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Faroe Petroleum Preliminary Results 2013

FAROE PETROLEUM PLC (“Faroe Petroleum”, “Faroe”, the “Company” or the “Group”)

Faroe Petroleum, the independent oil and gas group focussed on oil and gas exploration and production in Norway, the Atlantic margin and the UK North Sea, is pleased to announce its audited Preliminary Results for the year ended 31 December 2013.

HIGHLIGHTS
Exploration and appraisal

Reserves, production and development

Financial

Outlook

Graham Stewart, Chief Executive, commented:

“2013 was another year in which we delivered a sustained, high impact exploration programme, which delivered success with the drill bit, coupled with a significant increase in our 2P reserves and contingent resources.

“Our active exploration drilling programme continues with operations ongoing on three exploration wells in Norway – Pil (Faroe 25%), Solberg (Faroe 20%) and Butch East (Faroe 15%). Pil has already been announced as an oil and gas discovery and a production test is underway. Butch East is the first of two back‐to‐back wells on the Butch area, on the same structure as the significant Butch Main discovery with the Butch South West well to follow. Drilling operations are also ongoing on Solberg.

“Following the Pil and Snilehorn successes, further de‐risked drilling targets are currently being matured for near‐term drilling while additional prospects are also being prepared for drilling decisions. With the new Snilehorn and Pil discoveries, the Greater Njord Area is increasingly becoming an exciting asset with substantial remaining reserves, new discovered resources, and further high potential drilling targets.

“We have strengthened our production portfolio with the East Foinaven oil field acquisition and by bringing both the Hyme oil field and the Orca gas field on‐stream in 2013. The unscheduled production interruption on Njord and the Hyme satellite since July 2013 affected production levels in the year and we look forward to their return to production this summer.

“Faroe is in an excellent position to create significant shareholder value by continuing its successful and sustainable multi‐well drilling campaign while in parallel pursuing further investment and acquisition opportunities.”

For further information please contact:

Faroe Petroleum plc
Graham Stewart/Jon Cooper/Helge Hammer
Tel: +44 1224 650 920
Panmure Gordon (UK) Limited
Katherine Roe/Callum Stewart/Adam James
Tel: +44 20 7886 2500
Oriel Securities Limited
Michael Shaw/Ashton Clanfield
Tel: +44 20 7710 7600
FTI Consulting
Edward Westropp
Tel: +44 20 7831 3113

CHAIRMAN’S AND CHIEF EXECUTIVE’S STATEMENT

We are pleased to announce the audited Preliminary Results for the year ended 31 December 2013 – a period of considerable activity and progress for the Company. We have maintained the forward momentum in building a strong and high potential value portfolio with an active and material drilling programme in our core areas of Norway and UK, while growing significantly our reserves and contingent resources. Faroe Petroleum is emerging as one of the leading E&P players in the North Sea.

Strategy consistent, growth platform stronger

With the largest Norwegian and West of Shetlands exploration portfolio of any UK quoted company, Faroe has established itself as an increasingly important exploration‐led, production‐backed E&P company. Since 2006, Faroe has focussed on exploring Norway to take full advantage of the high remaining potential, the availability of licences through rounds and the financial incentives to explore there. We have built a diverse portfolio of attractive exploration, appraisal, development and production assets and we target significant expansion over the coming years. Our targeted strategy to grow reserves and resources is working very effectively. Our strategy has been consistent and our business model, focussed on exploration and monetisation, underpinned by a strong balance sheet and financial discipline, is delivering excellent results.

Global economy improves while E&P sector lags

Oil prices have remained stable despite continuing global uncertainties in both demand and supply. The global economy also continues to improve and the key stock market indices have performed well. In contrast however, the E&P sector remains out of favour relative to others. Concerns over future commodity prices, cost escalation and a lack of significant exploration success worldwide have led to a generally downbeat performance in the sector. However, Faroe is well positioned to outperform the sector in the period ahead as we continue our active investment programme.

Outstanding exploration successes

Faroe has recently made two oil and gas discoveries in Norway. At the end of 2013 we announced the discovery of the Snilehorn field close to our Njord field. Snilehorn has greatly exceeded pre‐drill expectation and has unlocked further significant potential in nearby prospects, which we aim to drill in the near future. More recently we announced an oil and gas discovery with the Pil well where again we exceeded pre‐drill expectations. Production testing is now underway at Pil ahead of drilling a side‐track to establish further resources.

