reserves, resources and economic assessment of the … · reserves, resources and economic...

SENERGY (GB) LIMITED6th FLOOR BRETTENHAM HOUSE, LANCASTER PLACE, LONDON WC2E 7EN UNITED KINGDOM

T: +44 20 7438 4700 F: +44 20 7438 4701 E: [email protected] IN SCOTLAND SC 125513 REGISTERED OFFICE: 15 BON ACC ORD CRESCENT ABERDEEN AB11 6DE

Senergy (GB) Limited is also registered to OHSAS 18001

SENERGY (GB) LIMITED

Senergy (GB) Limited is also registered to OHSAS 18001

w w w . l r - s e n e r g y. c o m

Reserves, Resources and EconomicAssessment of the Assets of FaroePetroleum plcConducted for

Faroe Petroleum plcBy

Allan Spencer

Jim Scallon

Christopher Priddis

Final

K16FAR044L

July 2016

Reserves, Resources and Economic Assessment of the Assets of Faroe Petroleum plc

www.lr-senergy.com ii FinalK16FAR044L July 2016

AuthorAllan Spencer, Jim Scallon,Christopher Priddis

Technical AuditBarry Squire

Quality AuditJennifer Ives

Release to ClientJim Scallon

Date Released 14th July 2016

LR Senergy has made every effort to ensure that the interpretations, conclusions andrecommendations presented herein are accurate and reliable in accordance with good industrypractice and its own quality management procedures. LR Senergy does not, however,guarantee the correctness of any such interpretations and shall not be liable or responsible forany loss, costs, damages or expenses incurred or sustained by anyone resulting from anyinterpretation or recommendation made by any of its officers, agents or employees.


www.lr-senergy.com iii FinalK16FAR044L July 2016

The Directors,Faroe Petroleum plc.24 Carden Place,Aberdeen,AB10 1UQ,United Kingdon.

The Directors,Stifel Nicolaus Europe Limited,150 Cheapside,London,EC2V 6ET,United Kingdom.

The DirectorsRBC Europe LimitedRiverbank House2 Swan LaneLondonEC4R 3BFUnited Kingdom

The DirectorsPareto Securities ASDronning Mauds Gate 3P.O. Box 1411 VikaOslo 0115Norway

14th July 2016

Dear Sirs,

In accordance with your instruction Senergy (GB) Limited (LR Senergy) has updated its reviewof a portfolio of assets in which Faroe Petroleum plc (Faroe), through its subsidiaries FaroePetroleum (U.K) Limited and Faroe Petroleum Norge AS, holds interests. The assets evaluatedcomprise producing fields, fields under development and appraisal, and prospective acreage.

LR Senergy was requested to provide an independent evaluation of the recoverablehydrocarbons expected for each asset categorised in accordance with the PetroleumResources Management System (2007 and 2011) prepared by the Oil and Gas ReservesCommittee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsoredby the World Petroleum Council (WPC), the American Association of Petroleum Geologists(AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). The results are presentedin accordance with the requirements of the AIM Market of the London Stock Exchange, and ofthe Prospectus Rules published by the UK Financial Services Authority from time to time, inparticular as described in the “Note for Mining and Oil and Gas Companies - June 2009” and“CESR’s recommendations for the consistent implementation of the European Commission’sRegulation on Prospectuses No. 809/2004” (January 2005), including the European Securitiesand Markets Authority’s (ESMA) amendments to such recommendations in ESMA documentESMA/2013/319.

Recoverable volumes are expressed as gross and net reserves or resources. Gross reservesor resources are the total estimated petroleum to be produced from the assets evaluated from


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1st January 2016. Net reserves or resources are that portion of the gross reserves or resourcesattributable to the interests owned by Faroe.

In conducting this review, LR Senergy has utilised information and interpretations supplied byFaroe, comprising operator information, geological, geophysical, engineering and other dataalong with various technical reports. LR Senergy has reviewed the information provided andmodified assumptions where appropriate. Site visits were not considered necessary for thepurposes of this report.

Standard geological and engineering techniques accepted by the petroleum industry were usedin estimating recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement; hence the resources included in this evaluation areestimates only and should not be construed to be exact quantities. It should be recognised thatsuch estimates of hydrocarbon resources may increase or decrease in future if there arechanges to the technical interpretation, economic criteria or regulatory requirements. As far asLR Senergy is aware there are no special factors that would affect the operation of the assetsand which would require additional information for their proper appraisal.

LR Senergy acknowledges that this report may be included in its entirety, or in part, indocuments prepared by the Company and its advisers in connection with commercial orfinancial activities and may be published electronically on websites accessible by the public,including a website of the Company.

Senergy (GB) Limited is a privately owned independent consulting company established in1990, with offices in Aberdeen, London, Abu Dhabi, Dubai, Perth, and Kuala Lumpur. Thecompany specialises in petroleum reservoir engineering, geology and geophysics andpetroleum economics. All of these services are supplied under an accredited ISO9001 qualityassurance system. Except for the provision of professional services on a fee basis, LR Senergyhas no commercial arrangement with any person or company involved in the interest that is thesubject of this report.

Dr Barry James Squire is the Commercial Project Manager of LR Senergy’s Reserves andAsset Evaluation group and was responsible for supervising this evaluation. He is aprofessional petroleum geologist with over 40 years of oil industry experience gained ininternational companies, consultancy companies and within LR Senergy. He is a Fellow of theGeological Society, a member of the Petroleum Exploration Society of Great Britain and has aB.Sc. in Geology and a Ph.D. in Sedimentary Geochemistry both from the University ofManchester.

Yours faithfully,

Barry Squire

Commercial Project Manager

For and on behalf of Senergy (GB) Limited


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Executive SummaryLR Senergy was requested to provide an update of its assessment of a portfolio of assets inwhich Faroe Petroleum plc, through its subsidiaries Faroe Petroleum (UK) Limited and FaroePetroleum Norge AS, holds interests in the UK, Norway and Ireland. The licence interests arelocated in a variety of basin settings from the mature North Sea to the under-exploredNorwegian Barents Sea.

LR Senergy has assessed the reserve and resource volumes and prepared an economicevaluation of these Faroe assets, which include a portfolio of producing fields, developmentopportunities and exploration prospects.

The LR Senergy estimates of reserves in producing fields use decline curve analysis and theresults of the operators’ simulation modelling. In evaluating the contingent and prospectiveresources, LR Senergy has not normally performed its own interpretation of raw data, but hasassessed whether the volume estimates and risk assessments have followed good petroleumpractices and where required has adjusted this assessment. The technically recoverableresources in this report are therefore based on review of the interpretations by others conductedon the assets.

The effective date of the reserves evaluation is 1st January 2016. Certain licences in the UKand Norway have been relinquished since the effective date and before the signature date ofthis report. These do not affect the reserves assessment. The contingent and prospectiveresources associated with these relinquished licences have been removed from the portfolio.The licences and assets involved in these relinquishments are noted in the asset descriptionsections of this report. In addition, five new Norwegian licences have been awarded on 5th

February 2016. The prospective resources assessed within the ten prospects and leadsidentified in these licences are incuded in the exploration portfolio.

The present report is based on an earlier report by LR Senergy dated 5th January 2016. Thisearlier report was prepared for Faroe internal purposes and reported risk discounted resourcesand economic assessments for both contingent and prospective resources, neither of whichare accepted for reporting by the UKLA or ESMA guidelines. The present report has removedthese references as well as the references to assets relinquished since 5th January 2016. Thereports are identical in every other respect.

Summary of the Portfolio

The Faroe assets comprise a large and diverse portfolio including reserves in producing fieldsand fields under development, contingent resources in discovered yet undevelopedaccumulations and prospective resources in un-drilled exploration prospects and leads.

Most of the producing fields are located in the mature hydrocarbon province of the UK andNorwegian sectors of the North Sea. There are fifteen fields in the UK and Norway eitherproducing or with a reasonable expectation of development, and three fields that have ceasedproduction. They include a mix of oil and gas assets and fields newly on-stream, or about tobe developed, as well as those with long established production.

The core producing areas include contingent resources in oil and gas discoveries that are asyet un-developed for a variety of reasons. There are eight discoveries in UK and Norwegianwaters.


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There are prospective resources in four high graded un-drilled exploration prospects with nearterm drilling plans in the next two years. There is also a large portfolio of other prospects andleads which are either still under evaluation or which could benefit from the results of drillinghigh graded wells.

Reserves: Fields in Production and Under Development

The reserves gross and net1 to Faroe, as of the effective date, are summarised in the tablebelow. These are the arithmetically summed reserves developed (in production) andundeveloped (justified for development2) for the producing assets and those underdevelopment.

The fifteen producing fields or fields under development are located in the mature hydrocarbonprovince of the UK and Norwegian sectors of the North Sea. These include the UK / Norwaymedian line Blane oil field in the Northern North Sea, the Schooner, Ketch, Orca and Topazgas fields in the UK Southern North Sea, and the East Foinaven field in the UK Atlantic Margin.The Njord, Hyme, Snilehorn, Ringhorne East, Brage, Jotun, Butch and Pil fields are located inNorwegian waters, as is the UK / Norway median line Enoch oil field. The UK Minke and Wisseyfields have ceased production but have continuing abandonment liabilities. Thedecommissioning of the Glitne field in Norway is near complete.

Table S13: UK Developed and Undeveloped Reserves

The Njord area (Njord, Hyme, Snilehorn) reserves assessment and classification poseschallenges because of unusual circumstances. The Njord and Hyme fields are in productionbut integrity issues with the platform means that the future development plan for these fieldsand the nearby Snilehorn discovery is currently being re-assesed and is subject to someuncertainty. Although there is currently no single agreed development plan, LR Senergy has

1 Net: the portion of the gross reserves that are attributed to the equity interests of Faroe.2 Reserves are categorised as ‘Developed’ and ‘Undeveloped’ and as either ‘In Production’, ‘approvedfor development’ or ‘justified for development’, and these are combined in the LR Senergy productionprofiles and are summed in the reserves reporting.3 Proved Reserves mean those reserves which have a better than 90% chance of being produced.Proved + Probable Reserves mean those reserves which have a better than 50% chance of beingproduced. Proved + Probable + Possible Reserves mean those reserves which have a better than 10%chance of being produced. NGL has been converted to barrels using 14 bbl/tonne.

Operator

Proved Proved &Probable

Proved,Probable &

PossibleProved Proved &

Probable

Proved,Probable &

PossibleOil & Liquids Reserves (MMbbl)

Schooner 0.0 0.1 0.1 0.0 0.0 0.1 FaroeKetch 0.1 0.2 0.2 0.1 0.1 0.1 Faroe

East Foinaven 2.0 2.8 5.0 0.2 0.3 0.5 BPBlane 6.1 11.4 17.4 1.9 3.5 5.3 Talisman

Total Oil & Liquids; MMbbls 8.2 14.5 22.7 2.1 3.9 6.0Gas Reserves (Bscf)

Schooner 5.1 11.4 22.5 3.0 6.8 13.5 FaroeKetch 9.1 18.3 22.9 5.5 11.0 13.7 FaroeOrca 0.4 0.6 1.4 0.0 0.0 0.0 ENGIE

Topaz 0.9 1.9 4.1 0.1 0.1 0.3 RWE

Total Gas; Bscf 15.5 32.2 50.8 8.6 18.0 27.6

Producing and Under Development (UK): Developed and Un-developed Reserves

Gross on Licence Net Attributable


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established confidence in a reasonable expectation of development based on evidence,comments and actions by the operator Statoil and the partnership.

Njord production restarted in July 2014 following removal of drilling deck loads and structuralreinforcement of the Njord A platform deck frame. The operator of the field, Statoil, initiated the“Njord Future Project” in 2013 to establish a long-term solution for continued production anddrilling operations on the Njord field together with the associated Hyme and Snilehorn tie backs.This project reached an important milestone in October 2014 when the feasibility of reinforcingthe existing hull was demonstrated and approved and the project passed through decision gate1 (DG1). While the project is not yet sanctioned, LR Senergy understands that the operatorand partners are committed to a long term solution to the Njord platform integrity problems and,consequently, is categorised as Reserves (justified for development). The operator’s currentassumptions are that production will continue until May 2016 when the platform will be broughtto shore for modifications. There will be no drilling or intervention activity during this time. Themodified platform will return and resume production in 2019 and infill drilling will start again atthis point.

Partners announced on 21st October 2015 that the Butch field will be developed as a subseatie-in to the Ula field. The Butch oil will be exported via the Ula oil export pipeline to Ekofiskand onwards into the Norpipe to Teeside terminal in England. Production is planned to start in2019 and is categorised as Reserves (justified for development).

The agreed development plan for the Pil field is to select either tie back to Draugen or a standalone FPSO. Both development options are demonstrated to be economically viable. LRSenergy is satisfied that the operator and partners have demonstrated firm intent to proceedwith the development and that there is a reasonable expectation of development within the timeframe recommended under PRMS guidelines. Consequently, this project is also categorisedas Reserves (justified for development).


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Table S2: Norway Developed and Undeveloped Reserves

Reserves are classed as ‘Developed’, and ‘In Production’, with the exception of the Njord andHyme re-development project and Snilehorn satellite, the new Butch and Pil developments, andscheduled infill wells to be drilled on Njord, Brage, Ringhorne East and Blane, where thereserves are categorised as ‘Undeveloped’ and either ‘justified or approved for development’.

Economic analysis was carried out on producing and fields under development. Estimates ofthe Net Present Value at 10% (NPV104) of future nominal net after tax cash flows derive fromFaroe’s share as of 1st January 2016. Calculations are based on the current fiscal terms for UKand Norway. The portfolio was assessed using the LR Senergy internal economic model forthe UK and Norway.

NPV10 Net to Faroe (£MM)UK 25.6 50.1 79.4

Norway 42.3 141.8 243.9

Total (£MM) 67.9 191.9 323.3

Table S3: NPV10 of UK & Norway Reserves

The values are inclusive of estimated UK tax losses and Norwegian undepreciated Capex andunused uplift balances brought forward at 1st January 2016.

4 NPV10 is the Net Present Value from economic analysis with a 10% discount rate.

Operator


Proved,Probable &


Probable

Proved,Probable &


Njord 30.4 54.2 83.2 2.3 4.1 6.2 StatoilHyme 8.9 17.7 22.5 0.7 1.3 1.7 StatoilBrage 17.1 32.7 48.2 2.4 4.7 6.9 Wintershall

Ringhorne East 18.4 31.2 42.1 1.4 2.4 3.3 ExxonMobilSnilehorn 35.2 52.1 68.4 2.6 3.9 5.1 Statoil

Jotun 0.5 0.6 0.7 0.0 0.0 0.0 ExxonMobilEnoch 0.7 1.6 3.1 0.1 0.2 0.4 TalismanButch 20.2 40.9 58.0 3.0 6.1 8.7 Centrica

Pil 25.6 71.0 108.7 6.4 17.8 27.2 VNGTotal Oil & Liquids; MMbbls 157.0 302.2 435.0 19.0 40.5 59.5Gas Reserves (Bscf)



Jotun 0.0 0.0 0.0 0.0 0.0 0.0 ExxonMobilButch 4.4 10.0 16.0 0.7 1.5 2.4 Centrica

Pil 79.0 144.9 215.2 19.8 36.2 53.8 VNGTotal Gas; Bscf 384.9 667.5 992.9 44.2 78.9 119.5

Producing and Under Development (Norway): Developed and Un-developed Reserves



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The oil price assumption is $55/bbl (2016), $63/bbl (2017), $70/bbl (2018), $75/bbl (2019) andfrom 2020 inflated at 2.5% pa. The gas price assumption is $6.00/Mscf (2016), $6.75/Mscf(2017), $6.92/Mscf (2018), $7.09/Mscf (2019), and from 2020 inflated at 2.5% pa.

The valuation of these reserves has been prepared using costs provided by the field operatoror Faroe, and production profiles based on LR Senergy’s reserve assessments. Capital andoperating costs were therefore derived from operator information. It was not part of the scopeof this study to review these costs in detail. The economic inputs including production profiles,operating, capital and abandonment costs, for each asset, are provided in Appendix 2.

The production forecasts in Appendix 2 should be consulted for information on peak and plateauproduction, anticipated field decline and field life. Production profiles were curtailed at the limitof economic production. These profiles make assumptions related to the success of futureoperations and delivery of projects in accordance with the operators’ current plans.

Sensitivity analysis to a variable discount rate and oil and gas price has been assessed for theproved plus probable reserves and is summarised in the table below.

2P Reserves Economic Sensitivity Analysis NPV10 Net (£MM)NPV8 NPV10 NPV12

UK 54.0 50.1 46.6Norway 155.5 141.8 118.4Total (£MM) 209.5 192.0 165.0

-ve 20% Base Price +ve 20%UK 34.7 50.1 68.4Norway 94.2 141.8 187.1Total (£MM) 128.9 192.0 255.5

Table S4: Proved Plus Probable Reserves Economic Sensitivity Analysis

Licences that are due to expire prior to the estimated cessation of field production wereassumed to be extended in each of the jurisdictions where Faroe has interests.

Contingent Resources: Un-developed Discoveries

The Perth, Lowlander and Dolphin discoveries in the UK North Sea, are under evaluation fornear term joint development and are also classified as Development On Hold. The contingentresources gross and net to Faroe are summarised in the table below.

Table S5: UK Contingent Resources in Discoveries

Risk Factor Operator

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate

Oil & Liquids Resources(MMstb)

Perth 26.4 51.8 77.3 9.1 17.9 26.8 20% Parkmead

Lowlander 11.6 22.5 30.8 11.6 22.5 30.8 20% Faroe

Dolphin 1.8 9.0 18.3 0.6 3.1 6.3 20% Parkmead

Total Oil & Liquids; MMstb 39.8 83.3 126.4 21.4 43.5 63.9

Contingent Resources (UK North Sea): Discoveries



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The contingent resources in the Norwegian Bue and Fogelberg discoveries are classified asDevelopment Pending. The SE Tor (Tor) discovery is classed as Development Pending whilstSE Tor Ekofisk reservoir discovery is classed as Development Unclarified, as is the Boomerangand discovery, until further post well evaluation studies are completed. The Shango/SkirneEast discovery is currently classed as Development Not Viable.

Table S6: Norway Contingent Resources in Discoveries

The risk factor5 for contingent resources6 is the chance of a commercial development within thespecified time frame.

The contingent resources in a variety of other incremental projects are not quantified in thisreport, but in LR Senergy’s opinion these represent significant additional potential. Theseinclude infill well opportunities in Schooner, Topaz, Njord, Brage and Ringhorne East andpossible future IOR projects on East Foinaven and Brage.

Prospective Resources: Exploration Portfolio

The exploration prospect portfolio of Faroe is located principally in three hydrocarbon provincesnamely the UK and Norway North Sea, the Norwegian Sea and the Barents Sea. There is alsopotential in the UK Atlantic Margin and the Irish Sea. The Barents Sea is under explored withmedium to high risk and large resource potential in areas with developing infra-structure. TheUK and Norway North Sea is a more mature province with good infra-structure and low to

5 Risk factor for contingent resources is the Chance of Commercial Development and is not the same asRisk factor for Prospective resources (see Appendix 1). It is estimated after considering subsurface risks,the chance of project approval, and a variety of commercial considerations including the economic viabilityof the proposed development and any host or infra-structure issues.6 Contingent Resources: the arithmetically summed resources attributable to those quantities ofpetroleum estimated to be potentially recoverable from known accumulations. These projects are notcurrently mature enough for commercial development due to one or more contingencies.


LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate

Oil & Liquids Resources (MMstb)

Bue 5.0 10.1 17.6 1.3 2.5 4.4 75% VNG

Boomerang 4.0 17.8 27.7 1.0 4.5 6.9 40% VNG

Fogelberg 3.7 7.2 11.4 0.9 1.8 2.9 65% Centrica

SE Tor (Tor) 4.0 14.3 37.5 3.4 12.2 31.9 35% Faroe

SE Tor (Ekofisk) 2.0 9.0 70.0 1.7 7.7 59.5 25% Faroe

Shango/Skirne East 0.1 0.2 0.4 0.0 0.0 0.1 10% Total

Total Oil & Liquids; MMstb 18.8 58.6 164.6 8.3 28.6 105.6Gas Resources (Bscf)

Bue 2.0 4.1 7.2 0.5 1.0 1.8 75% VNG

Boomerang 3.6 15.9 29.3 0.9 4.0 7.3 40% VNG


SE Tor (Tor) 4.8 17.2 45.0 4.1 14.6 38.3 35% Faroe



Total Gas; Bscf 159.2 332.4 612.1 43.8 99.1 226.3

Contingent Resources (Norway): Discoveries



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medium risk for more modest resource volumes, although there are some notably largerpotential resources in less mature play types.

The exploration portfolio is subdivided into those prospects with Near Term firm drilling plansin the next 2 years, of which there are four wells planned in Norway; Medium Term prospectsthat are considered to be strong drilling candidates within the next 3 to 5 years, there beingthree in the UK North Sea and ten in Norway; and the remainder of the portfolio comprisingnineteen leads and prospects in Norway, three in the UK, and thirteen in Ireland, that eitherrequire further evaluation or are considered likely to benefit from the drilling results of the Nearand Medium Term prospects.

The UK Medium Term un-risked prospective resources7 gross and net to Faroe, aresummarised in the table below. These are the arithmetically summed resources.

Table S7: UK Prospective Resources in Medium Term Exploration Prospects

The three ‘Other’ leads and prospects in the UK North Sea have arithmetically summed un-risked best estimate total prospective resource potential of 25 MMboe and risk factors (chanceof discovery) in the range of 12 to 18%.

The Norway Near Term and Medium Term un-risked prospective resources gross and net toFaroe, are summarised in the tables below. These are the arithmetically summed resources.

7 Prospective Resources are the arithmetically summed resources attributable to undrilled explorationprospects.

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate

Oil & Liquids Resources(MMbbl)

Perth Northern 1 8 66 0 3 23 65% FaroeFynn 17 31 41 4 8 10 30% ParkmeadBeta 4 10 19 1 3 6 64% Faroe

Total Oil & Liquids;MMbbls 22 48 126 6 14 40

Gross on Licence

Prospective Resources: Medium Term Exploration (UK North Sea)

Risk FactorNet Attributable

Operator


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Table S8: Norway Prospective Resources in Near Term Exploration Prospects

Table S9: Norway Prospective Resources in Medium Term Exploration Prospects

The nineteen ‘Other’ leads and prospects in Norway have arithmetically summed un-risked bestestimate total prospective resource potential of 382 MMboe and usually high risk as they aremostly at an early stage of evaluation. Further details of individual reseource size range andrisk are provided in the asset description section of this report.

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate


Edinburgh (Blackmore) 0 4 76 0 1 26 39% FaroeBrasse 14 23 33 7 12 17 43% Faroe

Dazzler Central 47 180 987 9 36 197 15% ENINjord NF2 4 18 37 0 1 3 54% Statoil

Total Oil & Liquids;MMstb 64 225 1133 17 50 243Gas Resources (Bscf)

Edinburgh (Blackmore) 0 24 476 0 9 167 39% FaroeDazzler Central 70 310 1553 14 62 311 15% ENI

Njord NF2 17 70 132 1 5 10 54% Statoil

Total Gas; Bscf 87 404 2161 15 76 487

Prospective Resources: Near Term Exploration (Norway)

Risk FactorGross on Licence Net Attributable

Operator

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate


Zircon 24 70 199 7 21 60 14% VNG NorgeDobby 3 10 21 0 1 2 60% Statoil

Nilus 8 14 30 1 1 2 15% StatoilRosapenna 17 30 111 3 6 22 18% StatoilSeychelles 11 80 459 2 16 92 12% Centrica

Mauritius 9 50 269 2 10 54 15% CentricaAerosmith 7 21 39 1 4 8 24% OMV

Oshun 11 22 31 2 4 6 23% TotalCassidy 5 40 132 1 6 20 32% CentricaRungne 34 46 75 14 18 30 30% Faroe





Rungne 21 28 43 8 11 17 30% Faroe

Total Gas; Bscf 190 556 2051 37 109 406

Prospective Resources: Medium Term Exploration Prospects (Norway)

OperatorRisk FactorGross on Licence Net Attributable


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The thirteen ‘Other’ leads and prospects in Ireland have arithmetically summed un-risked bestestimate total prospective resource potential of 220 MMboe and risk factors (chance ofdiscovery) in the range of 5 to 13%.


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Contents1 Introduction.......................................................................................................................1

1.1 Overview of the Assets..................................................................................11.2 Licence Details ..............................................................................................11.3 Sources of Information ..................................................................................11.4 Requirements ................................................................................................11.5 Standards Applied .........................................................................................21.6 No Material Change ......................................................................................21.7 Site Visit.........................................................................................................21.8 Liability...........................................................................................................31.9 Consent .........................................................................................................3

2 Producing and Fields Under Development ......................................................................42.1 UK Fields .......................................................................................................42.1.1 Blane Field: UK Block 30/3a and Norway Block 15/5a .................................42.1.2 Schooner Field: UK Blocks 43/30A, 44/26A..................................................72.1.3 Ketch Field: UK Block 44/28b .......................................................................92.1.4 Wissey Field: UK Block 53/4d .................................................................... 112.1.5 Minke Field: UK Block 44/24a .................................................................... 112.1.6 Orca Field: UK Blocks 44/29b, 24a ............................................................ 112.1.7 Topaz Field: UK Block 49/1a...................................................................... 142.1.8 East Foinaven Field: UK Blocks 204/24a, 25b........................................... 162.2 Norway Fields............................................................................................. 182.2.1 Njord Field: Norway Block 6407/7 and 6407/10......................................... 192.2.2 Hyme Field: Norway Block 6407/8 ............................................................. 232.2.3 Snilehorn Field: Block 6407/8 .................................................................... 262.2.4 Brage Field: Norway Blocks 30/6, 31/4 and 31/7....................................... 282.2.5 Ringhorne East Field: Norway Block 25/8.................................................. 312.2.6 Jotun Field: Norway Blocks 25/7 and 25/8................................................. 342.2.7 Glitne Field: Norway Block 15/5a ............................................................... 362.2.8 Enoch Field: Norway Block 15/5f ............................................................... 362.2.9 Butch Field: Norway Block 8/10 ................................................................. 382.2.10 Pil Field: Block 6406/11, 6406/12............................................................... 41

3 Un-Developed Discoveries............................................................................................ 453.1 UK Discoveries........................................................................................... 453.1.1 Perth, Lowlander and Dolphin: UK Blocks 15/21a, 15/21c and 14/25a ..... 453.2 Norway Discoveries.................................................................................... 553.2.1 Bue Discovery: Block 6406/11, 6406/12 .................................................... 553.2.2 Boomerang: Block 6406/11, 12.................................................................. 563.2.3 Fogelberg Discovery: Norway Blocks 6506/9 and 12 ................................ 583.2.4 South East Tor Discovery: Norway Block 2/5 ............................................ 593.2.5 Shango (Skirne East) Discovery: Block 25/3 ............................................. 62

4 Exploration Prospects ................................................................................................... 644.1 UK North Sea Prospects ............................................................................ 644.1.1 Medium Term Prospects ............................................................................ 644.1.2 Leads and Prospects Under Evaluation..................................................... 664.2 Norwegian Prospects ................................................................................. 664.2.1 Near Term Exploration ............................................................................... 674.2.2 Medium Term Prospects ............................................................................ 714.2.3 Additional Leads and Prospects Under Evaluation.................................... 734.3 Ireland Leads / Prospects........................................................................... 754.3.1 Leads Under Evaluation ............................................................................. 75

5 Economic Evaluation..................................................................................................... 775.1 Economic Inputs......................................................................................... 775.1.1 Production Profiles ..................................................................................... 77


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5.1.2 Capital Costs and Operating Costs............................................................ 775.1.3 Pricing......................................................................................................... 775.2 Economic Results....................................................................................... 78

6 References .................................................................................................................... 80Appendix 1: Evaluation Methodology ...................................................................................... 81

Reserves Estimation ..................................................................................................... 81Contingent Resource Estimation and Risk Factor ........................................................ 83Prospective Resource Estimation and Risk Factor ....................................................... 83Prospect Portfolio Evaluation Method ........................................................................... 84Economic Analysis Method and Assumptions .............................................................. 85

Appendix 2: Reserves & Resources Economic Inputs ............................................................ 86Appendix 3: PRMS Reserves Definitions .............................................................................. 100Appendix 4: LR Senergy and Author Credentials.................................................................. 108Nomenclature ........................................................................................................................ 109


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List of TablesTable 1.1: Faroe Petroleum Licences.................................................................................... 134

Table 2.1: Developed and Undeveloped Reserves (UK) ...........................................................4

Table 2.2: Developed and Undeveloped Reserves (Norway) ................................................. 19

Table 3.1: Contingent Resources (UK Atlantic and North Sea) .............................................. 45

Table 3.2: Contingent Resources (Norway) ............................................................................ 55

Table 4.1: Prospective Resources: Medium Term Exploration (UK North Sea) ..................... 64

Table 4.2: Prospective Resources: Other Exploration (UK North Sea)................................... 66

Table 4.3: Prospective Resources - Near Term Exploration (Norway) ................................... 67

Table 4.4: Prospective Resources - Medium Term Exploration (Norway) .............................. 71

Table 4.5: Prospective Resources – Other Exploration (Norway)........................................... 74

Table 4.6: Prospective Resources: Other Exploration (Ireland).............................................. 76

Table 5.1: Reserves NPV10 Net (UK Fields) .......................................................................... 78

Table 5.2: Reserves NPV10 (Norway Fields).......................................................................... 79

Table 5.3: Proved Plus Probable Reserves Economic Sensitivity Analysis............................ 79

List of Figures

Figure 1.1 Location Map: Faroe Licences, Fields, Discoveries and Prospects

Figure 1.2 UK Atlantic Margin: Portfolio Location Map

Figure 1.3 UK and Norway North Sea: Portfolio Location Map

Figure 1.4 UK Southern North Sea: Portfolio Location Map

Figure 1.5 Norway Northern North Sea: Portfolio Location Map

Figure 1.6 Norway Norwegian Sea: Portfolio Location Map

Figure 1.7 Norway Barents Sea: Portfolio Location Map

Figure 1.8 Ireland Celtic Sea: Portfolio Location Map

Figure 2.1 Blane: Development Scheme and Top F2 Structure Depth Map

Figure 2.2 Schooner: Location Map and Infill Locations

Figure 2.3 Schooner and Ketch Schematic of Facilities


www.lr-senergy.com xvii FinalK16FAR044L July 2016

Figure 2.4 Orca Location Map

Figure 2.5 Topaz: Top Carboniferous Depth Map and Export Route

Figure 2.6 East Foinaven: Reservoir Channel Sandstone Architecture and WellLocations

Figure 2.7 Njord: Structure Map with Well Tracks

Figure 2.8 Hyme and Snilehorn: Location Map

Figure 2.9 Brage: Field Outline

Figure 2.10 Ringhorne East: Structure Depth Map and Possible Future Infill WellLocations

Figure 2.11 Enoch: Location Map and Top Flugga Depth Map and Seismic Anomaly

Figure 2.12 Butch: Ula Tie Back Development Schematic

Figure 2.13 Pil: Top Reservoir Depth Map and Well Locations


www.lr-senergy.com 1 FinalK16FAR044L July 2016

1 IntroductionThis report was prepared by Senergy (GB) Limited (LR Senergy) between October and endDecember 2015 and was then updated in July 2016 to include the relinquishments and newlicence awards between the effective date (1st January 2016) and the report date, at the requestof the Directors of Faroe Petroleum Limited (Faroe).

1.1 Overview of the Assets

The report details the licence interests and the reserves, contingent resources, and prospectiveresources attributable to the assets. It consists of a technical evaluation of the Faroe producingassets, fields under development or requiring appraisal, the exploration prospects and leads inthe UK, Norway and Ireland (Figures 1.1 to 1.8).

The gross and net reserves and resources as of 1st January 2016 are detailed in Sections 2, 3and 4 of this report.

Field abandonment plans, other liabilities and any specific environmental protection issues orobligations are noted in the asset description sections of this report.

1.2 Licence Details

Table 1.1 details the licences held by Faroe in the UK, Norway and Ireland and the main licenceterms, including the duration. Further information on each licence is provided, if appropriate, inthe individual asset description sections of this report.

The legal, HSE planning and economic conditions for the working of these licences are basedon the current licensing regulations in the UK and Norway and the fiscal terms for the UK andNorway (see Section 5 and References 8 and 9).

Where appropriate any arrangements or agreements with partner companies are included inthe individual asset description sections of this report.

1.3 Sources of Information

The content of this report and our estimates of reserves and resources are based on dataprovided to us by Faroe. LR Senergy has accepted, without independent verification, theaccuracy and completeness of this data.

The data available for review varied depending on the asset and is noted in the body of thereport for each asset. The available data usually comprised information summarising thesubsurface interpretations of structure, reservoir, hydrocarbon-initally-in-place (HIIP) anddynamic data including field production data and reserves estimates by the operator,consultants and partners.

Budget and cost data was available from the operator for the producing assets and Faroeprovided scoping development cost estimates for the contingent and prospective resources.

1.4 Requirements

In accordance with the instructions, LR Senergy confirms that it:



is professionally qualified and a member in good standing of a self-regulatoryorganisation of engineers and / or geoscientists;

has at least five years relevant experience in the estimation, assessment andevaluation of oil and gas assets;

is independent of Faroe Petroleum plc “the Company”, its directors, seniormanagement and advisers;

will be remunerated by way of a time-based fee and not by way of a fee that is linkedto the Admission or value of the Company;

is not a sole practitioner;

has the relevant and appropriate qualifications, experience and technical knowledge toappraise professionally and independently the assets, being all assets, licences, jointventures or other arrangements owned by the Group or proposed to be exploited orutilised by it (“Assets”) and liabilities, being all liabilities, royalty payments, contractualagreements and minimum funding requirements relating to the Group’s workprogramme and Assets (“Liabilities”).

1.5 Standards Applied

In compiling this report, LR Senergy has used the definitions and guidelines set out in thePetroleum Resources Management System (2007 and 2011) prepared by the Oil and GasReserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointlysponsored by the World Petroleum Council (WPC), the American Association of PetroleumGeologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE) (References 1to 5). The results are presented in accordance with the requirements of the AIM Market of theLondon Stock Exchange, and of the Prospectus Rules published by the UK Financial ServicesAuthority from time to time, in particular as described in the “Note for Mining and Oil and GasCompanies - June 2009” and “CESR’s recommendations for the consistent implementation ofthe European Commission’s Regulation on Prospectuses No. 809/2004” (January 2005),including the European Securities and Markets Authority’s (ESMA) amendments to suchrecommendations in ESMA document ESMA/2013/319 (References 6 and 7).

1.6 No Material Change

LR Senergy confirms that to its knowledge there has been no material change of circumstancesor available information since the date of this report and we are not aware of any significantmatters, arising from our evaluation, that are not covered within this report which might be of amaterial nature.

1.7 Site Visit

LR Senergy did not undertake a site visit to inspect any of the Company’s exploration ordevelopment assets, as we did not consider that such an inspection would reveal informationor data that would be material.



1.8 Liability

All interpretations and conclusions presented herein are opinions based on inferences fromgeological, geophysical, engineering or other data. The report represents LR Senergy’s bestprofessional judgment and should not be considered a guarantee of results. Liability is limitedsolely to Faroe for the correction of erroneous statements or calculations. The use of thismaterial and report is at the user’s own discretion and risk.

1.9 Consent

LR Senergy hereby consent, and has not revoked such consent, to:

the inclusion of this report, in whole or in part, in documents prepared by the Companyand its advisers;

the electronic publication of this report on websites accessible by the public, includinga website of the Company; and

the inclusion of its name in documents prepared in connection to commercial orfinancial activities.

The report relates specifically and solely to the subject assets and is conditional upon variousassumptions that are described herein. The report must therefore, be read in its entirety. Thisreport was provided for the sole use of Faroe on a fee basis. Except with permission from LRSenergy this report may not be reproduced or redistributed, in whole or in part, to any otherperson or published, in whole or in part, for any other purpose without the express writtenconsent of LR Senergy.



2 Producing and Fields Under DevelopmentThe Faroe portfolio comprises fifteen producing fields or fields under development located inthe mature hydrocarbon province of the UK and Norwegian sectors of the North Sea (Figures1.1, 1.3, 1.4). There are also three fields which have ceased production.

In the UK there are the Schooner, Ketch, Orca and Topaz gas fields in the Southern North Sea,and the East Foinaven field in the Atlantic Margin. The Njord, Hyme, Snilehorn, Brage,Ringhorne East, Butch and Jotun fields are located in Norwegian waters. Enoch and Blane areUK / Norway median line fields. The Glitne field in Norway and Minke and Wissey fields in theUK have ceased production. Jotun is forecast to cease production in 2016.

2.1 UK Fields

Of the fifteen fields, six are located in the UK and on production. An infill well is expected to bedrilled on Blane and, in consequence, a portion of the reserves is categorised as undeveloped‘justified for development’. The Minke and Wissey gas fields have ceased production and areexpected to be decommissioned and, therefore, have continuing liabilities.

Table 2.1: Developed and Undeveloped Reserves (UK)

2.1.1 Blane Field: UK Block 30/3a and Norway Block 15/5a

The Blane oil field is located on the UK / Norway median line about 34 km southwest of the Ulafield. Blane was discovered in 1989 by Norwegian well 1/2-1 drilled by Phillips Petroleum andby UK sector well 30/3a-1 drilled by BP.

Production started in September 2007 and water injection commenced 18 months later in 2009.Gas lift also commenced in 2009. An infill well is scheduled for 2017.

