24 March 2015

FAROE PETROLEUM PLC

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

Final Results for the Year Ended 31 December 2014

Faroe Petroleum, the independent oil and gas company focusing principally on exploration, appraisal and production opportunities in Norway and the UK, announces its audited results for the year ended 31 December 2014.

Highlights

Exploration - successful year with significant Pil & Bue discoveries  

·      Significant Pil oil discovery in Norwegian Sea announced in March 2014, substantially  larger than pre-drill expectations, followed by further successful discovery with the Bue side-track (combined 20-50 mmboe net to Faroe's 25% equity)

·      An oil and gas discovery, not expected to be commercial on a stand-alone basis, made on Novus (close to producing Heidrun field) and condensate discovery on Solberg, announced in January and April 2014 respectively

·      Butch East and Butch South West exploration wells announced as unsuccessful in May and July 2014 following  the 2011 Butch Main oil discovery, which is now being planned for development

·      Continued success in exploration licence rounds including awards of five new exploration licences (under the 2014 Norwegian APA Licence Round, announced in January 2015), three of which are in the Pil area

Production & Reserves - strong production performance and increase in reserves and contingent resources

·      Average Economic Production(1) at 9,106 boepd (2013: 6,059 boepd) - at the upper end of guidance, with Njord and Hyme back on production, on schedule, and performing better than forecast

·      Average Accounting Production1 at 6,579 boepd (2013: 5,871 boepd)

·      Acquisition of operated interests in Schooner & Ketch gas fields (Faroe 60%) in the UK completed in October 2014, boosting gas production and improving tax efficiency through utilisation of carried forward tax losses

·      Reserves increased by 13% with closing reserves at 30.6 mmboe (2013: 27.2 mmboe)

·      Contingent resources increased by 49% to 109 mmboe (2013: 73 mmboe)

Financial - strong balance sheet and positive cashflows from operations, despite impairments

·      Cash and net cash of £92.6 million and £69.6 million respectively at 31 December 2014 (31 December 2013: £40.6 million cash and net cash) £23.0 million drawn for Schooner and Ketch acquisition against the £160 million ($250 million) Reserve Based Lending facility

·      Exploration Finance facility renewed and up-scaled to approx. £130 million (NOK1.5 billion) in September 2014

·      Revenue £129.2 million (2013: £129.4 million) and EBITDAX £59.1 million (2013: £80.1 million) - reduction in EBITDAX principally due to lower realised price per boe at $71 (2013: $105)

·      Loss after tax £55.0 million (2013: profit of £14.1 million) after pre-tax impairment charges of £38.5 million (2013: £2.1 million) and exploration write-offs of £131.7 million (2013: £15.4 million)

·      Pre-tax exploration and appraisal capex of £87.2 million (£23.0 million post-tax) (2013: £73.0 million pre-tax, £24.8 million post-tax) and development and production investments (including acquisitions) of £48.3 million (2013: £48.5 million)

·      Successful share placing in June 2014 raised £65 million (gross) - providing finance to accelerate exploration, appraisal and development activities and target further production acquisition opportunities

Outlook - active, fully funded exploration programme and well positioned for further acquisitions

·      Forward exploration and appraisal programme fully funded from existing resources

·      Four high impact exploration wells planned for 2015, including two follow up wells on the Pil discovery, all of which benefit from Norway's 78% exploration tax rebate

·      2015 exploration and appraisal capex is estimated to be approximately £100 million pre-tax (£26 million post-tax) and development and 2015 production capex is estimated to be approximately £17 million

·      Production guidance for 2015 of 8,000-10,000 boepd, split 58% liquids (oil and condensate) and 42% gas

·      58% of 2015 Post-tax Production hedged - average floor at $89 per barrel for oil and £0.50 per therm for gas, predominantly with put options at the mid-point of our 2015 production guidance.  Faroe aims to be cash-neutral in 2015 at an average Brent oil price of $60/bbl and gas price of £0.45 per therm with an expected average opex of approximately $30/boe

·      In strong position to capitalise on market conditions with the aim of building value through further selective value-enhancing production acquisitions

(1)      Economic Production in 2014 includes production from the acquired Schooner (53.1%) and Ketch (60%) fields from 1 January 2014 (the effective date).  Accounting Production excludes production between the effective date and date of completion on 9 October 2014.

Graham Stewart, Chief Executive of Faroe Petroleum, commented:

"We are pleased with the progress of the Company in 2014 despite the low oil price environment.   Operationally, the year delivered excellent results for the business with significant exploration success at the Pil and Bue wells, sustained production coming in at the upper end of expectations with Njord and Hyme back on production, and the acquisition of the Schooner and Ketch UK gas fields.  With a reserves increase of 13% and a 49% increase in contingent resources in the year, the Company has again proved that its strategy to convert exploration prospects into resources and convert resources to reserves is working effectively.

"Our Norwegian position is now one of the most significant of any UK independent E&P company and, despite the challenging market conditions, the Company is set for another year of growth, with a fully-funded drilling programme of low cost, high impact exploration wells, all of which will benefit substantially from Norway's tax-based exploration financing incentives.

