

- -

- -

-20

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.7

0.5

14.6

- -

20.1

38.7

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-203

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-79

456

215

.8 -

-4.51

-20

20 -

739

543

15.3

- -

6.20

-20

21 -

696

535

15.0

- -

9.19

-20

22 -

- -

- -

- -

3920

23 -

- -

- -

- -

-20

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.7

0.5

15.4

- -

19.9

38.7

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-204

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

-77

358

416

.4 -

-4.40

-20

20 -

727

573

16.2

- -

6.15

-20

21 -

698

575

16.2

- -

9.23

-20

22 -

- -

- -

- -

3920

23 -

- -

- -

- -

-20

24 -

- -

- -

- -

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bs

cf / £M

M)

-0.7

0.6

16.3

- -

19.8

38.7

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-205

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

2,94

9 -

- -

- -

32.83

-20

203,38

2 -

- -

- -

40.46

-20

213,56

1 -

- -

- -

44.59

-20

223,32

9 -

- -

- -

42.04

-20

233,18

3 -

- -

- -

46.48

-20

242,69

9 -

- -

- -

49.72

-20

252,89

6 -

- -

- -

54.67

-20

262,76

5 -

- -

- -

54.74

-20

272,64

4 -

- -

- -

57.03

-20

282,35

5 -

- -

- -

58.66

-20

292,43

8 -

- -

- -

58.25

-20

302,33

2 -

- -

- -

59.23

-20

31 -

- -

- -

- -

296

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

12.3

- -

- -

-59

8.7

295.7

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-206

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

3,26

9 -

- -

- -

33.15

-20

203,79

0 -

- -

- -

34.40

-20

214,05

5 -

- -

- -

37.31

-20

223,84

5 -

- -

- -

35.77

-20

233,72

3 -

- -

- -

38.04

-20

243,19

2 -

- -

- -

39.67

-20

253,46

0 -

- -

- -

43.08

-20

263,33

6 -

- -

- -

42.01

-20

273,22

1 -

- -

- -

41.11

-20

282,89

4 -

- -

- -

46.71

-20

293,01

8 -

- -

- -

46.56

-20

302,92

3 -

- -

- -

46.70

-20

31 -

- -

- -

- -

253

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

14.6

- -

- -

-48

4.5

253.2

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-207

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

3,97

2 -

- -

- -

32.21

-20

204,66

4 -

- -

- -

34.09

-20

215,05

9 -

- -

- -

38.06

-20

224,86

1 -

- -

- -

36.83

-20

234,76

5 -

- -

- -

39.98

-20

244,13

0 -

- -

- -

42.08

-20

254,52

4 -

- -

- -

45.14

-20

264,40

8 -

- -

- -

44.31

-20

274,29

8 -

- -

- -

45.63

-20

283,89

8 -

- -

- -

48.16

-20

294,10

3 -

- -

- -

47.35

-20

304,00

8 -

- -

- -

46.81

-20

31 -

- -

- -

- -

261

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

18.9

- -

- -

-50

0.6

260.8

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-208

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

265

- -

- -

-2.4

-20

2023

6 -

- -

- -

2.4

-20

2124

0 -

- -

- -

2.6

-20

2222

2 -

- -

- -

2.5

-20

2320

9 -

- -

- -

2.9

-20

2417

4 -

- -

- -

3.0

-20

2518

3 -

- -

- -

3.1

-20

2617

1 -

- -

- -

3.2

-20

2715

9 -

- -

- -

3.2

-20

2813

8 -

- -

- -

3.1

-20

2913

9 -

- -

- -

3.1

-20

3013

0 -

- -

- -

3.1

-20

31 -

- -

- -

- -

110

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

0.8

- -

- -

-34

.611

0.0

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-209

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

299

- -

- -

-2.6

-20

2027

2 -

- -

- -

2.1

-20

2128

5 -

- -

- -

2.1

-20

2227

1 -

- -

- -

2.3

-20

2326

4 -

- -

- -

2.5

-20

2422

6 -

- -

- -

2.7

-20

2524

6 -

- -

- -

2.8

-20

2623

7 -

- -

- -

2.8

-20

2722

8 -

- -

- -

2.7

-20

2820

5 -

- -

- -

3.0

-20

2921

4 -

- -

- -

3.1