The field is operated by Talisman and has been developed with a subsea facility tied to the Ulafield. The subsea templates are located on the UK continental shelf. The agreed split betweenUK licence P.111 and Norwegian licence PL143BS is 82 and 18% respectively. The unitisedequities in the field are as follows:

Operator


Proved,Probable &


Probable

Proved,Probable &


Schooner 0.0 0.1 0.1 0.0 0.0 0.1 FaroeKetch 0.1 0.2 0.2 0.1 0.1 0.1 Faroe

East Foinaven 2.0 2.8 5.0 0.2 0.3 0.5 BPBlane 6.1 11.4 17.4 1.9 3.5 5.3 Talisman

Total Oil & Liquids; MMbbls 8.2 14.5 22.7 2.1 3.9 6.0Gas Reserves (Bscf)

Schooner 5.1 11.4 22.5 3.0 6.8 13.5 FaroeKetch 9.1 18.3 22.9 5.5 11.0 13.7 FaroeOrca 0.4 0.6 1.4 0.0 0.0 0.0 ENGIE

Topaz 0.9 1.9 4.1 0.1 0.1 0.3 RWE

Total Gas; Bscf 15.5 32.2 50.8 8.6 18.0 27.6

Producing and Under Development (UK): Developed and Un-developed Reserves




Company Equity (%)Talisman (operator) 43.0%Faroe 30.5%Nippon Oil 13.99%Dana 12.5%

The main licence terms are summarised in Table 1.1 (see Section 1.2).

2.1.1.1 Subsurface Description and HIIP

Blane is situated in the North Sea Central Graben. The trap is a low relief (ca. 60 m) four-waydip closed structure (Figure 2.1) and, consequently, the depth maps are sensitive to the depthconversion method employed. A significant east to west trending fault separates the main fieldarea from the southern flank. Otherwise there is limited evidence for field compartmentalisationas faulting is minor. The reservoir is in the distal part of the main Paleocene Forties Fan systemcomprising Upper Forties high-density turbidite, amalgamated channel / lobe sandstone bodies.The gross Upper Forties interval is over 100 m thick in the Blane wells and the gross pay rangesfrom 47 to 23 m with net to gross averaging 70 to 80%. Good lateral connectivity is predictedalthough the interbedded nature of the reservoir means that vertical connectivity is limited.

There is significant water saturation uncertainty as a consequence of the generally lowpermeability (7 mD in Zones E and D, and 30 mD in Zone F) and as the structure is low relief.The 30/3-1 contact is prognosed to lie between 3,133 and 3,148 m tvdss; log picks indicate acontact at 3,122 m tvdss in well N1/2-1, although shows were noted down to 3,148 m tvdss; acontact was identified at 3,140 m tvdss in the water injector well 30/3-3z. The operator’s basecase assumes a tilted (hydrodynamic) contact with an east to west tilt.

The reservoir is highly over-pressured and contains good quality oil with a gravity of 42° APIand a gas oil ratio (GOR) of 367 - 430 scf/bbl. Initial pressure in the Blane reservoir was 5,625psia at 3,100 m tvdss) with a bubble point pressure of 1,930 psia. H2S was reported as rangingfrom 8 to 45 parts per million (ppm).

The most recent field stock tank oil initially in place (STOIIP) estimate reviewed by LR Senergyof 109 MMstb (range 85 to 143 MMstb, low-high cases) is based on the 2014 model updatewhich incorporates a new petrophysical study and more complex reservoir heterogeneity forimproved history matching and investigating the incremental recovery from the proposed infillwell. Over 99% of this STOIIP is in Zones E and F, with the deeper zones mainly sitting belowthe free water level. The main STOIIP uncertainties are the oil-water-contact (OWC) model,saturation height function, structure depth map and fault seal assumptions. There is a largerSTOIIP uncertainty in the southern and north eastern field areas.

2.1.1.2 Field Development

Blane was developed as a subsea tie-back to the Ula field utilising two production wells, 30/3a-2 (BPE) and 30/3a-4 (BPW) and one water injection well (30/3a-3z). The wells are tied backvia a 10-inch flowline to the platform which is located some 34 km to the northeast. Ula providesseparation and processing facilities for produced fluids together with water injection and gas-lift services. Oil is exported via Ekofisk and Norpipe to Teesside and gas is sold to the Ulapartners.

There is a design fault on the valves of the Xmas trees on the two producing wells.Consequently there is a chance of tree valve failure on the wells. The operator has plans to



drill an infill producer to recover additional incremental volume (including potentially from theSouthern Flank) as well as the remaining reserves in BPE and BPW if one or both of thesewells fail. This well is not yet approved by the partnership, and final design and costing isongoing but there is reasonable certainty that it will be drilled in 2017 or 2018.

Future field abandonment plans have not been reviewed in detail by LR Senergy but we areinformed that the operator’s plans meet current regulatory requirements. The decommissioningcost assumption is provided in Appendix 2. LR Senergy is not aware of any specificenvironmental protection issues beyond the statutory regulatory requirements.

2.1.1.3 Production Performance

Cumulative production to 31st December 2015 was 24.7 MMstb of oil and 7.1 Bscf of gas.

The overall field performance has been good. Production from Blane started in September2007. The producers benefit from some aquifer pressure support, which helped to sustain earlyproduction rates. Oil production remained reasonably steady above 16,000 bbl/d until mid 2008when a general decline commenced. Gas lift of the two production wells was started inFebruary 2009. Water injection was implemented to supplement the aquifer pressure supportin early 2009 and quickly resulted in an increase in oil rate, confirming the benefit of additionalpressure support and improved sweep efficiency. Water breakthrough occurred in 2011 andhas risen steadily to ca. 45% (BPE 50% WC, BPW 30% WC).

Relatively stable water injection proportional to production of around 4,000 bwpd has beenachieved. Lack of produced water from the Ula platform has necessitated the use of seawaterinjection. This is expected to induce barium sulphate scaling requiring well interventions forscale squeezes, representing a potentially significant future Opex commitment.

2.1.1.4 Reserves and Production Forecasts

The main uncertainties in forecasting future production from Blane are speed of watercutdevelopment in the existing wells, when the Xmas trees may fail on these wells potentiallyresulting in lost production, and when the infill well will be drilled.

The following assumptions have been made when creating the forecasts and reservespredictions.

1P Reserves. LR Senergy has matched the existing individual well performance usingexponential decline and has applied a 75% operating efficiency. A low caseincremental contribution from the planned infill well is included from September 2017based on the operator’s previous simulation work using the low case model.

2P Reserves. LR Senergy has matched the existing individual well performance usinghyperbolic decline and has applied a 75% operating efficiency. A base caseincremental contribution from the planned infill well is included from September 2017based on the operator’s latest simulation work using their base case model.

3P Reserves. LR Senergy has matched the existing individual well performance usinga more optimistic hyperbolic decline and has applied a 75% operating efficiency. Ahigh case incremental contribution from the planned infill well is included fromSeptember 2017 assuming a 25% uplift from the the operator’s base case simulationwork.



Reserves include both ‘Developed’ (on production) and ‘Undeveloped’ (justified fordevelopment) categories, the latter being for the infill well.

The production forecasts for all three reserves categories have been used in the economicevaluation of the reserves and are provided, together with the capital and operating cost inputs(including decommissioning cost assumptions), in Appendix 2.

The production forecasts should be consulted for information on peak and plateau production,anticipated field decline and field life.

2.1.2 Schooner Field: UK Blocks 43/30A, 44/26A

The Schooner field is located 145 km northeast of Theddlethorpe on the south eastern marginof the Silverpit Basin of the Southern North Sea. First gas was in September 1996. The infilldevelopment well, SA-11, was brought on stream in early November 2013. The well declinedmore quickly than expected and it is believed that salt precipitation has affected the potential ofthe well.

The Schooner field is unitised between licence P689, block 43/30a and licence P516, block44/26a. Faroe became the field operator on 9th October 2014 with a 60% unit interest followinga recent purchase. The unitised equities in the field are as follows:

Company Equity (%)Faroe Petroleum (operator) 60Tullow Oil 40



The Schooner field is a large (16 km long by 4 km wide) anticlinal, NW - SE trending, reversefault bounded closure, with approximately 1,000 ft of relief above the gas water contact (GWC).The majority of the GIIP and production is from the Carboniferous, Westphalian C/D 'Red Bed',Ketch Formation sandstones. The reservoir consists of a highly variable, low to moderate netto gross (25 to 40%) sequence of low sinuosity single and stacked fluvial braided channels.Unpredictable productivity is a function of poor interconnection of reservoir sands.

The latest static model reviewed by LR Senergy indicates full field GIIP of 558 Bscf. Of thissome 73 Bscf is considered to be in the undrilled Schooner Far NW compartments.

The SA-11 development well completed in 2013 and is a replacement for SA-07, but is alsointended to capture stranded reserves up dip from well SA-06Y.

Possible infill drilling locations have been identified based on the simulation and differencesbetween the static volumes and volumes in place estimated from production data. Theseinclude targets on the South Eastern Flank and Schooner Far NW (Figure 2.2). Owing tocurrent maturity levels of these infill opportunities, the potential associated with them is notincluded in the reserves categories but they do constitute additional Contingent Resourceswhich are not, however, quantified in this report.




The Schooner field has been developed utilising a four legged, 12 slot not-normally-mannedwellhead platform installed in a water depth of 71 m (233 ft). The jacket was installed duringthe second quarter of 1995 with five development wells pre-drilled. There are minimalprocessing facilities (apart from chemical injection) and thus reliability is high. First gas exportwas achieved in September 1996. Compression at the Murdoch platform has been availablesince September 2001.

Gas from Schooner is transported through a 16-inch, 28 km long pipeline to the ConocoPhillips-operated Murdoch platform. From the Murdoch platform, the gas is exported to shore via theConocoPhillips-operated Caister Murdoch System (CMS) and on to the processing plant at theConocoPhillips-operated terminal facilities at Theddlethorpe on the Lincolnshire coast.



Cumulative production to the 31st December 2015 was estimated to be 299.2 Bscf.

Six wells remain on production out of 11 drilled producers. Average field production while onstream at the year end was around 16 MMscf/d. Five wells were producing in cycles (SA-01,04, 08, 10, 11) with uptime ranging from 19 - 40%; SA-02 was producing relatively steadily(uptime 79%) with an average of about 6 MMscf/d. In well SA-11 a water wash and camerarun in May 2015 indicated the presence of halite in the tubing string. The data acquired will beused to design a long term solution to the halite issue in this well.

Future production levels will depend on the decline of the existing well stock, the managementof the cyclic wells and the long term solution for SA-11.


Decline curve analysis has been carried out on a well by well basis. The following assumptionshave been made when creating the forecasts and reserves estimates.

1P Reserves. LR Senergy has matched the existing individual well performance usingexponential decline and has applied 87% operating efficiency. It is assumed that SA-02 provides the major contribution to production with minor contributions from well SA-10 and SA-11. The cyclic producers SA-01, SA-04 and SA-08 remain shut in from 1st

January 2016.

2P Reserves. LR Senergy has matched the existing individual well performance usinghyperbolic decline and has applied 87% operating efficiency. It is assumed the cyclicproducers SA-01 and SA-08 stop producing in January 2018, SA-04 stops mid 2016.SA-11 is scheduled for workover to plug back water production and is assumed torecommence dry gas production from mid 2016.

3P Reserves. LR Senergy has matched the existing individual well performance usingmore optimistic hyperbolic decline and has applied 87% operating efficiency. It is



assumed the cyclic producers SA-01, SA-04 and SA-08 continue producing to the endof field life, albeit at low production levels. SA-11 is scheduled for workover to plugback water production and is assumed to recommence dry gas production from mid2016.

A gas shrinkage factor of 0.93 and a condensate yield factor of 7.5 bbl/MMscf were applied toall forecasts. All reserves are considered ‘Developed’ (on production). The contingentresources associated with infill well opportunities are not included in the current assessment,but represent additional potential.

The production forecasts for all three reserves categories have been used in the economicevaluation of the reserves and are provided, together with the capital and operating cost inputs,(including decommissioning cost assumptions), in Appendix 2.


2.1.3 Ketch Field: UK Block 44/28b

Ketch is located in licence P453, block 43/28b, 28 km southeast of Caister / Murdoch on thesouth eastern margin of the Silverpit Basin of the Southern North Sea. First gas was inSeptember 1999. Faroe is now the field operator with a 60% interest following a recentpurchase of Tullow equity.

Company Equity (%)Faroe Petroleum (operator) 60Tullow 40



The Ketch horst structure is elongated in a northwest to southeast trend. The trap is dip closedto the northwest, dip and fault closed to the south, and with stratigraphic closure to thenorthwest below the Base Permian (BPU). The field is subdivided, by northeast to southwestfaults, into three main fault terraces, and to the northeast is the Ketch NE Flank (Figure 2.3).

The reservoir is Carboniferous Ketch and Cleaver Formation (Westphalian C/D) fluvialsandstones of variable quality and lateral connectivity which subcrop the BPU. The reservoircomprises ten distinctive high net to gross layers.

A new static model and petrophysical review was completed at the end of 2012 and hassignificantly narrowed the discrepancy between the static in-place volume and the dynamic in-place volume. The latest Ketch static model indicates full field GIIP of 453 Bscf. Assuming acommon contact at 12,825 ft tvdss, Ketch NE Flank could contain 63 Bscf GIIP.


The Ketch field has been developed with a normally unattended, twelve-slot, four-leggedplatform (215 MMscf/d design capacity), with a working test separator. The platform has threespare well slots and the capability to provide a future riser and J-tube.



The gas is exported via an 18-inch, 28 km line to the Murdoch platform, where separation andcompression occurs, before onward transportation via the Caister Murdoch Infrastructure to theConocoPhillips operated facilities at Theddlethorpe on the Lincolnshire coast.

There is significant remaining development potential in Ketch. Opportunities include infill andsidetrack candidates. The Ketch NE Flank has potential for up to three infill targets in separatecompartments: North, Far North and Central. Other sidetrack options are also underconsideration. The infill potential is under evaluation by Faroe, as new operator, and as thesepotential targets are not firm at present, they are not included in the reserves categories. Theywill be assessed as contingent resources in the future.



Cumulative production to the 31st December 2015 was 247 Bscf. The field currently producesfrom five of the ten development wells: KA01, KA07, KA08z, KA09y and KA10y.


Decline curve analysis has been carried out on a well by well basis.

The following assumptions have been made when creating the forecasts and reservespredictions:

1P Reserves. The Proved case assumes exponential decline on the producing wellswith no further infill drilling activity.

2P Reserves. The Proved plus Probable assumes hyperbolic decline on the producingwells with no further infill drilling activity.

3P Reserves. The Proved plus Probable plus Possible assumes hyperbolic decline onthe producing wells with improvement in reservoir performance compared to the 2Pscenario.

An operating efficiency of 80% is assumed for all forecasts which accounts for well downtimeas well as facilities. A gas shrinkage factor of 0.91 is assumed and a condensate yield of 10.6bbl/MMscf. All reserves are ‘Developed’ (on production). The contingent resources associatedwith other infill well opportunities are not included in the current assessment, but representsignificant additional potential.

The production forecasts for all three reserves categories have been used in the economicevaluation of the reserves and are provided, together with the capital and operating cost inputs,(including decommissioning cost assumptions), in Appendix 2.




2.1.4 Wissey Field: UK Block 53/4d

The Wissey field is located in the UK Southern North Sea block 53/4d, licence P039, 10 kmeast of Horne and Wren. The current equity holders in licence P039 (block 53/4d) are:

Company Equity (%)Tullow Oil (operator) 62.50First Oil 18.75Faroe Petroleum 18.75

The Wissey field has been assessed to have no remaining reserves and will bedecommissioned.

Field decommissioning is in progress with a total cost provision of £4.5 MM gross. LR Senergyis not aware of any specific environmental protection issues beyond the statutory regulatoryrequirements.

2.1.5 Minke Field: UK Block 44/24a

The Minke field is located in the Southern North Sea Silver Pit Basin in UK block 44/24a, licenceP611, approximately 25 km east of Caister-Murdoch and 13 km southwest of the D15 platform.The current equity holders in the Minke field are as follows:

Company Equity (%)Gaz de France (operator) 15.60E.On Ruhrgas 42.67RWE DEA 35.84Faroe Petroleum 5.89

The 44/24a-6y well is shut in and there has been no production since 2010.

Further production from Minke is not planned and the Cessation of Production is in progress.The field abandonment plans have not been reviewed in detail by LR Senergy but we areinformed that the operator’s plans meet current regulatory requirements. LR Senergy is notaware of any specific environmental protection issues beyond the statutory regulatoryrequirements.

2.1.6 Orca Field: UK Blocks 44/29b, 24a

The Orca discovery is located in the Southern North Sea Silver Pit Basin in the UK blocks44/24a and 44/29b and Netherlands Southern North Sea blocks D15b and D18a (Figure 2.4).It lies 10 km to the south of Minke and 20 km southwest of the D15 platform. Productioncommenced in December 2013. The current equity holders in the Orca unit are as follows:

Company Equity (%)Gas de France Netherlands (operator) 22.50%EBN 22.50%Gaz de France UK 8.58%E.On Ruhrgas 21.34%RWE DEA 19.71%Faroe Petroleum 3.24%



The field unitisation split has been provisionally agreed at 55% in the UK and 45% in the Dutchsector; this was predicated on a 3 well development and any change in development plan mayresult in a revised split.



The Orca structure is fault closed to the west and southwest and dip closed to the east andnortheast. The dominant NNW - SSE fault trend and secondary NNE - SSW cross faultssubdivide Orca into a large number of structural segments. The calculated free water level(FWL) in 44/29b-4 (segment 6) is 11,962 ft tvdss and in D18-1 (segment 11 South) is 12,031 fttvdss. The reason for the different contacts is not conclusively explained. The contacts in theother undrilled segments are unknown.

The depth conversion in the Orca area is not straight forward and a number of methods havebeen tested. The lack of certainty in depth conversion feeds through to uncertainty in GIIP andreserves.

The reservoir is Carboniferous Westphalian C/D Ketch Member sandstones of the SchoonerFormation and comprises fluvial channel sandstones similar to those in Minke.

The probabilistic volumetric GIIP estimates are determined on a segment basis, and appear tocapture the full range of uncertainty in depth conversion, halite thickness, GWC and reservoirparameters. The reservoir gas contains 22 to 26% nitrogen.

Before the 3 development wells were drilled in 2013/2014 the most likely case combined GIIPin Segments 6 and 11 was 115 Bscf, of which 85 Bscf was considered to be connected. Thetotal unconnected GIIP in all segments was estimated to be as high as 380 Bscf.

Development drilling revealed a shallower GWC in Segment 11 North (-20 m, in line withSegment 6), deeper top reservoir in Segment 11 North and Segment 6 (ca. 15 m) leaving asmaller gas column in these areas and early water breakthrough in D18-A2 and D18-A3. D18-A1 in Segment 11 South saw poorer reservoir quality than expected which has resulted in lowerrate and reduced connectivity. All of these factors have led to a reduction in estimatedconnected GIIP, currently estimated to be 16 Bscf.

2.1.6.2 Field Development Plan

The development utilises a normally unmanned platform with three wells. Extended reach wellswere drilled perpendicular to the predominant N-S channel direction in order to try to maximisethe number of channels penetrated and the connected GIIP. The gas is transported via a 20km 8-inch export pipeline to D15-A for treatment and entry to the NGT pipeline system.

The first 2 wells, D18-A1 and D18-A2 came online in December 2013. D18-A3 came online inMarch 2014.

A sidetrack southeast of D18-A1 is currently being considered to access directly some of thebaffled volumes that D18-A1 appears to see but a decision will depend on further fieldmonitoring. Further appraisal wells could be considered if justified, for example in Segment 7.





D18-A1 saw poorer reservoir quality than expected resulting in a low but stable production rateof ca. 180 km3/d gas. Slow pressure build ups in this well suggest a baffled connectivity overa large area. D18-A2 saw water breakthrough very quickly and operations have been unableto restart the well since February 2014. D18-A3 saw strong production initially at a rate of 800km3/d, but this declined rapidly and water breakthrough occurred in July 2014 with the welldying shortly after. Pressure continues to build in this well and it is hoped it can be producedagain in 2016.

2.1.6.4 Reserves and Production Profiles

The cumulative production to the 31st December 2015 was 4.7 Bscf of gas and 1.45 Mstb ofcondensate.

The latest production profile scenarios from the operator are based on an updated staticestimate of GIIP post drill and dynamic analysis of well performance to date. Initial P/Z analysisin all the wells suggested very limited connected GIIP (ca. 3.5 Bscf per well) howeversubsequent longer build ups in D18-A1 would suggest a larger connected GIIP (over 7 Bscf)and the shut in pressure in D18-A3 continues to rise. The operator has therefore assumed ahigher connected GIIP in the 3P scenario which seems reasonable.

LR Senergy has reviewed the available production and pressure data, and the operator’stechnical work, and believes the following assumptions are reasonable and fit for purpose:

1P Reserves. Assumes only D18a-A1st1 produces going forward with a recoveryfactor of ca. 80% based on Segment 11 South connected GIIP and historicalperformance.

2P Reserves. D18a-A3 also comes back on production in 2015 for a limited time andD18a-A1st1 produces for longer. Recovery factor ca. 70% based on slightly higherGIIP (accounting for reservoir pressures continuing to rise in both wells when shut in).

3P Reserves. Both D18a-A3 and D18a-A1st1 on production. Assumes a higher GIIPagain on Segment 11 South and recovery factor ca. 75%.

A shrinkage factor of 0.67 has been applied to all the production profiles to account for fuelconsumption and losses to obtain a sales gas volume. Condensate yield is negligible with aCondensate / Gas ratio of ca. 0.26 bbl/MMscf.

All reserves are considered developed. Reserves have not been assigned to the potentialsidetrack southeast of D18a-A1st1 nor to other undrilled fault blocks. These have unquantifiedcontingent resources potential.

The production forecasts for all three reserves categories are provided in Appendix 2 andshould be consulted for information on peak and plateau production, anticipated field decline



and field life. These forecasts have been used in the economic evaluation of the reserves andare provided, together with the capital and operating cost inputs, in Appendix 2.

2.1.7 Topaz Field: UK Block 49/1a

The Topaz field is located in the Southern North Sea Silver Pit Basin in blocks 49/1a (P530),49/2a (P1013) and 49/2b (P847) in 32 m of water in the UK Southern North Sea, 15 km to thesoutheast of Schooner. The current unitised equities in Topaz are as follows:

Company Equity (%)RWE DEA (operator) 57.5Ithaca 35.0Faroe Petroleum 7.5

Faroe has a 7.5% interest in the Topaz field through its 25% working interest in block 49/1awhich is unitised with 49/2a to form the Topaz Unit. This equity is fixed for the duration of theUUOA and has been assumed for the calculation of net recoverable volumes.



The field consists of NW - SE trending fault blocks with a large GIIP range due to GWCuncertainty, reservoir connectivity concerns and a complex overburden, which gives rise tolarge depth conversion uncertainty. A NE - SW cross fault is clearly mapped in the south andseparates Fault Blocks 1 and 2 (Figure 2.5). The Westphalian C/D reservoir in the Topaz wellscomprises fluvial, low-sinuosity channelised sandstones. Well 49/2a-6z drilled sub vertically in2008 close to the bottom hole location of 49/2a-5z. This sidetrack penetrated a 53 m gross gascolumn within the Ketch Formation and tested >30 MMscf/d. The 49/2a-5z FWL is estimatedat 3,924.5 m tvdss, and for 49/1-3 at 3,942.5 m tvdss. This difference in contact depth implieseither structural or stratigraphic separation between the wells.

LR Senergy has reviewed the GIIP estimates which in the FDP were up to 142 Bscf in total,and the more recent work looking at connected GIIP in the different field areas, and concludesthat the work is robust and follows good industry practice.

The 2013 Petrel model estimates the 49/2a-6z connected GIIP ranges from 46 to 82 Bscf witha P50 of 54 Bscf. The partnership is considering a new well (location TN_1) located to the eastof 49/2a-6z updip of 49/1-3.

The GIIP estimates for Fault Block 2 (TS-1 location) are assessed to be up to 28 Bscf with aP50 of 17 Bscf, and this is currently considered to be insufficient to justify a well.


The subsea appraisal well 49/2a-6z is tied back to the Tullow operated Schooner platform viaa dedicated 15 km 6-inch export pipeline. Gas and associated liquids are evacuated to theCMS Murdoch platform via the existing 28 km 16-inch Schooner-CMS line.

The 49/2a-6z producer is depleting Fault Block 1. Connected volume estimates from P/Zanalysis are significantly lower than volumetric estimates of GIIP. The TN_1 infill well has beenproposed as a potential option to improve the recovery factor of the larger connected GIIP



identified. Recent simulation analysis by the operator indicates this well could potentiallyrecover an additional 10 - 38 Bscf. This well had been notionally planned for 2014 but thePartnership has decided to defer and there are currently no plans to drill this well.

The 15th October 2015 OCM reported possible Topaz field cessation of production at endSeptember 2016.



The cumulative production to the 31st December 2015 was 10.4 Bscf of gas and 26.2 MMtonnes of condensate.

Production commenced in November 2009. The initial rates from 49/2a-6z were around 22MMscf/d, but had declined with intermittent production incorporating short term gas ratedeclines of around 4.0 MMscf/d by the middle of 2015.

Earlier material balance work had indicated substantially less connected GIIP than volumetricestimates. However there is evidence of increasing levels of pressure support and connectedGIIP estimates have increased year on year. The latest 2014 analysis indicates 13 - 15 Bscfconnected GIIP. The longer term trend is difficult to predict leading to relatively high uncertaintyin recoverable volume estimates. There has been no water produced to date.

The 2015 operating efficiency on Topaz was only 26%. The major influence on operationalefficiency is the export system availability through Schooner and TGT.


Decline curve analysis has been used to derive gross technical reserves using the followingassumptions:

1P Reserves. The Proved reserve case is based on exponential decline matched toperformance, an operating efficiency of 45% (based average of last 4 years) and atechnical cut off of 800 Mscf/d based on the operator’s forecast of unstable production.

2P Reserves. The Proved plus Probable case is based on hyperbolic decline matchedto performance, an operating efficiency of 55% (based on Faroe’s estimate) and atechnical cut off of 500 Mscf/d based on the operator’s forecast of unstable production.

3P Reserves. The Proved plus Probable plus Possible case is based on harmonicdecline matched to performance and an operating efficiency of 60%.

Gas shrinkage is not assumed for Topaz based on the information provided. The condensate/ gas ratio is assumed to be constant at 13 bbl/MMscf. The infill well is currently considered tohave contingent resources potential, not quantified in this report, but representing upsidepotential.



The production forecasts have been used in the economic evaluation of the reserves and areprovided, together with the capital and operating cost inputs, in Appendix 2. The productionforecasts should be consulted for information on peak and plateau production, anticipated fielddecline and field life.

2.1.8 East Foinaven Field: UK Blocks 204/24a, 25b

The East Foinaven field is located in blocks 204/24a and 204/25b on the UK Atlantic Marginadjacent to the Foinaven main field and 190 km west of the Shetland Isles. The field wasdiscovered by well 204/25b-5 in 1995, and has been developed by three high angle productionwells (P41, 42 and 43) and two water injection wells (W41 and 42), tied back from a subseaproduction manifold (in 400 m water depth) to the main Foinaven field FPSO, the PetrojarlFoinaven, about 7 km to the northwest.

The partners in the field and their respective equities are as follows:

Company Equity (%)BP (operator) 43%Marathon 47%Faroe 10%



The East Foinaven field comprises a NW – SE oriented Paleocene turbidite channel system,resulting in a layered reservoir, which is interpreted to have been feeder channels for the sandsin the northern compartments of the main Foinaven field to the northwest (Figure 2.6). The oilis 26° API with GOR of 420 scf/stb at a depth of about 7,150 ft tvdss. Roughly west to easttrending faults are present but are not as prominent as in the main Foinaven field.

The Paleocene turbidite sandstone layered reservoir (T31 to T34) comprises a series ofamalgamated channel sandstone bodies, with an average net to gross ratio of 55% and averageporosity of 27% and core permeability in the range 500 to 2,000 mD.

The 3D seismic data is crucial for the modelling of the field, with both sand body geometry andnet / gross distributions being derived from seismic data, calibrated to the wells. The latestseismic reprocessing techniques are used on the large repeat seismic data-set that exists forthe greater Foinaven area. This 4D data is used to understand pressure variations, water-floodfrontal progression, connectivity and continuity. The operator considers the 4D surveillanceprogramme to be a tool for day to day management of base production.

A static model in 2011 resulted in a reduction in the STOIIP estimate by almost 50 to 138 MMstbwith the majority in the T34L interval (113 MMstb). The primary reason for this decrease is therecognition of thinner sand units as a result of improved seismic resolution (supported by theP43 well results), and reduction in Net to Gross (NTG) especially towards the field margins.

This model was used to assess infill drilling options. A total STOIIP of 46 MMstb is nowconsidered to be unconnected to existing wells. Unfortunately, this is in a large number ofcompartments and at present none of these is considered to be sufficiently large to justifydrilling.



The 2011 static model has been used to build an updated dynamic simulation model, FFM2011,which has now been adopted as the official forecasting tool for East Foinhaven after historymatching early in 2014. The impact of this on the operator’s simulated forecasts is discussedbelow.


East Foinaven has been developed by three high angle production wells and two water injectionwells, tied back from a subsea production manifold (in 400 m water depth) to the main Foinavenfield FPSO, the Petrojarl Foinaven, about 7 km to the northwest. First oil from the field was inSeptember 2001. Oil is exported by shuttle tanker and gas is exported via the West ofShetlands pipeline to Sullom Voe and on to Magnus.

The field was initially developed with two producers (P41 and P42) and two water injectors(W41 and W42), and a third producer (P43) was drilled in 2008.

Future opportunities at East Foinhaven are likely to be limited by the integrity of the Foinhavenplatform. Current Cessation of Production is estimated by the operator as 2020, which giveslimited scope for future improved recovery options.



Cumulative production to 31st December 2015 was 18.6 MMstb of oil and 9.1 Bscf of gas. Thetwo current producer wells P41 and P42 (P43 shut in) are supported by two injectors W41 andW42. The P41 production well was brought on-stream in September 2001, and water injectionfrom well W41 followed shortly after. Well P42, the second production well, was put on-streamin December 2004, and water injection from well W42, commenced in January 2005. Producerwell P43 (East Foinaven T34.1) rapidly cut water after coming on stream in 2009 and is nowshut in.

LR Senergy has received historical production data from 1st February 2006 to October 2015.The earlier production history has been provided as scanned plots.

The initial pressure in P41 was about 270 psi greater than that encountered in the discoverywell, whilst that in W41 was about 400 psi higher, demonstrating a net inflow from the mainFoinaven field injectors. The flowing bottom hole pressure (FBHP) in P41 dropped sharply atfirst. The initial peak rate of around 20,000 bopd fell, eventually stabilising at 9,000 to 10,000bopd once the effect of pressure support from W41 was established. Well P41 is currentlyproducing at approximately 500 bopd, at a 90% watercut.

Well P42 showed similar rapid fall off in production from an initial rate of 10,000 bopd to around3,000 bopd before stabilising at around 5,000 bopd after the well was choked back and thebenefit of W42 pressure support was seen. P42 is currently producing about 2,500 bopd with60% watercut production.




Future production performance was assessed using decline curve analysis on a well by wellbasis, and the results checked on a field basis, which gave consistent results.

1P Reserves. The Proved (1P) production profile is based on a decline curve fittingthe historical data with an exponential decline. Future operating efficiency is based onBP’s extensive planned maintenance work, averaging 63% up to 2020. The assumedGOR is 400 scf/bbl and the date of cessation of production (COP) is 1st January 2021.

2P Reserves. The production profiles and associated recoverable reserves for theProved plus Probable (2P) case were derived from hyperbolic decline curves. Futureoperating efficiency is based on the operator’s planned maintenance work with somereduction in 2018 towards the proposed COP date, averaging 70% up to 2020. Theassumed GOR is 550 scf/bbl and the date of COP is 1st January 2021.

3P Reserves. This case assumes harmonic decline and operating efficiency averageof 74%. The assumed GOR is 700 scf/bbl and the date of COP is 1st January 2023.

Fuel gas usage of 1.5 MMscf/d is assumed based on the the data supplied. Since this is higherthan the produced gas rate in all categories, sales gas reserves are assumed to be zero.

All reserves are ‘Developed’ (on production). Contingent resources associated withoptimisation of the waterflood performance and the introduction of either LoSal and / or Polymerinjection are not currently included. This could represent significant upside potential but wouldrequire an extension of production facility life beyond 2020 and further laboratory work andreview within the updated dynamic model.

The production forecasts for all three reserves categories have been used in the economicevaluation of the reserves and are provided, together with the capital and operating cost inputs,in Appendix 2. Gas production has been calculated using a constant GOR of 0.3 Mscf/bbl. Theproduction forecasts should be consulted for information on peak and plateau production,anticipated field decline and field life.

2.2 Norway Fields

Nine fields are located in Norway, six of which are currently on production, with three (Snilehorn,Pil and Butch) ‘justified for development’. In addition Glitne was decommissioned in 2014. Infillwells are expected to be drilled on Njord, Brage and Ringhorne East, and in consequence aportion of their reserves are categorised as undeveloped (justified for development). The Hymefield was brought on-stream early in 2013 but shut-in in summer 2013 together with the Njordfield due to structural integrity problems with the Njord platform. Both fields were brought backinto production in July 2014 and a redevelopment is planned, and therefore reserves in bothfields are currently classed as developed (in production) and undeveloped (justified fordevelopment).



Table 2.2: Developed and Undeveloped Reserves (Norway)

Totals may not sum exactly due to rounding. Njord and Brage liquids total include natural gasliquid (NGL) converted to barrels using 14 bbl/tonne.

2.2.1 Njord Field: Norway Block 6407/7 and 6407/10

The Njord field is located in the Haltenbanken of the Norwegian Sea approximately 30 km westof the Draugen field in a water depth of approximately 330 m. The current unitised equities inthe field are as follows:

Company Equity (%)E.ON Ruhrgas Norge AS 30.0Statoil Petroleum AS (operator) 20.0GDF SUEZ E&P Norge AS 40.0Faroe Petroleum Norge AS 7.5VNG Norge AS 2.5


Oil production started in 1997 and gas export in 2007. During the summer 2013 turnaroundperiod, platform integrity issues were detected. Inspection of the deck frame on the Njord Aplatform revealed deformation of the main deck beams. Analysis of an updated structural modelduring 1Q 2013 demonstrated that the Njord structure was overloaded and that the installationdid not comply with design requirements. Consequently, all variable drilling deck loads wereremoved and the Njord production was shut in for almost a year while structural reinforcementof the deck frame was carried out. Production restarted in July 2014, with continued monitoringfor deformations, and the assumption of further integrity work being carried out.

Operator


Proved,Probable &


Probable

Proved,Probable &




Jotun 0.5 0.6 0.7 0.0 0.0 0.0 ExxonMobilEnoch 0.7 1.6 3.1 0.1 0.2 0.4 TalismanButch 20.2 40.9 58.0 3.0 6.1 8.7 Centrica

Pil 25.6 71.0 108.7 6.4 17.8 27.2 VNGTotal Oil & Liquids; MMbbls 157.0 302.2 435.0 19.0 40.5 59.5Gas Reserves (Bscf)



Jotun 0.0 0.0 0.0 0.0 0.0 0.0 ExxonMobilButch 4.4 10.0 16.0 0.7 1.5 2.4 Centrica

Pil 79.0 144.9 215.2 19.8 36.2 53.8 VNGTotal Gas; Bscf 384.9 667.5 992.9 44.2 78.9 119.5

Producing and Under Development (Norway): Developed and Un-developed Reserves




The operator of the field, Statoil, initiated the “Njord Future Project” in 2013 to establish a long-term solution for continued production and drilling operations on the Njord field. This projectreached an important milestone in October 2014 when the feasibility of reinforcing the existinghull was demonstrated and approved and the project passed through DG1. While the projectis not yet sanctioned, LR Senergy understand that the operator and partners are committed toa long term solution to the Njord platform integrity problems and therefore considerredevelopment to be a reasonable expectation.


The Njord trap is a complexly faulted structure with Middle Jurassic (Aalenian to Bathonian)sandstone reservoirs containing light oil and associated gas, at a depth of about 2,850 m tvdss.The field is divided into Central Area (CA), East Flank (EF), Northern Area (NA), and the NorthWest Flank (NWF) (Figure 2.7).

The base 3D seismic survey was acquired in 1997 and since 2001 Njord has benefited fromtime-lapse seismic monitoring (4D). LR Senergy has not undertaken an independent seismicinterpretation but has reviewed the mapping of the operator. This data is used to monitormovement of injected gas and the areal extent of depleted reservoir in cases where thepressure has fallen below bubble point. A new ocean-bottom seismic (OBS) survey wasacquired in 2010 with the aim of improving fault imaging and better defining infill targets in theNWF as well as in the main field areas. A second OBS survey was acquired in June 2014 andthe 3D/4D processing was expected to be completed by end 2015.

The undeveloped NWF comprises downthrown fault blocks defined by NE to SW trending faults,two of which, segments A and B, have been tested by wells, both of which encountered gasand condensate. Well 6407/7-6, in the Tilje B segment encountered poor reservoir properties(approximately 1 mD permeability). Well 6407/7-7S in the A segment encountered gascondensate in better quality reservoir. This area has been the subject of a very detailedevaluation in early 2010, which formed the basis of a recommendation to drill two producers inthe NWF area in the A segment.