"In the current low oil price environment, there is much focus on both cost and financial strength.  Faroe is particularly robust despite low oil prices, due to a combination of factors including: a significant cash position and substantially undrawn debt facilities; sustained cash flow from a balanced, low-opex and substantially hedged oil and gas production portfolio; and, following the sale in 2014 of our interest in Glenlivet, the absence of any substantial development capital commitments.  Consequently, Faroe is well placed to deliver continuing commitment to its ongoing work programme and to capitalise potentially on attractive asset opportunities which may become available in the period ahead."

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CHAIRMAN'S AND CHIEF EXECUTIVE'S STATEMENT

We are pleased to announce the audited results for the year ended 31 December 2014. 

During the year we made the significant Pil & Bue discoveries in Norway, acquired interests in, and became operators of, the Schooner and Ketch gas fields in the UK, and raised £65 million through a share placing in June 2014.  Production rates and cash flow from our diverse asset base were strong with economic production at 9,106 boepd.  Market conditions are challenging with current low oil prices but Faroe's exploration-led/production-backed strategy remains unchanged.  With a robust balance sheet, significant credit facility headroom and a diversified high-quality portfolio Faroe is well positioned amongst its peers to make strong progress in the coming period.

Market conditions

The difficult market conditions caused by low oil prices have been extensively covered in the media.  Brent started the year at $111 per barrel and remained above $100 for the first eight months of the year.  In September it slipped below the $100-level and finally ended the year at $57, a five and a half year low, and a 50% fall from the June 2014 peak of $115.  The consequences of the low oil price for the E&P sector have been severe and are likely to continue well into 2015.  Across the board, investment plans have been slashed and cost-saving measures implemented.  An unfortunate consequence is significant job losses across the E&P and service sectors.   AIM-listed E&P stocks endured a difficult time in 2014 on the back of the falling oil price, with the AIM Oil & Gas Index falling by 47%.  Highly-leveraged companies will be in the spotlight in 2015 as banks are expected to reduce the commodity price decks that underpin borrowing facilities.  As a result of this and other factors consolidation is widely expected to take place in the sector.

European gas prices also declined during the course of the year, although not to the same extent as oil, starting the year at 66p per therm and finishing at 49 per therm.  The price initially fell throughout the first half of 2014, reaching a low of 35p per therm in the summer.  A combination of tight supply, largely because of colder weather, and concerns over Russia impacting Ukrainian gas supplies to Europe, led to a partial recovery in the second half of 2014.

One of the positives to emerge from the collapsing oil price for the E&P sector are clear signs of reduction in costs associated with the drilling of wells, developments and operations of producing fields.  Governments have also taken action to boost the industry and Faroe welcomes the Budget announcements made by the UK Chancellor on 18 March 2015, particularly the introduction of the investment allowance and the reduction of the supplementary tax charge from 32% to 20%.

Prudent financial management

Faroe has always maintained a prudent approach to financial management, and 2014 was no exception.  Whilst delivering an active and successful exploration programme as well as acquiring production assets, the Company has ensured at all times that its balance sheet remains strong.  This has been achieved through a combination of raising equity, monetising discoveries, optimising tax efficiencies, low gearing, modest commitments to development expenditure and spreading risk through a portfolio approach.

In order to maintain the exploration and growth momentum which has been built over recent years, the Company raised new equity finance in June 2014.  Strong support was received from existing and new investors with £65 million (gross) raised in an oversubscribed share placing.  The proceeds ensure that Faroe is funded to accelerate exploration and appraisal activities and target further potentially attractive production acquisition opportunities.  In November 2014 Faroe announced the sale of its 10% interest in the undeveloped Glenlivet gas field, west of Shetland, in return for a gross consideration of £10 million (£3 million of which is deferred and contingent upon field performance).  The Glenlivet sale eliminated Faroe's exposure to the significant capital expenditure of this substantial field development, scheduled for commencement in 2015, and realised a cash sum for reinvestment.

Faroe continues to benefit from the substantial tax incentive provided for exploration activity in Norway whereby the Company is able to reclaim 78% of exploration expenditure annually.   In the UK, Faroe benefits from its carried forward tax losses (£67.6 million at December 2014), further improving the cash flow from production.  With the acquisition of majority stakes in Schooner and Ketch in October 2014, the Company expects to utilise fully its UK carried forward tax losses over the next few years.

The Company finished the year with a cash balance of £92.6 million compared to £40.6 million at the previous year end.  In light of the current low oil prices, the Company has reviewed its investment plans and overheads.  Cost savings have been identified and measures implemented to preserve cash.  At prices averaging $60 per barrel for oil and 45 pence per therm for gas, the Company aims to run a cash-neutral budget in 2015.  Due to an effective hedging programme and the inherent tax offset mechanism in Norway, the Company's projected 2015 cash balance is not overly sensitive to commodity price levels below these.

