Operational Update and 2018 Guidance

13 February 2018

Faroe Petroleum plc

("Faroe", "Faroe Petroleum", the "Company")

Operational Update and 2018 Guidance

Faroe Petroleum, the independent oil and gas company focussing principally on exploration, appraisal and production opportunities in Norway and the UK, is pleased to provide an update on operations and guidance for 2018.


-      2017 average production of 14,300 boepd at the upper end of 2017 guidance  

-      2018 production is expected to be in the range of 12,000 to 15,000 boepd 

-     20% increase in 2P reserves to 97.7 mmboe at year-end following the successful Brasse appraisal well in 2017 and after adjusting for the Fenja transaction announced yesterday1. Year-end 2C resources are 78.6 mmboe, as adjusted for Fenja 

-     Fully funded for Brasse and ongoing development projects: Oda; Njord Future; Bauge and Fenja, following the divestment of 17.5% of Fenja  

-    High quality E&A drilling programme under way for 2018 with two wells already drilling: Iris/Hades and Fogelberg and with three further wells added: Rungne, Cassidy and Pabow 

Graham Stewart, Chief Executive of Faroe Petroleum commented:

"2017 has been another very good year for Faroe with strong operational performance enhanced by a general recovery in commodity prices and market sentiment. A highly successful appraisal well on our Brasse oil and gas discovery in Norway and its conversion to 2P reserves, combined with positive reserves revisions in Ula and Tambar led to Faroe's highest ever recorded year-end 2P reserves at 97.7 mmboe, an increase of 20% even after adjusting for the reduced interest in Fenja announced yesterday. The Tambar production project commenced last year and the two infill wells have now been drilled and early results are very positive showing good potential for increased production with the new wells expected on stream during February. 


"We announced yesterday that we have agreed a part-disposal of 17.5% of Fenja to Suncor, reducing our working interest from 25% to 7.5%. As well as generating an immediate cash consideration of $54.5 million, this will decrease our future capex on Fenja from an estimated £232 million to approximately £70 million. As a result, and with our existing cash position and unused debt, we are now fully funded for the operated Brasse project, which remains uncommitted at this stage, as well as our committed and ongoing Norwegian development projects.


"As we embark on another very busy year for the business, Faroe is again well positioned to capture the growth opportunities which we continue to generate from our balanced portfolio of development and exploration and appraisal opportunities, backed by our sustainable and increasingly cash generative production base."

1 as adjusted for sale of a 17.5% interest in Fenja                                                                                                                            



2017 operational update detail: 


Production - significantly enhanced by the field development programme to deliver long term profitable production growth 

  • Total average economic production for the full year 2017 was approximately 14,300 boepd, of which approximately 55% was liquids and 45% gas. Table 1 as attached, presents preliminary 2017 production data per field net to Faroe's participating interests
  • In a transaction with JX Nippon, Faroe increased its working interest in Blane, on attractive terms, to 44.5%, with a corresponding increase in production
  • Average full year 2018 production is currently forecast to be in the range of 12,000 to 15,000 boepd from all fields, split approximately 67% liquids and 33% gas. The range in this initial forecast reflects short term uncertainty on both the upside potential of the new wells due to come on stream on the Tambar and Brage fields, and the duration of the temporary shut in of the Trym field as a result of a pipeline integrity issue at the Tyra gathering hub.  The range will be narrowed when there is greater clarity on production from these fields
  • Average Opex in 2017 for producing assets was approximately $26.5 per boe (excluding accrued tariff costs in            relation to future upgrades ($29.5 per boe including tariff costs in relation to future upgrades))
  • Opex in 2018 is expected to be in the range of $23 to $27 per boe. Unit Opex is expected to decrease further as new production is brought on stream in 2019 and beyond
  • Faroe continues to seek suitable value-enhancing production acquisitions, taking advantage of the Company's strong balance sheet

Reserves and Resources - 20% increase in reserves in 2017 to record level of 97.7 mmboe

Faroe has completed its internal assessment of reserves and resources at 1 January 2018, which are as follows and include an adjustment for the disposal of a 17.5% interest in the Fenja Field: 