The Lower to Middle Jurassic Ile and Tilje reservoirs are deltaic to tidal deposits and were re-evaluated in 2008 and the results incorporated in a new full field model in 2010. LR Senergyhas accepted the results of this model.

The Tilje sandstone is the main reservoir in the CA, EF and NA. The Ile sandstone overlies theTilje in large parts of the EF and is a more restricted reservoir in the CA and NA areas. TheNWF also has both Tilje and Ile objectives. The high density faulting has resulted in a largenumber of isolated compartments with variable fault transmissibility, reservoir intervals, fluidtypes and contacts.

The current HIIP estimates combined for the Ile and Tilje in the main field areas (EF, CA andNA) date from the 2014 Njord Annual Status Report. The STOIIP range for the main field is723/828/1039 MMstb (P90 / P50 / P10) and the GIIP range is 1,119 / 1,275 / 1,564 Bscf (P90 /Expected / P10). The latest GIIP estimates for the NWF, also from the 2014 Annual StatusReport, are in the range 215 / 350 / 494 Bscf plus associated condensate. LR Senergy has notperformed a detailed assessment of these latest HIIP estimates.

A comprehensive update of the full field static and dynamic models for Njord is currently beinghistory matched.




The field has been developed with a semi-submersible drilling, accommodation and productionfacility, Njord A, and a storage vessel, Njord B. The oil in the storage vessel is offloaded totankers for export to the market. Njord A is located over subsea completed wells connectedthrough flexible risers. The Plan of Development and Operation (PDO) for Njord gas exportwas approved on 21st January 2005. At the beginning of 2010, the authorities consented toPDO exemption regarding development of the NWF.

The Njord field has so far been developed with 27 oil producers and 9 gas injectors drilled infour different drilling campaigns and including slot reclamations. The latest phase ofdevelopment well drilling commenced in September 2008 and six infill wells had been drilledsuccessfully by the end of 2011. There are currently 8 producers and 2 injectors in the Njordfield.

The longer term schedule for future infill development includes the following approved wells: A-20 H, A-11 AH, A-3 H, A-2 H, A-12 H (recompletion), A-18 CH, A-14 HT2 (recompletion), A-21H and A-14 AH. The recent platform problems mean that the drilling of these wells is delayedand is now planned to commence in 2019. While A-21 H and A-14 HT2 are not yet approved,these two wells are considered by the operator to be part of the Njord Future project and,therefore, becomes part of the projects uncertainty and associated recoverable volume.Additional infill wells, A-19 BH, A-4 BH, NA-P3, CA-P1 and SA-P1 currently in the workprogramme, constitute a separate incremental project with unquantified contingent resources,as firm intent to drill is not yet in place.

During the summer 2013 turnaround period, platform integrity issues were detected. Inspectionof the deck frame on the Njord A platform revealed deformation of the main deck beams.Analysis of an updated structural model during 1Q2013 demonstrated that the Njord structureis overloaded and that the installation does not comply with design requirements.Consequently, all variable drilling deck loads were removed and the Njord production was shutin for almost a year while structural reinforcement of the deck frame was carried out. Productionrestarted in July 2014 with continued monitoring for deformations and the assumption of furtherintegrity work being carried out.

The operator of the field, Statoil, initiated the “Njord Future Project” in 2013 to establish a long-term solution for continued production and drilling operations on the Njord field. This projectreached an important milestone in October 2014 when the feasibility of reinforcing the existinghull was demonstrated and approved and the project passed through DG1. While the projectis not yet sanctioned LR Senergy understands that the operator and partners are committed toa long term solution to the Njord platform integrity problems and therefore considerredevelopment to be reasonably certain. The operator’s current assumptions are thatproduction will continue until May 2016 when the platform will be brought to shore formodifications. There will be no drilling or intervention activity during this time. The modifiedplatform will return and resume production in 2019 and infill drilling will start again at this point.

Hyme is located 19 km east of Njord and is tied in to Njord A. Hyme started production in March2013. Hyme production was halted at the same time as Njord production in summer 2013 andresumed in July 2014. The recent Snilehorn discovery (Section 4) is also a candidate for tie-into Njord.





Cumulative allocated production as of 31st December 2015 was 167 MMstb of oil, 353 Bscf ofgas and 3.9 MM tonnes of NGL.

Production from Njord started in September 1997. The initial production strategy was gasinjection for pressure support in parts of the reservoir and pressure depletion in the rest of thereservoir. Since gas export started in 2007, only minor volumes of gas have been injected.During 2011 a minimum injection strategy was agreed, as well as some production restrictions,to limit reservoir depletion and allow continued infill drilling in the main field. This strategy isrevised every year.

The field has a relatively low recovery factor due to the complex reservoir with many faults.Optimisation of the field development scheme is challenging since faults and other reservoirheterogeneities greatly influence the fluid flow. Wells often drain much smaller parts of the fieldthan originally planned.

Future development plans for Njord are likely to include gas injection in the East Flank, theNorthern Area, and the Central Area. Gas injection in the Ile reservoir started in December2007 by conversion of a production well into a gas injector (A-5BH).


LR Senergy is informed that the operator and partners are committed to a long term solution tothe Njord platform integrity problems and therefore consider redevelopment to be reasonablycertain and continued production after the redevelopment in 2016-2019 to remain as reserves.

Owing to the complexity of the Njord field and the constant change in its operating conditions,the data in RNB2016 (annual reserves submission to the Norwegian Petroleum Directorate)has been used as the basis for the production forecasts.

LR Senergy consider that there is significant potential for an increase in 1P reserves in the nearfuture as the re-development project and infill well decisions mature.

1P Reserves. Assumes the low case production profiles from RNB2016 for the existingwellset and the approved infill wells. Reserves associated with the A-21 H infill are notincluded as this well will target the unpenetrated NE3 segment and there remainssignificant uncertainty in structure and OWC.

2P Reserves. Assumes the base case production profiles from RNB2016 for theexisting wellset, the approved infill wells and A21 H.

3P Reserves. Assumes the high case production profiles from RNB2016 for theexisting wellset, the approved infill wells and A21 H.

An NGL yield of 0.0025 bbl/m3 dry gas is assumed. All reserves beyond 2016 are considered‘Undeveloped’ (justified for development) as significant expenditure is required for the



redevelopment and though there is a reasonable expectation of development it is not yetapproved.

The production forecasts for all three reserves categories have been used in the economicevaluation of the reserves and are provided, together with the capital and operating cost inputs,in Appendix 2. The production forecasts should be consulted for information on peak andplateau production, anticipated field decline and field life.

2.2.2 Hyme Field: Norway Block 6407/8

The Hyme field is located in the Haltenbanken area of the Norwegian Sea approximately 19 kmnortheast of the Njord field (Figure 2.8). The current equities in the licence are as follows:

Company Equity (%)E.ON Ruhrgas Norge AS 17.50Statoil Petroleum AS (operator) 35.00GDF SUEZ E&P Norge AS 20.00Core Energy AS 17.50Faroe Petroleum Norge AS 7.50VNG Norge AS 2.50

Production commenced in March 2013 and the field is developed with a 4 slot template and a9-inch production flowline tied back 19 km to the Njord A platform. The field was shut down inJuly 2013 to allow structural reinforcement of the Njord deck frame. Production restarted inJuly 2014 with continued monitoring for deformations and the assumption of further integritywork being carried out.



The Hyme trap is a downthrown faulted roll over structure with a Middle Jurassic Tilje sandstonereservoir and is divided into eastern and western segments by a NE-SW trending fault (G2),the sealing capacity of which is uncertain.

The discovery wells 6407/8-5S and 6407/8-5A drilled in 2009 tested the eastern segment butthe presence of a direct hydrocarbon indicator (flatspot) in the Tilje reservoir western segmentis convincing evidence for a more extensive accumulation. An OWC in the Tilje was identifiedfrom pressure gradients in the 6407/8-5S well at 2,132 m tvdss.

A new 3D seismic survey was acquired and a PSDM cube interpreted in 2010/11. The easternsegment is reasonably well imaged, but interpretation in the western segment is still uncertaindue to data quality limitations. The presence of sub-seismic or poorly imaged internal faultingis considered likely.

The Middle Jurassic Tilje reservoir is deltaic to tidal deposits with porosity of over 30% from loganalysis and permeability is predicted to be very good. There is permeability uncertainty dueto the lack of direct data, however initial production data indicates high well productivity. Theexisting geomodel was modified in 2011 to incorporate the results of the new mapping and usedto generate STOIIP estimates. LR Senergy has not undertaken an independent interpretationbut has reviewed the structure maps and reservoir model inputs of the operator.



The HIIP volumes for the Tilje sandstone are probabilistically derived and are based onuncertainty analysis. The STOIIP range represented in the Hyme 2014 Annual Status report is27 / 56 / 90 MMstb (P90 / P50 / P10), and the GIIP range 28 / 60 / 95 Bscf (P90 / Expected / P10).

The current model and associated HIIP pre date production and the drilling of the productionwell, C-2 AH, into the Western Segment where there was previously no well control. The staticand dynamic models for Hyme were updated in 2015 with the latest geophysical interpretation,including a reinterpretation of the Base Cretaceous Unconformity (BCU) horizon which hasbeen lowered to achieve better consistency with the other horizons and well ties of drilled wells.The new reservoir model was expanded to include the Garn, Ile and Åre in order to reviewpotential infill targets. The new model (FFM) reduces both the in-place and reserves estimates(source 15th September 2015 MCM) by 20 - 30%, but detailed results were not available forreview. The STOIIP range is 27, 56 and 90 MMstb.


The Hyme field is developed with a 4 slot template and a 9-inch production flowline to Njord Alocated 19 km southeast. The drainage strategy is a two-branched well on the top of thestructure with water injection for pressure support. A water injection line is injecting de-aeratedsea water from Njord to Hyme. Gas lift will be installed in the production well to aid lifting of thewellstream when required as the watercut increases.

The operator drilled the horizontal advanced multilateral production well, C-2 AH, from thetemplate in the north, with the mainbore in the western segment and the lateral in the easternsegment. Branch control is installed, in the form of inflow control valves in both branches.Water breakthrough is expected to come earlier in the eastern lateral. The injector, C-4, wasdrilled into the northern part of the eastern segment (where the fault dies out) penetrating thewater zone. The injector supports both segments.

Production started from C-2 AH in March 2013. However, the field was shut in, in July 2013,due to the integrity issues with the Njord A platform. Injection into C-4 H started in Febraury2014 with an almost immediate response seen in C-2 AH. Production resumed in C-2 AH inJuly 2014 and the reservoir is currently produced at voidage replacement. C-2 AH is currentlyproducing at around its initial plateau rate of 15,500 bopd. However, maintaining this plateaurate is now challenging given water breakthrough during the year, and the watercut reported atthe 15th September 2015 MCM was 38%.

The operator’s current assumptions are that production will continue at Njord and Hyme untilMay 2016 when the platform will be brought to shore for modifications. The modified platformwill return and resume production from October 2019 and infill drilling will be considered at thispoint. An infill oppportiunity is currently identified, but the contingent resource potential is notquantified.

The Njord project has potential to extend Hyme’s end of field life from 2020 to 2028, whichwould increase ultimate recovery from the Hyme field.

Field abandonment plans are uncertain in view of the current platform integrity status, whichalso has implications for future HSE planning and protection. The decommissioning costassumption is provided in Appendix 2.




Cumulative allocated production as of 31st December 2015 was 10.2 MMstb of oil, 8.4 Bscf ofgas and 0.2 MM tonnes of NGL.

Well C-2 AY1HT3/Y2H, the Tilje formation producer found the un-depleted reservoir at virginpressure. The objective of both the main bore and the lateral were met during drilling. Sandswere present as expected and good drainage intervals were obtained in Tilje 3, Tilje 2.2 andTilje 4.

The well has been in low pressure production since 14th April 2015, without gas lift. Productionrates in Octobr 2015 were approximately 2,500 sm3/d (15,500 bopd) of oil, 500,000 sm3/d (17.5MMscf/d) of gas, a GOR of ca. 200 sm3/sm3 (1,120 scf/stb) with a water liquid ratio of 38%.

Start-up of water injection was postponed by 1 year due to operational issues. The waterinjection well, C-4 H is currently injecting approximately 4,750 m3/d (29,900 bwpd) of sea water.The operator has raised concerns that the injection strategy to maintain voidage replacementand if possible rebuild reservoir pressure, cannot be achieved with increasing watercut atplateau production.


LR Senergy is informed that the operator and partners are committed to a long term solution tothe Njord platform integrity problems and therefore consider redevelopment to be a reasonableexpectation, and continued Hyme production after the redevelopment in 2016-2019 to bereasonably certain.

The operator’s 2015 updated static and simulation models indicate a reduction in both the in-place volumes and reserves estimates of 20 - 30% from previous estimates.

In the 2014 report, LR Senergy made adjustments to maintain a broader range in the 1P – 3Pestimates, from that of the operator, in view of the current uncertainty on the long term water-cut performance of the field. For the 2016 profiles, LR Senergy has rephased the prior year’sprofiles in line with the revised Njord platform reparatory work. However, the profiles are notadjusted pending the establishment of a reliable decline trend post plateau.

1P Reserves. The low case production profile is based on a P90 scenario. It is assumedproduction stops in May 2016 and resumes in October 2019.

2P Reserves. Assumes a hyperbolic decline to the oil production to align with theRNB2015 base case production profile. It is assumed production stops in May 2016and resumes in October 2019.

3P Reserves. The high case production profile corresponds to a P10 scenario and alsoassumes production stops in May 2016 and resumes in October 2019.

The RNB2015 GOR (sales gas scf/bbl) profile has been applied to the LR Senergy oil profilesto estimate gas reserves. A NGL yield of 0.0038 bbl/sm3 dry gas is assumed.

All reserves beyond 2016 are considered ‘Undeveloped’ (justified for development) as theredevelopment, although a reasonable expectation, is not yet approved. The productionforecasts for all three reserves categories are provided in Appendix 2 and should be consulted



for information on peak and plateau production, anticipated field decline and field life. Theseforecasts have been used in the economic evaluation of the reserves and are provided, togetherwith the capital and operating cost inputs, in Appendix 2.

2.2.3 Snilehorn Field: Block 6407/8

The Snilehorn discovery in licence PL348 is located 4 km west and down dip of the Hyme field(see Section 2.2.2) on the Halten Terrace (Figure 2.8). The discovery well 6407/8-6 andsidetrack (6407/8-6A) were completed in 4Q 2013 and found oil and gas in Early / Mid JurassicIle and Tilje sandstones, as well as other formations.

The current equities in the licence are as follows:

Company Equity (%)E.ON Ruhrgas Norge AS 17.50Statoil Petroleum AS (operator) 35.00GDF SUEZ E&P Norge AS 20.00Core Energy AS 17.50Faroe Petroleum Norge AS 7.50VNG Norge AS 2.50

The development of Snilehorn is linked to the Njord Future Project (see Section 2.4.1).


The trap is a rotated fault block structure with Early / Middle Jurassic Ile and Tilje primaryreservoirs, and is mapped at the top of each of the reservoir horizons. Hydrocarbons were alsoencountered in Garn and Are sandstones and further data will be acquired during thedevelopment phase which may result in commercial oil volumes. However, these are notcurrently included in the volumetric assessments.

The structure is dip and fault bounded to the west, east and south, and divided into westernand eastern structural segments. The seismic picks of the top reservoir horizons are good increstal locations but uncertainty increases on the flanks especially to the east. Amplitudeanomalies are associated with the main reservoir sandstones and there is a good, but notperfect correlation between the Ile ODT and a decrease in amplitude down flank. The Tiljeamplitude response is more ambiguous with the ‘bright’ amplitude response being restricted tothe western segment where there is a good correlation between the amplitude shut-off andOWC identified in the sidetrack in this reservoir.

The depth mapping of the structure is sensitive to the velocity model and the discovery wellcame in 118 m low at the BCU. The degree of GRV sensitivity has been assessed by using arange of depth conversion methods and the resulting high to low ratio is almost 2. Thisuncertainty is reflected in the STOIIP range.

Reservoir properties are similar to the Njord field, where the best sands have permeability inexcess of 1 Darcy, but there is a large degree of facies controlled heterogeneity and limitedvertical communication. Both wells were cored and pressure data were acquired. However,the wells were not tested. Well 6407/8-6 encountered a 40 m gross oil column in Ile sandstoneswith a NTG of 57%, Sw 15% and porosity 23%. An approximately 130 m gross oil column inTilje sandstones had a NTG of 70%, Sw 30% and porosity 17%.



The 6407/8-6A sidetrack encountered a 43 m gross oil column in the Tilje with a NTG of 76%,Sw 50% and porosity 17%. A 75 m gross oil column in the Ile had a NTG of 67%, Sw 24% andporosity 18%. An OWC at 3,013 m tvdss was encountered in this well in the Tilje. All othercontacts were ODTs.

Pressure data in the Tilje indicates a best case FWL at 3,017 m tvdss which is compatible withthe sidetrack log derived contact. The Ile ODT is at 2,874 and the pressure data indicate aFWL between 2,875 and 2,900 m tvdss.

Average core derived permeability in the Ile sandsones is 118 mD, and in the Tilje is 60 mD.Four mini-DST’s were performed in the main bore and no tests in the lateral bore. The averageratio between the mini-DST permeability and the arithmetic average of core permeabilities forTilje formation is 0.25. The average ratio between the mini-DST permeability and the geometricaverage of core permeabilities for Tilje formation is 0.31. It should be noted that corepermeabilities measure the absolute permeability of cores while the mini-DST measures theaverage affective oil permeability of the tested interval. Core data in the Åre Formation weremeasured on side-wall cores making the values less reliable.

The Ile and Tilje reservoirs contain undersaturated oil with fairly similar properties. For Ile themulti-stage flash properties are GOR 265 sm3/sm3, STO density 0.794 g/cc and Bo at Psat1.916 Rm3/sm3. The saturation pressure is 216.9 bar and the oil viscosity at initial reservoirconditions is 0.147 cp. Initial reservoir pressure is 316.6 bar at 2,885 m tvdss with atemperature of 110 oC. For Tilje the multi stage flash properties are GOR 329 sm3/sm3, STOdensity 0.790 g/cc and Bo at Psat 2.124 Rm3/sm3. The saturation pressure is 238.4 bar andthe viscosity at initial reservoir conditions of 0.149 cp. Initial reservoir pressure is 350.2 bar at3,017 m tvdss with a temperature of 114 oC.

Structure and depth mapping uncertainty are incorporated into the GRV uncertainty range, asis the potential for lateral reservoir variability, especially reservoir thickness. Contact and otherreservoir parameters are reasonably well constrained. The probabilistically derived STOIIPrange for the Tilje and Ile is low 93, best 126, and high 169 MMstb, and LR Senergy considersthat this is a realistic reflection of the uncertainty.


The most likely development concept for project evaluation and planning purposes envisagestwo production wells and subsea tie-back to Njord A via a new-built production flowline. Thedepletion strategy has considered three options (depletion only, water injection with 2 injectorsand late water injection with one injector). Water injection, gaslift and umbilical would be viathe Hyme field. In this regard the Snilehorn development is linked to the Njord Futures Project(see Section 2.2.1). Oil processing is planned at Njord A and storage at Njord B. Associatedgas would be processed and transported from Njord A through Åsgard Transport to Kårstø.

The selection of the Njord A as host platform for Snilehorn has been approved subject toreinforcement of the Njord A structure being the selected concept for the Njord Future project,and the phased water injection strategy is being progressed as the preferred option.

An alternative being considered is to tie back production via Hyme to Njord with or without amultiphase pump and subsea separation. An alternative export route would be via the Shelloperated Draugen platform.



Slanted producers are planned with co-mingled Ile and Tilje production. One producer will belocated close to the discovery well in the Horst area. The second producer in the south will bein the eastern segment. The producers will be gas lifted.

Although the details of the final field development plan are not yet agreed, LR Senergy isinformed that the operator, Statoil, and partnership has approved the 2016 work programmeand budget and is firmly committed to the Snilehorn project in light of Statoil’s Projectprioritisation and deferral programme.


The operator has performed a reservoir uncertaintly study based on multiple realisations of the2014 geological model and the simulation model. The work flow that has been followed is astandard approach. The analysis quantatively assesses the principle uncertainties of STOIIP,fault seal, zonal barriers, absolute permeability, Kv/Kh ratio, relative permeability model andsaturation end points. Production efficiency uncertainty was also captured in the probabilisticassessment.

LR Senergy has reviewed the additional simulation uncertainty work reported in September2015 for the 3 main depletion scenarios (Section 2.2.3.2). This work is still in progress and willlead to a DG2 support package in 2016. LR Senergy has assumed the start date for productionwill be a short time after the re-instatement of the Njord platform. This has been taken asJanuary 2020 based on recent data review. LR Senergy considers that the uncertainty analysisand the range of parameters selected provide a representative range of outcomes. The P90,P50 and P10 outcomes from the uncertainty study have been used. The exact start date and thecessation of production date will be dependent on the selected development option and thelongevity of the host facility. The production profiles have been prepared based on theRNB2016 return.

1P Reserves. This is the P90 outcome from the simulation based uncertainty analysis.

2P Reserves. This is the P50 outcome.

3P Reserves. This is the P10 outcome.

All reserves are categorised ‘Undeveloped’ (justified for development). The productionforecasts are provided in Appendix 2 and should be consulted for information on peak andplateau production, anticipated field decline and field life. The gas profiles are gross wet gasproduction without any deductions for fuel and flare or NGL recovery. This forecast has beenused in the economic evaluation and is provided, together with the capital and operating costinputs. The decommissioning cost assumption is provided in Appendix 2. Details of eventualfield abandonment and environmental protection issues are currently not available, though anabandonment cost estimate is included in the economic evaluation.

2.2.4 Brage Field: Norway Blocks 30/6, 31/4 and 31/7

The Brage field is located in the North Sea west of Bergen, in the area between major fieldsTroll and Oseberg. The current unitised equities in the field are as follows:



Company Equity (%)Wintershall Norge AS (operator) 35.2000Repsol Norge AS 33.8434Faroe Petroleum Norge AS 14.2567Core Energy AS 12.2575VNG Norge AS 4.4424


Production started in 1993 and water injection in the Statfjord and Fensfjord Formationscommenced soon after. The field has 40 well slots and is currently producing from some 16wells, injecting water in 4 wells, gas in one well and waste in another well. There are also twoUtsira water producers. Gas injection in the Sognefjord Formation started in March 2009. Thefirst production from the Brent Group started in 2008, supported by water injection.


The trap is a horst block structure with multiple reservoir horizons in the latest Triassic andJurassic Statfjord, Fensfjord, Sognefjord and Brent sandstones (Figure 2.9). The reservoirquality varies from poor to excellent. Of the existing production wells ten are located in theStatfjord reservoir (seven producers and three injectors), thirteen in the Fensfjord (nineproducers and four injectors), four in the Sognefjord (three producers and one gas injector) andfour (three producers and one injector) in the Brent reservoir. The Brage reservoirs containlight oil (37o API) and associated gas.

An APA 2012 licence award covers a possible field extension to the north named Brage NorthFensfjord and Sognefjord, which is interpreted to be in communication with the Brage field andcomprises a continuation towards the northeast. The reserves associated with this extensionare stated by the operator to be between 1.9 and 3.5 MMstb with 2.5 MMstb in the best caseand with a chance of success of 35%.

The production from well 31/4-A-19 A since 2010 has increased reserves in the Fensfjordreservoir in the northern part of the field. New full field 3D/4D seismic acquired in 2014 will beused to mature new infill targets in all reservoirs in the future.

The operator’s field STOIIP estimate is approximately 1,000 MMstb.


Brage is developed from a fixed platform and the oil is transported by pipeline to Oseberg andthrough the Oseberg Transport System (OTS) to the Sture terminal. A gas pipeline is tied backto Statpipe.

Production start up was in 1993 and water injection in the Statfjord and Fensfjord Formationscommenced soon after. More than 30 production and injection wells have been drilled, someof which have been producing from both the Upper and Lower Fensfjord units without zone-control. The field is mature with many producers shut in due to high watercut and / or very poorproductivity (Middle Fensfjord). Some producers have been converted to injectors, some ofwhich have injected both water and gas.



Production from the Sognefjord reservoir started in 1997. Since then, only two additionalproducers have been drilled: A-31 T2 (2004) and A-40 B (2007). One gas injector (A-35 A)started injection in 2009.

The Brent reservoir has been in production since February 2008. A-28 B is producing from theBowmore Segment and A-1 A T2 (since November 2008) from the Knockando segment. TheBowmore injector A-22 A was drilled early in 2009.

Although in decline, efforts to increase field recovery are ongoing, through the identification ofadditional infill targets and new exploration. An infill drilling and well intervention programme iscurrently ongoing. Well A23D (Sognefjord / Fensfjord) was completed in 2014, A18A (FensfjordSouth) in 2015 and A07 (ORE) is currently being completed. Wells A-8B and A-6 A (StatfjordNorth Injector Producer pair) are also scheduled for drilling. In addition, recent work hasresulted in the addition of two producers and an injector to the expected drilling programme.They are Statfjord 1 (A-2 area), 2 (A-10 area) and WI (A-16 gain). Additional infill targets havebeen identified (including several “low perm” wells in Fensfjord) and are being matured by theoperator. These are currently considered unquantified contingent resources. A conceptfeasibility study for developing the Brage North area, located 8 to15 km north of the Brageplatform, via a subsea tie back has been completed in 2015. Due to marginal economics, thisproject will not be continued into concept select phase. Any volumes from Brage North willhave to be drained from future infill ERD (Extended Reach Drilling) wells from the Brage drillingfacilities.

Work is ongoing to find new ways of increasing recovery from the field including evaluatingseveral technologies for enhanced oil recovery. A pilot project for microbiological injection(MEOR) started in June 2014 in the Fensfjord however that also had to be stopped due to apump problem. SWAG and a water injector in Sognefjord and Polymer Assisted SurfactantFlooding (PASF) project in Statfjord may be implemented in the future. The incrementalresources for EOR projects are not incorporated in the reserves and constitute unquantifiedContingent Resources. Further numerical simulation and laboratory work is planned todetermine the impact of uncertainties on the economic viability of the IOR options.

The operator plan for Brage, as a production facility, is to increase the lifetime span to 2025 or2030. The platform systems will require upgrade in the coming years to handle the plannedextended field lifetime, and further develop the reservoir to increase the remaining productionpotential. Licence extension has been granted to 2030.



Production from Brage started in 1993 and water injection commenced soon thereafter.Cumulative production to the 31st December 2015 was 360 MMstb of oil and 128 Bscf of gas.

The field watercut is high and most of the wells require artificial lift (gas).

The infill drilling programme began in 2014 with A-23D. This well came online in November2014 after some drilling difficulties. However, the well performed badly and has since stoppedproduction. A-18 has been drilled and was put on production in 2015; well performance is



ahead of expectation. The latest well, A0-7, is coming in as prognosed and is planned to becompleted as an Ore reservoir producer and production is expected to commence in Q1 2016.Wells A-8B and A-6A are scheduled for drilling.

The start up of the Sognefjord gas cap production profile is dependent on the free gascompressor capacity, which is assumed to occur in different years for the 1P, 2P and 3Pprofiles. Due to rules for reporting, start-up time for all profiles are set at the start-up time forthe 2P profile which is 2018.


The Brage field is producing from four reservoirs: Brent, Fensfjord, Sognefjord and Statfjord.

Monthly total field data were downloaded from the Norwegian Petroleum Directorate (NPD)official database. The LR Senergy reserves estimates are based on the following assumptions:

1P Reserves. Oil production forecast for existing wells is based on exponential decline.For the ongoing drilling programme, incremental low case production profiles from thepre-drill documentation have been added for A-8B and A-6A, with timing according tothe latest drill schedule. A further three Statfjord reservoir wells (2 producers and aninjector, Statfjord 1, 2 and WI) have been included based on recent technical study.

2P Reserves. Oil production forecast for existing wells is based on hyperbolic decline.For the ongoing drilling programme, incremental base case production profiles from thepre-drill documentation have been added for A-8B and A-6A and the 3 Statfjord wells,Statfjord 1, 2 and WI, with timing according to the latest drill schedule.

3P Reserves. Oil production forecast for existing wells is based on harmonic decline.For the ongoing drilling programme, incremental high case production profiles from thepre-drill documentation have been added for A-8B and A-6A, A-6A and A-20, and the3 Statfjord wells, Statfjord 1, 2 and WI, with timing according to the latest drill schedule.

Gas reserves are based on the RNB2016 GOR profiles (sales gas scf/bbl), including expectedgas from the Sognefjord gas cap production, which commenced in 2015. A NGL yield of 0.004bbl/sm3 has been assumed.

Reserves include both ‘Developed’ (on production) and ‘Undeveloped’ (approved fordevelopment) categories, the latter being for infill wells. The contingent resources associatedwith further infill well opportunities, Brage North and EOR projects are not included in the currentassessment, but represent significant upside potential.


2.2.5 Ringhorne East Field: Norway Block 25/8

The Ringhorne East field is located in the North Sea west of Haugesund in the Balder field area.The Jotun field is located to the north in the same block. The water depth is about 130 m. Thecurrent unitised equities in the field are as follows:



Company Equity (%)ExxonMobil E & P Norway AS 77.38Statoil Petroleum AS 14.82Faroe Petroleum Norge AS 7.80

Production start up was in 2006. The RHE7 well was completed and started production in July2012. The Ringhorne rig was warm stacked in 2013 due to programme challenges and thenext phase of infill well drilling delayed. Resumption of infill drilling is now anticipated in 2019.



The trap is a fault block structure with a Jurassic Statfjord sandstone reservoir containing lightoil at 940 m depth and the mapping is subject to depth conversion uncertainty due to complexvelocity variation in the overburden.

A geological model incorporating reprocessed seismic data, improved time-to-depth conversionand new well 25/8-C24 was completed in 2008 and history matched. This model resulted inincreased in-place volume estimates with STOIIP from 186, 239 to 322 MMstb and GIIP from49, 55, to 60 Bscf. The high side incorporates volume from outside of the Central fault block.

A 4D seismic survey was acquired in 2009 and repeated in 2012. The existing simulation modelwas unable to match the water sweep pattern indicated by these 4D surveys. For this reason,and as a basis to assess additional infilll opportunities properly, the decision was made torebuild static and dynamic models. Results from this rebuild are not yet completed andconsequently were not available for this review.

The operator carries a diverse inventory of infill opportunities across the field (Figure 2.10).While several of these targets have been impacted by the 2012 4D seismic survey, and needto be re-assessed following the ongoing model update, the overall 4D survey results and currentSTOIIP assessment of the field do indicate significant remaining potential (ca. 50 MMstbrecoverable).


The field is developed by four production wells drilled from the Ringhorne platform on the Balderfield. After initial processing on the platform, the oil is exported to the Balder FPSO vessel forprocessing and export. Oil is offloaded from the Balder FPSO by shuttle tanker whilst gasvolumes are either exported or used as lift gas on the Jotun platform.

The Phase 2 drilling programme commenced with RHE7 (C13C) in 2012, but further drillingwas delayed pending a review of drilling operations due to the operational difficultiesencountered whilst drilling the extended reach RHE7 well. Based on the operator’s September2015 TCM a Ringhorne East opportunity generation project is in hand. This is due to updatethe static and dynamic model through 2016. Current plans are to recommence drilling in 2019with at least 1 infill well. The operator carries a diverse inventory of opportunities across thefield and LR Senergy considers that there is a reasonable expectation that at least 1 infill targetwill be matured for the 2019 timeframe, quite possibly more.

The status of the production facilities after 2025 is uncertain and the operator’s current basecase scenario is for COP in 2025.



Future field abandonment plans have not been reviewed in detail by LR Senergy, but we areinformed that the operator’s plans meet current regulatory requirements. The decommissioningcost assumption is provided in Appendix 2. LR Senergy is not aware of any specificenvironmental protection issues beyond the statutory regulatory requirements.


Cumulative production to 31st December 2015 was 71.2 MMstb of oil and 13.9 Bscf of gas.

Production from Ringhorne East started in 2006. Production performance suggests that theRinghorne East reservoir is receiving good pressure support from the regional aquifer withpressure dropping only 10 bar since start of production (this is consistent with pre-drillexpectations). Consequently there is no justification for water injection at present andsimulation indicates that injection will not be required. Early water breakthrough was seen onthe C-14 well in April 2006 within one month of start up. C-03 saw water breakthrough in August2008 with C-17 cutting water initially in March 2009. C13C started production in July 2012.Watercut increased rapidly from initial production to 60% and is increasing slowly. The field’swatercut at the end of 2015 was 66%. Chokes and gas lift have generally been increased overtime to maximise oil production.


The field is currently developed with four wells. The LR Senergy reserves estimates are basedon well by well decline curve analysis and the following assumptions:

1P Reserves. The Proved case assumes exponential decline fitted to well by wellhistorical production until COP, which is assumed in 2025 in line with the operator. Theoperating efficiency is assumed to be 90%, with an additional 50% downtime on C-14due to slugging issues. It is assumed that 1 infill well will be drilled in 2019 with anincremental recovery of 3.1 MMstb.

2P Reserves. The Proved plus probable case assumes hyperbolic decline fitted to wellby well historical production until a COP date of 2029. The operating efficiency isassumed to be 95%. It is assumed that 1 infill well will be drilled in 2019 with anincremental recovery of 5.2 MMstb.

3P Reserves. The Proved plus Probable plus Possible case assumes a harmonicdecline fitted to well by well historical production until a COP date of 2029. It isassumed that 1 infill well will be drilled in 2019 with an incremental recovery of 7.8MMstb.

Given the historical variation in GOR, the RNB GOR (sales gas scf/bbl) profile was used toassign gas reserves. Reserves are ‘developed’ (in production) except for the infill well which isreserves ‘justified for development’.

The contingent resources associated with further infill well opportunities are not included in thecurrent assessment, but represent significant upside potential.




2.2.6 Jotun Field: Norway Blocks 25/7 and 25/8

The Jotun field is in Norwegian Central North Sea blocks 25/7 and 25/8 in a water depth ofapproximately 74 m, 15 km southeast of the Heimdal field. The majority of the field lies inlicence PL027B and there is an extension into PL103B. The current unitised equities in thefield are as follows:

Company Equity (%)ExxonMobil Exploration and ProductionNorway AS (operator) 45

Faroe Petroleum Norge AS 3Det Norske 7Dana Petroleum PLC (KNOC) 45

Production start up was in 1999 and the field currently produces from 14 wells and with limitedsupport from one water injector. An FPSO (Jotun A) is tied back to a 24 slot wellhead platformwith full drilling capability (Jotun B). There are currently no plans for infill drilling and the existingfacilities and well stock are being optimally managed. COP is planned for 1st October 2016.



The trap comprises three four-way dip closed anticlinal structures named Elli, Elli South andTau West. The structures share a common aquifer with an OWC at 2,100 m tvdss. The oilcolumn is up to 46 m in these low relief structures.

The Paleocene Heimdal Formation reservoir comprises submarine fan sandstones with goodreservoir quality to the west though the shale content increases to the east. There was no staticdescription in the database and no information on reservoir characteristics or discussion of anycompartments or reservoir continuity issues for LR Senergy to review.

Since the PDO was submitted, the operator’s STOIIP estimate has been reduced by about 25%to its current base case of 276 MMstb (range 248 to 303 MMstb), as reported in the 2010 RNBsubmission. The latest base case GIIP estimate is 99 Bscf.

LR Senergy has not reassessed the STOIIP as in its view the operator’s estimates arereasonable and compatible with the reserves estimates.


Jotun has been developed by FPSO (Jotun A) tied back to a 24 slot wellhead platform with fulldrilling capability (Jotun B). Oil is exported by tanker and gas via a spur line to the Statpipesystem to Kårstø. The majority of produced water is injected either into the reservoir or disposalwells with the remainder being discharged to sea. Jotun provides processing and exportfacilities for oil and gas production from Ringhorne and for gas from Balder.

Performance of the facility has been good, with uptime routinely in excess of 94%. Jotun B isnow normally unmanned. Operations support is integrated with the Balder and Ringhorne fieldsand marine transportation is shared with the neighbouring Beryl field in the UK sector.



There is no planned infill drilling or enhanced recovery projects for Jotun, and the drilling rig isnot in operation. The Jette development project was tied-in to Jotun in 2013 and will prolongfield life through reduced Opex.

P&A (plug and abandonment) is scheduled to commence in early 2016 with COP planned for1st October 2016. The field abandonment plans have not been reviewed in detail by LRSenergy, but we are informed that the operator’s plans meet current regulatory requirements.The decommissioning cost assumption is provided in Appendix 2. LR Senergy is not aware ofany specific environmental protection issues beyond the statutory regulatory requirements.

2.2.6.3 Field Performance

Cumulative allocated production to 31st December 2015 was 145.1 MMstb of oil and 31.3 Bscfof gas. Production start up was in October 1999. In total seventeen oil production wells havebeen drilled. One Elli / Tau West water injection well and two water disposal wells arecompleted in the shallower Utsira Formation. Production is spread between the wells with nosingle dominant producer.

Jotun is believed to share a common aquifer with Heimdal and Frigg as the reservoir pressurewas below hydrostatic at start up due to depletion from these fields. Despite some tool failuresthe overall downhole pressure gauge data trends indicate good aquifer pressure support for allstructures.

The low reservoir pressure means that gas lift is required both to start up wells and to maintainproduction rates. Problems with gas lift have been experienced due to tubing corrosion. Gascan be imported from Balder and Ringhorne or from the gas export line if required.