-20

3020

7 -

- -

- -

3.0

-20

31 -

- -

- -

- -

110

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

1.1

- -

- -

-31

.611

0.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-210

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

335

- -

- -

-2.38

-20

2030

9 -

- -

- -

2.01

-20

2132

7 -

- -

- -

2.08

-20

2231

6 -

- -

- -

2.03

-20

2331

1 -

- -

- -

2.34

-20

2427

1 -

- -

- -

2.49

-20

2529

8 -

- -

- -

2.60

-20

2629

1 -

- -

- -

2.65

-20

2728

5 -

- -

- -

2.75

-20

2825

9 -

- -

- -

2.82

-20

2927

3 -

- -

- -

3.02

-20

3026

7 -

- -

- -

2.99

-20

31 -

- -

- -

- -

110

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

1.3

- -

- -

-30

.210

9.9

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-211

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

5,69

0 -

- -

78.4

-52

.22

-20

207,16

2 -

- -

2.9

-74

.88

-20

215,48

3 -

- -

- -

58.42

-20

224,12

3 -

- -

- -

49.54

-20

233,20

5 -

- -

- -

47.13

-20

242,34

4 -

- -

- -

43.71

-20

252,20

0 -

- -

- -

41.52

-20

261,89

0 -

- -

- -

38.82

-20

271,64

7 -

- -

- -

37.11

-20

281,36

2 -

- -

- -

34.57

-20

291,30

9 -

- -

- -

33.16

-20

301,16

6 -

- -

- -

31.69

-20

31 -

- -

- -

- -

331

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

13.2

- -

-81

.3 -

542.8

331.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-212

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

5,97

6 -

- -

78.4

-51

.13

-20

2010

,468

- -

-2.9

-81

.45

-20

218,82

6 -

- -

- -

65.80

-20

226,59

3 -

- -

- -

56.37

-20

235,59

9 -

- -

- -

55.92

-20

244,39

9 -

- -

- -

53.77

-20

254,46

8 -

- -

- -

53.07

-20

264,15

2 -

- -

- -

51.56

-20

274,32

3 -

- -

- -

53.72

-20

282,98

9 -

- -

- -

46.47

-20

292,89

1 -

- -

- -

44.71

-20

302,75

9 -

- -

- -

43.97

-20

31 -

- -

- -

- -

373

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

22.6

- -

-81

.3 -

657.9

373.0

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-213

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMsc

f/d)

(£MM)

(£MM)

(£MM)

(£MM)

2019

7,38

3 -

- -

78.4

-51

.70

-20

2012

,797

- -

-2.9

-83

.03

-20

2110

,008

- -

- -

-64

.31

-20

228,09

1 -

- -

- -

56.51

-20

236,66

9 -

- -

- -

54.58

-20

245,17

0 -

- -

- -

51.84

-20

255,34

4 -

- -

- -

51.35

-20

264,87

8 -

- -

- -

49.31

-20

274,51

7 -

- -

- -

48.51

-20

283,64

9 -

- -

- -

44.60

-20

293,63

7 -

- -

- -

43.37

-20

303,57

4 -

- -

- -

43.11

-20

31 -

- -

- -

- -

366

2032

- -

- -

- -

- -

2033

- -

- -

- -

- -

2034

- -

- -

- -

- -

2035

- -

- -

- -

- -

2036

- -

- -

- -

- -

2037

- -

- -

- -

- -

2038

- -

- -

- -

- -

2039

- -

- -

- -

- -

2040

- -

- -

- -

- -

2041

- -

- -

- -

- -

2042

- -

- -

- -

- -

2043

- -

- -

- -

- -

2044

- -

- -

- -

- -

2045

- -

- -

- -

- -

2046

- -

- -

- -

- -

2047

- -

- -

- -

- -

2048

- -

- -

- -

- -

2049

- -

- -

- -

- -

2050

- -

- -

- -

- -

2051

- -

- -

- -

- -

Tota

l (MMstb

/ Bs

cf / £M

M)

27.0

- -

-81

.3 -

642.2

366.1

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-214

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MM

Nm3/d)

()

()

()

()

2019

- -

-2.8

- -

50.87

-20

20 -

- -

2.2

- -

56.68

-20

21 -

- -

1.8

- -

50.90

-20

22 -

- -

1.4

- -

41.11

-20

23 -

- -

1.2

- -

37.29

-20

24 -

- -

0.9

- -

34.24

-20

25 -

- -

0.7

- -

33.05

-20

26 -

- -

0.6

- -

30.69

-20

27 -

- -

0.4

- -

30.64

-20

28 -

- -

- -

- -

5620

29 -

- -

- -

- -

3820

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

- -

Tota

l (MMstb

/ Bn

m3

/ )