Faroe's fundamental financial and commercial discipline has allowed it to build a strong business delivering one of the most attractive and high-potential exploration programmes in the sector. 

Consistent strategy

Faroe's strategy is to grow reserves and resources through exploration and appraisal drilling. This consistent strategy and business model, focused on exploration and monetisation, underpinned by good quality production, a strong balance sheet and financial discipline, has again delivered excellent results in the year. The Pil and Bue discoveries in Norway add between 20 and 50 mmboe net to the Company's contingent resources.  With two additional follow up wells scheduled for 2015, this is potentially Faroe's greatest exploration success to date, and offers real scope for further considerable growth.

During the year, Faroe's contingent resources increased by 49% from 73 mmboe to 109 mmboe, largely due to the Pil and Bue discoveries.  The Company achieved a reserves increase of 13%, with reserves standing at 30.6 mmboe at 1 January 2015 (1 January 2014: 27.2 mmboe) with 86% of reserves attributable to fields already on production.  This growth in reserves and resources substantiates Faroe's consistent strategy of growth through exploration and appraisal drilling.

High-potential exploration programme

The year began with Faroe being awarded 10 new exploration licences from the APA 2013 licensing round in Norway in strong completion with other companies. This was the Company's most successful licensing round to date and the largest number of licences awarded in the 2013 APA round, equal in number with Statoil and Centrica.  During the year the Company was also awarded three licence options in the Celtic Sea in Ireland and two North Sea licences in the UK 28^th Round.  Since the year end, Faroe has been awarded a further five licences in the Norway 2014 APA Round, three of which are in the now much sought after area surrounding the large Pil discovery.  The organic route of applying for and winning exploration licences through licensing rounds has proven to be very cost effective for the Company.  High-grading of exploration prospects in our portfolio is a continuous process, consistently providing feedstock for a sustained drilling programme, which has averaged five exploration wells per year over the last three years.  This same selective process also resulted in 14 licences being relinquished or sold, and relinquishment decisions made on a number of others.

Faroe was one of the most active and successful explorers in the Norwegian sector in 2014.   Following the Snilehorn discovery announced in November 2013 the Company has drilled six exploration wells, all in Norway.  Of these wells, Pil, Bue and Solberg were discoveries with combined estimated contingent resources of between 21 and 54 mmboe net to Faroe.  The operated Novus well was a small discovery, not expected to be commercial on a stand-alone basis, while Butch East and Butch South West (Faroe 15%) did not add further volumes to the 2011 Butch Main oil discovery.

Faroe's Norwegian position is now one of the most significant and attractive of any UK independent E&P company and includes four wells scheduled to be drilled in Norway in 2015.  Two of the wells are follow-up wells to the Pil and Bue discoveries while the other two wells are the Total-operated Shango (Skirne East) well near the producing Skirne field and the Statoil-operated Bister well in the Greater Njord Area.  The Shango well, the first of our four wells in 2015, spudded on 13 March 2015.

Good quality production portfolio

The Company's diverse and good quality production portfolio remains core to our strategy.  Cash flow from production is the principal source of funding for the Group's ongoing exploration investment programme.

Our latest production acquisition was announced in April 2014 when Faroe entered into an agreement to acquire a 60% operated interest in the Ketch Field and a 53.1% operated interest in the Schooner Field (Faroe already owned a 6.9% interest in Schooner), both normally unmanned platforms, in the UK Southern North Sea.  The consideration was an initial sum of £35 million, which was reduced to £24.6m after taking into account net revenue from the fields from the transaction effective date of 1 January 2014.  This acquisition, which was completed in October 2014, established Faroe as an operator of producing assets in the UK North Sea and provides the opportunity to add value to these fields over time, as both assets offer considerable technical upside. 

Following structural reinforcement work, the Njord and Hyme fields were brought back on stream on schedule in July 2014 which further boosted production. Including the Schooner and Ketch production from the effective date, Faroe had net average economic production of 9,106 boepd in 2014.  Accounting production (which includes Schooner and Ketch production from the date of completion) was 6,579 boepd.  The average realised price per boe was $71.4 and average opex per boe was $33.5 generating EBITDA per boe of $37.9.

Faroe's production is spread across a balanced and high quality portfolio of assets with an even split between Norway and UK and between oil and gas/condensate.  With forecast average opex per barrel in 2015 of $30 and 58% of post-tax production hedged predominantly with $90 per barrel and 50 per therm put options for oil and gas respectively, as well as carried forward UK tax losses, Faroe's production is expected to continue to provide substantial cash flow for the Company, even if the current low oil prices continue throughout 2015.

Board, broker changes and listing

On 1 September 2014 Ms Jorunn Saetre was appointed to the Board as an Independent Non-Executive Director. Jorunn is Norwegian and a chemical engineer by background.  She progressed to senior positions with Halliburton in Norway, Europe and the USA, over a 30 year period, including the role of Head of Halliburton's overall Scandinavian operations.  She is currently a board director of global oil and gas service company AGR Group ASA, Rig Team Leader and Head of AGR's Stavanger office.  Her knowledge of the sector and operational experience are first rate and we welcome her to the Board.  Hanne Harlem stepped down from the Board after serving for four years with Faroe, in order to meet the demands of her full time role with the City of Oslo.  We are very grateful to Hanne for her diligence, hard work and significant contribution during her time with the Company.

