Faroe Provides 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.”

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. 
  • 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

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.

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 (1) (Faroe 20%) and the Wintershall operated Yoshi prospect (2) (Faroe 30%).
  • 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:
  • Njord Area: £57 million
  • Ula Area: £96 million
  • 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:
  • approximately 70% of gas production hedged on a post-tax basis at average price of 42.5p/therm, mainly with put options
  • approximately 60% of post-tax oil production hedged at $57/bbl, all with put options

(1) 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.

(2) 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.