- -

-4.2

- -

365.5

94.3

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Ope

x (R

eal)

Tariff

Inco

me

(Rea

l)

T-215

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

- -

-3.0

- -

51.82

-20

20 -

- -

2.7

- -

60.88

-20

21 -

- -

2.3

- -

54.49

-20

22 -

- -

1.8

- -

44.29

-20

23 -

- -

1.6

- -

41.04

-20

24 -

- -

1.4

- -

37.95

-20

25 -

- -

1.1

- -

36.78

-20

26 -

- -

0.9

- -

33.88

-20

27 -

- -

0.7

- -

33.15

-20

28 -

- -

0.5

- -

31.82

-20

29 -

- -

0.4

- -

38.94

-20

30 -

- -

- -

- -

5620

31 -

- -

- -

- -

3820

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

- -

Tota

l (MMstb /

Bnm3 /

) -

- -

5.7

- -

465.0

94.3

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tar if

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-216

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

- -

-3.0

- -

52.05

-20

20 -

- -

2.9

- -

63.33

-20

21 -

- -

2.5

- -

58.84

-20

22 -

- -

2.2

- -

49.08

-20

23 -

- -

2.0

- -

46.42

-20

24 -

- -

1.8

- -

43.71

-20

25 -

- -

1.6

- -

42.36

-20

26 -

- -

1.4

- -

39.35

-20

27 -

- -

1.2

- -

38.28

-20

28 -

- -

0.8

- -

35.14

-20

29 -

- -

0.6

- -

30.96

-20

30 -

- -

0.4

- -

27.42

-20

31 -

- -

- -

- -

5620

32 -

- -

- -

- -

3820

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

- -

Tota

l (MMstb /

Bnm3 /

) -

- -

7.2

- -

527.0

94.3

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-217

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

-3

-0.14

0.2

-3.86

-20

20 -

2 -

0.12

- -

4.92

-20

21 -

1 -

0.10

- -

5.10

-20

22 -

1 -

0.06

1.0

-5.13

-20

23 -

- -

0.06

- -

4.96

-20

24 -

- -

0.05

- -

3.62

-20

25 -

- -

0.04

- -

3.48

1820

26 -

- -

0.04

- -

3.37

2020

27 -

- -

0.03

- -

3.27

-20

28 -

- -

0.03

- -

3.17

-20

29 -

- -

0.03

- -

3.09

-20

30 -

- -

0.02

- -

3.03

-20

31 -

- -

0.02

- -

2.92

-20

32 -

- -

0.02

- -

2.90

-20

33 -

- -

0.01

- -

2.83

120

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

) -

0.00

24 -

0.3

1.2

-55

.738

.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-218

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

-4

-0.2

0.2

-4.71

-20

20 -

3 -

0.2

- -

5.95

-20

21 -

2 -

0.2

- -

6.22

-20

22 -

2 -

0.2

1.0

-6.26

-20

23 -

- -

0.1

- -

6.02

-20

24 -

- -

0.1

- -

4.09

-20

25 -

- -

0.1

- -

3.90

1820

26 -

- -

0.1

- -

3.74

2020

27 -

- -

0.0

- -

3.60

-20

28 -

- -

0.0

- -

3.46

-20

29 -

- -

0.0

- -

3.35

-20

30 -

- -

0.0

- -

3.26

-20

31 -

- -

0.0

- -

3.11

-20

32 -

- -

0.0

- -

3.08

-20

33 -

- -

0.0

- -

2.97

120

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

) -

0.00

38 -

0.4

1.2

-63

.738

.9

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-219

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

-4

-0.2

0.2

0.00

5.56

-20

20 -

3 -

0.2

-0.00

6.99

-20

21 -

3 -

0.2

-0.00

7.33

-20

22 -

3 -

0.2

1.0

0.00

7.39

-20

23 -

- -

0.2

-0.00

7.08

-20

24 -

- -

0.1

-0.00

4.57

-20

25 -

- -

0.1

-0.00

4.31

1820

26 -

- -

0.1

-0.00

4.11

2020

27 -

- -

0.1

-0.00

3.93

-20

28 -

- -

0.1

- -

3.75

-20

29 -

- -

0.0

- -