  • 2P Reserves increased by 20% with closing reserves at 97.7 mmboe (1 Jan-17: 81.3 mmboe).  The significant increase (reserves replacement in excess of 700%) is a result of the conversion of Brasse from contingent resources to reserves and incremental projects across the portfolio, which generated positive reserve revisions notably on Tambar, which more than compensate for the divestment of a 17.5% interest in the Fenja field  
  • 2C Contingent Resources are 14% lower at 78.6 mmboe (1 Jan-17: 90.9 mmboe) as a result of the additional contingent resources, mainly in Ula, Tambar and Oselvar, not fully compensating for the transfer of Brasse to reserves and divestment in Fenja  

Table 2 of this announcement, as attached, presents Faroe's net 2P Reserves per field, split into liquids (oil and NGL) and gas reserves. 

Development - portfolio of high quality developments progressing well 


The Brasse Area 

  • Brasse oil and gas discovery (Faroe 50%): The preliminary reservoir drainage plan includes three to six subsea production wells and possible water injection for pressure support.  Gross plateau flow rates for this field have the potential to reach 30,000 boepd, and first production is targeted for 2021.  
  • At the end of 2017, the Brasse feasibility study phase was completed confirming several attractive development solutions and export routes. The key project milestone for 2018 will be the Concept Selection including the selection of a reservoir drainage plan and a processing host.  The Plan for Development and Operation (PDO) submission is expected in 2019.  
    • The Brage field (Faroe 14.3%): the infill well programme continues, with two producer-injector pairs in the Statfjord formation and one producer in the Fensfjord formation.  The first Statfjord producer and the Fensfjord producer are on stream.  The second Statfjord producer is to be put on stream during March and based on drilling results is expected to deliver production rates well above pre-drill expectations. 


The Ula Hub Area 

  • The development programme on the Tambar field (Faroe 45%) continues with the drilling of two infill wells and the installation of gas lift in three existing wells to increase overall field production. The two infill wells, which targeted undrained areas in the north and south of the field, have now been drilled and the results are promising, with both wells exceeding pre-drill expectations. The operator plans to bring the first well on stream this month and a second shortly thereafter. Initial production rates from the two wells are estimated to be in the range of 10,000 - 15,000 boepd (Faroe 4,500-6,750 boepd). It is expected that the overall development programme including gas lift will extend field life by up to 10 years, contributing to lower unit operating costs in the Ula hub area. The encouraging results from the infill campaign will be used to refine the field model and plan further development of the Tambar reservoir.  
  • The Oda oil field (Faroe 15%) is being developed as a subsea tie back to the Ula platform (Faroe 20%), approximately 13 kilometres to the east. The project, which is both on schedule and within budget is now entering a busy offshore construction phase this spring with three wells being drilled in the field (two producers and one water injection well). First oil is scheduled for mid-2019, with gross plateau production expected to be 30,000 boepd (4,500 boepd net to Faroe). Production from the Oselvar field (Faroe operated 55%) is scheduled to cease in Q2 2018 to allow the Oda tie-in to be undertaken. Upon cessation of production the Oselvar owners (Faroe 55%) will receive a final compensation payment, dependent on the Oselvar field production level at shut down. 
    • On the Ula field (Faroe 20%), the operator continues to mature targets for a new infill campaign which is expected to commence in 2019. Potential infill targets include wells to expand the use of WAG (water alternating gas) injection to increase recovery, the deeper Triassic reservoir which has only one well in production today, as well as near field discoveries such as Ula North. The 4D seismic survey successfully acquired in 2017 will provide important new information when processing is completed in Q2 this year. A number of significant upgrades to the field facilities are also under way which will support long term production.  
    • On the Blane Field (Faroe 44.5%), following the successful completion of the subsea upgrades in 2017 aimed at improving reliability, the operator is now considering infill targets.  