On 15 September 2014 it was announced that RBC Capital Markets were appointed as joint broker and Oriel Securities Limited, the Company's existing joint broker, became the Company's Nominated Adviser ('Nomad').  Panmure Gordon (UK) Limited concurrently stepped down as the Company's joint broker and Nomad having provided eight years of first class advice and broking services and we thank them for all of their support and guidance.  On 2 March 2015 it was announced that following an internal reorganisation, Stifel Nicolaus Europe Limited had taken over as NOMAD from Oriel Securities Limited.

As the business matures, and as and when markets improve, the Directors believe it would be appropriate for the Company to move to the Main Market of the London Stock Exchange.

Outlook

The recent exploration successes combined with the ongoing high-grading of exploration prospects in our wider portfolio have generated a strong programme of four high-potential wells scheduled to be drilled in 2015.  The wells will target considerable resource potential with a spread of risk and cost exposure, all to be fully funded from our existing cash, production cash flow and our Norwegian exploration finance facility, in order to benefit from Norway's 78% tax incentive for exploration.

In the period ahead, we aim to make good progress in adding further contingent resources and in converting existing contingent resources to proven reserves.  With our strong balance sheet, hedged and low-opex production, and with no material development commitments in 2015, we are also well placed to continue building our producing portfolio through a combination of potential acquisitions and asset swaps. 

Faroe Petroleum has an outstanding team of professionals, committed to creating value and achieving success for stakeholders.  We are very grateful for their commitment and outstanding achievements and we intend to take full advantage of our solid technical and commercial expertise going forward.  The Company is well positioned for significant growth despite the headwinds currently facing our industry and together with our team, we look forward to the period ahead with excitement as Faroe pursues its active programme.

REVIEW OF ACTIVITIES

Faroe Petroleum's focus is on exploration, appraisal and production opportunities in Norway and the UK where the Company has built a substantial portfolio over many years. In addition, the Company has recently initiated a new entry to Ireland, as a low cost exploration project.

Exploration

Portfolio overview

The Company continues to be among the most successful independents in winning prime quality exploration acreage.  During 2014, the Company was awarded a total of 15 new licences of which ten were in Norway, two in the UK and three in Ireland.  At year end, the exploration portfolio consisted of a total of 50 exploration and appraisal assets following a continuous programme of active management, relinquishments and high-grading. In January 2015, an additional five new licences were awarded in Norway in the Awards in Predefined Area (APA) licensing round.  2014 was a very active year of drilling with a record six wells completed in the year.  Four wells are scheduled for drilling in 2015, all in Norway.

The Company's principal exploration focus in 2014 was Norway, which offers very significant resource potential backed by substantial tax incentives whereby 78% of exploration expenditure can be reclaimed annually.  Faroe's Norwegian portfolio contains a diverse range of risk/reward profiles and maturity and extends from the shallower water region in the southern part of the Norwegian North Sea, across the Norwegian Sea and into the Arctic region with our Barents Sea licences.  At the year end Faroe held 17 exploration and appraisal licence areas in the Norwegian North Sea, 13 in the Norwegian Sea and three in the Barents Sea.

Exploration in the UK Atlantic Margin is no longer a principal focus area for the Company notwithstanding six exploration wells drilled since 2009 of which two were discoveries.  Given the relatively low regional success record in recent years and the high costs associated with drilling in deep water, we believe that only a small proportion of the Company's resources should be utilised in this area.  At the year end Faroe held seven licence areas in the UK Atlantic Margin which has since been reduced to three.  In the UK Central North Sea the Company held five exploration licences at the year end and is focussing on areas around the undeveloped Perth-Dolphin-Lowlander fields and other opportunities close to existing infrastructure.

In October 2014 the Company was awarded three new licence options in Ireland located in the southern margin of the North Celtic Sea basin, targeting the substantially un-explored Triassic Play.  The objective in this area is to exploit low-cost reprocessing technology to de-risk prospects ahead of making any significant further cost commitments.  The cost of any wells which Faroe may eventually drill here would be farmed out to third parties - Faroe currently holds 100% of the licence equity.

Drilling operations

During 2014 Faroe drilled one operated and five non-operated wells in Norway, three of which were successes.