Monthly total field production data was downloaded from the NPD official database and wasused as the basis for total field decline analysis and for LR Senergy’s production and reservesassessment. The following assumptions were applied:

1P Reserves. The forecast was generated using exponential decline and a technicalCOP date cut off of 1st October 2016.

2P Reserves. The forecast was generated using a hyperbolic decline and a technicalCOP date cut off of 1st October 2016.

3P Reserves. This forcast assumes a more optimisitic hyperbolic decline and atechnical COP date cut off of 1st October 2016.

Jotun does not currently pass the economic test and consequently no reserves are reported.




2.2.7 Glitne Field: Norway Block 15/5a

The Glitne field, discovered in 1995, is located 40 km northwest of the Sleipner gas condensatefield, 5 km northeast of Enoch and commenced production in August 2001. The current equityholders in the field are:

Company Equity (%)Statoil (operator) 58.90Total 21.80Det Norske 10.00Faroe Petroleum 9.30

The Glitne decommissioning plan was approved by MPE in April 2013, and according to thedecommissioning plan all field cessation activities shall be completed by end 2018.

The field was developed with an FPSO which was demobilised from the field on 28th April 2013.The current status of the field is that all seven wells have been permanently plugged andabandoned. The remaining and final decommissioning work will be the removal of subseaequipment.

The total gross decommissioning costs are estimated to be NOK 3,096 million.

2.2.8 Enoch Field: Norway Block 15/5f

Enoch is a UK / Norway cross border field located in the South Viking Graben 15 km to thesoutheast of the Brae A platform. Production commenced in June 2007 from one horizontalproducer (16/13a-7) which was shut in, in 2012 and is awaiting re-instatement. Enoch is sharedbetween UK block 16/13a (licence P219) and Norwegian block 15/5f (licence PL 048). Basedon the agreed equity split of 80% to P219 and 20% to PL 048, the equity holders in the field areas follows:

Company Equity (%)Talisman (operator) 25.2Dyas 14.0Bow Valley Energy 12.0Statoil 11.78Dana Petroleum 8.8Endeavour Energy 8.0Noreco 4.36Det Norske 2.0Faroe Petroleum 13.86



The Enoch structure is a low relief faulted four-way dip closure (175 ft column) with astratigraphic trap component. The Eocene Sele Formation (Flugga) reservoir distribution is notclearly defined but the interval is spatially imaged by seismic attributes that assist in theprediction of NTG characteristics away from well control (Figure 2.11).



The Enoch reservoir is an easterly thinning (distal) base of slope turbidite fan system within theSele Formation (Flugga) characterised by west to east trending channels and crevasse splaycomplexes (lower NTG fringe).

The most recent in-place volume assessment was in 2008. Estimates of the field’s STOIIPappear to be reasonably well constrained with the “Base Case” of a number of reviewers beingin the region of 50 MMstb (range 36 to 67 MMstb). The assessment has been reviewed andLR Senergy concludes that, based on the current dataset, the volumes represent a reasonableestimate of the range of possible outcomes.


The Enoch reservoir has been developed using a single subsea 1,500 m horizontal producerin the oil leg tied back to the Brae A platform. The development includes an 8-inch insulatedproduction flowline, 3-inch gas lift flowline and an umbilical to provide the control and chemicalinjection. The subsea control system and umbilical have been designed for 2 producing wellsand 1 injection well. Gas lift is provided via a tie-in to the Brae A gas lift manifold to supply liftgas to the Enoch gas lift riser. A 3-inch gas lift flowline supplies gas from Brae A to the Enochwell. Oil is exported via the Forties Pipeline System to landfall at Cruden Bay, whilst the gas issold offshore to the Brae owners.

Future field abandonment plans have not been reviewed in detail by LR Senergy, but we areinformed that the operator’s plans meet current regulatory requirements. LR Senergy is notaware of any specific environmental protection issues beyond the statutory regulatoryrequirements.


Cumulative production to the 31st December 2015 was 9.25 MMstb oil and 1.87 Bscf gas.Production to date is consistent with the well depleting a relatively small gas gap during the firstfew months of production, followed by the onset of pressure support from a less well connectedoil or water volume triggered by the increasing pressure drop.

The GOR trend, increasing in earlier time then later declining and stabilising at around 700 to1,000 scf/stb, suggests that initial production may have been dominated by oil of the type foundin 16/13a-4, but later produced oil more akin to that from 16/13a-3 or -5. Oil production declinedsignificantly during 2010 from around 8,000 to 4,000 bopd, and decreased further to about2,000 bopd in January 2012 when it was shut in due to a Xmas tree failure. Water has brokenthrough and had risen to about 60% in January 2012. The produced gas is sufficient for gaslift requirements. There could be some scope in gas lift optimisation. No further drillingactivities are foreseen.

The workover has been completed and the well came back on production in December 2015.


The operator has estimated a range of ultimate reserves using a 2010 simulation model,adjusting for the water breakthrough timing. These scenarios appear to over predict recent oilrates and LR Senergy has carried out independent decline curve analysis. The mainuncertainties are the continued watercut development and the true well potential following re-instatement after work over.



1P Reserves. The Proved case is based on exponential decline starting at 2,000 bopdbased on performance before the well was shut in. An operating efficiency of 80% isassumed.

2P Reserves. The Proved case is based on hyperbolic decline starting at 2,200 bopdbased on performance before the well was shut in. An operating efficiency of 90% isassumed.

3P Reserves. The Proved plus Probable plus Possible is based on harmonic declinestarting at 2,350 bopd based on performance before the well was shut in. An operatingefficiency of 95% is assumed.

Based on the data supplied, an oil shrinkage factor of 90% has been applied.

The reserves are classed as ‘on production’ now that the workover is complete and productionhas recommenced.


2.2.9 Butch Field: Norway Block 8/10

The licence PL405 is situated in the Central Graben. The Butch discovery is close to significantexisting infrastructure, with the Ula field approximately 13 km to the northwest, Tambarapproximately 10 km to the southwest and Gyda approximately 20 km to the south. The licenceequity split is as follows:

Company Equity (%)Centrica Energy Norway (operator) 40Suncor Energy 30Faroe Petroleum 15Tullow Oil 15

The 2011 discovery well 8/10-4S was the updip sidetrack of 8/10-4A. New 3D seismic datawas acquired in late 2012, the interpretation of which has been incorporated in a new reservoirmodel. Two unsuccessful exploration wells on Butch East and Butch South West were drilledin early 2014. Nevertheless, Butch Main is a viable project and pre-development studies are inprogress. New static and dynamic reservoir models were completed in January 2015 andprovide input to the DG2 select decision which was taken in October 2015.

Three development options had been evaluated and the operator, Centrica Energy Norway,and partners announced on 21st October 2015 that the Butch discovery will be developed as asubsea tie-in to the Ula field. With the selected subsea tie-in concept the Butch well stream willbe transported to the BP operated Ula platform where processing will be performed. The Butchoil will be exported via the Ula oil export pipeline to Ekofisk and onwards into the Norpipe toTeeside terminal in England. The produced gas from Butch will be injected into the Ula fieldreservoir to improve oil recovery. Production is planned to start in 2019 with a peak productionof 35,000 boepd.




The Butch trap is a high relief salt dome flank structure mapped at the Top Ula level, with bothfault and stratigraphic side seal against Permian Zechstein salt, on the margins of the Ulareservoir sandstone fairway. The discovery well 8/10-4S was an updip sidetrack of 8/10-4A.

The steeply dipping salt dome flank is divided into three main structural compartments: ButchMain (being the NW segment), Butch SW and Butch East. Wells 8/10-5 and 8/10-6S on ButchEast and SW respectively, drilled in 2014, proved these segments of the salt dome structure tobe water bearing. The latest seismic interpretation (2014) recognises that Butch Main can bedivided into five fault segments, one of which (Butch Main 1) is proven oil bearing by thediscovery well 8/10-4S. Butch Main 2, 3 and 4 segments are part of the project although subjectto mapping uncertainty. Butch Main 5 is not part of the current project.

The salt dome edges are not always clearly imaged and there is salt piercement at the crest ofthe diapir with the Ula reservoir being absent. The recent vintages of seismic data andinterpretation show significant differences in fault positioning. The latest seismic interpretationof new 3D PSDM data identifies three areas of map and structural uncertainty at Top Farsund(top Ula): a graben to the northeast (Butch Main 2), the boundary of the main salt wall (ButchMain 3), and the horizon mapping towards the southwest (Butch Main 4).

The Butch Main 2 segment is a structurally well defined graben area with low amplitude(dimming) at the Top Farsund reflector probably due to imaging limitations below a shallowerlow angle fault. The amplitude dimming in the Butch Main 2 area, adjacent to the saltwall, isprobably due to a combination of steep dips and shallow faulting. Butch Main 4 is a structurallycomplex faulted area with an ambiguous salt interpretation. The Butch 2 and 4 segmentseffectively define the range of uncertainty about where Butch Main ends in both northerly andsoutherly directions respectively.

The Upper Jurassic shallow marine Ula sandstone reservoir in the well 8/10-4S, comprised 48m net pay in a 55 m gross interval with 21% average porosity, average permeability of about 1darcy and Sw 17%. Log porosity evaluation is matched to overburden-corrected core porosityfor 8/10-4S (70 m core). Highly saline formation water is measured from water samples innearby wells. The original well 8/10-4A though water wet, encountered a thicker gross reservoirinterval. Both 8/10-4A and 8/10-4S are located in the Butch Main 1 segment on the northwestflank of the salt dome.

Core data have been acquired from wells 8/10-4 S, 8/10-5 S and 8/10-6 S. Four different rocktypes have been identified. Permeabilities in the the best rock type (RT A), upper shorefaceand highest quality lower shoreface, are generally in excess of 1 Darcy. Permeabilties in RTB, the remaining lower shoreface, range between 35 mD to 1 Darcy. Rock type C, which isdescribed as a “transition zone”, has permeabilities generally less than 35 mD. Mobility datafrom the measurement drilling tool (MDT) measurements were in reasonable agreement withcore data and with the permeability transform estimates. No DST’s have been performed.However, based on the log, core and mobility data, the productivity of the reservoir is notconsidered to be an issue. Injectivity into the water leg is more of a concern, although thermalfraccing may help to enhance injectivity.

The FWL is not penetrated by any of the wells in Butch Main and it is estimated to be at 2,985m tvdss from pressure data. There are 14 good pressure points establishing an oil gradient in8/10-4S. Wells 8/10-4A, 8/10-4AT and 8/10-4S are located in the fault compartment on the



northwest flank of the salt dome, known as Butch Main 1. Well 8/10-4S was fully oil bearing,whilst the other two wells were both full water bearing. The oil and water gradients are clearlydefined in these wells from MDT data and provide an interection at 2,985 m tvdss. It is likelythat these three wells are not in in the same pressure compartment. The exploration wells inButch East and South West were both water bearing.

Down-hole MDT samples were collected in well 8/10-4S. The oil is undersaturated with abubble point pressure of 115 bar compared to the initial reservoir pressure of 414 bar (at 2,985m tvdss). The stock tank oil density is 830 kg/sm3 and the initial GOR is 85 sm3/sm3. Thediscovery has an oil column in excess of 650 m oil and one unknown is whether there is acompositional gradient. The oil samples taken were towards the base of the oil column.

The static model build assumes average thickness for each zone totalling 48 m and thereservoir interval is divided into 4 zones (and 28 layers in order to capture permeability variationwithin the reservoir). Zone 3 has the highest permeability.

LR Senergy has reviewed the model derived STOIIP estimates (January 2015) provided by theoperator and the associated uncertainty sensitivities, and compared these to the previousSTOIIP assessments. The static model and uncertainty analysis provides information on theuncertainty range associated with the Butch segments, possible reservoir thickness andparameter variability, and the salt edge seismic imaging problems that are associated with thehigh dip on the salt dome flank. The Gross Rock Volume is uncertain due to seismicinterpretation ambiguity, and re-processing of the seismic data is in progress for well locationplanning. LR Senergy considers that the following scenarios represent a reasonable in placerange.

Low case: 53 MMstb. The model STOIIP for Butch Main 1 only is 53 MMstb. This isnot a P90 for this segment, but is the model best technical case. This volume excludesall of Butch 2, 3 and 4 as these are decribed as uncertain segments by the operator.The probabilistic P90 case for all segments is 61 MMstb. Overall LR Senergy concludethat the Butch Main 1 model value is a reasonable proven case.

Best case: 83 MMstb. This is P50 from the probabilistic assessment involving allsegments.

High case: 107 MMstb. This is P10 from the probabilistic assessment involving allsegments.


Three development scheme options had been evaluated and the partnership has decided onthe Ula subsea tie back option.

The development plan reference case anticipates a sea bed template, 2 producers and 1 waterinjector, with design rates of 35,000 bopd (38.5 °API), 2,500 bwpd, 15 MMsfc/d gas and 34,000bpd water injection.


The operator has performed an extensive reservoir uncertainly study based on multiplerealisations of the geological model and the simulation model. The analysis incorporateduncertainties on STOIIP and the dynamic parameters. The STOIIP uncertainty included



whether or not the less certain regions were present. The dynamic uncertainties includedrelative permeability end points, Kv/Kh, fault connectivity and compositional gradient effects.Reservoir communication and injectivity is uncertain due to fault compartmentalisation andbaffling effectiveness. Side-tracks or infill wells may be required. Residual oil saturation isuncertain due to sweep efficiency and the potential for high residual oil saturation after waterflooding.

This is a high relief structure and recovery efficiency will be dominated by gravitational effects.Given the oil properties and the mixed wetability of the rock, indicated by SCAL results, highrecovery efficiency may be expected. Factors that may counteract this are faulting, unsweptattic oil and poor areal sweep as a result of having only one injector. The recovery factorsunder water injection were very similar for the different development options. For the Uladevelopment plan the P90, P50 and P10 recovery factors were 43, 51 and 53%.

The resource range is based on the recent reservoir uncertainly study using multiplerealisations of the geological model and the simulation model.

Low estimate (1C) is low case STOIIP with recovery factor of 40%.

Best estimate (2C) is the P50 outcome.

High estimate (3C) is the P10 outcome.

All reserves are categorised ‘undeveloped’ (justified for development). The productionforecasts are provided in Appendix 2 and should be consulted for information on peak andplateau production, anticipated field decline and field life. The gas profiles are gross wet gasproduction without any deductions for fuel and flare or NGL recovery. This forecast has beenused in the economic evaluation and is provided, together with the capital and operating costinputs. The decommissioning cost assumption is provided in Appendix 2. Details of eventualfield abandonment and environmental protection issues are currently not available, though anabandonment cost estimate is included in the economic evaluation.

2.2.10 Pil Field: Block 6406/11, 6406/12

The Pil field and Bue discovery in licence PL 586 are located on the Southern Halten Terraceabout 32 km southwest of the Njord field and 60 km to Draugen. VNG Norge is the operatorand the Faroe equity is 25%.

The Pil discovery well, 6406/12-3S was spudded in January 2014 to test an Upper Jurassicsandstone reservoir objective and, after successful evaluation, coring and testing was pluggedand abandoned in May 2014. A sidetrack appraisal well, 6406/12-3B was subsequently drilledon the structure to test the easterly extent of the discovery, and again after successfulevaluation was plugged and abandoned. A further sidetrack, 6406/12-3A, was then drilled tointersect the Bue accumulation, which is immediately adjacent to the northwest.

LR Senergy has reviewed the DG1 interpretation and in progress DG2 evaluation of thediscovery, and the status of development studies for the agreed development plan of either atie back to Draugen or a stand alone FPSO. A project selection decision is anticipated in 2016.Both development options are demonstrated to be economically viable. LR Senergy is satisfiedthat the operator and partners have demonstrated firm intent to proceed with the developmentand that there is a reasonable expectation of development within the time frame recommended



under PRMS guidelines. Consequently, the project is categorised as reserves (justified fordevelopment).


The Pil trap is a combined structural and stratigraphic closure with reservoir truncation to thewest and north. The adjacent Bue trap is less well defined and is also a combined structuraland stratigraphic closure that appears to be separated from the Pil accumulation by a pressurebarrier that may be the result of an impermeable sequence of reworked sediments.

The accumulation is mapped on 3D seismic data at the top reservoir that is partly synonymouswith the BCU event and partly the Top Melke 5 horizon. There is uncertainty associated withthe Top Melke 5 pick (and base reservoir Top Melke 3 pick), as well as depth conversionuncertainty, and the resulting GRV range is not fully reflected in the current assessment.

The structure is interpreted to be updip of well 6406/12-1S to the north, which was reported dry,but with shows that could be indicative of a paleo oil column of light oil or condensate in the top20 m, and encountered 37 m gross Volgian (Rogn) sandstones with 70% NTG and 16%average porosity.

The Pil accumulation is trapped beneath Lower Cretaceous and Upper Jurassic Spekk shales.The trap is complex and a Lower Melke sequence (defined by the Top Melke 3 horizon) isinterpreted to form a base seal associated with sand truncation to the west. The Pil ‘container’is interpreted to have a ‘lateral’ seal to the east formed of a younger Volgian clastic sequence(above Top Melke 5).

The reservoir seismic character has been assessed for attribute response, and impedance datais used both as a positive sand and hydrocarbon (fluid) indicator. The fluid indicator seismicattribute can be correlated to both the GOC and OWC, but is not sufficiently precise to separatethe two OWC’s.

The charge is considered to be from Upper Jurassic Spekk shales, which are modelled to be inthe oil window in the vicinity of the discoveries.

The Pil discovery well, 6406/12-3S (Pil 1) encountered Callovian to Oxfordian Melkesandstones. The sandstones are interpreted to comprise fan delta and lower shoreface, andconglomeratic debrite and turbidite deposits. The main reservoir interval is Melke Zone 5-4.Pil 1 encountered a GOC at 3,346 m tvdss (alternate at 3,342 m as the GOC is 4 m deeperfrom pressure data than core and log) and an OWC at 3,481 m tvdss in Melke 4 Zone sandsfrom pressure data. On logs there is an ODT between 3,488 and 3,492 m tvdss. The sidetrackappraisal well, 6406/12-3B (Pil 2) also encountered reservoir sandstone with a clear OWC at3,499 m tvdss. Hence the field OWC and segmentation are uncertain.

Porosity averages 14.6% with an 89% NTG and Sw 22% in Pil 1. Well Pil 2 Melke 5 Zoneaverage porosity was 14% with net to gross 74% and Sw 34%. However, the water bearingMelke 4 Zone in this well had a lower net to gross of 64%. There is a significant discrepancybetween log and core porosity with log values lower than core measurements. The averagecore porosity is 15.4% versus 14.6% from logs in well Pil 1. Net pay was calculated using cut-off values for porosity of 8%, Sw 60% and Vclay 40%.



The Bue discovery well, 6406/12-3A, found an OWC at 3,420 m tvdss in Upper Jurassic Spekksandstones. In the Bue core, turbidites dominate while lower shoreface deposits are ofsecondary importance and minor interbedded mudstones are present.

The Pil accumulation’s areal extent is currently represented by a single structural model caseand single ‘container polygon’. The contact and reservoir input parameters are varied from thewell values to reflect a range of lateral uncertainty. The current static model and an uncertaintyassessment have been used to assess the HIIP range. The main uncertainties are porosity,OWC, GRV and Sw. The base case static model assumed a GOC at 3,342 m tvdss and OWCat 3,499 m tvdss, with average porosity of 14.6%, Sw of 25% and net to gross 88%. Theuncertainty assessment used a porosity range from 12 to 19% and net / gross from 80 to 96%,and OWC uncertainty was handled by a standard deviation of 10. Although a reasonableapproach it is not clear that the uncertainty assessment fully reflects the GRV uncertaintyassociated with picking and depth conversion, nor low case uncertainty associated with net /gross lateral variability and estimation uncertainty, nor with uncertainty associated with theidentification of two OWC’s with a difference of ca. 18 m.

The Pil static model deterministic STOIIP is 154 MMstb compared to the P90 of 132 MMstb andP50 of 170 MMstb. Consequently LR Senergy consider the 154 MMstb (and 226 Bscf) to bereasonable best case HIIP and the uncertainty assessment P10 of 214 MMstb (311 Bscf) toreflect high case potential. However, the low case is proposed to be reduced by 15%, as theuncertainty study may not have captured the full uncertainty range as noted during Peer review,and this generates values of 112 MMstb and 161 Bscf. It is likely that the low case can beimproved following completion of further studies and later model and uncertainty assessmentrevisions, but a conservative approach is proposed at this stage whilst studies are in progress.

The subsequent model revisions and uncertainty assessment will further refine the correlation,mapping and parameter issues that can reduce uncertainty in volume estimates.

The 6406/12-3S well encountered a combined gas and oil column of 226 m, of which 134 mwas oil in the Upper Jurassic sandstones of the Melke 4 formation. An extensive data gatheringset was acquired including coring, logs, pressure data and well test. Simulated well testanalysis results indicated good reservoir performance. Average permeability of 330 mD, a skinof 6 and a Productivity Index of 75 bbl/d/psi drawdown were interpreted. Well test analysisindicated poor vertical communication with no direct influence of gas cap pressure response.In order to obtain a match, no-flow boundaries to the south, west and north of 150, 750 and 400m respectively, were required with a constant pressure boundary some 1,124 m distant,indicating potential pressure support from a larger system, possibly the gas cap.

It should be noted that since it was not possible to do DTS production logging, there are someuncertainties concerning the effective test interval and pay thickness contributing to flow duringthe DST. The container could be either homogenous within a closed system, equivalent to thePil structure, or alternatively in a system with vertical flow barriers that is in contact with a largervolume outside the container.

Fluid sampling results indicate a strong correlation between the two Pil wells, with a virtuallyidentical composition. Compositional analysis demonstrates a stock tank oil density range ofca. 855 to 865 kg/sm3 and a GOR of ca. 177 to 210 sm3/sm3.




The two development options are technically and economically viable. These are a stand-aloneFPSO development and tie back to Draugen. The partnership has provided evidence of firmintent to proceed to development and the final development decision will be dependent uponongoing negotiations.

Flow assurance is an issue due to the long tie-back distances and the oil composition withhydrate, wax and gelling challenges. At this stage Bue is considered to represent upsidepotential to the Pil project due to data limitation and interpretation challenges and it is expectedthat appraisal will be required prior to commitment. Consequently Bue volumes are categorisedas contingent resources.

Water injection is expected for all development options (standalone and tie-backs). Thoughthere may be injection availability limitations depending on the host tie back option selected.Sand control will be required and gas lift is being planned. Three horizontal producers and twohorizontal water injectors are enviaged for Pil with a single producer / injector pair in the caseof possible future Bue development.


Recoverable resource estimation has been derived from reservoir simulation by the operator.Recovery factor input ranges of 30 to 52% for oil with 55 to 70% for non-associated gas arepredicted based on the simulation studies. LR Senergy consider that these ranges arereasonable.

The reserves range is based on the recent reservoir uncertainly study using multiple realisationsof the geological model and the simulation model.

Low estimate (1C) is low case STOIIP with recovery factor of 30% oil and 55% gas

Best estimate (2C) is the P50 HIIP outcome with recovery factor of 48% oil and 65% gas

High estimate (3C) is the P10 HIIP outcome with recovery factor of 52% oil and 70%gas

All reserves are categorised ‘undeveloped’ (justified for development). The productionforecasts are provided in Appendix 2 and should be consulted for information on peak andplateau production, anticipated field decline and field life. These forecasts have been used inthe economic evaluation and are provided, together with the capital and operating cost inputs.The decommissioning cost assumption is provided in Appendix 2. Details of eventual fieldabandonment and environmental protection issues are currently not available, though anabandonment cost estimate is included in the economic evaluation.



3 Un-Developed DiscoveriesThe contingent resources are in the Bue, Boomerang, Fogelberg, SE Tor, and Shango / SkirneEast discoveries in Norwegian waters; and the Perth, Lowlander, Dolphin oil discovery clusterin the Moray Firth of the UK North Sea (Figures 1.1, 1.2, 1.4, and 1.5).

A decision to relinquish the Rodriguez / Solberg discovery in licence PL475 in Norway wastaken in early 2016 (between the effective date and signature date of this report) and is awaitingministry approval. Withdrawal from the UK Tornado discovery in licence P1190 was completedon 30th March 2016 (between the effective date and signature date of this report).

3.1 UK Discoveries

The contingent resources in the three UK discoveries as of 1st January 2016 are summarisedin the table below:

Table 3.1: Contingent Resources (UK Atlantic and North Sea)

A joint development of Perth, Lowlander and Dolphin is classified as Development On Hold.

3.1.1 Perth, Lowlander and Dolphin: UK Blocks 15/21a, 15/21c and14/25a

The Perth field is in licences P218 (block 15/21a) and P588 (block 15/21c) and P2154 (block14/25a), in the Outer Moray Firth area of the Central North Sea. Block 14/25a is a recent 28thLicensing Round award. The discovery wells 15/21a-7 and 15/21b-47 were followed by the15/21b-47z, 47y, 15/21b-49 and 15/21b-56 appraisal wells which encountered oil in UpperJurassic Claymore sandstones and tested at rates up to 6,000 bopd, with high hydrogensulphide and carbon dioxide concentrations. The Faroe equity is 34.6% and Parkmead is thelicence operator.

The Lowlander discovery, located 16 km north of Perth, is a fault compartmented structuraltrap. The discovery well 14/20b-17 was followed by the 14/20b-20, -22, -23 and -27 appraisalwells, all of which were drilled by Texaco between 1986 and 1991 and found oil bearing UpperJurassic Piper sandstone reservoir, that tested at rates up to 6,800 bopd with high hydrogensulphide concentrations. Faroe is the licence operator with 100% equity.

The Dolphin discovery well 15/21a-46 is located about 12 km south of the Perth field and tested38o API oil from Upper Jurassic Claymore sandstones. The trap, as currently defined, is partlyon blocks 15/21a Gamma Subarea and partly on 15/21g. Faroe equity is 34.6% and Parkmeadis the licence operator.


LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate


Perth 26.4 51.8 77.3 9.1 17.9 26.8 20% Parkmead

Lowlander 11.6 22.5 30.8 11.6 22.5 30.8 20% Faroe

Dolphin 1.8 9.0 18.3 0.6 3.1 6.3 20% Parkmead

Total Oil & Liquids; MMstb 39.8 83.3 126.4 21.4 43.5 63.9

Contingent Resources (UK North Sea): Discoveries




An Exchange Agreement formalising equalised equities across the three fields is at a maturedraft stage and the equity split is expected to be Faroe 52.04%, Parkmead 38.17%, Atlantic9.89% based on P50 recoverable resource estimates.

A joint development of Perth, Lowlander and Dolphin is being planned. Subject to OGAagreement, the current project schedule assumes a new build FPSO with a project select gatein 1Q 2017 and a final investment decision in 1Q 2018. First oil is envisaged in 1Q 2022 forPerth and Lowlander and 2Q 2022 for Dolphin. High H2S content means that special metallurgywill be required for the development scheme. LR Senergy understand that the partners intendto conduct a farm down when market conditions are appropriate, to attract a major equityinvestor to progress the project.

The key contingencies are associated with confirming the participation of a new partner,finalising commercial arrangements with field partners, FPSO contractors and projectfinanciers.

3.1.1.1 Perth Subsurface Description and HIIP

Perth is a combined structural / stratigraphic trap comprising Upper Jurassic Claymoresandstones onlapping the Tartan Ridge to the north. The reservoir thickens and dips to thesouth.

The trap had previously been mapped on two 3D seismic datasets, both of which are difficultto interpret. A new seismic interpretation in 2014 has involved mapping the Top Claymorehorizon over the main Core Perth area, using a new inversion dataset (Odegaard), and theprevious geological modelling has been updated accordingly.

The field comprises an appraised and apparently un-faulted Core Perth area in the south, anda poorly appraised area in the north with only the discovery well 15/21b-7, which found oil in anattenuated Claymore sequence. The Core Perth area has been appraised by wells 15/21b-47,47z, 47y, 15/21b-49 and 15/21b-56, which found thicker reservoir development. The northernPerth area is separated from Core Perth by a mainly west to east trending fault zone, whichwas previously interpreted to include north to south cross faults. The sand distribution andreservoir thickness in the northern area is a major uncertainty.

The precise fault orientations and locations have always been difficult to define in the Pertharea, especially on the northern boundary of Core Perth. The most recent interpretationappears to have reduced this uncertainty. However, key fault positions incorporated in themodel are still based on upward extrapolations from deep-seated faults, including the NE-SWoriented ‘fault’ located in the western part of the field. Sub-seismic faults may be present in theCore Perth area and could have large enough offsets to place higher permeability beds againstthose of lower permeability. Image log interpretation concludes that only north to southorientated fractures are likely to be permeability baffles.

A comparison of the most recent Top Claymore depth map to previous maps shows significantdifferences on the Core Perth northern boundary and northern areas. The northern portion isnow separated into an untested ‘Perth Northern Area’ (classed as prospective resources, seeSection 4.1.1) and the ‘NE Segment’ or Beta Terrace tested by well 15/21a-7, which hasadditional resource potential that is not quantified by LR Senergy. The Core Perth area, thoughlargely similar between interpretations, still has uncertainty associated with the western andeastern field limits, the former due to the interpreted presence of a NE - SW trending cross faultand the latter as a result of more distal reservoir of uncertain extent. The ‘Western Extension’



has now been added to the Core Perth area following the award of block 14/25a, in which it ismostly located. The possible eastern field extension is termed the Beta prospect and hasassociated prospective resources (see Section 4.1.1.).

The Upper Jurassic Claymore reservoir deep water channelised and non-channelised turbiditesandstones were sourced either from the Halibut Horst and Tartan Ridge to the north or fromthe west. The sequence is characterised by thin interbeds (usually less than 3 ft) and agenerally low net to gross in a thick gross interval. The sands are heterogeneous and of low tomoderate quality with layer permeabilities ranging from less than 10 mD in most of the netvolume up to 600 mD in occasional high permeability beds. The distribution of the latter iscritical to reservoir performance. The average reservoir parameters encountered in the “Core”wells are porosity 13% and Sw 35%, with a gross reservoir interval between 445 and 857 ft andNTG varying from 28 to 74%. An OWC is not identified in any of the wells and the interpretedfree-water level (FWL) at 12,993 ft tvdss is based on pressure gradients. The contactuncertainty is reflected in a range from 12,900 to 13,050 ft tvdss.

There are several vintages of petrophysical interpretation, which indicate significant porosityand NTG uncertainty, and this has been captured in the revised model sensitivity analysis.

LR Senergy has reviewed the tests on wells 47, 47Y, 49 and 56 and has concluded that theexisting interpretations are valid. The 15/21b-47, 47Y, 49 wells flowed for short periods of <18hours and the well tests investigated relatively small reservoir volumes. Most of the tests sawboundaries, which can be interpreted as due to either faulting or thinning of the highpermeability intervals. The radius of investigation of the 15/21b-49 well test was about 150 ftand, in this instance, no boundaries were detected. The test performed on 15/21b-56 was anextended well test with a main flow period of about 10 days and two barriers / baffles wereinterpreted at 25 to 50 ft and at 120 to 220 ft.

The initial reservoir pressure is 5,849 psia at 12,325 ft tvdss. Perth oil is light, 30 to 32° APIgravity, sour, and under-saturated (saturation pressure 2,985 psia) with a GOR of 750 to 900scf/bbl, and with high wax content. High concentrations of hydrogen sulphide and carbondioxide are observed in tested wells, averaging 6,500 ppm (range 2,350 to 11,444 ppm) and35.4 mol% (range 33.5 to 39.5 mol%) in gas respectively. Fluid properties vary from well towell although sampling methods, analytical accuracy and the time between drilling the wellscould explain the differences. Alternatively, they could indicate compartmentalisation within thereservoir. The low permeability of the reservoir may also restrict mixing of fluids in the reservoir,also explaining the differences. Various pressure measurements could be interpreted asindicating compartmentalisation. However, inaccuracies in the measurements could alsoexplain the differences.

Well deliverabilty is expected to be modest, consistent with the performance of the wells testedto date, which flowed at rates up to 6,000 bbl/d, with well productivities of 0.5 to 4.5 bbl/d/psi.The 15/21b-56 EWT flowed dry oil for 10 days during the main flow period at initial rates of upto 4,400 bbl/d, although bottom hole pressure and rates were still dropping, albeit slowly, at theend of the main flow period. Test interpretation indicates a minimum connected reservoirvolume of 21 MMstb, and modelling in a dynamic simulator indicates a connected volume of 30MMstb. The drainage area areal extent interpreted from these EWT results is estimated to bebetween 1.3 and 3 km.

LR Senergy has reviewed the latest model derived STOIIP estimates provided by the operator(static model from October 2014 and reservoir simulation study December 2014) and the



associated uncertainty sensitivities, and compared these to the numerous STOIIP assessmentsby previous operators. The main uncertainties affecting the STOIIP estimates are structureextent and definition, lateral reservoir variability and porosity estimation. LR Senergy considersthat the following scenarios, for the Core area and its western extension only, represent areasonable in place range.

Low case 120 MMstb. The most recent static assessment does not include a singlelow or proven case. However, uncertainty analysis using the simulation model hasbeen used to estimate a proven case of circa 120 MMstb. This incorporatesuncertainties on porosity, NTG and OWC. This volume excludes the ‘western area’ tothe west of the fault and the ‘far east’ area.

Best case: 225 MMstb. The revised base case model Core area of the structureincluding the ‘western area’.

High case: 276 MMstb. This is the high case extent of the mapped Core area includingareas to the west, east and north.

There is additional resource potential associated with the untested Northern Area, and testedNE Segment. The presence of oil in the NE Segment is proved by well 15/21a-7 but theconfidence in the seismic interpretation is low and the lateral extent of the Claymore sandstonesis uncertain and could be much more limited than currently interpreted. The current static modelis an optimistic base case and the resulting STOIIP is calculated to be 40 MMstb. The provenSTOIIP is likely to be significantly lower. However, a STOIIP and resource range (1C, 2C and3C) is not included in the current assessment as this segment is not part of the initialdevelopment plan for the field.

The prospective resource potential of the Northern Segment is described in Section 4.1.

3.1.1.2 Perth Resource Assessment and Production Profiles

The Perth resource estimates are based on an uncertainty study performed using full fieldreservoir simulation models, using Eclipse software. This work evaluated the sensitivity of theresources and recovery factors to a number of reservoir parameters and to uncertainty inreservoir architecture and distribution. LR Senergy did not review the simulation model, buthas reviewed a comprehensive report and presentations. The construction of the simulationmodel and the work undertaken by the operator appears to be of a good technical standard.The DST and EWT results have been history matched to a reasonable standard. LR Senergyhas used the operator’s work to determine Low, Best and High recovery factors. These havebeen applied deterministically to the STOIIP range specified above to provide an appropriateestimate of the range of resources.

The latest development plan proposed by the operator assumes five producers and twoinjectors, with the producers under gas lift. LR Senergy has varied this well count according tothe area under development for which the STOIIP has been determined.

Low case (1C) assumes four producers and two water injectors. A recovery factor of22% is applied to account for potential downside uncertainty associated with sand bodyarchitecture and connectivity.



Best case (2C) again assumes four producers and two water injectors and an additionalproducer injector pair in the ‘western extension’. A recovery factor of 23% is applied tothe Best case STOIIP.

High case (3C) assumes an additional producer injector pair in the ‘western extension’and an additional producer in the east. A recovery factor of 25% is consideredappropriate for this larger area.

The main uncertainties affecting the Perth ultimate recovery are expected to be the oil in place,distribution and connectivity of the high permeability sand beds and the extent of fault barriersand baffles. In consequence there is a relatively large uncertainty range which is refelected inthe 3C/1C ratio.

The gas profiles are gross without any deductions for fuel and flare or removal of CO2. Asignificant proportion of the gas is expected to be used for Fuel and Flare (F&F) and the projectis likely to become gas deficient in later years.

3.1.1.3 Lowlander Subsurface Description and HIIP

The latest seismic interpretation was performed by the new operator, Faroe, in 2014 using theexisting 3D PreSDM seismic volume, this is the basis of the current assessment. The top Piperreservoir seismic event (weak trough) is a difficult pick and has a generally poor tie to well databy synthetics. The pick uncertainty has been quantified by preparing alternative interpretationsand comparing to the earlier interpretation of the previous operator.

The field comprises a fault bounded structural and stratigraphic trap downthrown along anorthwest to southeast fault trend. The field could be compartmentalised by mainly northeastto southwest cross faults. The extent of lateral seal on these faults is uncertain and is a crucialuncertainty in assessing likely field production performance. The structure is divided into NW,Central and SE areas.

The Central or Core area comprises at least three and possibly more compartments tested by14/20b-27, 14/20b-17, 14/20b- 23 and 14/20b-22. The NW area could comprise two or morecompartments neither of which has been tested. This area is separated from the 14/20b-27well by a complex faulted area. This well is reported to have encountered a possible shallowercontact at 13,184 ft tvdss, though the evidence is inconclusive. The SE area comprises at leasttwo compartments, the first of which is partly tested by the down dip 14/20b-20 well andinterpreted to be located on the cross fault separating this area from the Central area.

LR Senergy has not performed an independent seismic interpretation. However it is clear thatthe imaging of major faults at reservoir level is challenging, but that the current interepretationis reasonable, though internal fault definition is variable on the different depth map vintages.

The degree of transmissibility across faults and therefore the extent of flowcompartmentalisation is very uncertain and this is addressed in different fault seal models inthe different dynamic simulation model vintages and development planning work.