The Njord Hub Area  

  • In December 2017 a PDO was submitted for the Fenja field in the Greater Njord Area (Faroe 7.5% following  completion of the Suncor transaction announced yesterday), comprising three horizontal production wells - one  gas injector well and two water injector wells - tied back to the Njord A floating production facility for processing  and export via the Njord B FSO (floating storage and offloading vessel).  The Fenja licence partners are planning to invest NOK 10.2 billion (approximately £900 million) with planned production start-up in Q1 2021 and a planned  field life of 16 years.  
  • The Njord Future project encompasses refurbishment of the Njord facilities for continued production and    development of the Njord and Hyme fields and upgrading and modifications to enable the Bauge and Fenja fields to be tied back. The Njord Future Project is progressing on schedule and within budget. In 2018, key milestones include installation of blisters on all four columns, installation of column top extensions and deck boxes. Trusswork reinforcement work is also ongoing. Current timing is for the Njord A platform to be towed offshore during spring 2020. 
  • The Bauge development project is also progressing on schedule and within budget. Contracts for marine and    drilling operations are currently being progressed.  
  • Njord and Hyme is expected to recommence production in Q4 2020 followed by first oil from Bauge shortly    thereafter. 
  • The table set out below provides an illustrative development project matrix for the committed and ongoing development project as well as for the operated and uncommitted Brasse project. 
Illustrative Development Project Metrics 
Field WI(%)  Prodstart Production 1)Net boepd  ReservesNet mmboe Capex 2)Net (£m) Opex($/boe) 
Oda 15.0

10 – 15
Njord   and Hyme 7.5



10 – 15




6 – 10

Fenja   3)



10 – 15
Brasse 4) 50.0

10 – 20

1) Target Plateau Rate 

2) From PDO date converted from NOK assuming a NOK/GBP rate of 11.0 

3) The reduction in the participating interest of Fenja to 7.5% remains subject to approval by Norwegian Authorities 

4) Brasse is less mature than the committed projects. Capex and opex levels depend on development concept and commercial terms for tie-back   

Exploration & Appraisal - High impact and near field exploration and appraisal programme continuing 

  • The Iris/Hades well (Faroe 20%) spud in November 2017, targeting two separate formations, one Cretaceous and the other Jurassic. Well results are expected in the coming weeks. 
  • The Fogelberg appraisal well (Faroe 28%) commenced drilling in February 2018 with the main objective of narrowing the range in the resources estimate of between 105 and 530 bcf (between 19 and 116 mmboe including the condensate) and to provide additional information for development planning. 
  • In H2 2018, Faroe expects to drill the operated Rungne (40%) exploration well. Rungne is located in licence PL825 immediately north of the Oseberg field in the Northern North Sea. The primary target will be the Middle Jurassic Oseberg Formation, with secondary targets in the Etive, Ness and Tarbert formations. The unrisked gross resources (100%) are estimated to be c. 70 mmboe. Work is ongoing to secure a rig for this drilling operation. 
  • The Cassidy exploration well (Faroe 15%) is also expected to be drilled in H2 2018, back-to-back with the production wells in Oda. Cassidy sits within the PL405 Oda licence to the north of Oda in the Southern North Sea. The well will target a prospect with the same Jurassic Ula formation level as the Oda field with gross unrisked potential of c. 50 mmboe. 
  • Two further exploration wells have been committed to recently - the Statoil operated Pabow prospect (Faroe 20%) and the Wintershall operated Yoshi prospect (Faroe 30%): 

o  Pabow is located on the western flank of the Stord Basin in licence PL870 to the east of the Utsira High and the Ringhorne East field in the Northern North Sea. The primary target in the Lower Jurassic Statfjord Group has a gross (100%) unrisked gas resources potential of c. 70 mmboe, and with considerable upside. The well is expected to be drilled in late 2018 or in 2019. 

o  Yoshi is located in licence PL 836 S immediately to the south-west of the Smørbukk South Field and West of the former Faroe Maria Field in the Norwegian Sea. The Jurassic Fangst Group reservoirs, proven and effective in numerous nearby fields, are expected to be present within a fault bounded structural closure on the licence. Gross (100%) unrisked resources of c. 30 MMboe have been estimated. The well is expected to be drilled in 2019. 

  • Progress is being made in the seismic interpretation of Brasse and the evaluation of the potential for adding further resources to Brasse in northern and eastern directions. A possible exploration and appraisal well to target this area is currently being considered for drilling in late 2018 or 2019. 