The Norwegian Sea Pil discovery (Faroe 25%), first announced in March 2014, is located 33 kilometres south west of the Njord production facility (Faroe 7.5%).  Exploration well 6406/12-3S encountered a gross hydrocarbon-bearing reservoir section of approximately 135 metres of oil and 91 metres of gas in the Jurassic reservoir of the Rogn Formation.  The well was tested and flowed at a stable rate of 6,710 bopd of 37° API oil from a 56/64" choke providing clear evidence of a prolific reservoir.  This formation has proved to be a very effective reservoir at the Shell-operated Draugen oil field, located 60 kilometres to the north east.  The range of recoverable resources for the Pil discovery has been estimated by the operator, VNG Norge AS, to be between 72 and 172 mmboe (18 to 43 mmboe net to Faroe).   A successful side-track to prove the lateral extent of the Pil discovery was announced in May 2014 followed by a successful side-track into the neighbouring Bue oil and gas prospect announced in July 2014.  The operator estimates that the separate Bue accumulation contains between 6 and 25 mmboe bringing the combined gross estimate of resources for Pil and Bue to between approximately 80 and 200 mmboe (20 to 50 mmboe net to Faroe), of which around 80% is estimated to be oil and condensate.

The Novus exploration well 6507/10-2S (Faroe 30%), operated successfully by Faroe, located nine kilometres from the producing Statoil-operated Heidrun field, targeted the Jurassic reservoirs of the Garn, Ile, and Tilje formations.  The main well bore targeting the Novus West horst block encountered a 12 metre net gas column and a 12.5 metre net oil column in a high quality, thicker than expected Garn formation.  The Ile and Tilje formations were encountered in line with expectations but were found to be water wet.   Extensive data gathering was undertaken including pressure and fluid samples from the main reservoir zones, and the preliminary volumetric estimate of the size of the discovery was between 6 and 15 mmboe recoverable gross (1.8 to 4.5 mmboe net to Faroe) which is unlikely to be commercial on a stand-alone basis.

The Solberg well 6407/1-7 (Faroe 20%) commenced in February 2014 to assess the lateral extent and size of the Lower Cretaceous Rodriguez discovery announced by Faroe in January 2013.   The well encountered a 12 metre net pay interval of similar fluids to those encountered in the Rodriguez well, in two sandstone intervals and in better reservoir quality than expected.  The gross interval encountered was 16 metres.  The subsequent down-dip side-track 6407/1-7A was drilled to the north east to a total depth of 3,311 metres below sea level, and encountered two sandstone intervals with total net vertical thickness of seven metres in a gross reservoir section of 13 metres.   The Solberg well has confirmed the play model and that 3D seismic amplitude can be used to identify pay in lower Cretaceous sands in this area.  Analysis is continuing in order to assess the commercial potential of the discovery prior to committing to any further appraisal drilling.

Based on the significant discovery of light crude oil encountered in the 2011 Butch Main discovery (Faroe 15%) the joint venture committed to drill the adjacent Butch East and Butch South West prospects, prior to proceeding towards field development.  The two wells were drilled back-to-back, commencing in December 2013, and tested the eastern and south western sides of the large central Butch salt structure.  In July 2014, it was clear that both wells had failed to encounter hydrocarbons.  The Butch operator (Centrica) is currently working on a development plan for the Butch Main field, with concept selection expected in 2015 and field development plan submission planned for 2016.

Licence rounds

In January 2014 Faroe was awarded 10 new exploration licences, including two operatorships, under the 2013 Norwegian APA Licence Round.  The 10 licences equated to the largest number awarded in the APA round, equal only with Centrica and Statoil.

In addition to the three licences awarded in the Irish Celtic Sea, in November 2014 Faroe was awarded two new licences in the UK 28th Licensing Round.  These are located in the Central North Sea extending the acreage position around the strategically important Perth-Dolphin-Lowlander area. 

In January 2015 Faroe announced that it had been awarded a further five new prospective exploration licences in Norway, including one operatorship, under the 2014 APA Licence Round.  These awards included three new licences in the now much sought after area surrounding the Company's Pil and Bue discoveries, with Shell, Statoil and Centrica each operating one licence, and two licences in the North Sea as extensions to existing exploration licences.  Work has also started on the Norwegian 23^rd licensing round which will focus on the Barents Sea, where the Company has identified several prospective opportunities.

Production and pre-development

Production

During 2014, Faroe generated net average accounting production of 6,579 boepd (2013: 5,871 boepd) with net average economic production of 9,106 boepd (2013: 6,059 boepd) following the acquisition of the Schooner and Ketch interests, announced in April 2014 and completed in October 2014.  The Njord and Hyme fields were brought back on stream in July and Group production is now generated from a well balanced portfolio of oil and gas assets in the UK and Norway (58% liquids and 42% gas in 2014) with the principal fields being Njord, Hyme, Brage and Ringhorne East in Norway and Schooner, Ketch and Blane in the UK.

In April Faroe acquired a 60% operated interest in the Ketch Field and a 53.1% operated interest in the Schooner Field in the UK Southern North Sea gas basin (Faroe already owned a 6.9% interest in Schooner).  Schooner and Ketch are established gas fields each with potential to increase production, grow reserves and extend field life.  This acquisition establishes Faroe as an operator of producing assets in the UK North Sea and provides the opportunity to add value to these fields. 