3.60

-20

30 -

- -

0.0

- -

3.49

-20

31 -

- -

0.0

- -

3.29

-20

32 -

- -

0.0

- -

3.25

-20

33 -

- -

0.0

- -

3.10

120

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

) -

0.00

46 -

0.6

1.2

-71

.838

.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-220

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

2,30

4 -

- -

11.9

-16

.20

-20

202,14

5 -

- -

4.0

-21

.95

-20

211,97

6 -

- -

- -

20.61

-20

221,82

0 -

- -

- -

20.22

-20

231,67

7 -

- -

- -

19.84

-20

241,54

5 -

- -

4.0

-19

.59

-20

251,42

3 -

- -

- -

19.68

-20

261,31

1 -

- -

- -

19.41

-20

271,20

8 -

- -

- -

19.88

-20

281,11

3 -

- -

4.0

-19

.56

-20

291,02

5 -

- -

- -

19.05

-20

3094

4 -

- -

- -

19.24

-20

3187

0 -

- -

- -

19.24

-20

3280

1 -

- -

4.0

-18

.48

-20

3373

8 -

- -

- -

19.20

-20

3468

0 -

- -

- -

18.89

-20

3562

7 -

- -

- -

18.39

-20

3657

7 -

- -

4.0

-18

.34

-20

3753

2 -

- -

- -

18.50

-20

3849

0 -

- -

- -

18.37

-20

3945

1 -

- -

- -

18.66

-20

40 -

- -

- -

- -

9220

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bn

m3

/ )

8.7

- -

-31

.9 -

403.3

92.3

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-221

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

2,51

8 -

- -

11.9

-16

.20

-20

202,35

2 -

- -

4.0

-21

.95

-20

212,18

7 -

- -

- -

20.61

-20

222,04

4 -

- -

- -

20.22

-20

231,91

7 -

- -

- -

19.84

-20

241,80

5 -

- -

4.0

-19

.59

-20

251,70

5 -

- -

- -

19.68

-20

261,61

6 -

- -

- -

19.41

-20

271,53

5 -

- -

- -

19.88

-20

281,46

2 -

- -

4.0

-19

.56

-20

291,39

5 -

- -

- -

19.05

-20

301,33

4 -

- -

- -

19.24

-20

311,27

9 -

- -

- -

19.24

-20

321,22

7 -

- -

4.0

-18

.48

-20

331,18

0 -

- -

- -

19.20

-20

341,13

6 -

- -

- -

18.89

-20

351,09

5 -

- -

- -

18.39

-20

361,05

7 -

- -

4.0

-18

.34

-20

371,02

1 -

- -

- -

18.50

-20

3898

8 -

- -

- -

18.37

-20

3995

7 -

- -

- -

18.66

-20

40 -

- -

- -

- -

9220

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bn

m3

/ )

11.4

- -

-31

.9 -

403.3

92.3

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-222

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

2,58

4 -

- -

11.9

-16

.20

-20

202,46

9 -

- -

4.0

-21

.95

-20

212,34

9 -

- -

- -

20.61

-20

222,24

0 -

- -

- -

20.22

-20

232,14

0 -

- -

- -

19.84

-20

242,04

9 -

- -

4.0

-19

.59

-20

251,96

5 -

- -

- -

19.68

-20

261,88

7 -

- -

- -

19.41

-20

271,81

5 -

- -

- -

19.88

-20

281,74

9 -

- -

4.0

-19

.56

-20

291,68

7 -

- -

- -

19.05

-20

301,62

9 -

- -

- -

19.24

-20

311,57

5 -

- -

- -

19.24

-20

321,52

4 -

- -

4.0

-18

.48

-20

331,47

7 -

- -

- -

19.20

-20

341,43

2 -

- -

- -

18.89

-20

351,39

0 -

- -

- -

18.39

-20

361,35

0 -

- -

4.0

-18

.34

-20

371,31

2 -

- -

- -

18.50

-20

381,27

7 -

- -

- -

18.37

-20

391,24

3 -

- -

- -

18.66

-20

40 -

- -

- -

- -

9220

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bn

m3

/ )

13.3

- -

-31

.9 -

403.3

92.3

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-223

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MM

Nm3/d)

()

()

()

()