The Upper Jurassic Piper reservoir is typically 310 to 440 ft thick and comprises high-energy,shallow marine, shoreface facies. There is evidence of more distal facies towards the west andnorthwest away from the paleo-shoreline. The best reservoir quality is associated with clean,coarse-grained sandstones, which are especially well developed in well 14/20b-20. Thedepositional model combined with evidence from outcrop analogues predicts good lateral facies



continuity and good vertical facies continuity within thick upper shoreface intervals. Verticalcommunication is likely to be significantly lower in the more distal facies to the northwest.

DSTs in 14/20b-17, 20, 22, 23 and 27 had flow rates from 708 to 6,200 bopd. LR Senergy hasreviewed the tests and test interpretations on these wells. Test calculated average reservoirpermeability is variable from 2.5 to 138 mD. Reservoir quality variability is significant with thebest reservoir quality in upper shoreface sandstones. Well 14/20b-20 has the highest net pay,NTG ratio, permeability, and DST performance. Well 14/20b-27 has the poorest reservoirquality due to a high degree of cementation. All the well tests exhibit complex behaviour eitherdue to reservoir heterogeneity and / or due to bounded systems.

The oil has an average oil gravity of 39° API and an average GOR of 815 scf/bbl based on thewell tests. The associated gas CO2 content varied from 14 to 26 Mol% and H2S varied from9,000 to 24,000 ppm.

There is significant OWC uncertainty as the contact is penetrated only in well 14/20b-20 and isinterpreted from petrophysical analysis to be between 13,270 and 13,305 ft tvdss. Othercontacts are extrapolated from pressure data and, in the past, at least two and possibly threeOWC’s were identified from RFT data indicating significant compartmentalisation of the field.However, the pressure data show a high degree of scatter and are ambiguous to interpret. Thepressure data could indicate one or several contacts in the depth range 13,240 to 13,341 fttvdss. The validity of the deeper contact in well 14/20b-20 is crucial to the resource estimates.The latest combined petrophysical analysis of all Lowlander wells predicts a field wide contactwithin the range 13,270 to 13,305 ft tvdss with a most likely at 13,290 ft tvdss.

LR Senergy has reviewed the latest model and the probabilistically derived STOIIP estimatesand associated uncertainty sensitivities provided by the operator (September 2014), andcompared these to the numerous STOIIP assessments by previous operators. The mainuncertainties affecting the STOIIP estimates are structure extent and definition, depth of OWCand degree of segmentation, and lateral reservoir variability. LR Senergy considers that thefollowing outcomes represent a reasonable in-place range.

Low case 62 MMstb. This is a P90 outcome where the low case input included the mostconservative seismic pick and a conservative shallow contact at 13,241 ft tvdss for allbut the SE area around well 14/20b-20.

Best case: 118 MMstb. This is the P50 outcome and the mid case input is a single fieldwide contact at 13,290 ft tvdss.

High case: 150 MMstb. This is the P10 outcome and the high case inputs for the topreservoir seismic pick and contact depths.

3.1.1.4 Lowlander Resource Assessment and Production Profiles

The Lowlander resource estimates and profiles are based primarily on an uncertainty studyperformed using full field reservoir simulation models, using Eclipse software (LowlanderSensitivity Analysis September 2014). This work evaluated the sensitivity of the resources andrecovery factors to a number of reservoir parameters and to uncertainty in reservoir architectureand fault sealing. LR Senergy did not review the simulation model but has reviewed acomprehensive report. The construction of the simulation model and the work undertaken bythe operator appears to be of a good technical standard. Subsequent “optimisation” workperformed by the operator increased the recoverable volumes and reduced the number of



producers from three to two. The “optimisation” included changing assumptions on the sealingnature of certain faults and the findings of this work have been taken into consideration. LRSenergy has estimated resources based on the results from the original uncertainty study towhich an increment has been added based on optimisation of well length, position andTHP/BHP assumptions.

The latest development plan assumes two producers and one water injector. However, themove to only two producers may have been driven by the revised fault transmissibilityassumptions. LR Senergy has retained the original plan with three producers and one waterinjector. The producers would be under gas lift.

Low estimate (1C). This is the P90 outcome from the uncertainty study of 10.2 MMstbplus an optimisation increment of 1.4 MMstb. This equates to 18% recovery of the lowcase STOIIP.

Best estimate (2C). This is the P50 outcome from the uncertainty study of 20.5 MMstbplus an optimisation increment of 2.0 MMstb. This equates to 19% recovery of the bestcase STOIIP.

High estimate (3C). This is the P90 outcome from the uncertainty study of 28.5 MMstbplus an optimisation increment of 2.3 MMstb. This is equivalent to 21% recovery of thehigh case STOIIP.

Well productivity from the tests has generally been modest in part due to the reservoir qualityand, in some cases, also due to the skin factors. The test PI’s have varied between 0.2 to 5.9stb/d/psi.

The Lowlander oil contains sulphur and a discount to Brent is included in the economicassessment. The gas profiles are gross gas production without any deductions for fuel andflare or removal of CO2. A significant proportion of the gas is expected to be used for F&F andthe project is likely to become gas deficient in later years.

3.1.1.5 Dolphin Subsurface Description and HIIP

LR Senergy has reviewed a new 2014 static model which is based on a revised seismicinterpretation of the Top Claymore reservoir map horizon together with new petrophysical andsedimentological studies.

The discovery well 15/21a-46 encountered a gross thickness of 329 ft of Main Claymoresandstones with average porosity of 14%, Sw of 12% and a NTG ratio of about 50% and anODT at 11,341 ft tvdss. There are higher permeability intervals with porosity of about 20% andpermeability generally in the range 40 - 150 mD (up to 600 mD). The well tested 3,245 bopdof 38o API oil (4,200 ppm H2S) from a 295 ft gross interval. The low NTG ratio is due tocarbonate cementation especially in the lower part of the reservoir. The new sedimentologicalstudy concludes that the degree of cementation should decrease basinwards, though this is notcertain and the resulting porosity uncertainty is captured in model sensitivity.

Well 15/21a-55 located updip and 0.5 km to the southwest encountered a low NTG Claymorereservoir that was 363 ft thick and with 19 ft net sand and porosity of 13%. The well had oilshows but was not tested. The new sedimentological study has attempted to explain thesereservoir quality variations and concludes that the sediments in the 15/21a-55 well are



dominated by slumped claystone with injected sand dykes. This poor reservoir is, therefore,considered to be a locally developed basin margin facies.

The FWL is not known as no water leg has been encountered in either well. The ODT depth inwell 15/21a-46 is 11,341 ft and this is the absolute minimum. The deepest interpreted oil in thewell is at 11,518 ft in sands that are probably not in pressure communication with the overlyingClaymore. Consequently, its significance is doubtful. The high case contact is the mappedstructural spill point at 11,600 ft tvdss. There is also an absolute maximum case at 12,050 ftbased on the intersection of the oil gradient from the 15/21a-46 well with the Perth water points(well 15/21b-47Y). This case requires an unidentified structural or stratigraphic barrier to the15/21a-38 and 15/21-2 well areas.

Previous seismic interpretations have defined a structural / stratigraphic trap combining TopClaymore Depth structure and the RMS amplitude, the latter being interpreted to be a poroussand indicator. The current interpretation is a structural trap with a mapped spill point at 11,600m tvdss. Confidence in the Top Claymore seismic pick is only moderate, especially downdip,and alternative Top Claymore seismic picks have been interpreted to assess this uncertaintyand its impact on the resource assesment. The alternative structural trap model would resultin a more extensive closure to the west and south and is captured in the high case resourceestimate. It has not been possible to map the Base Claymore reservoir confidently.Consequently, the reservoir thickness isochore is uncertain. LR Senergy has not undertakenan independent seismic interpretation but has reviewed the maps provided and considers themsuitable for an estimate of the potential resource volume range.

The seismic amplitude response of the Claymore interval is no longer considered to besufficiently reliable to predict Claymore sand distribution. Nevertheless, the high amplituderesponse of the reservoir interval in well 15/21a-46 is in marked contrast to that of well 15/21a-55, which has a very low NTG ratio.

Oil samples have only been taken from well 15/21a-46. Dolphin contains sour undersaturatedoil. The physical properties of the oil are a saturation pressure of 2,375 psia, an oil density atinitial conditions of 0.668, an oil viscosity of 0.35 cP and a GOR of 770 based on two stageseparator test results. The associated gas has high H2S content of over 4,000 ppm v/v and aCO2 content of over 30 mol% in gas. Initial reservoir pressure is 5,543 psia at 11,600 ft tvdss.

A DST was performed on well 15/21a-46. The DST summary table indicates a maximum flowrate of 3,245 bopd (duration 1 hr) and a main flow period rate of 1,694 bopd (duration 9 hrs).The pressure transient analysis is not repeated for this current work and the originalinterpretation was by Amerada Hess. This analysis gave an average permeability of 12 mDassuming a net flowing interval of 105 ft. However, core data indicates that higherpermeabilities are present, though core coverage over the test interval is limited.

LR Senergy has reviewed the latest model derived STOIIP estimates provided by the operator(October 2014) and the associated uncertainty sensitivities. The key uncertainties are relatedto mapping limitations, lateral porosity variability and the hydrocarbon contact. LR Senergyconsiders that the following scenarios, taken from the uncertainty sensitivities provided,represent a reasonable in place resource range. However, all cases assume the base casestructural interpretation.

Low case 18 MMstb. This scenario uses the low case porosity model and relativelypositive structural and contact assumptions.



Best case: 30 MMstb. The model core area of the structure and the positive porositymodel, but with a contact at 11,518 ft tvdss which is about 82 ft above the mapped spillpoint. It is compatible with previous best estimates for the accumulation, though thejustification for the 11,518 ft depth is weak.

High case: 61 MMstb. This includes the high case structural interpretation and porositymodels and with the contact at the structural spill point at 11,600 ft tvdss.

The additional upside potential associated with the enlarged hypothetical stratigraphic trapcould be in the range 144 to 182 MMstb.

3.1.1.6 Dolphin Resource Assessment and Production Profiles

The Dolphin resource estimates are based on an uncertainty study performed with full fieldreservoir simulation models, using Eclipse software. This work evaluated the sensitivity of theresources and recovery factors to a number of reservoir parameters and to uncertainty inreservoir architecture and distribution. LR Senergy did not have access to the simulation model,but has reviewed a comprehensive report and presentations. The construction of the simulationmodel and the work undertaken by the operator appears to be of a good technical standard.LR Senergy has used the operator’s work to determine low, best and high recovery factors that,when applied to the STOIIP range specified above, provide an appropriate estimate of the rangeof resources. This work showed a significant downside to the recovery factor related to the lowporosity model in which water injection becomes ineffectual because of the associatedreduction in permeability. The recovery factors from the operator P90, P50 and P10 selectedmodels were 9, 30.4 and 31.3% respectively.

The latest development plan assumes one crestally located gas lift producer and one down dipwater injector. For the high case LR Senergy assumes that a second production well is drilledto exploit the larger oil in place and area.

Low estimate (1C). This is based on a 10% recovery factor. This reflects the lowporosity downside model in which water injection becomes ineffectual.

Best estimate (2C). This assumes a 30% recovery factor.

High estimate (3C). This assumes that a second production well is drilled to exploit thelarger oil in place and area. A 30% recovery factor is applied to the high case STOIIP.

The gas profiles are gross gas production without any deductions for fuel and flare or removalof CO2. A significant proportion of the gas is expected to be used for F&F and the project islikely to become gas deficient in later years.

New static and dynamic models and sensitivity analysis are noted in the September 2015meeting brochure with a P50 recoverable of 11 MMstb quoted. LR Senergy has not revised itsassessment at this stage as the work is still in progress.

3.1.1.7 Development Plan and Chance of Development

A combined development of Perth, Lowlander and Dolphin is assessed and developmentfeasibility studies are in progress.



The core of the project is the joint Perth and Lowlander development utilising subsea wells tiedback to an FPSO located adjacent to the Perth field with Lowlander tied back using an 18 kmsubsea flowline. As envisaged, the FPSO effectively becomes a regional sour crude processinghub. Recent studies indicate that a Full Gas Processing option (FGP) is technically feasible.A tieback of Dolphin is now included as part of the development. .

The maximum concentration of H2S could be 24,000 ppm and with up to 16 mol % CO2. AnH2S level of 24,000 ppm has not been produced in the North Sea before and this level of sourgas processing has not previously been installed on an FPSO. However, these levels of H2Sare not unusual in other parts of the world, including Kazakhstan and the Middle East. Theassociated gas will be used for fuel on the FPSO. Export of excess gas is potentially feasiblesubject to commercial terms and conditions. However, the options for the produced gas arestill under consideration and include the gas export option with sweetening of high pressure(HP) gas stream and export via pipeline (Reference Case), and the no gas export flaring optionwith sweetening of fuel gas and lift gas only and flaring of surplus gas.

The total FPSO nameplate gas compression capacity is 55 MMscf/d. In order to avoid thisbeing exceeded, the designated lift gas rates are 2 MMscf/d per well for Perth and Dolphin and3 MMscf/d per well for Lowlander.

A production efficiency of 85% is assumed, which includes all planned and unplanned downtimeand applies to all production and injection streams.

Project sanction is likely to be dependent on the results of the ongoing joint developmentfeasibility studies and LR Senergy understands that the development is contingent on a 3rd

party farm-in. Consequently, LR Senergy categorises the project as Contingent resourcesDevelopment On Hold, and proposes an overall chance of commercial development of Perthand Lowlander of 20%.

For Dolphin, LR Senergy assesses the chance of commercial development to be 20%. This isprimarily due to this part of the project being a second phase of the development. There issignificant subsurface risk associated with trap definition and reservoir quality and lateral extent,and the low case is currently sub-commercial.



3.2 Norway Discoveries

The un-risked contingent resources in the five Norway discoveries are summarised below:

Table 3.2: Contingent Resources (Norway)

The Bue and Boomerang discoveries are located proximal to the Njord area, and Bue is classedas Development Pending, whereas Boomerang is classed as Development Unclarified untilfurther post well evaluation studies are completed. The Norwegian Sea Fogelberg discovery isplanned for development when pipeline ullage is available and is also classed as DevelopmentPending.

The Shango / Skirne East discovery is classed as Development Not Viable. The SE Tordiscovery is in two reservoirs with the Tor resources classed as Development Pending and theEkofisk resources as Development Unclarified.

3.2.1 Bue Discovery: Block 6406/11, 6406/12

The Pil field and adjacent Bue discovery in licence PL 586 are located on the Southern HaltenTerrace about 32 km southwest of the Njord field and 60 km to Draugen. VNG Norge is theoperator and the Faroe equity is 25%.

Following the drilling of the Pil discovery wells a further sidetrack, 6406/12-3A, was then drilledto intersect the Bue accumulation, which is immediately adjacent to the northwest. Extensivepost well studies are in progress and LR Senergy has reviewed the DG1 interpretation of thediscovery.


LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate

Oil & Liquids Resources (MMstb)

Bue 5.0 10.1 17.6 1.3 2.5 4.4 75% VNG

Boomerang 4.0 17.8 27.7 1.0 4.5 6.9 40% VNG


SE Tor (Tor) 4.0 14.3 37.5 3.4 12.2 31.9 35% Faroe



Total Oil & Liquids; MMstb 18.8 58.6 164.6 8.3 28.6 105.6Gas Resources (Bscf)

Bue 2.0 4.1 7.2 0.5 1.0 1.8 75% VNG

Boomerang 3.6 15.9 29.3 0.9 4.0 7.3 40% VNG


SE Tor (Tor) 4.8 17.2 45.0 4.1 14.6 38.3 35% Faroe



Total Gas; Bscf 159.2 332.4 612.1 43.8 99.1 226.3

Contingent Resources (Norway): Discoveries





The Bue trap is less well defined than the nearby Pil accumulation and is also a combinedstructural and stratigraphic closure that appears to be separated from the Pil accumulation bya pressure barrier that may be the result of an impermeable sequence of reworked sediments.

The accumulation is mapped on 3D seismic data and is mapped at the top reservoir that ispartly synonymous with the BCU. The accumulation is trapped beneath Lower Cretaceous andUpper Jurassic Spekk shales.

The charge is considered to be from Upper Jurassic Spekk shales, which are modelled to be inthe oil window in the vicinity of the discoveries.

The Bue discovery well, 6406/12-3A, found an OWC at 3,420 m tvdss in Upper Jurassic Spekksandstones. In the Bue core, turbidites dominate, lower shoreface deposits are of secondaryimportance and minor interbedded mudstones are present.

The Bue deterministic base case STOIIP is 24 MMstb and this is considered the Best case.The operators low and high cases are 21 and 32 MMstb respectively. However, at this stagethere is a concern that low case uncertainties associated with ‘data limitations’ and the needfor ‘appraisal to confirm volumes’ are not fully captured. Hence, as an interim measure a 20%reduction in low case STOIIP is proposed, pending the completion of further uncertainty studies.Future model revisions and uncertainty assessment will further refine the correlation, mappingand parameter issues that can reduce uncertainty in volume estimates.

Bue has a different composition, reservoir pressure and saturation pressure to Pil. Preliminarystudies on Bue samples indicate narrower ranges for stock tank oil density of ca. 836 to 837kg/sm3 and GOR of ca. 114 to 115 sm3/sm3.

3.2.1.2 Resources and Development Concept

Recoverable resource estimation has been derived from reservoir simulation by the operator.Recovery factor input ranges of 38 to 55% are indicated for Bue. LR Senergy recommendsusing a lower downside RF and a range of 30, 42 and 55% for a one producer / injector pairdevelopment, at this early stage of evaluation. Recoverable resources gross and net to Faroeare given in Table 3.2 using these recovery factors and the HIIP range described above.

The development options under evaluation include a stand-alone FPSO development and tieback to Draugen. At this stage, Bue is considered to represent upside potential to the Pilproject due to data limitation and interpretation challenges and it is expected that appraisal willbe required prior to commitment. Water injection is expected with a single producer / injectorpair.

3.2.1.3 Risk or Chance of Development

Development risk is assessed at 75% as, although considered part of the Pil project, it isplanned for a second stage of development and uncertainty is greater.

3.2.2 Boomerang: Block 6406/11, 12

The Boomerang discovery well 6406/12-4S located adjacent to the Pil discovery, wascompleted in August 2015 and encountered an ambiguous pay interval in Upper Jurassic



Volgian to Ryazanian (Spekk/Rogn) sandstones. LR Senergy has undertaken a high levelreview of the provisional well results data, but a full and complete interpreted data set was notavailable for review as the evaluation is still in progress.


Prior to drilling, the Boomerang area was divided into depostional units defined by separate fandelta sandstone depositional sequences of both Volgian / Ryazanian and Callovian / Oxfordianage. Boomerang is mapped on 3D seismic data at the Near Top Volgian (Spekk) and NearTop Oxfordian (Melke) horizons and the well was located to test interpreted fluid indicators atthe Spekk and Melke target horizons. The significance of the Spekk ‘anomaly’ is uncertain andfurther evaluation is in progress.

The trap is dependent on Lower Cretaceous shale and Upper Jurassic (Spekk Formation) topseal. The overall mapped closure has a structural spill point to the south at ca. 3,400 m tvdssand this is the maximum case contact assumption in the resource calculations.

Well 6406/12-4S found ca. 27 m gross (24 m net) Spekk sandstone with average 16% porosityand uncertain Sw. Water saturation is very uncertain due to the lack of Rw and large mud-losses that were controlled by LCM and graphite, which may have distorted the resistivityreading. In addition the well encountered 51 m net Intra Melke sandstone with just 2 m net pay,and 56 m net water bearing Melke 4 sandstone.

The well was not tested but a limited number of successful pressure data points were obtainedwith low observed mobilities, which makes their interpretation difficult. The 6406/12-4S PVTanalysis is crucial to the interpretation of the Spekk reservoir being oil bearing and, althoughmost samples are mud contaminated, the reservoir oil proven in all tanks was 5 vol-% and theoil component distribution is reported as being similar to that analysed for Pil.

Well 6406/12-4A did not encounter a reservoir quality Spekk interval but found a thick (479 mgross and 110 m net) Intra Melke sandstone interval with about 9 m net pay, with 13% porosityand Sw 50%. The well results suggest that Melke sandstones in well 6406/12-4S and 4A havelower porosity and significantly reduced reservoir quality due to increased cementation close tothe Vingleia fault.

The nearby Pil wells encountered hydrocarbons in a thick Callovian / Oxfordian (Melke) clasticsequence immediately beneath the BCU (see Section 3.2.1) but did not encounter reservoirquality Spekk sandstones.

LR Senergy has reviewed the initial post-well resource assessment and considers it to be areasonable reflection of uncertainty assuming an oil saturation in the range of 62 to 70% andthat the log analysis is invalid. The risk associated with this interpretation is included in theoverall risk assessment (see Section 3.2.2.3 below) until post well evaluation studies have beencompleted. The depth map has a +/- 20% sensitivity applied and the porosity range is 16 to18.5%, net to gross 75 to 85%, and gross thickness 27 to 43 m. The contact is assumed to bebetween 3,290 and 3,363 m tvdss.


A provisional recovery factor range of ca. 35 to 45% is assumed to derive an initial view ofrecoverable resource potential. This range will need to be aligned with a detailed comparisonto Bue in due course, in order to ensure that the assumptions are compatible. The post well



evaluation is too immature to propose a detailed development concept, though a potential tiein to the Pil development (as envisaged for Bue) would be the most likely option.

3.2.2.3 Risk Factor or Chance of Development

The risk associated with the Sw interpretation is included in the overall risk assessment untilpost-well evaluation studies have been completed. In view of this and the fact that post wellstudies are still in progress, LR Senergy categorises Boomerang as Development Unclarifiedand consider a risk factor of 40% to be appropriate.

3.2.3 Fogelberg Discovery: Norway Blocks 6506/9 and 12

This APA 2006 Licence comprising blocks 6506/9 and 12 is situated on the Halten Terrace inthe Norwegian Sea, northeast of the Smørbukk field and 10 km along strike to the southwestof the recent Morvin oil and gas discovery. The licence operator is Centrica with Faroe equitybeing 25%.

The project is currently in ‘hibernation’ until mid 2016 which is the FEED decision point and isexpected to lead to FEED start in 1Q 2017, PDO submission in 1Q 2018 and 1st Production in2021. Concept selection of subsea tie back to Åsgard B was agreed by the partnership in 2014.First gas has been postponed to 2021 due to capacity constraints in the Åsgard transportationsystem. Project improvement studies have been completed including host modification studies.A term sheet has been neither signed nor agreed with the Åsgard Group.


Fogelberg is a tilted fault block structure to the north of and down thrown from the Smørbukkfield. The structure is controlled by two bounding faults to the south and west. The reservoir isMiddle Jurassic (Aalenian to Bathonian) sandstones. The discovery well 6506/9-2S drilled inJuly 2010 encountered gas and condensate in Garn and Ile reservoirs with the Tofte and Tiljebeing water bearing. The key map horizons are the BCU and the Top Ile, which are subject tosome depth conversion uncertainty that is quantified and incorporated in the volume range.

The Garn interval is 60 m gross sand with 50 m net pay and 9 to 11% average porosity and 25to 35% average Sw. The Ile interval is 73 m gross sand with 17 m net pay and 9% porosityand 40 to 47% average Sw. The basal 20 m of the Ile is tight.

A GDT was identified in the Garn at 4,306 m tvdss, and possible GWC in the Ile at 4,354 mtvdss. The contact at 4,354 m tvdss (4,441 m md) coincides with degradation in reservoirquality and hence could also be interpreted as a GDT. This is apparently similar to the situationobserved in the nearby Morvin field. If the resistivity change at 4,354 m is a GDT, due toreservoir quality degradation, then the hydrocarbon column could be greater up to a maximumof 320 m based on the Garn structural spill point at 4,550 m tvdss and this represents aconsiderable upside potential.

Fogelberg is an HPHT discovery and PVT analysis indicates a gas condensate. There is CO2

with a consistent value of 4.2%.

Static and dynamic models have been prepared in 2011 and the results have been reviewedby LR Senergy. The operator’s volume estimates are based on a detailed uncertainty study.The main volumetric uncertainty is the FWL. The reservoir parameters are reduced for the lowcase and increased in the high case to reflect spatial uncertainty. LR Senergy has reviewed



this approach and considers it to be a reasonable reflection of the range of possible outcomes,which is from 214, 528 to 852 Bscf plus associated condensate.


The Fogelberg development has passed concept selection and will involve tie-in from a subseatemplate at 280 m water depth, processing and transportation services to Åsgard. The hostmodification issues, including weight limit risk on the Asgard platform, are still underconsideration.

Three producers are expected to be required with 75 degree trajectories through the reservoirand are simulated to give a production plateau of 125 to 150 MMscf/d. A scenario involvingtwo producers has also been considered. The current base case profile envisages a plateaurate of ca. 134 MMscf/d. Spare gas production capacity is unlikely to be available before about2021 and is the basis for the economic evaluation.

LR Senergy has reviewed the recovery factor range proposed by the operator of 58 to 72% forGarn and 50 to 70% for Ile and considers these estimates to be reasonable. The condensateyield is approximately 27 bbl/MMscf.

Development plans are currently too immature to provide an assessment of eventual fieldabandonment and environmental protection issues.


Although the structure definition is good there is hydrocarbon contact uncertainty which meansthat there is a large upside potential. Development will require agreement of commercial termswith the host and will need to await ullage in about 2021. Consequently, LR Senergy considersthe chance of a commercial development to be 65%.

3.2.4 South East Tor Discovery: Norway Block 2/5

SE Tor is located on the Mandal High in the East Central Graben in Norwegian block 2/5 some9 km northeast of the Tor field and 15 km east of Ekofisk. An appraisal well is being plannedfor 2017. Faroe recently announced that it has acquired Lundin’s interest and the operatorshipof SE Tor. The transaction has been approved by the MPE and Faroe will be the new operatorof the asset with an 85% interest.


The discovery well 2/5-3, drilled in 1971, found a light oil of 43° API with GOR of 1,200 scf/bblin Tertiary and Upper Cretaceous Chalk (the Tor interval tested 4,525 bopd and Ekofisk interval4,281 bopd and 110 bwpd). Water production from the Ekofisk reservoir in this well needs tobe understood. Two additional wells were drilled to appraise the structure in 1973 (2/5-5) andin 1988 (2/5-8) but with disappointing results. The well 2/5-5 was drilled near the spill point ofthe structure and tested the Tor interval at 456 bopd and 1,228 bwpd. The Ekofisk had highwater saturations and was not tested. Well 2/5-8, encountered low porosity and high watersaturation in both the Tor and Ekofisk and was not tested. An unsuccessful exploration well2/5-14S, on the downflank Hyme prospect, was drilled in early 2009 and disproved a model ofhydrocarbon presence based on seismic inversion data.



SE Tor is a faulted four-way dip closed structure over a salt dome with a north to southorientation mapped at the top Tor and top Ekofisk horizons. The proved volume is restricted tothe fault block tested by the 2/5-3 well and is conservative. The north to south trending faultscompartmentalise the structure and deeper fault blocks to the west were tested by the twoappraisal wells with ambiguous results. The most recent interpretation identifies the north tosouth trending fault separating the 2/5-3 well from 2/5-8 as defining the boundary betweenwestern and eastern field segments. The better reservoir quality is indicated to be in the easternsegment by well and seismic data.

Syn-depositional faulting during Tertiary and Upper Cretaceous deposition is responsible forvariation in thickness as well as the quality of the Ekofisk and Tor Formation reservoir intervals.The porosity in the Tor Formation away from the well control has been estimated using inversionand rock physics analysis. The data suggest that porous areas within closure in the Tor areprobably present, although effective reservoir thickness cannot be confidently predicted.Additional seismic amplitude and RAI volumes, calibrated to well data, will be re-assessed in2016 for porosity mapping. This will follow on from the earlier work conducted by the previousoperator. Fractures were identified in the cored section of 2/5-3. However, fracture distributionis not well understood at this stage and further studies are planned. The area of the well 2/5-8had previously been interpreted as a crestal collapse zone with limited reservoir potential andwas excluded from the GRV calculations. Porosity is generally low in the current wells and it isunclear how representative these are of the field.

Redeposited Chalks, if present, could indicate higher poroperm intervals. Averaging wellporosities and Sw values can underestimate / mask the true potential of the high poroperm(redeposited) intervals that may have significant lateral extent and be below seismic resolution.

As is often the case in Chalk fields, the position of the OWC is ambiguous. A FWL in the TorFormation is interpreted at ca. 3,400 m tvdss and the OWC could be in the range ca. 3,300 to3,355 m tvdss. Historic low case volume sensitivities used an ODT in well 2/5-3 at 3,160 mtvdss.

The porosity input to STOIIP determination is particularly uncertain and is based on the seismicinversion data, which has been used as direct input to the model. This is a valid approximationthat has been proved in other Chalk fields but is nevertheless an indirect method subject to alarge range of uncertainty. Historic STOIIP range estimates have been reported as 26, 57, 89MMstb, and 23, 66, 126 MMstb. A new Tor model has been prepared in 2013 and generatesa ‘base case’ STOIIP of 107 MMstb, and a range of 25 to 125 MMstb is reported. The increasedSTOIIP is partly a result of a deeper contact used in the new model compared to historicassessments (from 3,300 to 3,355 m tvdss).

As new work on the assessment of this discovery is at an early stage and still in progress, LRSenergy has undertaken a high level review of current and historic interpretations in order tounderstand the uncertainties. All estimates quoted above have a low case STOIIP of ca. 25MMstb and consequently this is taken as the low case for the Tor Formation. This correspondsto the crestal eastern segment area with the ODT from well 2/5-3. A high case of 125 MMstbis justified by the historic evaluations and assumes an OWC at 3,355 m tvdss and both westernand eastern segments. The best estimate from the revised model is 107 MMstb (a lognormalplot would suggest 60 to 70 MMstb for a P50). However, there is no uncertainty assessmentassociated with this work and the new operator, Faroe, plans to re-assess the model inputs andundertake new work to understand the porosity modelling better and a fracture analysis toassess, distribution, orientation and intensity of the fracture system.



The STOIIP in the model is reported to be split approximately 50% each in the western andeastern segments. The DST well test results to date suggest that the eastern area has betterproductive capacity due to a naturally active fracture system in the Chalk. The western areapotential is uncertain in view of the 2/5-8 well results.

Ekofisk STOIIP has been estimated deterministically for the east and west flanks of thestructure in order to provide a provisional volumetric range pending the initiation and completionof further more detailed subsurface studies that are planned by Faroe as new licence operator.The existing well 2/5-3 log interpretation has been used to estimate matrix porosity and a lowcase contact of 3,093 m tvdss corresponding to base Ekofisk in 2/5-3 and a high case of 3,355m tvdss has been assumed as for the Tor. The resulting matrix STOIIP range is wide at 20,75, 465 MMstb for the east flank and 2, 4, 48 MMstb for the west flank, reflecting the high levelof uncertainty. However, LR Senergy considers that it is likely that the end member valuesreflect probabilities closer to P99 and P1 rather than P90 and P10. An appraisal well will berequired to assess the potential of the Ekofisk reservoir, and further studies planned for 2016will inform a location decision for a possible well in 2017.


Several development concept options are under consideration for the Tor reservoir. The nearbyTor field had been the base case for a subsea tieback but is no longer an option as it is likelyto be shut-in in 2016. A Tor redevelopment project was planned by Tor operator ConocoPhillips(CoP) based on a Wellhead Platform (WHP) tied directly back to Ekofosk, with a multi phaseflowline. However, this has now been put on hold until at least 2017. Nevertheless a tie backto a future Tor redevelopment may be an option as may the alternative of a joint developmentwith Tor. Other potential developments of the field are a stand alone Jack Up ProductionSystem or possibly a Valhall tieback.

The current development reference case envisages tie-back to the Tor redevelopment platformwith first oil in 2020, and assumes water injection drive with one injector and two horizontalproducers which applies for both the Ekofisk and Tor formation. SE Tor is a light oil 43° APIwith GOR of 1,200 scf/bbl.

Water injection and water handling may reduce ultimate recovery by bypassing matrix oil (as inthe UK Banff field), although it is successful in the Ekofisk, Tor and Hod fields. Nearby fieldsall benefit from gravity compaction drive.

The Chalk reservoirs in SE Tor have only been tested by vertical wells and, with appropriatehorizontal well design, areas in the east compartment in particular could have high recoveries.Horizontal wells can increase production up to ten-fold in Chalk reservoirs. With appropriatehorizontal and stimulated wells, recovery from the eastern compartment could be over 30% forboth Tor and Ekofisk. Acid wash and / or proppant fracturing in long horizontal wells couldincrease recovery from both reservoirs especially from the matrix.

The resource range for the Tor is provisional and based on the currently available work fromthe previous operator, which is incomplete:

Low estimate (1C) is the low case STOIIP assuming a higher contact close to the ODTand assuming a recovery factor of 16% (depletion with gas lift).

Best estimate (2C) is the 2013 model STOIIP for the eastern segment with waterinjection and assuming a recovery factor of 27%.



High estimate (3C) is the high case STOIIP for both eastern and western segments,with water injection assuming a 30% recovery.

The evaluation of the Ekofisk reservoir is at a much earlier stage of maturity. There is currentlya provisional matrix STOIIP estimate (see above), but a fractured reservoir is predicted in atleast the central part of the structure and consequently a dual porosity model will be requiredto assess reservoir potential fully. A provisional recovery factor range for the east flank of 10,12, and 15% is proposed at this early stage of evaluation. The low case assumes recoverywith at least some contribution from natural fractures in the compartment tested by well 2/5-3.The best and high cases assume increasing levels of recovery from combined stimulation andfracture networks but RF only increases moderately in view of the large STOIIP incrementsproposed for the best and especially the high cases.

Development plans are currently too immature to provide an assessment of eventual fieldabandonment and environmental protection issues.


The structural compartmentalisation and reservoir variability mean that there is risk associatedwith any further appraisal drilling (downdip appraisal of the north central or east area of the fieldis being evaluated). The project is just economic for the best estimate volume. LR Senergyproposes an overall chance of commercial development for the Tor reservoir of 35%, and of25% for the Ekofisk. The Tor reservoir resources are classed as development pending whereasthe Ekofisk resources are classed as Development Unclarified until the completion of studiesplanned for 2016.

3.2.5 Shango (Skirne East) Discovery: Block 25/3

The Shango discovery (Skirne East of Total) is located in licence PL627, on the Utsira High inthe northern North Sea about 8 km from the subsea multi-well template on the rich gas andcondensate Skirne field, and 25 km from the Jotun FPSO.


The slightly deviated discovery well 25/6-5S was drilled in 2Q 2015 and found the top reservoirvery close to prognosis at 2,307 m tvdss with 9 m of gas in Middle Jurassic Hugin sandstone,with a GWC at 2,316 m tvdss. The gross reservoir thickness was 36 m, with a net / gross of82% and average porosity of 23% with Sw 31%. Pressure measurements were taken but noformation fluid samples were acquired.

The well result disproved the large pre-drill trap that required fault seal to the east and south.The accumulation appears to be confined to a small four-way dip closure with leakage at deeperlevels across the boundary fault to the south and the structure tested by well 25/6-2. This wascorrectly anticipated to be the main pre-drill prospect risk and is the reason for the discoveryvolume being so much less than the pre-drill prediction. Three top Hugin depth maps havebeen prepared with different velocity models in order to investigate sensitivity, and the range ofresulting GRV estimates are used in the resource range estimates.

The discovery is situated between the Skirne field 25/5-3 well (GWC at 2,404 m tvdss) in thewest and the 25/6-1 and 25/6-2 wells to the east. The small 25/6-1 discovery encountered anODT at 2,257 m tvdss and 25/6-2 was dry with shows.



The operator’s post drill resource volume estimates are for the small four-way dip closure andare a reasonable reflection of the uncertainty range for the proven accumulation. .

There is remaining exploration potential to the east of the discovery well in the easterly portionof the original prospect. This remaining potential appears to be confined to a separate smallfour-way dip closure. The interpretation of the NE – SW fault zone separating this dip closurefrom that tested by well 25/6-5S is critical to the definition of any larger prospective resourcepotential in this eastern area.


A potential development of the field would be by 8 km subsea tie back to Skirne and the Heimdalpipeline. Since the structure is relatively flat a highly deviated producer would be required andearly water breakthrough would be anticipated.


In view of the currently sub-commercial size and operator’s recommendation, LR Senergyproposes an overall chance of commercial development of 10%.



4 Exploration ProspectsThe exploration prospect portfolio of Faroe is located principally in the UK North Sea, theNorwegian North Sea, the Norwegian Sea and the Barents Sea (Figures 1.1, 1.2, 1.3, 1.5, 1.6and 1.7). The Barents Sea is an under explored province often with medium to high risk andlarge resource potential in areas with developing infrastructure. The UK and Norwegian NorthSea is a more mature province with good infrastructure and low to medium risk for more modestresource volumes, although there are some notably larger potential resources in less matureplay types. There are also newly acquired exploration licences in Ireland.

Several licence relinquishments have been confirmed between the effective date and thesignature date of this report. These include UK licences P2011 in the Atlantic Margin, P1948(Curlew South) and P1993 (Birnam), and Norway licences PL590 (Milagro), PL670 (Betula,Sorbus), PL665 (Caramelo). Notice to relinquish Norwegian licence PL534 has been submittedin May 2016. In addition, five new Norwegian licences (PL810, PL811, PL825, PL836S andPL845) containing ten prospects and leads, have been awarded in early 2016 and theassociated resources are included in the Medium Term category (for one prospect) and Othercategory (for nine prospects). The Kvaltann / Kvalross exploration well was drilled as a dry holein 1Q 2016, after the effective date of this report, but before the signature date, and theassociated resources have been removed from the portfolio.