In July 2013 the Njord and adjacent Hyme fields were shut in for repair and maintenance.  The deck structure of the Njord A floating facility was reinforced and in July 2014, as planned, the Njord and Hyme fields were successfully brought back onto production.  Production is expected to continue from the fields until mid-2016, whereafter further more extensive modifications to the facility are expected to be undertaken to extend facility life and capability.  The cost of the modifications and the length of time they will take to complete are still to be determined.  In the meantime, as a result of continued weight restrictions, Njord A will not be used to drill further development wells until the long term structural modifications have been completed. 

The Njord partnership is currently evaluating a number of scenarios for the long term further development of the Greater Njord Area with the potential to extend Njord's life by many years and to generate maximum reserves exploitation and value.  Considerable resources remain in the Greater Njord Area (currently encompassing Njord, Hyme and Snilehorn).  The area also contains significant exploration potential including the Blink and Boomerang exploration wells in the Pil licence and the Bister exploration well in the Hyme licence, all planned for drilling by Faroe this year.  Following a full scenario evaluation and incorporating exploration and appraisal results, the partnership will decide on the final development concept for the Greater Njord Area and commence the front-end engineering and design studies.

Pre-development

In line with our strategy to monetise discoveries, Faroe's stake in the Glenlivet gas field (Faroe 10%) was sold to the field operator Total for a combined consideration of £10 million, part deferred with £3 million of the total consideration contingent on future performance.  This west of Shetland gas development represents one of the most significant new pieces of infrastructure in UK waters, with a requirement for considerable capital investment which, in the current environment, would not have benefitted the Company. 

On Butch, the operator is working to complete field development studies and host platform studies to make a concept selection decision for the Butch Main discovery in 2015.  Three concepts are being studied: subsea tie-back to the Ula field, subsea tie-back to the Gyda field and a standalone development with a lease contract of a jack-up rig.  The plan is to submit the FDP in 2016.

On Fogelberg the current focus is on refining the development concept while awaiting the availability of sufficient free gas export capacity in the Åsegard transportation system before making a final commitment in the licence and starting preparations for an FDP submission.

A joint future development of the Perth (Faroe 34.26%), Dolphin (Faroe 34.62%) and Lowlander (Faroe 100%) fields ("PDL") took a significant forward step when the partners recently entered into a heads of agreement which addresses ownership alignment, a joint work programme and joint financing activity.  The plan is for the PDL fields to share the same dedicated production facilities creating economies of scale to allow a development to proceed, whilst providing a long-term hub for future projects in the area.  These fully appraised fields have a combined total of eleven wells drilled and are estimated to contain approximately 80 mmbbls of recoverable oil.

Reserves and Contingent Resources

The Company's internal estimate of Proven and Probable (2P) Reserves at 1 January 2015, prepared in accordance with the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers has been estimated at 30.6 mmboe (1 January 2014: 27.2 mmboe) - increasing reserves by 13% over the year.  The increase in 2P Reserves results from new reserves booked for the Snilehorn discovery, the Schooner and Ketch acquisition and technical revisions to existing assets, which more than compensate for the reduction in reserves as a result of the sale of Faroe's interest in the Glenlivet field and production over the year of 2.4 mmboe. 

At 1 January 2015, 2C Resources were estimated to be 109 mmboe representing an increase of 49% over the year (73 million boe at 1 January 2014).  New 2C Resources booked for the Pil and Bue discoveries and positive revisions of the Perth, Dolphin and Lowlander assets are the main reasons for the increase, partly offset by the conversion of the Snilehorn Contingent Resources to 2P Reserves.  The Butch field (Faroe 15%) which is scheduled for FDP submission in 2016 has been retained in Contingent Resources despite its mature technical definition.

FINANCE REVIEW

Overview

The Group generated cash flow from operations (not including the Norway tax rebate) during the year of £48.9 million (2013: £74.7 million), which, together with the Norwegian exploration financing facility, funded all exploration and development capital expenditure. Furthermore, the share placing in June 2014 raised £65.0 million, before expenses.  In the year the Company acquired operated interests in the Schooner and Ketch fields for net consideration of £24.6 million paid on completion.  The Group continued its considerable exploration activity, with a record six exploration wells drilled in 2014.  The Group ended the year in a strong cash position with £92.6 million of unrestricted cash (2013: £40.6 million).   At the year end £23.0 million of debt was drawn under the reserve based lending facility (2013: £nil).  Net cash at the year end was £69.6 million (2013: £40.6 million). 

Revenue averaged $71.4 per boe (2013: $105 per boe) after taking account of £18.4 million of Overlift that is included in 2014 revenue (see analysis of Cost of Sales in Note 3).  This fall in revenue on a boe basis, compared to 2013, was predominantly explained by the rapid fall in commodity prices during H2 2014.  Operating cost fell from $42.2 boe to $33.5 per boe and DD&A per boe fell $2.9 per boe to $21.1 boe (2013: $24 boe) mainly as a result of higher production in 2014.