Financial - Faroe ended 2017 in a robust and differentiated financial position with significant cash reserves, enhanced production cashflow and an undrawn seven year RBL facility of $250 million

  • 2017 year-end unaudited cash was approximately £149 million and net cash (net of the 2017 NOK Bond) was £75    million
  • 2017 exploration and appraisal capex was approximately £48 million pre-tax (£11 million post-tax) and development and production capex was approximately £96 million (unaudited)
  • 2018 exploration and appraisal capex is estimated to be approximately £80 million pre-tax (£20 million post-tax)        and development and production capex approximately £175 million, split as follows:

o  Njord Area:    £57 million

o  Ula Area:         £96 million

o  Brage Area:    £22 million

  • 2018 decommissioning costs is expected at approximately £13 million
  • Opex in 2018 is expected to be between $23-27 per boe
  • 2018 hedging programme in place to underpin value:

o  approximately 70% of gas production hedged on a post-tax basis at average price of 42.5p/therm, mainly with put options

o  approximately 60% of post-tax oil production hedged at $57/bbl, all with put options

- Ends -


Site Visit 

On 20 February and 21 February 2018, Faroe will be hosting a sell-side analyst visit to its offices in Stavanger. The site visit will include presentations by Faroe management and operational team on the producing field performance, the development projects and the exploration drilling programme. 

For further information please contact: 

Faroe Petroleum plcGraham Stewart, CEO Tel: +44 (0) 1224 650 920
Stifel Nicolaus Europe Limited  Callum   Stewart / Nicholas Rhodes / Ashton Clanfield  Tel:   +44 (0) 20 7710 7600 
BMO   Capital Markets   Neil Haycock /   Tom Rider / Jeremy Low  Tel:   +44 (0) 207 236 1010 
FTI   Consulting Edward   Westropp / Emerson Clarke  Tel:   +44 (0) 20 3727 1000 


John Wood, UK Asset Manager of the Company with over 15 years' experience of the oil and gas industry and who holds an M.Sc in Petroleum Engineering from Imperial College, has read and approved the production and development disclosure in this regulatory announcement.

Andrew Roberts, Group Exploration Manager of Faroe Petroleum and a Geophysicist (BSc. Joint Honours in Physics and Chemistry from Manchester University), who has been involved in the energy industry for more than 25 years, has read and approved the exploration and appraisal disclosure in this regulatory announcement.


The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014, and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations. 



Table 1 

Production   data 
Preliminary   2017 Net Economic Production1 
Field  Working Interest   boepd  Notes 
Ula  20.0%  1,610 
Tambar  45.0%  1,740 
Oselvar  55.0%  1,210  The field is expected to   shut down in April 2018. The pipeline between Oselvar and Ula will be cut to   allow Oda to connect to the Ula facility, for which the Oselvar owners are   being compensated 
Trym  50.0%  4,540  Production guidance for   2018 assumes that Trym will recommence production in full at the beginning of   April 2018 
Brage  14.3%  1,240 
Ringhorne Øst  7.8%  590 
Total Norway  10,930 
Schooner & Ketch  60.%  2,220  The fields are expected   to permanently cease production in Q3 2018 
Blane  44.5%  880  1Includes 210 boepd of production attributable to the acquired   14% of the Blane field interest, where Faroe received the economic benefit of   production from 1 January 2017 but can only account for it from the   completion of the acquisition on 31 October 2017 
Other UK  270 
Group  14,300  1Accounting production, was 14,100 boepd 




Table 2 

Proven   plus Probable (2P) Reserves at 1 January 2018 1 
Field  Working Interest  Liquids (mmstb)  Gas (bcf)  Total (mmboe) 
Ula  20.0%  9.7  0.0  9.7 
Oda  15.0%  6.8  2.5  7.2 
Tambar  45.0%  9.8  15.7  12.4 
Trym  50.0%  0.6  11.9  2.6 
Brage  14.3%  2.5  3.3  3.1 
Ringhorne Øst  7.8%  2.3  0.0  2.3 
Brasse  50.0%  25.0  34.1  30.7 
Njord  7.5%  6.2  37.6  12.5 
Hyme  7.5%  0.5  0.4  0.6 
Bauge  7.5%  4.6  4.9  5.4 
Fenja 2  7.5%  5.6  8.3  7.0 
Other  0.2  0.3  0.3 
Total Norway  73.9  119.1  93.7 
UK (incl. Blane)  3.4  3.4  4.0 
Group  77.3  122.5  97.7 

1 As adjusted for the disposal of a 17.5% participating interest in Fenja 

2The reduction in the participating interest of Fenja to 7.5% remains subject to approval by Norwegian Authorities  

Reserves Assessment  

This table presents the 2P Reserves net to Faroe per field and split into oil and liquids reserves and gas reserves. To assess the reserves, the Company has used the definitions and guidelines set out in the 2007 Petroleum Resources Management System prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). 