4.1 UK North Sea Prospects

The North Sea exploration portfolio comprises leads and prospects of several play types.Exploration activity is currently focussed on two areas:

Outer Moray Firth Quad 15, where the Perth / Lowlander / Dolphin discoverydevelopment plans are progressing (see Section 3.1) and Faroe has an associatedexploration portfolio with medium term and longer term drilling plans.

Central Graben Quad 29 where longer-term drilling plans are supported by severalopportunities that are currently being matured.

4.1.1 Medium Term Prospects

There are three high graded prospects in the UK North Sea that could become drillingcandidates in the medium term. The gross on block and net to Faroe resource volumes aresummarised below:

Table 4.1: Prospective Resources: Medium Term Exploration (UK North Sea)

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate

Oil & LiquidsResources (MMbbl)

Perth Northern 1 8 66 0 3 23 65% 2 FaroeFynn 17 31 41 4 8 10 30% 2 ParkmeadBeta 4 10 19 1 3 6 64% 2 Faroe

Total Oil & Liquids;MMbbl 22 48 126 6 14 40 6

Gross on Licence 'Risked'Net Best

Prospective Resources: Medium Term Exploration (UK North Sea)

Risk FactorNet Attributable

Operator



It is likely that a decision to drill Perth Northern will be influenced by the results of the plannedPerth / Lowlander / Dolphin development and ongoing seismic interpretation in the area.

4.1.1.1 Perth Northern Prospect: UK Block 15/21a,b

The Perth Northern Prospect is a structural and stratigraphic trap located immediately north ofthe Perth Core field and on trend to the west of the Perth NE segment (see Section 3.1). Thepresence of the Upper Jurassic Claymore sand reservoir target in the northern Perth segmentis not proven by a well. The gross isopach between the top Piper and BCU seismic events isin the range 1,200 to 1,500 ft. Regional well control suggests that this interval could compriseca. 750 ft Kimmeridge Clay shale overlying the Claymore and an underlying shale thickness,which was 375 ft in the 15/21b-47 well in Perth. Assuming these thicknesses are representativeof the northern area, there is the potential for 100 to 300 ft of Claymore sands.

LR Senergy has not undertaken an independent assessment of the resource potential but hasused the operator’s latest upside STOIIP estimate of 220 MMstb to generate a lognormaldistribution. This gives P90 and P50 values of 4 and 30 MMstb respectively. The Claymore sandreservoir presence risk is reflected by uncertainty in this very small low case STOIIP in thismethod of resource calculation and, hence, the chance of discovery risk assessment does not‘double hit’ the reservoir risk. Chance of discovery is, therefore, assessed by LR Senergy as65% for this resource size range.

The recoverable resource estimates use a recovery factor range of 20, 25 and 30%, which iscompatible with the Perth field.

4.1.1.2 Fynn Prospect: UK Block 15/11 and 16d

The Fynn prospect in P2156 (28th Round award) is a downthrown fault closure on a NW – SEoriented fault terrace with a Middle Jurassic Piper sandstone reservoir target, located 5 kmnortheast of Lowlander (see Section 3.1). There are secondary reservoir targets in the PermianZechstein and Carboniferous. The mapped closure is immediately updip of the 14/15-2 well,which encountered hydrocarbon saturations in the upper 17 m of the Piper sandstone and anoil saturation of 40% is interpreted from log analysis in the top 2 m. Fluorescence and cut werenoted in the upper 20 m of the Piper. The base of log derived hydrocarbon saturation isinterpreted to be at 2,366 m tvdss. The Piper interval displays an amplitude anomaly that ispartially coincident with the mapped closure. The main risk is fault lateral seal to the northeast.Seismic reprocessing of a new PSDM volume is planned to improve data resolution, primarilyto assess fault juxtaposition along this northeastern boundary of the prospect. The licence hasa well commitment contingent on the PSDM confirming offset of the Piper against seal units inthis critical area. The resource assessment does not appear to capture the full range ofdownside uncertainty, but is not unreasonable and the LR Senergy risk assessment iscompatible with that of the operator.

4.1.1.3 Beta Prospect: UK Block 15/21a

The Beta prospect is a possible eastward extension of the Perth field. The trap requires adownthrown fault seal or may be in communication with the upthrown fault terrace of Perth(tested by well 15/21a-7). There is dip closure to the east and south. LR Senergy finds theresource assessment reasonable and calibrated to the Perth field data. The Claymore reservoiris likely to extend east from the adjacent Perth field, though there is a risk that the turbiditesands do not extend this far to the east or will be a more distal facies of lower quality.



4.1.2 Leads and Prospects Under EvaluationThere are three other prospects and leads in the UK North Sea, the decision to drill beingdependant on further evaluation and / or future drilling results in the area. Some of these arelikely to become drilling candidates in the medium term.

The risk and resource volumes are summarised below and, where the most likely hydrocarbonphase is gas, the quoted volumes are oil equivalent:

Prospect Gross BestEstimate

Equity(%)

Net BestEstimate Risk (%)

Block 15/11 Penny 39 25 10 15Block 29/13 Fulmar B 29 33 10 12Block 29/13 Fulmar A 16 33 5 18UK North Sea Total (MMboe) 120 25

Table 4.2: Prospective Resources: Other Exploration (UK North Sea)

The Penny prospect in the 28th Round award block 15/11 is adjacent to and updip of the Fynnprospect (see Section 4.1.2.2). This high risk structural trap is located between wells 15/11-3and 15/11-1 and has a Piper sandstone reservoir target. LR Senergy has adjusted the overallrisk to 15%.

There are two interpod play structural Leads in block 29/13 with Upper Jurassic Fulmarsandstone objectives. The forward work programme planned by the operator (Endeavour) willinitially include 2D seismic acquisition and reprocessing to improve seismic imaging in order tounderstand the structural / stratigraphic framework of the area and the reasons for the existingwell failures. The licence carries a drill-or-drop decision by end December 2016. The FulmarB lead is defined on 2D, whereas the Fulmar B Lead is mapped on 3D seismic. Nevertheless,LR Senergy has adjusted the risk for the latter from 20 to 18% in view of the limitedunderstanding of nearby well failures.

4.2 Norwegian Prospects

The extensive Norwegian exploration portfolio covers a large range of play types in a variety ofbasin settings. This portfolio is subdivided into:

Near Term: four prospects with drilling plans in the next 2 years,

Medium Term: ten high graded prospects that are considered to be strong drillingcandidates in the next 3 to 5 years,

Other longer term opportunities comprising nineteen leads and prospects that eitherrequire further evaluation or are considered likely to benefit from the drilling results ofthe near and medium term prospects.

There are five areas of exploration focus close to producing fields and discoveries in whichFaroe has an equity interest as well as new exploration provinces:

Njord / Hyme field area (Section 2.2) in the Haltenbanken of the Norwegian Sea,includes the recent Pil, Bue, Boomerang and Snilehorn discoveries and a portfolio ofNear Term (Njord NF2), Medium Term (Zircon, Dobby, Nilus, Rosapenna, Seychelles



and Mauritius) and Other longer term prospects (Tommeltott, Yoshi, Luigi, Slynge andSprettert).

Fogelberg area (Section 3.2) in the Norwegian Sea, in addition to these discoveriesincludes a Medium Term (Aerosmith) and Other longer term prospect (Sierra).

Northern North Sea province with the Brage, Ringhorne East and Jotun fields has anexploration portfolio comprising Near Term (Brasse), Medium Term (Rosapenna,Oshun, Rungne), and Other longer term prospects (Aganju and Mjod).

Butch discovery area in the Central North Sea is near to the Blane field and SE Tordiscovery and includes a Medium Term (Cassidy) and Other longer term prospects(Bamsemums, Katie, Gullaxy and Kid).

Barents Sea is an under explored region and the Faroe exploration portfolio includesthe Near Term Dazzler Central prospect and the Other longer term prospects (DazzlerEast, South, West, Rowlf West and East).

4.2.1 Near Term Exploration

The four prospects with Near Term exploration plans are scheduled for drilling in the next 2years. The well on the Kvaltann / Kvalross prospects in the Norwegian Barents Sea was drilledin 1Q 2016 and confirmed dry.

Table 4.3: Prospective Resources - Near Term Exploration (Norway)

Success in any of the planned wells will have positive impacts on the risk assessments for otherprospects in the portfolio.

4.2.1.1 Brasse Prospect: Block 31/7 and 30/9

The Brasse Prospect is located immediately south of and on trend with the Brage field (seeSection 2.2) and to the east of the Oseberg Sør J structure. It is a four-way dip closed structure

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate


Edinburgh (Blackmore) 0 4 76 0 1 26 39% Faroe

Brasse 14 23 33 7 12 17 43% Faroe

Dazzler Central 47 180 987 9 36 197 15% ENI

Njord NF2 4 18 37 0 1 3 54% Statoil


Edinburgh (Blackmore) 0 24 476 0 9 167 39% Faroe

Dazzler Central 70 310 1553 14 62 311 15% ENI

Njord NF2 17 70 132 1 5 10 54% Statoil

Total Gas; Bscf 87 404 2161 15 76 487

Prospective Resources: Near Term Exploration (Norway)

Risk FactorGross on Licence Net Attributable

Operator



and the primary reservoir target is locally derived sandstones of the Upper Jurassic DraupneFormation. Additional potential may be present in the deeper Upper Jurassic Sognefjord andFensfjord and the Middle Jurassic Brent sandstones. The current interpretation is based onmixed vintage 3D seismic surveys. The new broadband 3D seismic survey over Brage acquiredin 2014 will be pre-stack merged with existing 3D seismic surveys. A commitment to drill anexploration well was taken in 1Q 2016.

The BCU is the principle map horizon and is confidently mapped. There is assumed to be auniform interval thickness to the Top Draupne, which is not directly mapped. This is due to lackof impedance contrast in the Upper Jurassic interval and the abundant presence of multiples.These seismic resolution limitations also mean that the Top Sognefjord and Fensfjord mapsare based on the BCU mapping, and the Top Brent in the latter case. The immediate area isstructurally complex and characterised by faults with north to south and northeast to southwestorientations, though the former are dominant in the prospect itself. The Top Draupne mappedclosing contour is at 2,144 m tvdss and the crest is at 2,104 m tvdss.

Syn-tectonic, late Jurassic, Volgian to Ryazanian Draupne sandstones are postulated to havebeen sourced from local highs. Nearby wells 30/9-11 and 15 encountered thin Upper Jurassicsand rich intervals directly overlying Middle Jurassic Brent indicating the presence of a localerosional hiatus. The nearest well, 30/9-23, 1.5 km west and down dip of the northern tip of theBrasse prospect, encountered 10 m of Draupne sandstone with 21% porosity, and a 50 m thickSognefjord Formation sandstone. Presence and quality of reservoir is considered to be themain risk. The reservoir quality of the Draupne / Sognefjord sandstone is predicted to beequivalent to that encountered in the Brage field (23% porosity).

Oil migration routes to the prospect from Upper Jurassic Heather and Draupne shales aremodelled to be from the Oseberg area to the west and south. Hydrocarbons are predicted tobe oil phase and could be analogous to either Oseberg or Brage.

The probabilistic resource assessment is a reasonable reflection of the uncertainty, although asingle contact at the structure spill point is assumed, resulting in a rather narrow range. Thekey reservoir variable is the assumed Draupne sand net thickness, which is varied in a rangefrom 7, 10 to 40 m. The chance of discovery risk assessment is, in LR Senergy’s opinion,realistic and appropriate to the assessed resource size range. About 93% of the structure ison block at the lowest closing contour.

There is upside resource potential that is currently not quantified in a possible Draupnesandstone pinch out to the south, and in stacked pay potential in Sognefjord, Fensfjord andBrent sandstones. The latter potential closures are tilted fault blocks.

The most likely field development in the event of a discovery is a subsea developmentconsisting of a conventional 4-slot template with a tieback to the Brage platform.

4.2.1.2 Dazzler Central Prospect: Block 7318/12

The Dazzler Central prospect (also known as Bigorna and Bone) in licence PL716 is locatedon the southern flank of the Stappen High adjacent to the Bjørnøya Basin in the Barents Sea.The nearest producing field is the Snøhvit field, 190 km to the south and the nearest discoveriesare Skrugard and Havis, about 90 km to the southeast. The trap is a double culmination NE-SW to NS oriented faulted structure with a Lower Jurassic Kapp Toscana Group Sto sandstoneprimary objective and Nordmela Formation and Upper Triassic (Fruholmen Formation)



sandstone secondary objectives and is mapped at the top Sto sandstone horizon. The structureis mapped as 2 separate prospects, Bigorna and Bone, by the licence operator, ENI.

Both conventional and innovative seismic techniques give positive indications for the presenceof hydrocarbons. A well is scheduled for drilling in 2016/2017.

The LR Senergy resource estimate has combined input from the independent assessments byENI and Faroe. The licence application assessment by ENI recognises two separate prospects,which Faroe map as a single much larger structure. The combined low case HIIP of ENI fortheir two prospects (Bigorna and Bone) for the Sto primary target has been assessed as theP90 input (using a 25% recovery factor) on a lognormal plot. The Faroe high case recoverableresource for the entire structure has been assessed as the P10 input. The P50 value has thenbeen derived from this plot. The hydrocarbon phase is uncertain and both oil / gas and gasonly scenarios have been considered. The oil / gas case is provided in this report and the riskassessment is for this scenario.

The trap is a prominent horst structure though mapped differently in detail by ENI and Faroe.The main risks are a consequence of the significant uplift and erosion that is characteristic ofthe area. The reservoirs have, therefore, been more deeply buried in the past than the present-day burial depths, with consequent potential for porosity reduction and seal breach. Both ENIand Faroe assess a similar chance of discovery (for the reported phase) of 15 and 16%respectively.

4.2.1.3 Edinburgh Prospect: Block 1/6

The Edinburgh (previously Blackmore) prospect is a large, complex, salt cored, tilted fault blockshared across four licences including into UK waters, and with closure against a large boundingfault and a salt wall. About 19% of the mean prospect volume is in block 1/6 (PL660), whichFaroe operates with 35% equity. However the portion on licence varies with the uncertaintycases with all of the low case being off block and 12% of the best (P50) and 28% of the highcase being on block.

The licence carries a drill-or-drop decision by February 2016. A joint well operated by Maerskand shared between the 4 licence groups is planned for drilling in 2017.

The prospect is located at the southern edge of the “J” (Josephine) Ridge which has HP/HTJurassic and Triassic proven fields (Jasmine, Judy and Jade). The UK 30/14-1 (Flyndre) wellencountered oil in the Paleocene and Chalk above the prospect, but did not penetrate thedeeper sequences. The Cawdor field to the southwest encountered gas / condensate inPaleocene Balmoral sandstones and oil shows in the Ekofisk Chalk.

There are both Triassic Skagerrak and Jurassic sandstone reservoir objectives. However, thegeological model is uncertain due to structural complexity, seismic data limitations and limitedwell penetrations at depth. There is agreement on the likely presence of Triassic Skagerrak(Joanne and Judy) sandstone targets, but the presence, burial depth and likely age of Jurassicreservoir sandstones is less certain with Upper Jurassic Fulmar sandstones and MiddleJurassic Freshney deep water sands being potential objectives. The considerable uncertaintyover reservoir quality is fully reflected in the resource calculation inputs.

The complexity of the trap and the steep dips require high quality seismic imaging in order toconfirm the extent of the structure. The prospect was re-mapped in 2014 using newlyreprocessed PSDM data from 2002. The trap at both Jurassic and Triassic levels is analogous



to the Jasmine field being dip closed to the east and southwest and requires fault lateral sealto the southeast and lateral seal against salt to the north and west. The Top Triassic event isparticularly uncertain. The overall geometry and presence of the salt walls is confidentlymapped, though the precise position of the salt edge is uncertain.

Trap integrity requires salt wall seal as in the analogous Jasmine field and fault seal as in Jadeand Jasmine. Horizon identification uncertainty means that fault juxtaposition is uncertain, andthe fact that the Flyndre and Cawdor accumulations directly overly the prospect could indicateseal breach.

Potential migration routes across faults from adjacent Upper Jurassic Kimmeridge Clay sourcekitchens in the West and East Central Graben, are demonstrated on seismic data, thoughTriassic charge may be more problematic and depends on the uncertainties in the geologicalmodel. The most likely phase is predicted and modelled to be gas-condensate with a CGRrange from ca.50 to 250 bbl/MMscf. Maximum column height is not expected to exceed topseal fracture pressure.

The reported volumes reflect a very wide uncertainty range with a very small low case and alarge high / low ratio. This indicates that a ‘best industry practice’ methodology has been used.The risk assessment has been benchmarked to a ‘success rate’ assessment for the play in thisarea. Of 28 exploration wells within the HPHT Fairway in the J Ridge area, there were 22discoveries and 6 dry holes, a success rate of 79%. With 11 commercial accumulations thecommercial success rate for HPHT tests in the area is 39%. The reported risk assessment isconsidered reasonable and benchmarked, and is compatible with the resource calculationmethodology. It should be emphasised that the PL660 licence share of any discovery increasesconsiderably for the upside cases above the P50 volume. The partnership use the Pmeanresource volume as the best technical case and LR Senergy has referenced this in theeconomic evaluation.

4.2.1.4 Njord NF2 Prospect: Block 6407/7 and 6407/10

The Njord North Flank 2 (NF 2) prospect is located in the NF segment of the Njord Field. A wellis approved for drilling in 2016 though the well may slip to 2017 in the drilling schedule.

The principle reservoir target is Tilje sands with Ile sands being a secondary objective. Themain risk is trap integrity as down-faulted seal is required and fault offset at the crest is negligible(possibly less than 30 m). A combination of fault juxtaposition and fault plane seal is required.The operator, Statoil, has considerable data and experience of fault seal in the area andconcludes that “despite the small observed fault throws and low observed shale contents atcritical points, numerous other fields have shown that similar faults have sealing potential”. Inaddition, seismic inversion data shows positive indications of hydrocarbons in both Tilje and Ile.There are structurally conformant amplitude ‘brightening’ anomalies on far offset and AVO data.AVO and inversion agree with well log responses. There is a good match with observationsfrom elsewhere in areas of proved hydrocarbons in the Njord field.

Recoverable volumes are predicted to be a combined gas and oil case, though gas is the mainphase in the nearest NWF discoveries and at Noatun C. The resource and risk assessmentsuse industry best practice methodology and are considered to be reasonable. The reportedbest case value is the Mean of the estimated volume distribution.



4.2.2 Medium Term Prospects

The understanding of the extensive Norwegian exploration portfolio (Figures 1.2, 1.3, 1.4 and1.5) will improve considerably with the results of ongoing studies and with the results of theexploration wells scheduled in the near term. Success in any of the planned wells may havepositive impacts on the risk assessments for other prospects in the portfolio.

There are ten prospects in Norway that could be drilling candidates in the Medium Term. Thegross on block and net to Faroe resource volumes are summarised below:

Table 4.4: Prospective Resources - Medium Term Exploration (Norway)

The Zircon prospect is located in blocks 6407/5, 7, and 8 (part) in the Gimsan basin on theeastern margin of the Halten Terrace about 10 km north of Njord field (see Section 2.2). ThisLower Cretaceous (Albian to Aptian) Lange sandstone stratigraphic trap is mapped on mixedvintage 3D data of moderate to poor quality. The locally derived sandstones are interpreted toonlap the structural highs on the margins of the basin. Well 6407/8-1 located within the trapencountered hydrocarbon shows in a 62 m thick interval with 5.5 m net reservoir and averageporosity of 15%, average water saturation 70% and NTG of 9%. The interval was neither corednor tested due to poor quality reservoir. Reservoir quality is predicted to improve away fromthe well based on the geological model and seismic attribute analysis. Seismic data showsthickening associated with lenticular units with high seismic amplitude and sinuous featurestrending northwest to north, that are interpreted to be slope channel sandstones with potentialfor improved reservoir quality.

LR Senergy has reviewed the resource and risk assessment, which is considered to bereasonable. However, the base case quotes the Mean value (in line with NPD practice but this

LowEstimate

BestEstimate

HighEstimate

LowEstimate

BestEstimate

HighEstimate





Oshun 11 22 31 2 4 6 23% TotalCassidy 5 40 132 1 6 20 32% CentricaRungne 34 46 75 14 18 30 30% Faroe





Rungne 21 28 43 8 11 17 30% Faroe

Total Gas; Bscf 190 556 2051 37 109 406

Prospective Resources: Medium Term Exploration Prospects (Norway)

OperatorRisk FactorGross on Licence Net Attributable



conflicts with PRMS guidance) which is skewed to the high side and LR Senergy has, therefore,plotted the P90 and P10 outcomes on a lognormal plot and derived a slightly reduced P50 (bestcase) of 70 MMstb. LR Senergy has reviewed and concurs with the risk assessment, whichidentifies reservoir presence and quality and trap effectiveness as significant risks. The licencecarries a drill-or-drop decision by February 2017.

The Dobby and Nilus prospects in PL348 are fault block structures located close to theSnilehorn discovery (see Section 3.2.2) and Hyme field (Section 2.2) and with Lower to MiddleJurassic sandstone reservoir objectives. The principal targets in Dobby are Ile sandstones thatexhibit an only partially structure consistent amplitude anomaly, and Tilje sandstones with AVOand amplitude anomaly that do not cover the same area and could represent gas over oil. Thereis additional potential in a downflank fault block. Nilus has a Garn principal reservoir objectiveand is located further down dip and could be connected to the Dobby Downflank fault block.There is secondary potential in the Ile and Tilje sandstones. The main risk is lateral seal breachdue to Lower-Middle Jurrassic sand-sand juxtaposition across the main fault between theprospects. However, it is also possible that the Nilus and Dobby Downflank fault blocks couldbe part of a larger closure. The licence has a drill-or-drop decision in December 2016.

The Aerosmith prospect is located in licence PL644, on the western part of the Halten Terracein the Norwegian Sea about 30 km from the Morvin and Smørbukk fields and close to the recentCentrica operated Fogelberg discovery (see Section 3.2.2). The trap is a prominent dip closurewith updip pinchout and associated amplitude anomalies, located on the eastern flank of theSklinna High. The Lower Cretaceous Lange sandstones could comprise poorly developedreservoir and this together with the potential for hydrofracturing of the top-seal due to highreservoir overpressure are the main risks for this prospect. There is a drill-or-drop decision inFebruary 2017.

The Cassidy prospect is located 8 km to the north of Butch and is part of the same trend (seeSection 3.2.3). The Butch well results demonstrate that salt dome structures in this area arecomplex with both a discovery and dry wells on the same structure. The 2014 well on ButchEast is interpreted to be a lateral seal breached trap that once contained hydrocarbons. TheCassidy trap is interpreted to be the southern compartment of the dome separated from the8/10-1 dry hole on the north side of the dome. LR Senergy has reviewed the probabilisticresource assessment and note that the critical contact assumption inputs are skewed to thehigh side, based on the assumption of a similar column height (800 m) to the Butch maindiscovery. This results in a P50 output that is not considered unreasonable in view of the Butchanalogue. The interpreted hydrocarbon migration route is from kitchen areas to the west andsouth. The main risk is integrity of the lateral fault and salt side seals and this has beenincreased slightly by LR Senergy from 60 to 50% (in view of the recent Butch well results),resulting in an overall chance of discovery of 32%, which is still compatible with the operator'sassessment.

The Oshun prospect is in the same licence as the Shango / Skirne East discovery.

The Seychelles prospect is in block 6306/4 in the under-explored Rås Basin on the westernmargin of the Frøya High. The Ormen Lange gas field is 30 km to the west and the Njord oilfield is 90 km to the northeast. The Upper Jurassic Mauritius prospect overlies Seychelles.Both prospects are mapped on a 2D seismic grid. The Seychelles trap is a downthrown faultblock adjacent to the Frøya High with Middle Jurassic Fangst (Garn and / or Ile) sandstonereservoir target. The trap has a three-way dip closure and requires lateral seal againstbasement. The Mauritius trap is interpreted to be a slumped Upper Jurassic sub-marine fan



sandstone sequence. LR Senergy has reviewed the operator’s resource and risk assessmentand concurs with the conclusion that reservoir presence and quality are the main risks for bothprospects, though trap effectiveness (lateral seal) and hydrocarbon charge are also significantrisks. Although the prognosed UpperJurassic Spekk Formation organic rich shales are notproven in the immediate area, there is a large potential ‘kitchen’ area. The hydrocarbon phase(gas versus oil) is a more significant risk. The resource assessment is considered to bereasonable with a large uncertainty range and as the operator’s base case reports the Mean,LR Senergy has back-calculated a P50 (best estimate) value. There is a drill-or-drop decisionin February 2017.

The notice to relinquish licence PL 534 containing the Hegg gas prospect on the BjarmelandPlatform in the Central Barents Sea has been submitted in May 2016.

The Rosapenna prospect is located in PL794, which was awarded in early 2015, and is 4 to 6km southwest of the Njord field. The reservoir target is Upper Jurassic Rogn and MelkeFormation sandstones that are interpreted to form a depositional ‘wedge’, and the trap isdownthrown along the western margin of the Frøya and ‘Njord’ High. The depositionalenvironment of the Oxfordian to Volgian Rogn sandstones is interpreted to be a Gilbert-typefan delta. A complex fault seal is envisaged comprising the Vingleia and the Kya Fault Zonesand their intersection. The trap and interpreted depositional geometric style is analogous toexploration potential currently under evaluation in the adjacent licence PL586, which containsthe recent Pil / Bue and Boomerang discoveries and their exploration satellites, and the sameinternal geometries in the Upper Jurassic succession are identified on seismic in a similarstructural setting. The resource assessment is a reasonable reflection of the uncertainty andis compatible with the risk assessment. The risk assessment at 18% is considered to berealistic and lateral fault seal is the highest risk component, especially where the Kya andVingleia Fault zones meet. The possible presence of a gas chimney at this location couldindicate leakage along the fault.

The Rungne prospect located 5 km north of Oseberg and about 20 km northwest of Brage is innew 2016 licence PL825. The prospect has a Lower-Middle Jurassic Oseberg sandstoneprimary objective and a Brent sandstone secondary target. The trap is a truncated tilted faultblock eroded in the Late Jurassic and Early Cretaceous. The main risk is due to thin top sealand fault seal along the main structure bounding fault. The licence has a drill or drop decisionin early 2018 and the next year work program includes 3D merge and reprocessing. Theresource size range is narrow with a high/low ratio of 2 and the risk has been increased to 30%by LR Senergy in view of the large low case resource volume.

4.2.3 Additional Leads and Prospects Under Evaluation

There are nineteen other prospects and leads that are likely to be dependent on either furtherevaluation and / or future drilling results of the high graded prospects described above. Someof these are likely to become drilling candidates in the medium to longer term.

The risk and resource volumes are summarised below and, where the most likely hydrocarbonphase is gas, the quoted volumes are oil equivalent:



Lead/Prospect Gross BestEstimate

Equity(%)


Tommeltott 61 25 15 34Aganju 33 20 7 17Bamsemums 236 40 94 10Dazzler East 204 20 41 13Dazzler South 100 20 20 10Dazzler West 84 20 17 13Rowlf West 47 20 9 16Rowlf East 40 20 8 16Slynge 150 50 75 12Sprettert 23 50 12 12Katie 38 40 15 16Gullaxy 41 20 8 28Kid 20 20 4 34Mjod 19 40 8 20Yoshi 14 30 4 48Luigi 14 30 4 17Hardhaus 83 20 17 10Myrsildre 42 20 8 10Gjedde 79 20 16 8

Norway Total (MMboe) 1,328 382

Table 4.5: Prospective Resources8 – Other Exploration (Norway)

The Tommeltott gas prospect (PL586) is a dip and fault closed structural trap with LowerJurassic Ile, Tofte, Tilje and Åre sandstone objectives that is adjacent to the Pil and Buediscoveries (see Section 3.2).

The Aganju prospect is in the same licence (PL627) as the Shango discovery and Oshunprospect.

There are three additional prospects in PL716 (Dazzler East, South and West) analogous toand adjacent to Dazzler Central (see Section 4.2.1) that would become high graded in the eventof a discovery.

The Slynge and Sprettert leads are located in licence PL792, which is a 2015 award with a drill-or-drop decision in February 2017. Despite the generally poor quality of the existing 2D seismicdata both leads are considered to be analogous to the recent Pil discovery located 12 km to thenortheast. Slynge is a three-way downthrown trap, requiring fault seal against the basementsequence on the Frøya High. The reservoir target could be Upper Jurassic Intra Spekksandstone (Rogn Formation) or an Intra Melke sandstone, or a combination of both. The targetinterval shows apparent thickening on 2D lines. Sprettert is located downdip of Slynge and isa low relief structural closure. The principal risk is trap definition though other key risks arereservoir quality at the greater burial depth compared to Pil, and fault seal. The LR Senergyrisk assessment reflects these concerns at this early evaluation stage.

8 Totals may not sum exactly due to rounding.



The Katie prospect in the new 2016 licence PL810 (Faroe) has an Upper Jurassic Ulasandstone target in a stratigraphic trap, about 8 km south of the Butch field. Seismic imagingimprovement will be required to mature this prospect and this will be the objective of the firstphase exploration work program, and the prospect risk has been increased to 16% to reflectthis concern.

The Gullaxy and Kid prospects are located 20 to 30 km NW of Butch field in new 2016 licencePL811 (Centrica). Both prospects are salt-induced structures on the Sørvestlandet High withUpper Jurassic Ula sandstone reservoir objectives. The main risk for both is charge/migrationand the initial work program is intended to address this risk prior to considering a wellcommitment.

The Mjod Lead is located in the same new licence P825 as Rungne prospect (Section 4.2.2).The Lead has Osebrg and Brent sandstone objectives in a fault block structure located on trendwith the Rungne structure. The trap is poorly imaged. The resource size range reported has anarrow range with a high/low ratio of 2 and the risk has been increased by LR Senergy in viewof the large low case resource volumes.

The Yoshi and Luigi prospects are located 7 km southeast of Smorbukk South and the samedistance west of Maria in the Halten Terrace in the Norwegian Sea. The licence is a new 2016award (PL836S) operated by Wintershall with a drill or drop decision in early 2018. Yoshi is atriangular faulted structure mapped at Top Lower Jurassic Tilje reservoir target horizon. Luigiis an Upper Jurassic Melke stratigraphic trap, analogous to the recent Pil and Bue discoveries,in the hanging wall immediately west of Yoshi. The principal risk for both prospects is fault sealeffectiveness due to the risk of sand to sand juxtaposition resulting in leakage through thebounding faults.

The Hardhaus, Myrsildre and Gjedde prospects are located in licence PL845 awarded in 2016which is on the Grønøy High south of the Vestfjorden Basin in the Norwegian Sea. The nearestfield is Norne 120 km to the southwest. Hardhaus and Myrsildre are fault-dependent trapsmapped on 2D seismic data with Lower Jurassic Åre sandstone reservoir objectives. TheGjedde Lead is a currently poorly defined high amplitude area corresponding to an isochorethickening just below the Base Cretaceous that is interpreted to correspond to an UpperJurassic Melke sandstone stratigraphic trap. Trap presence amd effectiveness and charge areall high risk for these prospects/leads. The P50 volume has been estimated using a lognormalplot as only the P90, mean and P10 were provided in the database. The licence specifies atwo year 3D or drop and a four year drill or drop decision.

4.3 Ireland Leads / Prospects

The Ireland exploration portfolio (Figure 1.8) comprises thirteen leads in three licencesacquired in 2015.

4.3.1 Leads Under EvaluationThere are thirteen leads in three Irish licences that will require further evaluation before theymature into nearer term drilling candidates.

The gross and net prospective resource volumes are summarised below:



Prospect Gross BestEstimate

Equity(%)


PL Lead A 39 100 39 9PL Lead B 16 100 16 13PL Lead C 21 100 21 6PL Lead D 15 100 15 13PL Lead E 8 100 8 13PL Lead F 19 100 19 13PL Lead G 14 100 14 13PL Lead H 11 100 11 13PL Lead I 20 100 20 6PL Lead J 17 100 17 6PL Lead K 14 100 14 8PL Lead L 14 100 14 5PL Lead M 12 100 12 7

Ireland Total (MMboe) 220 220

Table 4.6: Prospective Resources: Other Exploration (Ireland)

There are three licences in the North Celtic Sea Basin. Licence 14/1 is located in thesouthwestern part of the basin immediately adjoining the Barryroe field. Licence 14/2 is in thenorthern part of the basin on its southeastern flank, 25 km southwest of the Dragon fielddiscovery in the UKCS, and Licence 14/3 in the southwest.

The primary reservoir target in all three licences is Triassic sandstones. This is an under-explored play in the North Celtic Sea Basin, but is proven productive in the Slyne Basin (Corribfield), the East Irish Sea Basin (Morecambe field) and the Wessex Basin (Wytch Farm field).

Four tilted fault block structures are mapped in Licence 14/1, on generally poor quality 2Dseismic data. These potential closures are located proximal to a predicted Lower Jurassic(Lias) source rock kitchen area. The only Triassic well penetration in the licence is 48/30-1,which encountered dominantly mudstone and siltstone (Mercia Mudstone Group) with theSherwood sandstone possibly being faulted out. Well 56/20-1 located 98 km to the southwestof 48/30-1, encountered both Triassic Sherwood sandstone and ‘MMG’ sandstone with a grossthickness of 108 and 63 m respectively.

A trend of five fault block closures has been provisionally mapped in licence 14/2 on poor quality2D seismic data, at top Triassic level along an elongate ridge. The leads are about 15 kmsoutheast of the probable Lower Jurassic source rock kitchen. The nearest Triassic sandstonewell control is in 56/15-1 and 56/20-1, located 18 and 14 km respectively to the southwest.

Three tilted fault block leads are tentatively mapped in Licence 14/3 on the generally poorquality 2D seismic data. The nearest Triassic sandstone well control is in UKCS 103/2-1,located about 30 km to the east. The well encountered a gross sandstone interval of 265 mand petrophysical analysis indicates 113 m of net reservoir with an average net porosity of 13%.

The main risks for all leads are reservoir presence and trap integrity, and the reprocessing ofseismic data is planned in order to improve structure definition on each licence.



5 Economic EvaluationEconomic analysis uses NPV calculations and was carried out on producing and fields underdevelopment, to determine reserves for cumulative production to the economic limit based onthe proposed plan for the Proved (1P), Proved plus Probable (2P) and Proved plus Probableplus Possible (3P) cases.

5.1 Economic Inputs

The NPV calculations are based on the current fiscal terms for UK and Norway. The portfoliowas valued using a MS Excel based economic model for UK and Norway. The UK modelcomprises UK ring fence Corporation Tax of 30% of profits and Supplementary Charge at 20%of profits (as of 1st January 2015). Capital allowances are available at 100% in the first year.All UK assets are exempt from Petroleum Revenue Tax (PRT) and Royalty. The Norway modelcomprises of Corporate Tax of 27% and Special Tax of 51%. Special Tax includes an uplift of22% of investment for 4 years. Depreciation is based on six year linear from the year ofinvestment. CO2 tax has been included with the Opex totals and is assumed as deductible fortax purposes.

The values are inclusive of estimated UK tax losses and Norwegian undepreciated Capex andunused uplift balances brought forward at 1st January 2016.

5.1.1 Production Profiles

Economic analysis was carried out for the 1P, 2P and 3P reserves for the producing fields andfields under development. These include the UK / Norway cross border Blane and Enoch oilfields; UK Southern North Sea Schooner, Ketch, Orca and Topaz gas fields; UK Atlantic MarginEast Foinaven field: and Norwegian fields, Njord, Hyme, Snilehorn, Pil, Brage, Butch,Ringhorne East, and Jotun.

The gross gas and liquids production profiles for each field are provided in Appendix 2.

5.1.2 Capital Costs and Operating Costs

LR Senergy has reviewed the development plans for the producing fields and the undevelopeddiscoveries. The plans and associated costs were mainly based on the operators budgetstogether with Faroe input. Operating costs were provided by Faroe for the producing fields andare based on the operator budgets and adjusted for LR Senergy profiles, for the 1P, 2P and 3Pcases.

Where appropriate, the costs were modified prior to undertaking the economic analysis. It wasnot part of the scope of this study to review these costs in detail. The gross capital andoperating costs for the reserves and resources are provided in Appendix 2.

5.1.3 Pricing

The economic assumptions used in this evaluation are as follows:

Assumed 2016 costs escalated at 2.0% per annum.

Exchange rate of US$1.50/GBP, US$1.33/Euro and US$8.30/NOK.



Currently applicable tax regimes for the UK and Norway.

CO2 tax has not been applied and is assumed to be included in the operating costs.

10% discount rate with mid-year discounting to 1st January 2016.

Oil price assumption is $55/bbl (2016), $63/bbl (2017), $70/bbl (2018), $75/bbl (2019) and from2020 inflated at 2.5% pa.

Gas price assumption is $6.00/Mcf (2016), $6.75/Mcf (2017), $6.92/Mcf (2018), $7.09/Mcf(2019), and from 2020 inflated at 2.5% pa. While there may be very small crude qualitydifferentials to Brent between the assets, on an aggregate basis it has been assumed that allproduced crude oil is sold at Brent. NGLs are assumed to be sold at an average of 75% ofBrent.

Gas is sold on a spot basis, with Norwegian gas mainly sold at the Dutch TTF trading hub inEuros and UK gas sold in Pounds Sterling at the UK NBP hub. There is generally only a smalldifference in the hub prices, so for the purposes of this evaluation an average price in USD/Mscfhas been used for both Norwegian and UK gas, assuming a calorific value for dry gas of 1,000btu/scf.