Income statement

Revenue for the year was £129.2 million (2013: £129.4 million).  Cost of sales, including depreciation of producing assets, but before impairment charges, was £102.8 million (2013: £76.5 million).  Pre-tax impairment charges of £38.5 million (post-tax £29.2 million) (2013: £2.1 million and £0.5 million pre- and post-tax respectively) were incurred, primarily on Brage, East Foinaven and Schooner and Ketch.  With regard to the impairment on Schooner and Ketch, a significant portion of the consideration had internally been allocated to UK tax synergies. However, a separate deferred tax asset relating to carried forward UK tax losses was recognised in 2014 as a result of the transaction and consequently the tax synergies generated cannot be used in the calculation of the recoverable value of the asset. This is the main reason for the impairment charge. The other impairments were triggered by the significant decline in the oil price in 2H 2014 and also field performance.  These  impairment charges resulted in a gross loss for the year of £12.1 million (2013: £50.9 million gross profit).  EBITDAX for the year decreased 26% to £59.1 million (2013: £80.1 million).

Pre-tax exploration and evaluation expenses for the year were £139.4 million (post-tax: £47.2 million) (2013: £22.2 million and £7.8 million pre- and post-tax respectively).  This includes pre-award exploration expenses of £7.7 million and write-offs of licence-specific exploration and evaluation expenditure on previously capitalised licences where active exploration has now ceased (£131.7 million).  The exploration costs which were written off during the year related to relinquished licences and unsuccessful well costs on PL477 (Cooper), PL006C (SE Tor), PL645 (Novus), PL531 (Darwin), PL405 Butch and P1192 (North Uist) along with other exploration costs on a number of licences.

The Group's reported loss before tax was £165.8 million (2013: £10.0 million profit).  Loss after tax was £55.0 million (2013: £14.1 million profit).  The loss before and after tax year-on-year is due primarily to the higher exploration write-offs and impairment charges on producing assets in the year ended 31 December 2014.

Hedging

In line with Group policy approximately 62% of oil and gas sales (on a post-tax production basis) in 2014 were hedged, with realised hedging gains of £1.4 million (2013: £0.1 million). The cost incurred for the 2014 hedges was £1.0 million (2013: £1.2 million). 

At December 2014, the Group had entered into hedging arrangements covering approximately 52% of 2015 and 24% of 1H 2016 total expected oil and gas production (on a post-tax production basis).  The hedging arrangements are predominantly put options with floors at US$90 per barrel for oil and 50 pence per therm for gas.  Unrealised hedging gains for these open hedge contracts at December 2014 were £6.1 million (2013: £nil) based on mark-to-market calculations and are recognised as derivative financial assets.  These hedging gains are shown as Other Income in the Income Statement, net of hedging costs of £1.5 million.

Further hedging has been carried out after the year end for both oil and gas where the Company has bought swaps for relatively low volumes during recent price spikes.  The Company continues to monitor the commodity market and aims to extend the current hedging programme at opportune moments taking a layered approach to its hedging strategy.

Taxation

In Norway, the Company benefits from a 78% exploration and appraisal cost rebate, meaning that for every £1 spent the Norwegian Government will return 78p of eligible expenditure in the form of a rebate at the end of the following year, to the extent it is not offset against current year profits from producing assets.  The Company can also borrow under its Norwegian exploration financing facility 96% of the 78 pence per £1 rebate, thereby maximising equity leverage in Norwegian exploration wells and minimising the need to farm down to third parties.  The Norwegian tax system therefore ensures a very cost-effective fiscal environment in which to explore for hydrocarbons, and also cushions the cash impact of falling oil prices, as lower profits from production result in an increased tax rebate.

At December 2014 the Group had unrelieved tax losses in the UK of £67.5 million (2013: £77.9 million).  The unrelieved tax losses are available indefinitely for offset against future taxable profits, with the potential to materially enhance the Group's net results going forward.  Following the acquisition of Schooner and Ketch in 2014, it is now likely that the UK tax losses will be utilised in the coming years and consequently a deferred tax asset of £30.0 million relating to the carried forward tax losses in the UK has been recognised in 2014.

The amount of tax receivable at 31 December 2014 was £45.8 million (2013: £23.9 million) which is the tax refund on exploration expenditure in Norway net of taxable profits generated by the Norwegian producing assets.  The refund will be received in December 2015.  The tax credit in the Income Statement was £110.8 million (2013: £4.1 million) being the tax receivable plus a prior year adjustment of £46.3 million, the recognition of the deferred tax asset in the UK of £30.0 million, an increase in deferred tax liabilities and prior year adjustments in Norway of £27.3 million and exchange differences relating to the movement of NOK in relation to GBP of £7.2 million.

On 18 March 2015 the UK Chancellor announced a new investment allowance (IA) as well as reductions in the supplementary tax charge to 20% (previously 32%) and the PRT rate to 35% (previously 50%).  Faroe welcomes these measures.  Details of what expenditure is eligible for the IA are still to be released but initial impressions of this tax uplift introduced are very positive.  The reduction of SCT is likely to reduce the recognised deferred tax asset in the UK by £5.0 million.  The rate cut improves the economics of Faroe's portfolio and may result in further investments being made to develop discovered resources or extend the life of existing fields.