"2C Resources"  Best   estimate of Contingent Resources 
"bcf"  billions   of standard cubic feet 
"boe"  barrel of oil equivalent 
"boepd"  barrels of oil equivalent per day 
"capex"  capital expenditure 
"Contingent Resources"  Those quantities of petroleum estimated,   as of a given date, to be potentially recoverable from known accumulations by   application of development projects but which are not currently considered to   be commercially recoverable due to one or more contingencies. Contingent   Resources are a class of discovered recoverable resources 
"E&A"  exploration and appraisal 
"FSO"  Floating storage and offloading vessel  
"mmboe"  millions of barrels of oil equivalent 
"mmstb"  millions of barrels of stock tank oil 
"net"  the portion that are attributed to the equity interests of Faroe 
"Opex"  operating expenditure 
"Proved + Probable Reserves" or "2P"  those additional Reserves which analysis of geoscience and   engineering data indicate are less likely to be recovered than Proved   Reserves but more certain to be recovered than Possible Reserves. It is   equally likely that actual remaining quantities recovered will be greater   than or less than the sum of the estimated Proved plus Probable Reserves   (2P). In this context, when probabilistic methods are used, there should be   at least a 50% probability that the actual quantities recovered will equal or   exceed the 2P estimate 
"PDO"  The   Plan for Development and Operation 
"reserves"  reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development   projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria:   they must be discovered, recoverable, commercial, and remaining (as of the   evaluation date) based on the development project(s) applied. Reserves are   further categorized in accordance with the level of certainty associated with   the estimates and may be sub-classified based on project maturity and/or   characterized by development and production status 
"WAG"  water alternating gas 


Notes to Editors 

The Company has, through successive licence applications and acquisitions, built a substantial and diversified portfolio of exploration, appraisal, development and production assets in Norway, the UK and Ireland.  

Faroe Petroleum is an experienced licence operator having operated several exploration wells successfully in Norway and the UK and is also the production operator of the Schooner and Ketch gas fields in the U.K. Southern Gas Basin and the Trym and Oselvar fields in the Norwegian North Sea.  Faroe also has extensive experience working with major and independent oil companies both in Norway and in the UK. 

The Company's substantial licence portfolio provides a considerable spread of risk and reward.  Faroe has an active E&A drilling programme and has interests in a portfolio of producing oil and gas fields in the UK and Norway, including the Schooner and Ketch gas fields and the Blane oil field in the UK, and interests in the Brage, Ringhorne East, Ula, Tambar, Oselvar and Trym fields in Norway.  In December 2016 the Company completed the acquisition of a package of Norwegian producing assets from DONG Energy including interests in the Ula, Tambar, Oselvar and Trym fields. Full year average production for 2018, is estimated to be between 12-15,000 boepd.   

In November 2013 and March 2014 Faroe announced the Snilehorn and Pil (Fenja) discoveries in the Norwegian Sea in close proximity to the Njord and Hyme fields.  In July 2016 the Company announced the Brasse discovery, next to the Brage field, and the Njord North Flank discovery, next to the Njord field, both in Norway.  In February 2018, the Company announced the sale of part of its interest in the Fenja field. 

Norway operates a tax efficient system which incentivises exploration, through reimbursement of 78% of costs in the subsequent year.  Faroe has built an extensive portfolio of high potential exploration licences in Norway which, together with its established UK North Sea positions provides the majority of prospects targeted by the Company's sustainable exploration drilling programme. 

Faroe Petroleum is quoted on the AIM Market of London Stock Exchange.  The Company is funded from cash reserves and cash flow, and has access to a $250million reserve base lending facility, with a further US$100million available on an uncommitted "accordion'' basis.  Faroe has a highly experienced technical team who are leaders in the areas of seismic and geological interpretation, reservoir engineering and field development, focused on creating exceptional value for its shareholders. 



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