5.2 Economic Results

Economic analysis was carried out on producing fields and fields under development todetermine reserves based on cumulative production to the economic limit based on theproposed plan for the 1P, 2P and 3P cases using the base case assumptions detailed in Section5.1. The NPV calculations are based on the current fiscal terms for UK and Norway, and includethe respective UK and Norwegian brought forward tax positions allocated or pro-rated to therelevant assets. The UK opening tax loss position was taken as £54.0 MM net to Faroe, andthe opening values of undepreciated Capex and unused Capex uplift for Norway were NOK570.8 MM and NOK 62 MM respectively net to Faroe. The brought forward tax positions wereprovided by Faroe. Faroe has a loss carried forward of special tax allowance, estimated atNOK 328 MM at year end 2015. This has been incorporated in the economics and this losscan be utilised once Faroe comes in to a full tax paying position in Norway, which is expectedonce Butch, Njord / Hyme, Snilehorn and Pil come on stream.

.NPV10 (£MM) for Reserves Net to Faroe - UK


Proved, Probable& Possible

Schooner 0.0 1.6 6.6Ketch 1.8 5.8 9.3East Foinaven 1.5 2.3 4.3Blane 22.3 40.3 58.9Orca 0.0 0.2 0.3Topaz 0.0 0.0 0.0Total 25.6 50.1 79.4

Table 5.1: Reserves NPV10 Net (UK Fields)



NPV10 (£MM) for Reserves Net to Faroe - Norway


Proved, Probable& Possible

Enoch 0.0 0.4 1.2Njord 0.0 11.1 27.0Hyme 13.0 17.2 19.3Brage 7.5 27.2 43.5Ringhorne 8.7 13.8 18.4Jotun 0.0 0.0 0.0Snilehorn 7.3 13.3 19.5Butch 0.0 8.4 15.4Pil 5.8 50.5 99.5Total 42.3 141.8 243.9

Table 5.2: Reserves NPV10 (Norway Fields)

Sensitivity analysis to variable discount rate and oil and gas price has been assessed for theproved plus probable reserves and is summarised in the table below.

NPV8 NPV10 NPV12

UK 54.0 50.1 46.6

Norway 155.5 141.8 118.4

Total (£MM) 209.5 192.0 165.0

-VE20% Base Price +VE20%

UK 34.7 50.1 68.4

Norway 94.2 141.8 187.1

Total (£MM) 128.9 192.0 255.5

Table 5.3: Proved Plus Probable Reserves Economic Sensitivity Analysis



6 References1. “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve

Information”, published by the Society of Petroleum Engineers (SPE) in June 2001,SPE website (www.spe.org).

2. “Standards Pertaining to the Estimating and Auditing of Oil and Gas ReserveInformation Approved by SPE Boards June 2001 - Revision as of February 19, 2007”,published by the Society of Petroleum Engineers (SPE); SPE website (www.spe.org).

3. “Petroleum Resources Management System”, Sponsored by SPE, AAPG, WPC,SPEE, published 2007; SPE website (www.spe.org).

4. “Guidelines for Application of the Petroleum Resources Management System”Sponsored by SPE, AAPG, WPC, SPEE, published 2011; SPE website (www.spe.org).

5. “Petroleum Reserves Definitions” approved by SPE and WPC March 1997; SPEwebsite (www.spe.org).

6. Note for Mining and Oil & Gas Companies, London Stock Exchange, AIM Guidelines,June 2009.

7. European Securities & Markets Authority (ESMA), Commission Regulation (EC) No809/2004, Guidelines for Implementing the Prospectus Directive, 2013.

8. UK Department of Energy and Climate Change (DECC) website:www.gov.uk/browse/business/licences/oil-and-gas-licensing.

9. Norwegian Petroleum Directorate (NPD) website: www.npd.no/en.



Appendix 1: Evaluation MethodologyLR Senergy was requested to provide an independent assessment of the recoverablehydrocarbons expected for each asset and an economic evaluation of the reserves andresources. Standard geological and engineering techniques accepted by the petroleumindustry were used in estimating recoverable hydrocarbons. These techniques rely onengineering and geo-scientific interpretation and judgement; hence the reserves and resourcesincluded in this evaluation are estimates only and should not be construed to be exactquantities. It should be recognised that such estimates may increase or decrease in future ifthere are changes to the technical interpretation, economic criteria or regulatory requirements.

The asset evaluations have been conducted in accordance with the Petroleum ResourcesManagement System (2007 and clarified in 2011) prepared by the Oil and Gas ReservesCommittee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsoredby the World Petroleum Council (WPC), the American Association of Petroleum Geologists(AAPG) and the Society of Petroleum Evaluation Engineers (SPEE).

Where noted gas prospective resources have been converted to oil equivalent using 6.0 Mscf= 1 boe.

Reserves Estimation

The reserves for producing fields were verified through Decline Curve Analysis, or otherindustry standard practices. This report contains descriptions of each asset and the method(s)used in calculating reserves. LR Senergy has reported gross and net reserves. For theavoidance of doubt this means recoverable volumes with economic cut off as indicated by theeconomic analysis. Application of an economic test is required for full compatibility with theReserves definitions, which, depending on the economic assumptions used, may result inReserves being less than the Technically Recoverable Volumes.

Reserves are categorised as ‘Developed’ and ‘Undeveloped’ and these are combined in the LRSenergy production profiles and are summed in the reserves reporting in accordance withLondon Stock Exchange Alternative Investments Market (LSE AIM) reporting format.

The changes to the PRMS guidelines for reserves and contingent resource reporting that wereclarified in the 2011 supplementary guidance document (References 4 and 5) mean thatadditional resource potential often previously reported in the 3P reserves are now moreappropriately reflected as Contingent Resources.

When assigning reserves to projects or incremental projects LR Senergy has followed PRMSguidance (References 4 and 5). Relevant extracts are quoted as follows. “Discoveredrecoverable volumes (Contingent Resources) may be considered commercially producible, andthus Reserves, if the entity claiming commerciality has demonstrated firm intention to proceedwith development and such intention is based upon all of the following criteria:

Evidence to support a reasonable timetable for development.

A reasonable assessment of the future economics of such development projectsmeeting defined investment and operating criteria:



A reasonable expectation that there will be a market for all or at least the expectedsales quantities of production required to justify development.

Evidence that the necessary production and transportation facilities are available orcan be made available:

Evidence that legal, contractual, environmental and other social and economicconcerns will allow for the actual implementation of the recovery project beingevaluated.

In order to be included in the Reserves class, a project must be sufficiently defined to establishits commercial viability. There must be a reasonable expectation that all required internal andexternal approvals will be forthcoming, and there is evidence of firm intention to proceed withdevelopment within a reasonable time frame. A reasonable time frame for the initiation ofdevelopment depends on the specific circumstances and varies according to the scope of theproject. While 5 years is recommended as a benchmark, a longer time frame could be appliedwhere, for example, development of economic projects are deferred at the option of theproducer for, among other things, market-related reasons, or to meet contractual or strategicobjectives. In all cases, the justification for classification as Reserves should be clearlydocumented”.

The PRMS guidance goes on to note that “Incremental projects are designed to increaserecovery efficiency and/or to accelerate production through making changes to wells orfacilities, infill drilling, or improved recovery. Such projects should be classified according tothe same criteria as initial projects. Related incremental quantities are similarly categorised oncertainty of recovery. The projected increased recovery can be included in estimated Reservesif the degree of commitment is such that the project will be developed and placed on productionwithin a reasonable timeframe.”

“There may be circumstances in which the project meets criteria to be classified as Reservesusing the forecast case but does not meet the external criteria for Proved Reserves. In thesespecific circumstances, the entity may record 2P and 3P estimates without separately recordingProved. As costs are incurred and development proceeds, the low estimate may eventuallysatisfy external requirements, and Proved Reserves can then be assigned”.

Historically, there has been overlap (and hence ambiguity) between the distinct characteristicsof project maturity and uncertainty in recovery, when assigning reserves categories. LRSenergy has avoided this ambiguity by assessing whether infill wells, for example, meet thecommerciality criteria described above. When an infill wells inclusion in the project isconsidered ‘reasonably certain’ then the associated undeveloped reserves are categorisedaccordingly. In some cases only 2P and/or 3P reserves are assigned by LR Senergy for aspecific infill well according to our assessment of the uncertainty associated with thecommercial criteria noted above and the technical evaluation and the data provided.

Some incremental projects will not currently meet all criteria noted above for reservesclassification. In the past these projects have sometimes been included in the 3P reservescategory. The clarifications in the 2011 PRMS supplementary guidance document emphasisethat this is not appropriate and that such incremental projects should be categorised asContingent Resources.



In this report, reserves are allocated beyond current licence periods. PRMS guidelines notethat “Reserves should not be claimed for those volumes that will be produced beyond theending date of the current agreement unless there is reasonable expectation that an extension,a renewal, or a new contract will be granted. Such reasonable expectation may be based onthe historical treatment of similar agreements by the license-issuing jurisdiction”. The 2011guidelines go on to note that: “If the contract contained provisions for extension and thelikelihood of extension was judged to be reasonably certain, additional reserves would likely berecognized for the length of the extension period, provided requirements for project commitmentand funding were satisfied”. LR Senergy consider that there is a reasonable expectation andreasonable certainty of licence extension in the UK and Norway.

Contingent Resource Estimation and Risk Factor

Contingent resources for incremental projects in fields and for un-developed discoveries wereverified through review of operator studies and by comparison with analogue fields whereavailable. The quoted low, best and high volume estimates are either deterministic orprobabilistic estimates as described for each asset in the text. If deterministic estimates areused this is noted in the asset description. For probabilistic estimates the low is P90 (90%probability), best estimate is the P50, and high is P10. LR Senergy has generally assessed, andwhere appropriate modified, the operator’s estimates of resources and may refer to the Clientestimates where relevant and especially if there are differences between the two evaluations.

The contingent resource volumes quoted are technically recoverable resources and are notsubject to economic cut off.

An assessment has been made of the risk factor which is defined as the chance of commercialdevelopment. The definition follows LSE AIM guidelines. The risk factor for contingentresources involves the assessment of a range of technical and commercial considerations. Foreach project LR Senergy has proposed an overall probability of a commercial developmentoccurring within the specified time frame used in the economic evaluation. A single estimatedpercentage value is quoted. This assessment accounts for the degree of confidence in thesubsurface definition and whether appraisal is required, commerciality and infra-structureconsiderations including ullage, partner alignment and government and regulatory status. Abrief description of each of these factors is included in each asset description in order to explainthe choice of risk factor value.

The contingent resource projects are classified as eith Development Pending or DevelopmentOn Hold in alignment with PRMS guidelines (References 4, 5).

It should be noted that there is no single method of contingent resource and risk assessmentin use within the industry and different operators employ different methodologies.

Prospective Resource Estimation and Risk Factor

The quoted low, best and high volume estimates are normally probabilistic estimates but canbe deterministic, and this is usually stated for each asset in the text. For probabilistic estimatesthe low is P90 (90% probability), best estimate is the P50 value, and high is P10. However theremay be instances where the best estimate volume is the mean value and this will be stated inthe text. LR Senergy has generally assessed, and where appropriate modified or independentlyasessed, the operator’s estimates of resources and risk and also refer to the Client estimateswhere relevant and especially if there are differences between the two evaluations.



It should be noted that there is no single method of prospect resource and risk assessment inuse within the industry and different operators employ different methodologies.

Deterministic single point resource size estimates are used by some operators and give ageneral indication of the prospects potential. However this method will not normally capturethe full range of uncertainty and consequently most operators favour using a probabilistic orMonte Carlo approach. This will often capture the uncertainty, but this is not always the caseas the results are dependent on the choice of input values especially the low case inputparameters and the distribution type used in the input ranges. In many cases, the low end ofthe distribution is removed or “clipped” and this has the effect of increasing the best estimatevolume (P50) and the mean. This is not always considered to be unreasonable provided thatthe assigned risk factor is appropriate to the choice of low case inputs and the resource sizedistribution, and is not just the chance to find a sufficient volume to test.

The risk factor for prospective resources is the chance of discovery and is usually the productof four prospect elements; trap presence (or structure geometry), reservoir (presence andquality), seal integrity (vertical and lateral) and charge (source and migration). There is asecond risk component which is the ‘chance of development’ in the event of a discovery beingmade.

The definition of ‘chance of discovery’ is handled differently by different operators. In somecases it is the chance to find the low case volume or greater and in others it is the chance tofind a sufficient volume of hydrocarbons to test to the surface. This distinction can be extremelyimportant as use of the former definition ensures that the risk factor is appropriate to theresource size distribution whereas the latter can result in a disconnection between the risk andresource estimates and invalidate the calculation of risked volumes. LR Senergy assesswhether the risk is appropriate to the resource size distribution with specific reference to thelow case volume.

Prospect Portfolio Evaluation Method

The large size of the Faroe prospect portfolio means that LR Senergy has not prepared a fullyindependent resource and risk assessment for each prospect. The evaluations prepared forthe partnership by the licence operators have been assessed and modified by LR Senergyusing a portfolio evaluation methodology. Independent assessments have been prepared whenconsidered appropriate and this is noted in the prospect description sections of this report. Thelevel of assessment by LR Senergy has been more detailed for the Near Term prospects andless detailed for the Medium Term and Other prospects.

LR Senergy has reviewed the data for each prospect and where necessary made alterations.The data quality, resource calculation methodology and the high/low resource size ratio havebeen reviewed in order to assess whether the resource calculation is, in LR Senergy’s opinion,capturing the full range of uncertainty. Low ratios indicate low uncertainty and can imply a “lowend clipped” distribution that may require a compensating risk adjestment.

The ‘shape’ of the resource distribution is also considered in order to identify ‘skewed’distributions. There can be good technical reasons for a best estimate to be skewed towardsthe high case size but this can also be indicative of an optimistic assessment. In someinstances, skewed distributions have been recomputed by LR Senergy using the low and highcase values to generate a P50 value on a lognormal scale. These cases are noted andexplained in the relevant asset description sections of the report.



Economic Analysis Method and Assumptions

Economic analysis is based on the current fiscal terms for UK and Norway. The portfolio wasvalued using aMS Excel based economic model for UK and Norway. The UK model comprisesof UK ring fence Corporation Tax of 30% of profits and Supplementary Charge at 32% of profits.Capital allowances are available at 100% in the first year. All UK assets are exempt fromPetroleum Revenue Tax (PRT) and Royalty. The Norway model comprises of Corporate Taxof 28% and Special Tax of 50%. Special Tax includes an uplift of 30% of investment for 4years. Depreciation is based on six year linear from year of investment. CO2 tax has beenincluded with the opex totals and is assumed as deductible for tax purposes.

The NPV calculations were made for the 1P, 2P and 3P reserves for the producing fields andfields under development. The development plans and costs for the producing fields and theundeveloped fields were mainly based on the operator’s budget and Client input. Operatingcosts were provided by Client for the producing fields and are based on the operator budgetsand adjusted for LR Senergy profiles for the 1P, 2P and 3P cases.

The recoverable volumes are reported to a date estimated where cessation of production wouldoccur as a result of economic conditions, these conditions are dependent upon the productionlevels at that time, the operating costs and tariffs assumed and the oil price achieved for theproduction at that time. It is assumed that if a licence is required to be extended that this willbe granted by the relevant authorities.

The capital, operating and abandonment cost assumptions for the economic inputs for theproducing fields and those under development, were obtained from operator information andClient. It was not part of the scope of this study to review these costs in detail.



Appendix 2: Reserves & Resources Economic InputsThe following tables provide the production profile, operating and capital cost inputs to the economic analysis for UK Reserves.

Blane Liquids Gas Capex Opex Blane Liquids Gas Capex Opex Blane Liquids Gas Capex Opexkbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 1.8 0.6 0.0 13.1 2016 2.8 0.9 0.0 14.0 2016 3.4 1.1 0.0 14.5

2017 2.7 0.9 72.8 16.1 2017 3.4 1.1 72.8 16.8 2017 4.3 1.4 72.8 17.6

2018 2.7 0.9 0.0 5.2 2018 3.8 1.3 0.0 6.3 2018 5.0 1.7 0.0 7.4

2019 2.1 0.7 0.0 4.6 2019 3.3 1.1 0.0 5.8 2019 4.5 1.5 0.0 7.0

2020 1.6 0.5 0.0 4.3 2020 2.8 0.9 0.0 5.5 2020 4.1 1.3 0.0 6.7

2021 1.3 0.4 0.0 4.0 2021 2.5 0.8 0.0 5.2 2021 3.7 1.2 0.0 6.5

2022 1.0 0.3 0.0 3.8 2022 2.2 0.7 0.0 5.0 2022 3.4 1.1 0.0 6.4

2023 0.8 0.3 0.0 3.7 2023 1.9 0.6 0.0 4.9 2023 3.2 1.1 0.0 6.2

2024 0.7 0.2 0.0 3.6 2024 1.8 0.6 0.0 4.8 2024 3.0 1.0 0.0 6.1

2025 0.5 0.2 0.0 3.5 2025 1.6 0.5 0.0 4.7 2025 2.8 0.9 0.0 6.1

2026 0.4 0.1 0.0 3.5 2026 1.5 0.5 0.0 4.6 2026 2.7 0.9 0.0 6.0

2027 0.4 0.1 0.0 3.5 2027 1.3 0.4 0.0 4.6 2027 2.5 0.8 0.0 6.0

2028 0.3 0.1 0.0 3.5 2028 1.2 0.4 0.0 4.6 2028 2.4 0.8 0.0 5.9

2029 0.3 0.1 0.0 3.5 2029 1.1 0.4 0.0 4.5 2029 2.3 0.8 0.0 5.9

2030 0.0 0.0 31.2 0.0 2030 0.0 0.0 31.2 0.0 2030 0.2 0.1 0.0 3.5

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 31.8 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0

Total 6.1 2.0 103.9 76.0 Total 11.4 3.8 103.9 91.3 Total 17.4 5.7 104.6 112.0

Proved Proved+Probable Proved+Probable+Possible



Schooner Liquids Gas Capex Opex Schooner Liquids Gas Capex Opex Schooner Liquids Gas Capex Opexkbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.1 7.7 0.0 13.8 2016 0.1 12.0 0.0 16.1 2016 0.1 15.2 0.0 17.7

2017 0.0 6.2 0.0 10.0 2017 0.1 11.4 0.0 12.4 2017 0.1 14.5 0.0 13.8

2018 0.0 0.0 43.3 0.0 2018 0.1 7.7 0.0 12.0 2018 0.1 12.0 0.0 14.6

2019 0.0 0.0 0.0 0.0 2019 0.0 0.0 44.1 0.0 2019 0.1 10.5 0.0 15.3

2020 0.0 0.0 0.0 0.0 2020 0.0 0.0 0.0 0.0 2020 0.1 9.4 0.0 16.0

2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 45.9 0.0

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Ketch Liquids Gas Capex Opex Ketch Liquids Gas Capex Opex Ketch Liquids Gas Capex Opexkbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.1 10.2 0.0 17.3 2016 0.1 13.0 0.0 18.3 2016 0.2 15.2 0.0 19.1

2017 0.1 8.1 0.0 11.4 2017 0.1 11.1 0.0 12.5 2017 0.1 13.5 0.0 13.4

2018 0.1 6.6 0.0 12.1 2018 0.1 9.7 0.0 13.8 2018 0.1 12.3 0.0 15.1

2019 0.0 0.0 30.5 0.0 2019 0.1 8.6 0.0 14.6 2019 0.1 11.2 0.0 16.4

2020 0.0 0.0 0.0 0.0 2020 0.1 7.7 0.0 15.3 2020 0.1 10.4 0.0 17.5

2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 31.8 0.0 2021 0.0 0.0 31.8 0.0

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Orca Liquids Gas Capex Opex Orca Liquids Gas Capex Opex Orca Liquids Gas Capex Opexkbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.0 1.2 0.9 9.4 2016 0.0 1.6 0.9 9.4 2016 0.0 3.8 0.9 9.4

2017 0.0 0.0 0.0 0.0 2017 0.0 0.0 10.2 0.0 2017 0.0 0.0 10.2 0.0

2018 0.0 0.0 0.0 0.0 2018 0.0 0.0 0.0 0.0 2018 0.0 0.0 0.0 0.0

2019 0.0 0.0 0.0 0.0 2019 0.0 0.0 0.0 0.0 2019 0.0 0.0 0.0 0.0

2020 0.0 0.0 0.0 0.0 2020 0.0 0.0 0.0 0.0 2020 0.0 0.0 0.0 0.0

2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 0.0 0.0

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Topaz Liquids Gas Capex Opex Topaz Liquids Gas Capex Opex Topaz Liquids Gas Capex Opexkbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.0 1.0 0.0 2.3 2016 0.0 1.2 0.0 2.0 2016 0.0 1.6 0.0 2.5

2017 0.0 0.8 0.0 1.3 2017 0.0 1.0 0.0 1.4 2017 0.0 1.4 0.0 1.6

2018 0.0 0.7 0.0 1.3 2018 0.0 0.9 0.0 1.4 2018 0.0 1.2 0.0 1.6

2019 0.0 0.0 11.3 0.0 2019 0.0 0.8 0.0 1.4 2019 0.0 1.1 0.0 1.6

2020 0.0 0.0 0.0 0.0 2020 0.0 0.7 0.0 1.4 2020 0.0 1.0 0.0 1.6

2021 0.0 0.0 0.0 0.0 2021 0.0 0.6 0.0 1.3 2021 0.0 0.9 0.0 1.6

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 12.0 0.0 2022 0.0 0.9 0.0 1.6

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.0 0.8 0.0 1.6

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.0 0.8 0.0 1.6

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.7 0.0 1.6

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.7 0.0 1.6

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 13.2 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





The following tables provide the production profile, operating and capital cost inputs to the economic analysis for Norway Reserves

EastFoinaven

Liquids Gas Capex Opex EastFoinaven

Liquids Gas Capex Opex EastFoinaven

Liquids Gas Capex Opex

kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM kbpd MMscf/d £MM £MM2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 1.5 0.0 2.1 9.6 2016 1.9 0.0 2.1 12.1 2016 2.3 0.0 2.1 14.6

2017 1.4 0.0 0.0 7.3 2017 1.7 0.0 0.0 9.0 2017 2.1 0.0 0.0 10.7

2018 0.6 0.0 0.0 3.6 2018 1.4 0.0 0.0 7.9 2018 1.9 0.0 0.0 10.6

2019 1.0 0.0 0.0 5.9 2019 1.4 0.0 0.0 8.7 2019 2.0 0.0 0.0 12.4

2020 0.8 0.0 0.0 5.4 2020 1.3 0.0 0.0 8.3 2020 1.9 0.0 0.0 12.2

2021 0.0 0.0 79.6 0.0 2021 0.0 0.0 79.6 0.0 2021 1.8 0.0 0.0 12.1

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0 2022 1.7 0.0 0.0 12.1

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 82.8 0.0

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Njord Liquids Gas Capex Opex Njord Liquids Gas Capex Opex Njord Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 1.1 3.4 2140.1 709.8 2016 2.3 8.4 2140.1 709.8 2016 4.0 16.3 2140.1 709.8

2017 0.0 0.0 2837.7 250.7 2017 0.0 0.0 2837.7 250.7 2017 0.0 0.0 2837.7 250.7

2018 0.0 0.0 4007.2 275.9 2018 0.0 0.0 4007.2 275.9 2018 0.0 0.0 4007.2 275.9

2019 2.6 19.5 1406.6 602.8 2019 4.4 30.4 1406.6 675.4 2019 6.4 40.6 1406.6 749.2

2020 16.0 111.7 844.6 1884.4 2020 25.9 172.4 844.6 2299.2 2020 37.3 232.6 844.6 2738.4

2021 16.3 117.1 1005.1 2142.8 2021 26.8 182.6 1005.1 2593.9 2021 39.1 251.0 1005.1 3091.8

2022 13.7 102.2 498.0 1817.0 2022 23.2 164.3 966.6 2247.2 2022 34.9 233.5 966.6 2746.5

2023 10.8 81.0 119.5 1559.7 2023 18.9 134.7 119.5 1873.8 2023 29.2 196.5 119.5 2250.0

2024 8.4 62.4 121.9 1138.1 2024 15.1 107.0 121.9 1243.9 2024 23.6 158.6 121.9 1371.8

2025 5.6 45.7 124.3 1138.3 2025 10.7 81.4 124.3 1222.5 2025 17.1 122.8 124.3 1323.8

2026 3.8 30.5 126.8 863.8 2026 7.7 57.7 126.8 929.6 2026 12.3 87.2 126.8 1004.0

2027 2.9 22.7 0.0 733.7 2027 6.2 45.8 0.0 790.8 2027 10.1 70.2 0.0 854.1

2028 2.1 17.5 0.0 664.2 2028 4.8 36.7 0.0 712.1 2028 7.9 56.5 0.0 763.6

2029 0.0 0.0 2008.4 0.0 2029 2.7 22.7 0.0 723.5 2029 4.4 34.2 0.0 753.4

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 2048.6 0.0 2030 1.7 12.0 0.0 742.1

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 2089.5 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Hyme Liquids Gas Capex Opex Hyme Liquids Gas Capex Opex Hyme Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 3.0 2.1 99.9 134.3 2016 3.4 2.5 99.9 135.4 2016 4.0 3.1 99.9 136.5

2017 0.0 0.0 113.5 22.3 2017 0.0 0.0 113.5 22.3 2017 0.0 0.0 113.5 22.3

2018 0.0 0.0 111.5 28.1 2018 0.0 0.0 111.5 28.1 2018 0.0 0.0 111.5 28.1

2019 2.5 1.9 38.6 58.4 2019 3.2 2.4 38.6 59.8 2019 3.5 2.5 38.6 60.0

2020 8.2 5.8 0.0 236.2 2020 10.6 7.7 0.0 241.6 2020 11.1 8.1 0.0 241.7

2021 4.7 3.6 0.0 164.3 2021 7.8 5.9 0.0 170.8 2021 9.2 7.0 0.0 173.2

2022 2.8 2.0 0.0 143.3 2022 5.9 4.4 0.0 150.3 2022 7.2 5.3 0.0 152.3

2023 1.6 1.3 0.0 135.4 2023 4.6 3.3 0.0 141.5 2023 5.8 4.0 0.0 143.1

2024 0.9 0.7 0.0 131.6 2024 3.7 2.6 0.0 137.6 2024 4.9 3.5 0.0 139.9

2025 0.5 0.3 0.0 144.7 2025 3.0 2.0 0.0 150.1 2025 4.2 3.1 0.0 153.1

2026 0.0 0.0 904.2 0.0 2026 2.5 1.5 0.0 127.7 2026 3.6 2.3 0.0 130.0

2027 0.0 0.0 0.0 0.0 2027 2.1 1.1 0.0 118.2 2027 3.1 1.8 0.0 120.0

2028 0.0 0.0 0.0 0.0 2028 1.8 0.5 0.0 115.1 2028 2.7 1.0 0.0 116.4

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 959.6 0.0 2029 2.4 0.9 0.0 118.4

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 978.8 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Snilehorn Liquids Gas Capex Opex Snilehorn Liquids Gas Capex Opex Snilehorn Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.0 0.0 0.0 0.0 2016 0.0 0.0 0.0 0.0 2016 0.0 0.0 0.0 0.0

2017 0.0 0.0 175.8 0.0 2017 0.0 0.0 175.8 0.0 2017 0.0 0.0 175.3 0.0

2018 0.0 0.0 808.6 25.5 2018 0.0 0.0 808.6 25.5 2018 0.0 0.0 808.6 25.5

2019 0.0 0.0 1746.0 37.9 2019 0.0 0.0 1746.0 37.9 2019 0.0 0.0 1746.0 37.9

2020 0.0 0.0 1859.3 135.8 2020 0.0 0.0 1859.3 135.8 2020 0.0 0.0 1859.3 135.8

2021 20.9 26.6 0.0 474.4 2021 25.4 32.9 0.0 544.7 2021 29.1 37.8 0.0 600.6

2022 14.0 17.3 0.0 362.9 2022 19.2 24.1 0.0 442.5 2022 23.4 29.8 0.0 508.0

2023 10.2 12.7 0.0 312.8 2023 14.2 17.4 0.0 371.8 2023 17.8 21.9 0.0 427.4

2024 8.3 11.3 0.0 295.8 2024 12.5 15.6 0.0 354.7 2024 16.2 19.4 0.0 407.2

2025 9.1 14.9 0.0 330.8 2025 13.6 20.9 792.3 405.6 2025 18.1 24.9 792.3 465.7

2026 5.8 10.5 0.0 281.9 2026 9.2 16.9 0.0 351.8 2026 12.9 21.6 0.0 412.5

2027 5.3 11.5 0.0 290.2 2027 8.1 17.0 0.0 350.3 2027 11.1 22.0 0.0 390.5

2028 4.6 9.5 0.0 268.3 2028 7.4 14.4 0.0 322.1 2028 10.6 19.3 0.0 328.9

2029 4.2 6.0 0.0 233.9 2029 6.7 10.2 0.0 270.4 2029 9.6 15.0 0.0 311.8

2030 4.4 5.3 0.0 237.5 2030 6.8 9.2 0.0 272.9 2030 9.5 13.7 0.0 312.8

2031 3.7 3.9 0.0 230.6 2031 6.1 7.7 0.0 266.0 2031 8.6 11.4 0.0 301.9

2032 2.7 3.1 0.0 224.0 2032 5.2 6.5 0.0 259.1 2032 7.6 10.3 0.0 295.1

2033 1.8 2.1 0.0 216.5 2033 4.4 5.4 0.0 252.8 2033 6.8 8.8 0.0 288.1

2034 1.6 1.8 0.0 217.1 2034 3.8 4.6 0.0 248.8 2034 5.9 7.8 0.0 281.3

2035 0.0 0.0 1439.9 0.0 2035 0.0 0.0 1439.9 0.0 2035 0.0 0.0 1439.9 0.0

2036 0.0 0.0 0.0 0.0 2036 0.0 0.0 0.0 0.0 2036 0.0 0.0 0.0 0.0





Brage Liquids Gas Capex Opex Brage Liquids Gas Capex Opex Brage Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 7.5 2.9 337.1 1294.9 2016 10.4 6.1 337.1 1310.8 2016 13.6 10.0 337.1 1328.9

2017 5.3 1.3 831.5 994.7 2017 8.3 4.6 831.5 1011.2 2017 10.1 8.2 831.5 1025.8

2018 5.2 8.1 1098.6 1004.8 2018 10.7 18.7 1098.6 1048.8 2018 15.1 38.9 1098.6 1118.0

2019 8.6 10.6 543.3 974.5 2019 14.6 21.9 543.3 1022.9 2019 21.0 46.9 543.3 1112.2

2020 8.3 11.6 0.0 956.8 2020 11.6 19.3 0.0 988.3 2020 14.0 35.9 0.0 1044.1

2021 5.1 7.0 0.0 953.6 2021 8.6 14.3 0.0 985.1 2021 11.4 30.2 0.0 1040.9

2022 3.9 5.1 0.0 729.4 2022 7.3 12.2 0.0 760.4 2022 10.1 27.1 0.0 814.3

2023 2.9 2.2 0.0 731.8 2023 5.8 5.0 0.0 748.6 2023 8.2 16.6 0.0 792.2

2024 0.0 0.0 2785.9 0.0 2024 5.0 3.2 0.0 755.7 2024 7.3 13.3 0.0 794.7

2025 0.0 0.0 0.0 0.0 2025 4.2 2.0 0.0 764.3 2025 6.4 9.7 0.0 796.1

2026 0.0 0.0 0.0 0.0 2026 3.1 1.1 0.0 773.6 2026 4.7 5.4 0.0 792.6

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 2956.4 0.0 2027 3.6 3.6 0.0 799.2

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 3.4 1.8 0.0 808.3

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 3.3 1.5 0.0 822.6

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 3137.4 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Ringhorne Liquids Gas Capex Opex Ringhorne Liquids Gas Capex Opex Ringhorne Liquids Gas Capex Opex

kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 8.8 1.6 3.1 203.8 2016 10.3 1.9 3.1 218.2 2016 11.3 2.1 3.1 229.1

2017 7.2 1.2 3.2 203.3 2017 8.7 1.5 3.2 218.8 2017 10.1 1.7 3.2 233.5

2018 5.9 1.3 442.9 212.2 2018 7.5 1.7 442.9 229.2 2018 9.0 2.0 443.0 245.0

2019 6.3 1.4 451.8 233.6 2019 8.4 1.9 451.8 256.1 2019 10.1 2.3 451.9 274.8

2020 6.2 1.3 0.0 209.6 2020 8.8 1.9 0.0 237.8 2020 10.8 2.3 0.0 260.9

2021 4.8 0.9 0.0 198.0 2021 7.5 1.4 0.0 227.7 2021 9.7 1.9 0.0 252.9

2022 3.8 0.6 0.0 190.0 2022 6.5 1.1 0.0 220.7 2022 8.8 1.5 0.0 247.2

2023 3.0 0.4 0.0 184.5 2023 5.7 0.8 0.0 215.7 2023 8.1 1.1 0.0 243.2

2024 2.4 0.3 0.0 181.2 2024 5.1 0.7 0.0 212.8 2024 7.5 1.0 0.0 241.0

2025 2.0 0.3 0.0 179.3 2025 4.6 0.6 0.0 210.9 2025 7.0 0.9 0.0 239.7

2026 0.0 0.0 134.5 0.0 2026 4.2 0.6 0.0 209.9 2026 6.6 0.9 0.0 239.1

2027 0.0 0.0 0.0 0.0 2027 3.0 0.4 0.0 199.7 2027 6.2 0.8 0.0 239.1

2028 0.0 0.0 0.0 0.0 2028 2.7 0.4 0.0 199.5 2028 5.8 0.8 0.0 239.5

2029 0.0 0.0 0.0 0.0 2029 2.5 0.3 0.0 201.2 2029 4.3 0.6 0.0 223.7

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 145.6 0.0 2030 0.0 0.0 145.6 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Enoch Liquids Gas Capex Opex Enoch Liquids Gas Capex Opex Enoch Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 1.0 0.0 0.0 41.4 2016 1.3 0.0 0.0 41.4 2016 1.5 0.0 0.0 41.4

2017 0.0 0.0 215.6 0.0 2017 1.1 0.0 66.1 84.6 2017 1.4 0.0 66.1 84.6

2018 0.0 0.0 0.0 0.0 2018 0.8 0.0 67.4 91.6 2018 1.2 0.0 67.4 92.2

2019 0.0 0.0 0.0 0.0 2019 0.7 0.0 0.0 100.3 2019 1.1 0.0 0.0 100.7

2020 0.0 0.0 0.0 0.0 2020 0.5 0.0 0.0 110.8 2020 0.9 0.0 0.0 110.2

2021 0.0 0.0 0.0 0.0 2021 0.0 0.0 233.4 0.0 2021 0.7 0.0 0.0 120.7

2022 0.0 0.0 0.0 0.0 2022 0.0 0.0 0.0 0.0 2022 0.7 0.0 0.0 132.5

2023 0.0 0.0 0.0 0.0 2023 0.0 0.0 0.0 0.0 2023 0.6 0.0 0.0 135.2

2024 0.0 0.0 0.0 0.0 2024 0.0 0.0 0.0 0.0 2024 0.6 0.0 0.0 137.9

2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 0.0 0.0 2025 0.0 0.0 252.6 0.0

2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0 2026 0.0 0.0 0.0 0.0

2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0 2027 0.0 0.0 0.0 0.0

2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0 2028 0.0 0.0 0.0 0.0

2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0 2029 0.0 0.0 0.0 0.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 0.0 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Butch Liquids Gas Capex Opex Butch Liquids Gas Capex Opex Butch Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.0 0.0 234.1 0.0 2016 0.0 0.0 234.1 0.0 2016 0.0 0.0 234.1 0.0

2017 0.0 0.0 1216.1 220.7 2017 0.0 0.0 1216.1 220.7 2017 0.0 0.0 1216.1 220.7

2018 0.0 0.0 3694.3 221.9 2018 0.0 0.0 3694.3 221.9 2018 0.0 0.0 3694.3 222.3

2019 22.2 5.8 1139.4 408.2 2019 28.6 7.7 1139.4 510.1 2019 28.6 11.2 1139.4 513.9

2020 17.6 4.5 0.0 510.1 2020 28.6 7.7 0.0 688.8 2020 28.7 10.2 0.0 693.3

2021 8.4 1.8 0.0 368.4 2021 23.8 7.6 0.0 624.9 2021 28.6 9.3 0.0 704.7

2022 3.5 0.0 0.0 292.4 2022 13.0 4.3 0.0 454.0 2022 28.4 7.7 0.0 713.4

2023 1.5 0.0 0.0 264.0 2023 4.9 0.0 0.0 321.5 2023 21.0 3.8 0.0 598.7

2024 1.0 0.0 0.0 261.4 2024 3.7 0.0 0.0 307.7 2024 9.3 1.6 0.0 405.1

2025 1.1 0.0 0.0 268.3 2025 2.4 0.0 0.0 291.3 2025 4.8 0.0 0.0 332.8

2026 0.0 0.0 776.2 0.0 2026 2.4 0.0 0.0 296.7 2026 4.3 0.0 0.0 329.9

2027 0.0 0.0 0.0 0.0 2027 1.6 0.0 0.0 287.5 2027 2.3 0.0 0.0 300.0

2028 0.0 0.0 0.0 0.0 2028 1.8 0.0 0.0 297.4 2028 1.6 0.0 0.0 294.3

2029 0.0 0.0 0.0 0.0 2029 1.4 0.0 0.0 296.5 2029 1.4 0.0 0.0 295.0

2030 0.0 0.0 0.0 0.0 2030 0.0 0.0 840.1 0.0 2030 0.0 0.0 840.1 0.0

2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0 2031 0.0 0.0 0.0 0.0

2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0 2032 0.0 0.0 0.0 0.0

2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0 2033 0.0 0.0 0.0 0.0

2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0 2034 0.0 0.0 0.0 0.0

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 0.0 0.0





Pil Liquids Gas Capex Opex Pil Liquids Gas Capex Opex Pil Liquids Gas Capex Opexkbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM kbpd MMscf/d NOKMM NOKMM

2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0 2015 0.0 0.0 0.0 0.0

2016 0.0 0.0 0.0 0.0 2016 0.0 0.0 0.0 0.0 2016 0.0 0.0 0.0 0.0

2017 0.0 0.0 0.0 0.0 2017 0.0 0.0 0.0 0.0 2017 0.0 0.0 0.0 0.0

2018 0.0 0.0 600.6 46.6 2018 0.0 0.0 600.6 58.3 2018 0.0 0.0 600.6 58.3

2019 0.0 0.0 977.4 42.3 2019 0.0 0.0 977.4 52.8 2019 0.0 0.0 977.4 52.8

2020 0.0 0.0 2443.3 57.1 2020 0.0 0.0 2443.3 71.3 2020 0.0 0.0 2443.3 71.3

2021 0.0 0.0 3404.4 58.2 2021 0.0 0.0 3404.4 72.8 2021 0.0 0.0 3404.4 72.8

2022 21.1 0.0 0.0 1313.9 2022 41.2 0.0 0.0 1770.1 2022 61.4 0.0 0.0 1899.1

2023 17.5 0.0 0.0 1257.4 2023 38.3 0.0 0.0 1707.1 2023 57.2 0.0 0.0 1829.6

2024 10.2 0.0 358.5 1220.2 2024 24.1 0.0 0.0 1617.0 2024 35.9 0.0 0.0 1695.5

2025 7.0 0.0 914.2 1203.5 2025 16.7 0.0 0.0 1570.0 2025 25.0 0.0 0.0 1625.6

2026 8.5 144.0 0.0 1475.5 2026 12.6 0.0 0.0 1670.5 2026 18.9 0.0 0.0 1713.4

2027 5.8 72.5 0.0 1337.9 2027 10.4 0.0 0.0 1600.7 2027 15.5 0.0 0.0 1636.5

2028 0.0 0.0 1947.6 0.0 2028 8.4 0.0 0.0 1595.6 2028 12.5 0.0 0.0 1625.2

2029 0.0 0.0 0.0 0.0 2029 7.0 0.0 0.0 1595.5 2029 10.5 0.0 0.0 1620.9

2030 0.0 0.0 0.0 0.0 2030 6.0 0.0 403.8 1597.7 2030 8.9 0.0 403.8 1619.7

2031 0.0 0.0 0.0 0.0 2031 5.0 0.0 1029.6 1943.7 2031 7.4 0.0 1029.6 1962.4

2032 0.0 0.0 0.0 0.0 2032 10.3 170.1 0.0 1921.6 2032 18.7 252.6 0.0 2117.8

2033 0.0 0.0 0.0 0.0 2033 9.6 170.6 0.0 1934.0 2033 17.7 253.4 0.0 2132.0

2034 0.0 0.0 0.0 0.0 2034 4.9 56.3 0.0 1725.1 2034 8.4 83.6 0.0 1798.5

2035 0.0 0.0 0.0 0.0 2035 0.0 0.0 2237.1 0.0 2035 0.0 0.0 2237.1 0.0

2036 0.0 0.0 0.0 0.0 2036 0.0 0.0 0.0 0.0 2036 0.0 0.0 0.0 0.0





Appendix 3: PRMS Reserves DefinitionsThe following figures and tables have been extracted from the 2007 Petroleum ResourcesManagement System (PRMS) prepared by the Oil and Gas Reserves Committee of the Societyof Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World PetroleumCouncil (WPC), the American Association of Petroleum Geologists (AAPG) and the Society ofPetroleum Evaluation Engineers (SPEE). The complete document is available fromwww.spe.org.