2019

- -

-2.6

5.0

-42

.71

-20

20 -

- -

2.3

5.0

-53

.08

-20

21 -

- -

2.0

5.0

-49

.43

-20

22 -

- -

1.7

5.0

-46

.15

-20

23 -

- -

1.5

5.0

-42

.79

-20

24 -

- -

1.3

5.0

-40

.01

-20

25 -

- -

1.1

5.0

-37

.67

-20

26 -

- -

1.0

5.0

-35

.22

-20

27 -

- -

0.8

3.0

-32

.75

-20

28 -

- -

0.7

3.0

-31

.04

-20

29 -

- -

0.6

- -

29.37

-20

30 -

- -

0.5

- -

27.74

-20

31 -

- -

0.5

- -

26.39

-20

32 -

- -

0.4

- -

25.12

-20

33 -

- -

0.4

- -

23.90

-20

34 -

- -

0.3

- -

22.49

-20

35 -

- -

0.3

- -

21.44

-20

36 -

- -

0.2

- -

20.43

-20

37 -

- -

0.2

- -

19.45

-20

38 -

- -

0.2

- -

18.67

3020

39 -

- -

0.2

- -

17.84

112

2040

- -

-0.1

- -

17.05

7320

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Total (MMstb /

Bnm3 /

) -

- -

6.6

46.0

-68

0.7

214.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-224

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

- -

-2.7

5.0

-43

.20

-20

20 -

- -

2.4

5.0

-54

.12

-20

21 -

- -

2.1

5.0

-50

.88

-20

22 -

- -

1.9

5.0

-47

.46

-20

23 -

- -

1.7

5.0

-44

.62

-20

24 -

- -

1.5

5.0

-41

.99

-20

25 -

- -

1.3

5.0

-39

.42

-20

26 -

- -

1.1

5.0

-37

.13

-20

27 -

- -

1.0

3.0

-34

.57

-20

28 -

- -

0.9

3.0

-32

.20

-20

29 -

- -

0.6

- -

30.25

-20

30 -

- -

0.5

- -

28.35

-20

31 -

- -

0.5

- -

26.91

-20

32 -

- -

0.4

- -

25.59

-20

33 -

- -

0.4

- -

24.32

-20

34 -

- -

0.3

- -

22.70

-20

35 -

- -

0.3

- -

21.62

-20

36 -

- -

0.2

- -

20.64

-20

37 -

- -

0.2

- -

19.71

-20

38 -

- -

0.2

- -

18.67

-20

39 -

- -

0.2

- -

17.84

3020

40 -

- -

0.2

- -

17.05

112

2041

- -

-0.1

- -

16.22

7320

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

) -

- -

7.3

46.0

-71

5.5

214.9

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-225

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

- -

-2.8

5.0

-43

.51

-20

20 -

- -

2.5

5.0

-54

.73

-20

21 -

- -

2.2

5.0

-51

.59

-20

22 -

- -

1.9

5.0

-48

.49

-20

23 -

- -

1.7

5.0

-45

.52

-20

24 -

- -

1.5

5.0

-43

.04

-20

25 -

- -

1.3

5.0

-40

.55

-20

26 -

- -

1.2

5.0

-38

.22

-20

27 -

- -

1.0

3.0

-36

.15

-20

28 -

- -

0.9

3.0

-34

.23

-20

29 -

- -

0.8

3.0

-32

.18

-20

30 -

- -

0.7

- -

29.50

-20

31 -

- -

0.6

- -

27.69

-20

32 -

- -

0.5

- -

26.33

-20

33 -

- -

0.5

- -

25.00

-20

34 -

- -

0.4

- -

23.15

-20

35 -

- -

0.4

- -

22.01

-20

36 -

- -

0.3

- -

20.92

-20

37 -

- -

0.3

- -

19.96

-20

38 -

- -

0.3

- -

18.89

-20

39 -

- -

0.2

- -

18.06

-20

40 -

- -

0.2

- -

17.26

3020

41 -

- -

0.2

- -

16.49

112

2042

- -

-0.2

- -

15.75

7320

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

) -

- -

8.0

49.0

-74

9.2

214.9

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-226

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

226

- -

- -

-4.99

-20

2073

9 -

- -

1.8

-4.70

-20

2140

5 -

- -

- -

8.24

-20

2230

5 -

- -

- -

8.56

-20

2323

6 -

- -

- -

6.51

-20

2411

1 -

- -

- -

3.07

-20

25 -

- -

- -

- -

-20

26 -

- -

- -

- -

-20

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

5220

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

)0.7

- -

-1.8

-36

.151

.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-227

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

354

- -

- -

-5.25

-20

2083

1 -

- -

1.8

-4.95

-20

2154

2 -

- -

- -

8.68

-20

2240

1 -

- -

- -

9.01

-20

2333

3 -

- -

3.6

-6.86

-20

2428

5 -

- -

3.7

-5.97

-20

2524

8 -

- -

- -

5.22

-20

2620

3 -

- -

- -

4.27

-20

2710

1 -

- -

- -

2.13

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

5220

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

)1.2

- -

-9.1

-52

.351

.5

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-228

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MMNm3/d)