Balance sheet

Development and production investments of £48.3 million (2013: £48.5 million) were made in the year, including £24.6 million for the acquisition of Schooner and Ketch.  Further consideration of up to £10 million will be due to Tullow if up to 10 Bcf gross (6 Bcf net to Faroe) of incremental gas is produced from a specific reservoir compartment on the Schooner SA11 well. In addition, Faroe has identified several potential areas for investment in these assets, certain of which are the subject to contingent royalties, up to a maximum of £92.2 million. For such royalties to be paid in full, approximately 35mmboe net to Faroe would have to be produced from new reservoirs (compared to the acquired 5.9 mmboe of 2P reserves).  Exploration and evaluation investments of £87.2 million (post-tax: £23.0 million) (2013: £73.0 million pre-tax, £24.9 million post-tax) were made in the year.  These mainly related to drilling the Butch and Pil wells in Norway.  After exploration write-offs in the year of £131.7 million (2013: £15.4 million), the intangible assets decreased by £57.5 million to £128.3 million (2013: £185.8 million). Net assets increased during the year to £245.5 million (2013: £235.6 million).

Cash flow

Closing cash was £92.6 million (2013: £40.6 million).  Net cash at the year end was £69.6 million (2013: £40.6 million). The increase is due largely to the share placing in June 2014, which resulted in gross proceeds of £65.0 million, production cash flows and cash flows from the exploration financing facility (EFF) and reserve based lending facility (£23 million drawn for the Schooner and Ketch acquisition), offset by funding of the exploration programme, investment in development and production assets, acquisitions and finance costs.

Faroe Petroleum benefits significantly from a revolving credit facility of NOK 1,500 million for provision of 75% (as described above) of its eligible net exploration costs in Norway on a cash flow basis, such that only 25% of this expenditure is funded from Company equity.  The borrowings under the EFF are repaid when the tax rebate is received in December of the year following the related expenditure.  In December 2014 the Company received the tax rebate for 2013 of £22.5 million, most of which was used to repay the 2013 utilisations of the EFF.

The Group also has a secured US$250 million (approximately £160.0 million) reserve based lending facility which is substantially available, for both debt and issuance of letters of credits.  At the year end there was an amount drawn down of £23.0 million under this facility (2013: £0 million).

With a combination of the current cash in the business, cash flow from producing assets and available headroom in the Group's bank facilities, the Group will be able to fund currently committed capital expenditure (exploration and development/production).  The pre-tax capital expenditure for 2015 is forecast to be up to £100 million. 

Notes

1.            The financial information set out above does not constitute the Company's financial statements for the years ended 31 December 2014 or 2013. The financial information is derived from the financial statements for 2014 prepared in accordance with IFRS.  The auditors have reported on the 2014 financial statements and their report was unqualified. The financial statements are yet to be delivered to the Registrar of Companies.

2.            No dividend is proposed.

3.            Cost of sales analysis

4.            Taxation

5.            Post balance sheet events:

Norwegian exploration licence awards

On 21 January 2015, the Company announced that it has been awarded five new prospective exploration licences, including one operatorships, under the 2014 Norwegian APA Licence Round on the Norwegian Continental Shelf. These include three licences in the Norwegian Sea surrounding the Company's Pil and Bue discoveries and two licences in the Norwegian North Sea.

Shango exploration well commences drilling in the Norwegian North Sea

On 16 March 2015, the Company announced the spudding of the Shango exploration well 25/6-5S. The Shango prospect on Licence PL627 is located in the Norwegian North Sea on the northern part of the Utsira High, approximately 5 kilometres from the producing Skirne field. Licence PL627 is operated by Total E&P Norge AS, which also operates the Skirne field.

UK Budget Announcement

The Chancellor of the Exchequer of the United Kingdom announced in his Budget Statement on 18 March 2015 that the rate of supplementary charge tax (SCT) will be reduced from 32% to 20% with effect from 1 January 2015.  The reduction in SCT will affect the carrying value of the Group's deferred tax liability; reducing the rate at which fixed asset and other temporary differences will reverse and also reducing the rate at which UK ring fence losses will be relievable in future.  It is estimated that, following the reduction in the SCT, the current deferred tax liability will reduce by £2,842,000 and the deferred tax asset will reduce by £7,838,000, resulting in a net reduction in the recognised deferred tax asset of £4,996,000.

6.            Copies of the full report and accounts will be posted to all shareholders. Further copies will be available from the Company's head office at 24 Carden Place, Aberdeen AB10 1UQ, from the date of posting, telephone +44 (0)1224 650 920, and will be available on the Company's website www.fp.fo

George Y C Man, Corporate Reserves Manager of Faroe Petroleum and a Reservoir Engineer (BSc Honours in Mining and Petroleum Engineering and MSc in Information Technology Systems from University of Strathclyde, PGDip in Business Administration from University of Surrey), who has been involved in the oil and gas industry for 24 years, has read and approved the production, development, reserves and resources technical 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.

Glossary