Application of an economic test is required for full compatibility with the PRMS Reservesdefinitions, which, depending on the economic assumptions used, may result in Reserves beingless than Technically Recoverable Volumes.

Figure A4.1 Petroleum Resources Classification Framework



Figure A4.2 Project Maturity Sub-Classes



Class/Sub-Class Definition GuidelinesReserves Reserves are those

quantities of petroleumanticipated to becommercially recoverable byapplication of developmentprojects to knownaccumulations from a givendate forward under definedconditions.

Reserves must satisfy four criteria: they mustbe discovered, recoverable, commercial, andremaining based on the developmentproject(s) applied. Reserves are furthersubdivided in accordance with the level ofcertainty associated with the estimates andmay be sub-classified based on projectmaturity and/or characterized by theirdevelopment and production status.

To be included in the Reserves class, a projectmust be sufficiently defined to establish itscommercial viability. There must be areasonable expectation that all requiredinternal and external approvals will beforthcoming, and there is evidence of firmintention to proceed with development within areasonable time frame.

A reasonable time frame for the initiation ofdevelopment depends on the specificcircumstances and varies according to thescope of the project. While 5 years isrecommended as a benchmark, a longer timeframe could be applied where, for example,development of economic projects aredeferred at the option of the producer for,among other things, market-related reasons, orto meet contractual or strategic objectives. Inall cases, the justification for classification asReserves should be clearlydocumented.

To be included in the Reserves class, theremust be a high confidence in the commercialproducibility of the reservoir as supported byactual production or formation tests. In certaincases, Reserves may be assigned on the basisof well logs and/or core analysis that indicatethat the subject reservoir is hydrocarbonbearing and is analogous to reservoirs in thesame area that are producing or havedemonstrated the ability to produce onformation tests.

On Production The development project iscurrently producing andselling petroleum to market.

The key criterion is that the project is receivingincome from sales, rather than the approveddevelopment project necessarily beingcomplete. This is the point at which the project“chance of commerciality” can be said to be100%.

The project “decision gate” is the decision toinitiate commercial production from the project.

Approved forDevelopment

All necessary approvalshave been obtained, capitalfunds have been committed,and implementation of thedevelopment project isunder way.

At this point, it must be certain that thedevelopment project is going ahead. Theproject must not be subject to anycontingencies such as outstanding regulatoryapprovals or sales contracts. Forecast capitalexpenditures should be included in thereporting entity’s current or following year’sapproved budget.

The project “decision gate” is the decision tostart investing capital in the construction ofproduction facilities and/or drillingdevelopment wells.



Class/Sub-Class Definition GuidelinesJustified forDevelopment

Implementation of thedevelopment project isjustified on the basis ofreasonable forecastcommercial conditions at thetime of reporting, and thereare reasonable expectationsthat all necessaryapprovals/contracts will beobtained.

In order to move to this level of project maturity,and hence have reserves associated with it,the development project must be commerciallyviable at the time of reporting, based on thereporting entity’s assumptions of future prices,costs, etc. (“forecast case”) and the specificcircumstances of the project. Evidence of afirm intention to proceed with developmentwithin a reasonable time frame will be sufficientto demonstrate commerciality. There shouldbe a development plan in sufficient detail tosupport the assessment of commerciality anda reasonable expectation that any regulatoryapprovals or sales contracts required prior toproject implementation will be forthcoming.Other than such approvals/contracts, thereshould be no known contingencies that couldpreclude the development from proceedingwithin a reasonable timeframe (see Reservesclass).

The project “decision gate” is the decision bythe reporting entity and its partners, if any, thatthe project has reached a level of technical andcommercial maturity sufficient to justifyproceeding with development at that point intime.

ContingentResources

Those quantities ofpetroleum estimated, as of agiven date, to be potentiallyrecoverable from knownaccumulations byapplication of developmentprojects, but which are notcurrently considered to becommercially recoverabledue to one or morecontingencies.

Contingent Resources may include, forexample, projects for which there are currentlyno viable markets, or where commercialrecovery is dependent on technology underdevelopment, or where evaluation of theaccumulation is insufficient to clearly assesscommerciality. Contingent Resources arefurther categorized in accordance with the levelof certainty associated with the estimates andmay be sub-classified based on projectmaturity and/or characterized by theireconomic status.

DevelopmentPending

A discovered accumulationwhere project activities areongoing to justifycommercial development inthe foreseeable future.

The project is seen to have reasonablepotential for eventual commercialdevelopment, to the extent that further dataacquisition (e.g. drilling, seismic data) and/orevaluations are currently ongoing with a viewto confirming that the project is commerciallyviable and providing the basis for selection ofan appropriate development plan. The criticalcontingencies have been identified and arereasonably expected to be resolved within areasonable time frame. Note thatdisappointing appraisal/evaluation resultscould lead to a re-classification of the project to“On Hold” or “Not Viable” status.

The project “decision gate” is the decision toundertake further data acquisition and/orstudies designed to move the project to a levelof technical and commercial maturity at whicha decision can be made to proceed withdevelopment and production.

DevelopmentUnclarified or onHold

A discovered accumulationwhere project activities areon hold and/or wherejustification as a commercialdevelopment may besubject to significant delay.

The project is seen to have potential foreventual commercial development, but furtherappraisal/evaluation activities are on holdpending the removal of significantcontingencies external to the project, orsubstantial further appraisal/evaluation



Class/Sub-Class Definition Guidelinesactivities are required to clarify the potential foreventual commercial development.Development may be subject to a significanttime delay. Note that a change incircumstances, such that there is no longer areasonable expectation that a criticalcontingency can be removed in theforeseeable future, for example, could lead toa reclassification of the project to “Not Viable”status.

The project “decision gate” is the decision toeither proceed with additional evaluationdesigned to clarify the potential for eventualcommercial development or to temporarilysuspend or delay further activities pendingresolution of external contingencies.

Development NotViable

A discovered accumulationfor which there are nocurrent plans to develop orto acquire additional data atthe time due to limitedproduction potential.

The project is not seen to have potential foreventual commercial development at the timeof reporting, but the theoretically recoverablequantities are recorded so that the potentialopportunity will be recognised in the event of amajor change in technology or commercialconditions.

The project “decision gate” is the decision notto undertake any further data acquisition orstudies on the project for the foreseeablefuture.

ProspectiveResources

Those quantities ofpetroleum which areestimated, as of a givendate, to be potentiallyrecoverable fromundiscoveredaccumulations.

Potential accumulations are evaluatedaccording to their chance of discovery and,assuming a discovery, the estimated quantitiesthat would be recoverable under defineddevelopment projects. It is recognized that thedevelopment programs will be of significantlyless detail and depend more heavily onanalogue developments in the earlier phasesof exploration.

Prospect A project associated with apotential accumulation thatis sufficiently well defined torepresent a viable drillingtarget.

Project activities are focused on assessing thechance of discovery and, assuming discovery,the range of potential recoverable quantitiesunder a commercial development program.

Lead A project associated with apotential accumulation thatis currently poorly definedand requires more dataacquisition and/or evaluationin order to be classified as aprospect.

Project activities are focused on acquiringadditional data and/or undertaking furtherevaluation designed to confirm whether or notthe lead can be matured into a prospect. Suchevaluation includes the assessment of thechance of discovery and, assuming discovery,the range of potential recovery under feasibledevelopment scenarios.

Play A project associated with aprospective trend ofpotential prospects, butwhich requires more dataacquisition and/or evaluationin order to define specificleads or prospects.

Project activities are focused on acquiringadditional data and/or undertaking furtherevaluation designed to define specific leads orprospects for more detailed analysis of theirchance of discovery and, assuming discovery,the range of potential recovery underhypothetical development scenarios.

DevelopedReserves

Developed Reserves areexpected quantities to berecovered from existingwells and facilities.

Reserves are considered developed only afterthe necessary equipment has been installed,or when the costs to do so are relatively minorcompared to the cost of a well. Where requiredfacilities become unavailable, it may benecessary to reclassify Developed Reservesas Undeveloped. Developed Reserves may be



Class/Sub-Class Definition Guidelinesfurther sub-classified as Producing or Non-Producing.

DevelopedProducingReserves

Developed ProducingReserves are expected tobe recovered fromcompletion intervals that areopen and producing at thetime of the estimate.

Improved recovery reserves are consideredproducing only after the improved recoveryproject is in operation.

Developed Non-ProducingReserves

Developed Non-ProducingReserves include shut inand behind-pipe Reserves.

Shut in Reserves are expected to be recoveredfrom (1) completion intervals which are open atthe time of the estimate but which have not yetstarted producing, (2) wells which were shut infor market conditions or pipeline connections,or (3) wells not capable of production formechanical reasons. Behind-pipe Reservesare expected to be recovered from zones inexisting wells which will require additionalcompletion work or future recompletion prior tostart of production.

In all cases, production can be initiated orrestored with relatively low expenditurecompared to the cost of drilling a new well.

UndevelopedReserves

Undeveloped Reserves arequantities expected to berecovered through futureinvestments:

(1) from new wells on undrilled acreage inknown accumulations, (2) from deepeningexisting wells to a different (but known)reservoir, (3) from infill wells that will increaserecovery, or (4) where a relatively largeexpenditure (e.g. when compared to the cost ofdrilling a new well) is required to (a) recompletean existing well or (b) install production ortransportation facilities for primary or improvedrecovery projects.

Table A.1: Reserves & Resources Definitions and Guidelines.

Category Definition GuidelinesProved Reserves Proved Reserves are those

quantities of petroleum,which by analysis ofgeoscience and engineeringdata, can be estimated withreasonable certainty to becommercially recoverable,from a given date forward,from known reservoirs andunder defined economicconditions, operatingmethods, and governmentregulations.

If deterministic methods are used, the termreasonable certainty is intended to express ahigh degree of confidence that the quantitieswill be recovered. If probabilistic methods areused, there should be at least a 90% probabilitythat the quantities actually recovered will equalor exceed the estimate.The area of the reservoir considered as Provedincludes (1) the area delineated by drilling anddefined by fluid contacts, if any, and (2)adjacent undrilled portions of the reservoir thatcan reasonably be judged as continuous with itand commercially productive on the basis ofavailable geoscience and engineering data.In the absence of data on fluid contacts, Provedquantities in a reservoir are limited by thelowest known hydrocarbon (LKH) as seen in awell penetration unless otherwise indicated bydefinitive geoscience, engineering, orperformance data. Such definitive informationmay include pressure gradient analysis andseismic indicators. Seismic data alone may notbe sufficient to define fluid contacts for Provedreserves (see “2001 SupplementalGuidelines,” Chapter 8).Reserves in undeveloped locations may beclassified as Proved provided that:



Category Definition Guidelines The locations are in undrilled areas of

the reservoir that can be judged withreasonable certainty to becommercially productive.

Interpretations of availablegeoscience and engineering dataindicate with reasonable certainty thatthe objective formation is laterallycontinuous with drilled Provedlocations.

For Proved Reserves, the recovery efficiencyapplied to these reservoirs should be definedbased on a range of possibilities supported byanalogs and sound engineering judgmentconsidering the characteristics of the Provedarea and the applied development program.

ProbableReserves

Probable Reserves arethose additional Reserveswhich analysis ofgeoscience and engineeringdata indicate are less likelyto be recovered than ProvedReserves but more certainto be recovered thanPossible Reserves.

It is equally likely that actual remainingquantities recovered will be greater than or lessthan the sum of the estimated Proved plusProbable Reserves (2P). In this context, whenprobabilistic methods are used, there shouldbe at least a 50% probability that the actualquantities recovered will equal or exceed the2P estimate.Probable Reserves may be assigned to areasof a reservoir adjacent to Proved where datacontrol or interpretations of available data areless certain. The interpreted reservoircontinuity may not meet the reasonablecertainty criteria.Probable estimates also include incrementalrecoveries associated with project recoveryefficiencies beyond that assumed for Proved.

PossibleReserves

Possible Reserves arethose additional reserveswhich analysis ofgeoscience and engineeringdata indicate are less likelyto be recoverable thanProbable Reserves.

The total quantities ultimately recovered fromthe project have a low probability to exceed thesum of Proved plus Probable plus Possible(3P), which is equivalent to the high estimatescenario. When probabilistic methods areused, there should be at least a 10% probabilitythat the actual quantities recovered will equalor exceed the 3P estimate.Possible Reserves may be assigned to areasof a reservoir adjacent to Probable where datacontrol and interpretations of available data areprogressively less certain. Frequently, thismay be in areas where geoscience andengineering data are unable to clearly definethe area and vertical reservoir limits ofcommercial production from the reservoir by adefined project.Possible estimates also include incrementalquantities associated with project recoveryefficiencies beyond that assumed for Probable.

Probable andPossibleReserves

(See above for separatecriteria for ProbableReserves and PossibleReserves.)

The 2P and 3P estimates may be based onreasonable alternative technical andcommercial interpretations within the reservoirand/or subject project that are clearlydocumented, including comparisons to resultsin successful similar projects.In conventional accumulations, Probableand/or Possible Reserves may be assignedwhere geoscience and engineering dataidentify directly adjacent portions of a reservoirwithin the same accumulation that may beseparated from Proved areas by minor faulting



Category Definition Guidelinesor other geological discontinuities and have notbeen penetrated by a wellbore but areinterpreted to be in communication with theknown (Proved) reservoir. Probable orPossible Reserves may be assigned to areasthat are structurally higher than the Provedarea. Possible (and in some cases, Probable)Reserves may be assigned to areas that arestructural lower than the adjacent Proved or 2Parea.Caution should be exercised in assigningReserves to adjacent reservoirs isolated bymajor, potentially sealing, faults until thisreservoir is penetrated and evaluated ascommercially productive. Justification forassigning Reserves in such cases should beclearly documented. Reserves should not beassigned to areas that are clearly separatedfrom a known accumulation by non-productivereservoir (i.e., absence of reservoir, structurallylow reservoir, or negative test results); suchareas may contain Prospective Resources.In conventional accumulations, where drillinghas defined a highest known oil (HKO)elevation and there exists the potential for anassociated gas cap, Proved oil Reservesshould only be assigned in the structurallyhigher portions of the reservoir if there isreasonable certainty that such portions areinitially above bubble point pressure based ondocumented engineering analyses. Reservoirportions that do not meet this certainty may beassigned as Probable and Possible oil and/orgas based on reservoir fluid properties andpressure gradient interpretations.

Table A.3: Reserves Category Definitions and Guidelines.



Appendix 4: LR Senergy and Author CredentialsLR Senergy (GB) Limited is a privately owned independent consulting company established in1990, with offices in Aberdeen, London, Stavanger, Abu Dhabi, Dubai, Kuala Lumpur, andPerth. The company specialises in petroleum reservoir engineering, geology and geophysicsand petroleum economics. All of these services are supplied under an accredited ISO9001quality assurance system. Except for the provision of professional services on a fee basis, LRSenergy has no commercial arrangement with any person or company involved in the interestthat is the subject of this report.

Dr Barry James Squire is the Commercial Project Manager of LR Senergy’s Reserves andAsset Evaluation group and was responsible for supervising this evaluation. He is aprofessional petroleum geologist with over 40 years of oil industry experience gained ininternational companies, consultancy companies and within LR Senergy. He is a Fellow of theGeological Society, a member of the Petroleum Exploration Society of Great Britain and has aB.Sc. in Geology and a Ph.D. in Sedimentary Geochemistry both from the University ofManchester.

Allan Spencer is a Petroleum Engineer and Project Manager with over 40 years of operationalexperience in corporate planning, field development, economic evaluation, petroleumproduction and reservoir engineering. Allan’s focus is project management, resourceassessment and asset evaluation and a broad range of oilfield operations management and isan expert on reserves reporting, reserves regulations, production forecasting, uncertaintyanalysis and economic evaluation. He is a member of the Society of Petroleum Engineers(SPE).

Jim Scallon is a geologist and petroleum analysis professional with over 40 years experiencein a variety of technical and management positions in numerous worldwide locations and in awide range of major company operating environments. He is an advisor to both small and largeoil companies on a wide range of topics ranging from exploration to production declinemanagement, and has extensive experience in the preparation of Competent Person’s Reports.He has a degree in Geology from the University of Sheffield.

Christopher Priddis is a Petroleum Economist with extensive business analysis experiencewithin investment banks and investment managers. In previous roles, he has been responsiblefor the generation and development of economic models for oil and gas fields for establishmentof economically recoverable reserves and optimisation of field development plans. Hisexperience covers numerous fiscal regimes around the globe.



Nomenclature

Variable Meaning Units

1P Proved Reserves2P Proved plus Probable Reserves3P Proved plus Probable plus Possible Reserves2D Two dimensional3D Three dimensionalAAPG American Association of Petroleum GeologistsAdmission Process of admission of an entity to a Stock Market.AI Acoustic impedanceAPI American Petroleum InstituteAVO Amplitude versus offset or amplitude variation with

offset is often used as a direct hydrocarbon indicator.b/tonne Barrels per tonnebbl Barrel of oilBest Estimate An estimate representing the best technical

assessment of projected volumes. Usually the P50

value.b/d Barrels per dayBscf Billion standard cubic feetBCU Base Cretaceous UnconformityBHP Bottom Hole Pressurebopd Barrels of oil per dayBPU Base Permian UnconformityBscf Billions of standard cubic feetbwpd Barrels of water per dayCA Central AreaCapex Capital expenditureCMS Caister Murdoch SystemCO2 Carbon dioxideCOGE Canadian Oil & Gas EvaluationContingent Resources Contingent Resources are those quantities of

petroleum estimated, as of a given date, to bepotentially recoverable from known accumulations, butthe applied project(s) are not yet considered matureenough for commercial development due to one ormore contingencies.

COP Cessation of production.cp CentipoiseCp CentipoiseCPI Computer-processed interpretationd DayDST Drill stem testEMV Expected Monetary Value



EOR Enhanced Oil RecoveryERD Extended reach drillingESMA European Securities and Markets Authority’sEWT Extended Well Testº F / º C Degrees Fahrenheit / CentigradeF&F Fuel and FlareFBHP Flowing bottom hole pressureFDP Field Development ProgrammeFEED Front End Engineering DesignFGP Full gas processingFPSO Floating Production, Storage, OffloadingFWL Free water levelGDT Gas down toGIIP Gas-Initially-In-PlaceGR Gamma ray apiGOR Gas Oil RatioGRV Gross Rock VolumeGWC Gas-water contacth Thickness ft or mH2S Hydrogen SulphideHIIP Hydrocarbons Initially in PlaceHP High pressureHSE Health, Safety, EnvironmentIOR Improved oil recoveryk Permeability mDKh Permeability-thickness mDftKv Vertical permeabilityMbal Material Balance. A means of assessing HIIP.Mbd Thousand barrels per daymd Measured depth ft or mmD MillidarciesMDT Measurement Drilling ToolMean The arithmetic average of a set of valuesMedium Term In this report this refers to those prospects which

could become viable drilling candidates in a 5 yeartimeframe.

MEOR Microbiological injectionMJ/Sm3 Mega Joules per standard metre cubed.MM MillionMMboe Millions of barrels of oil equivalentMMstb Million barrels oilMMscf/d Million standard cubic feet per dayMMstb Millions of barrels of stock tank oilMNOK Millions Norwegian Kroner



mol% A chemistry measurement defined as the amount of aconstituent (expressed in moles)

Mscf Thousands standard cubic feetNA Nothern AreaNGL Natural Gas LiquidNPD Norwegian Petroleum DirectorateNPV Net present valueNTG Net to GrossNear Term In this report this refers to those prospects which are

expected to be drilled in the next 2 yearsNPV Net present valueNWF North West FlankOBS Ocean-bottom seismicODT Oil down toOpex Operating expenditureOWC Oil water contactP99 The probability that a stated volume will be equalled

or exceeded. In this example a 99% chance that theactual volume will be greater than or equal to thatstated.

PASF Polymer Assisted Surfactant FloodingPDO Plan of Development and OperationPI Productivity IndexPres Reservoir pressure psippg pounds per gallonppm Parts per millionPRMS Petroleum Resources Management SystemProducing Related to development projects (e.g. wells and

platforms): Active facilities, currently involved in theextraction (production) of hydrocarbons fromdiscovered reservoirs.

ProspectiveResources

Prospective Resources are those quantities ofpetroleum estimated, as of a given date, to bepotentially recoverable from undiscoveredaccumulations by application of future developmentprojects. Prospective Resources have both anassociated chance of discovery and a chance ofdevelopment.

Proved Proved Reserves are those quantities of petroleum,which, by analysis of geoscience and engineeringdata, can be estimated with reasonable certainty to becommercially recoverable, from a given date forward,from known reservoirs and under defined economicconditions, operating methods, and governmentregulations. If deterministic methods are used, theterm reasonable certainty is intended to express ahigh degree of confidence that the quantities will berecovered. If probabilistic methods are used, thereshould be at least a 90% probability that the quantitiesactually recovered will equal or exceed the estimate.



Proved plus Probable Probable Reserves are those additional Reserveswhich analysis of geoscience and engineering dataindicate are less likely to be recovered than ProvedReserves but more certain to be recovered thanPossible Reserves. It is equally likely that actualremaining quantities recovered will be greater than orless than the sum of the estimated Proved plusProbable Reserves (2P). In this context, whenprobabilistic methods are used, there should be atleast a 50% probability that the actual quantitiesrecovered will equal or exceed the 2P estimate.

Proved plus Probableplus Possible

Possible Reserves are those additional reserveswhich analysis of geoscience and engineering datasuggest are less likely to be recoverable thanProbable Reserves. The total quantities ultimatelyrecovered from the project have a low probability toexceed the sum of Proved plus Probable plusPossible (3P) Reserves, which is equivalent to thehigh estimate scenario. In this context, whenprobabilistic methods are used, there should be atleast a 10% probability that the actual quantitiesrecovered will equal or exceed the 3P estimate.

PRT Petroleum Revenue TaxPSDM Pre-Stack Depth MigrationPVT Pressure Volume Temperature: Measurement of the

variation in petroleum properties as the statedparameters are varied.

P/Z Reservoir pressure (P) divided by the compressibilityfactor (Z), which plotted against cumulative gasvolume produced provides a simplified materialbalance analysis for gas fields.

Reserves Reserves are those quantities of petroleumanticipated to be commercially recoverable byapplication of development projects to knownaccumulations from a given date forward underdefined conditions. Reserves must further satisfy fourcriteria: they must be discovered, recoverable,commercial, and remaining (as of the evaluation date)based on the development project(s) applied.Reserves are further categorized in accordance withthe level of certainty associated with the estimatesand may be sub-classified based on project maturityand/or characterized by development and productionstatus.

RFT Repeat formation testerSCAL Special Core Analysisscf Standard cubic footsm3 Standard metre cubed.SNS Southern North SeaSPE Society of Petroleum EngineersSPEE Society of Petroleum Evaluation Engineersstb/d Stock tank barrels per daySTOIIP Stock tank oil initially in placeSw Water saturation ratio



TCM Technical Committee MeetingTHP Top Hole PressureTD Total depth ft or mtvdbrt True vertical depth below rotary table ft or mtvdss True vertical depth sub sea ft or mUUOA Unitisation and Unit Operating AgreementVoK Average velocity function for depth conversion of time

based seismic data, where Vo is the initial velocityand k provides information on the increase ordecrease in velocity with depth. V0+k thereforeprovides a method of depth conversion using a linearvelocity field, increasing or decreasing with depth foreach geological zone.

WHP Wellhead pressure PsiWPC World Petroleum Council

File No. Faroe\K16FAR044L\Final Prepared for: Faroe Petroleum plc

Reserves, Resources and Economic Assessment of the Assets of Faroe Petroleumplc

Faroe Petroleum Licences Table 1.1

UK Licences

Asset Operator Interest(%) Status Licence

Expiry DateLicenceArea (km2) Comments

P039 53/4d Tullow Oil UK Limited 18.75 Production 17 09 2028 19.0 Wissey ceased production

P.559 204/24a B.P. Exploration OperatingCompany Ltd 10.0 Production 13 06 2021 4 East Foinaven in production

P.803 204/25b B.P. Exploration OperatingCompany Ltd 10.0 Production 18 03 2029 20 East Foinaven in production

P611 44/24a GDF Suez E&P UK Ltd 5.89 Development 04 06 2023 75.0 Minke ceased production

P454 44/29b GDF Suez E&P UK Ltd 5.89 Production 11 05 2019 40.5 Orca production expected toresume in 2016

D15b D15b GDF Production Nederland B.V 5.0 Production 06 09 2021 146 Orca production expected toresume in 2016

D18a D18a GDF Production Nederland B.V 2.5 Production 09 10 2032 58 Orca production expected toresume in 2016

P689 43/30a Faroe Petroleum (U.K.) Ltd 6.9 Production 20 07 2025 14.1 Schooner in production

P516 44/26a Faroe Petroleum (U.K.) Ltd 53.1 Production 20 07 2025 99.2 Schooner in production

P453 44/28b Faroe Petroleum (U.K.) Ltd 60.0 Production 20 07 2025 85 Ketch in production

P530 49/1a,2a,2b RWE Dea UK Limited 7.5 Production 14 06 2021 22.2 Topaz in production

P218 15/21a rest,21f rest Deo Petroleum UK Limited 34.62 Development 16 03 2018 44.5Perth joint development plannedwith Lowlander and Dolphin; andProspects Perth Northern and Beta

P588 15/21b rest, 21c all Deo Petroleum UK Limited 34.62 Development 04 06 2023 27.2 Perth joint development plannedwith Lowlander and Dolphin

P111 30/3a Upper Talisman Energy Norge AS 30.5 Production 09 06 2016 32.9 Blane in production

P2156 15/11, 15/16f Parkmead E&P Limited 25.0 Exploration 30 11 2018 93.7 Prospect Fynn




Norway Licences


Expiry dateLicence Area(km2) Comments

PL006C 2/5 Lundin Norway AS 85 Development 31.12.2028 93.2 SE Tor undeveloped discovery

PL048D 15/5 Statoil Petroleum AS 13.86 Production 18.02.2018 9.5 Enoch in production

PL053B 30/6 Statoil Petroleum AS 25.4 Production 06.04.2030 8.5 Brage in production

PL055 31/4 Statoil Petroleum AS 13.4 Production 06.04.2030 122.2 Brage in production

PL055B 31/4 Statoil Petroleum AS 13.4 Production 06.04.2030 5.1 Brage in production

PL055D 31/4 Statoil Petroleum AS 13.4 Exploration 08.02.2014 22

PL103B 25/7 Det Norske Oljeselskap ASA 30.0 Production 01.03.2021 22.7 Jotun in production

PL107 6407/7 Statoil Petroleum AS 7.5 Production 01.03.2021 70.5Njord production to cease in 2016for re-development. NF-2Exploration well in 2017

PL107C 6407/7 Statoil Petroleum AS 7.5 Exploration 23.01.2019 21

PL132 6407/10 Statoil Petroleum AS 7.5 Production 10.04.2023 21Njord production to cease in 2016for re-development. NF-2Exploration well in 2017

PL169E 25/8 Statoil Petroleum AS 7.58 Production 01.03.2030 19.4 Ringhorne East in production

PL169E 25/8 Statoil Petroleum AS 30 Exploration 01.03.2030 19.4

PL185 31/7 Statoil Petroleum AS 13.4 Production 06.04.2030 25.5 Brage in production.

PL348 6407/8, 6407/9 Statoil Petroleum AS 7.5 Development 17.12.2029 207.7 Snilehorn in development

PL348B 6407/8 Statoil Petroleum AS 7.5 Development 17.12.2029 13.5 Snilehorn in development

PL348C 6407/8 Statoil Petroleum AS 7.5 Exploration 17.12.2029 49.3 Prospects Dobby and Nilus. Bisterdry well drilled in May 2015

PL405 7/9 & 12, 8/7, 8,10, & 11 Centrica Resources Norge AS 15.0 Development 01.12.2016 624.7 Butch in development and

Prospect Cassidy

PL433 6506/9, 12 Centrica Resources (Norge) AS 25.0 Exploration 16.02.2017 79.5 Fogelberg un-developeddiscovery

PL534 7224/7, 8 and 11 Wintershall Norge AS 50.0 Exploration 15.05.2016 947.6 Hegg/Sansom Dome.Relinquishment notice submitted

PL586 6406/11 & 12 VNG Norge AS 25.0 Development 04.02.2017 287.4 Pil in development

PL611 7223/3, 6 and7224/1, 2, 3, 4 & 5. Wintershall Norge AS 40.0 Exploration 13.05.2017 2,153.6 Kvalross dry well in Q1 2016

PL627 25/5, 6, 8 & 9 Total E&P Norge AS 20.0 Exploration 03.02.2019 458.7 Shango un-developed discoveryand Prospect Oshun

PL627B 25/6 Total E&P Norge AS 20.0 Exploration 03.02.2019 12.2

PL644 6506/8, 10 & 11 OMV (Norge) AS 20.0 Exploration 03.02.2020 275.1 Prospect Aerosmith

PL644B 6506/8, 10 & 11 OMV (Norge) AS 20.0 Exploration 03.02.2020 27.5 Propsect Zappa

PL660 1/6 Faroe Petroleum Norge AS 35.0 Exploration 08.02.2020 59.2 Edinburgh Exploration well in2017

PL716 7318/11 & 12 Eni Norge AS 20.0 Exploration 21.06.2017 603 Dazzler Central Exploration wellin 2016/17

PL740 31/7 & 30/9 Faroe Petroleum Norge AS 50.0 Exploration 07.02.2020 87 Prospect Brasse, spud 23.5.2016

PL749 6306/4 & 5 Centrica Resources Norge AS 20.0 Exploration 07.02.2017 768 Prospects Seychelles andMauritius




Norway Licences

PL753 6407/7,8 VNG Norge 30.0 Exploration 07.02.2022 243.4 Prospect Zircon

PL792 6306/2 Centrica Resources Norge AS 50.0 Exploration 06.02.2022 118.4 Prospects Slynge

PL793 6407/7, 8, 10 & 11 Shell 20.0 Exploration 06.02.2022 227 Portrush dry well drilled in 2015

PL794 6407/7 & 10 Statoil Petroleum AS 20.0 Exploration 06.02.2022 67.6 Prospect Rosapenna (Satus)

PL810 2/1, 7/12 & 8/10 Faroe Petroleum Norge AS 40.0 Exploration 05.02.2025 127.7 Prospect Katie, Licence awardedin Q1 2016

PL811 7/9, 12 & 8/7 Centrica Resources Norge AS 20.0 Exploration 05.02.2025 352.4 Prospect Gullaxy, Licenceawarded in Q1 2016

PL825 30/3 & 6 Faroe Petroleum Norge AS 40.0 Exploration 05.02.2025 77.7 Prospect Rungne, Licenceawarded in Q1 2016

PL836 S 6406/2 & 3 Wintershall Norge AS 30.0 Exploration 05.02.2025 131.8 Prospect Yoshi, Licence awardedin Q1 2016

PL845 6609/6, 6610/4, 5& 6 ConocoPhillips Skandinavia AS 20.0 Exploration 05.02.2025 1,440.7 Prospect Gronoy High, Licence

awarded in Q1 2016




Ireland Licences


Expiry dateLicence Area(km2) Comments

14/148/28, 29, 30(parts), 49/26,57/3, 4 & 5

Faroe Petroleum Norge AS 100 Exploration 30.09.2016 1035.7 Leads under evaluation

14/2 57/7, 11, 57/6, 8, 9& 12 (parts) Faroe Petroleum Norge AS 100 Exploration 30.09.2016 1086.2 Leads under evaluation

14/350/10, 14, 16, 17,50/9, 11, 13 & 18(parts)

Faroe Petroleum Norge AS 100 Exploration 30.09.2016 1336.0 Leads under evaluation

File No. Faroe\K16FAR044Lreport Prepared for: Faroe Petroleum Plc


Figure 1.1

Location Map: Faroe Licences, Fields, Discoveries & Prospects



Figure 1.2

UK Atlantic Margin: Portfolio Location Map

P803East Foinaven Field



Figure 1.3

UK and Norway North Sea: Portfolio Location Map



Figure 1.4

UK Southern North Sea: Portfolio Location Map



Figure 1.5

Norway Northern North Sea: Portfolio Location Map



Figure 1.6

Norway Norwegian Sea: Portfolio Location Map



Figure 1.7

Norway Barents Sea: Portfolio Location Map



Figure 1.8

Ireland Celtic Sea: Portfolio Location Map

File No. \Faroe\K16FAR044L\Report Prepared for: Faroe Petroleum Plc

Figure 2.1


Blane: Development Scheme andTop F2 Structure Depth Map


Figure 2.2


Schooner: Location Map and Infill Locations

SA-11 Completedin 2013

SA-12 PossibleWell?

NW AreaInfillPotential


Figure 2.3


Schooner and Ketch Schematic of Facilities


Figure 2.4


Orca Location Map

D15

Orca


Figure 2.5


Topaz: Top Carboniferous Depth Map and Export Route

49/1-3

49/1-2

49/2a-6

49/2a-6z49/2a-5z

Fault Block 1

Fault Block 2

49/1 49/2a

Infill Target Area


Figure 2.6


East Foinaven : Reservoir Channel Sandstone Architecture and Well Locations

W41

W42

P41

P42

P43


Figure 2.7


Njord: Structure Map with Well Tracks (Source : Statoil 2010)


Figure 2.8


Hyme and Snilehorn: Location Map


Figure 2.9


Brage: Field Outline


Figure 2.10


Ringhorne East: Structure Depth Map and Possible Future Infill Well Locations


Figure 2.11


Enoch: Location Map and Top Flugga Depth Map and Seismic Anomaly


Figure 2.12


Butch: Ula Tie Back Development Schematic


Figure 2.13


Pil: Top Reservoir Depth Map and Well Locations

reserves, resources and economic assessment of the … · reserves, resources and economic...

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