()

()

()

()

2019

483

- -

- -

-5.78

-20

2089

6 -

- -

1.8

-5.44

-20

2165

1 -

- -

- -

9.55

-20

2249

2 -

- -

- -

9.91

-20

2342

2 -

- -

3.6

-8.86

-20

2437

0 -

- -

3.7

-7.76

-20

2532

9 -

- -

- -

6.90

-20

2629

6 -

- -

- -

6.21

-20

2726

9 -

- -

- -

5.65

-20

2824

7 -

- -

- -

5.18

-20

2922

8 -

- -

- -

4.78

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

5220

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb /

Bnm3 /

)1.7

- -

-9.1

-76

.051

.5

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tariff

Inco

me

(Rea

l)

Ope

x (R

eal)

T-229

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MM

Nm3/d)

2019

- -

-0.5

- -

10.91

-20

20 -

- -

0.2

- -

11.49

-20

21 -

- -

0.1

- -

9.77

-20

22 -

- -

0.1

- -

9.00

-20

23 -

- -

0.0

- -

8.00

-20

24 -

- -

0.0

- -

7.00

1720

25 -

- -

- -

- -

5920

26 -

- -

- -

- -

3720

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ -

- -

0.3

- -

56.2

113.2

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-230

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MM

Nm3/d)

()

()

()

()

2019

- -

-0.5

- -

12.36

-20

20 -

- -

0.3

- -

14.11

-20

21 -

- -

0.2

- -

11.85

-20

22 -

- -

0.1

- -

11.00

-20

23 -

- -

0.1

- -

10.00

-20

24 -

- -

0.0

- -

9.00

1720

25 -

- -

- -

- -

5920

26 -

- -

- -

- -

3720

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bn

m3

/ )

- -

-0.4

- -

68.3

113.2

ABEX

Cos

t (R

eal)

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-231

Tota

l Cap

exTo

tal O

pex

(stb/d)

(bbl/d)

(bbl/d)

(MM

Nm3/d)

()

()

()

()

2019

- -

-0.5

- -

13.56

-20

20 -

- -

0.4

- -

16.08

-20

21 -

- -

0.3

- -

14.29

-20

22 -

- -

0.2

- -

11.85

-20

23 -

- -

0.1

- -

11.00

-20

24 -

- -

0.1

- -

10.00

1720

25 -

- -

- -

- -

5920

26 -

- -

- -

- -

3720

27 -

- -

- -

- -

-20

28 -

- -

- -

- -

-20

29 -

- -

- -

- -

-20

30 -

- -

- -

- -

-20

31 -

- -

- -

- -

-20

32 -

- -

- -

- -

-20

33 -

- -

- -

- -

-20

34 -

- -

- -

- -

-20

35 -

- -

- -

- -

-20

36 -

- -

- -

- -

-20

37 -

- -

- -

- -

-20

38 -

- -

- -

- -

-20

39 -

- -

- -

- -

-20

40 -

- -

- -

- -

-20

41 -

- -

- -

- -

-20

42 -

- -

- -

- -

-20

43 -

- -

- -

- -

-20

44 -

- -

- -

- -

-20

45 -

- -

- -

- -

-20

46 -

- -

- -

- -

-20

47 -

- -

- -

- -

-20

48 -

- -

- -

- -

-20

49 -

- -

- -

- -

-20

50 -

- -

- -

- -

-20

51 -

- -

- -

- -

-

Tota

l (MMstb

/ Bn

m3

/ )

- -

-0.5

- -

76.8

113.2

Year

Oil Sa

les

Rate

Con

dens

ate

Sales Rate

NGL Sa

les

Rate

Gas

Sales

Rate

Cap

ex (R

eal)

ABEX

Cos

t (R

eal)

Tarif

f Inco

me

(Rea

l)

Ope

x (R

eal)

T-232

sterling 172846

RockRose Energy plc...2019/07/19 · Apart from the responsibilities and liabilities, if any, which...

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Transcript of RockRose Energy plc...2019/07/19 · Apart from the responsibilities and liabilities, if any, which...