This area, now dubbed the ‘Greater Njord Area’, is set for important future drilling as we look to unlock the potential these two new discoveries have de‐risked. Prior to the announcement of the Pil success, 2P and 2C Resources in the Greater Njord Area were already large, estimated at over 170 mmboe gross. With the discovery of Pil, the additional potential surrounding Pil and the additional potential surrounding Snilehorn, the value in this area could turn out to be exceptional. Considerable follow‐up drilling will be required to establish how large the resources are in this area, and preparation for this has already started.

2013 was a very active year with the drill bit for Faroe. It began with the announcement in January 2013 of a significant gas condensate discovery on the Rodriguez/Solberg prospect in the Norwegian Sea where the Group has built a significant portfolio and has already had considerable exploration successes on Fogelberg and Maria. This discovery led to a decision to drill the Solberg appraisal well which is currently drilling.

Since 2009, Faroe has built a significant presence in the frontier Norwegian Barents Sea comprising four very large licences, and in March 2013 the Company drilled its first well in the region, the Darwin wildcat exploration well. Darwin recorded gas shows but no hydrocarbons in the targeted Cretaceous horizons, however the existence of an active hydrocarbon system in the area provides encouragement for further potential on the licence.

We operated the Novus exploration well in Norway successfully and with a clean safety record. The well was announced in early 2014 as a small discovery, likely to require a further nearby discovery to prove commercial.

Faroe’s active drilling programme has continued into 2014 with three high impact wells drilling concurrently: Butch East, Pil and Solberg, with the Butch South West well to spud when Butch East is completed. The Centrica‐operated Butch East well is a follow‐up well to the 2011 Butch Main commercial oil discovery and is the first of a two‐well programme to test the eastern and south western sides of the large Butch salt structure.

Exceptional licence round award track record

One of Faroe’s hallmarks is its exceptional track record in winning new exploration licences in licensing rounds. This cost effective approach has allowed the Company to generate an average of four to five wells per annum in recent years, ensuring maximum possible exposure to the significant upside potential of high impact exploration drilling.

Faroe has continued to focus on building organically its portfolio of exploration licences through active participation in licensing rounds across its core areas. 2013 success began with the January announcement of eight new licence awards in the 2012 Norwegian APA Licence Round, including three operated by Faroe. These licences are held in joint ventures which include companies such as Statoil, Petoro, Mærsk and Total. As an extension of our northern seas focus, the Company was granted a new exploration licence on the Jan Mayen Ridge in Icelandic waters earlier in the year. Faroe operates the licence in partnership with Iceland Petroleum and the Norwegian State‐owned oil company Petoro AS. This is the first time that Petoro has taken a licence position outside Norway. In January 2014, Faroe announced 10 new exploration licence awards from the 2013 Norwegian APA Licensing Round, its most successful licence round to date and the largest number awarded in this APA round, equal in number with Centrica and Statoil.

Our Barents Sea presence was strengthened further in June when the Company was awarded a new 22nd Norwegian Round licence together with Eni, one of the most successful Barents Sea operators. Frontier work has also started on the Norwegian 23rd licensing round focussing on the Barents Sea, which is set to be an extremely competitive round. In the UK, Faroe is also preparing for the announced 28th licensing round.

Pre‐development and development value growth accelerating

A number of new developments are now taking shape starting with the Dong‐operated Glenlivet gas field west of Shetland, with development planning to commence by the end of 2014. In Norway the partnership is continuing to mature the Centrica‐operated Fogelberg gas and condensate discovery, while plans for development of the significant Butch Main oil discovery are making good progress. Work is also ongoing in parallel with the drilling of the two back‐to‐back Butch exploration wells, which have the potential to significantly increase the scale of this project.

An important feature of Faroe’s business model is to be open to exceptional and high potential value opportunities. One such opportunity is the Perth and Lowlander sour crude oil fields in the UK North Sea. These two fields have remained undeveloped for many years despite being fully appraised. Faroe saw the opportunity for their combination to unlock development potential and considerable value. Consequently 100% of the Lowlander field was acquired in 2013 to combine with the Company’s 34% holding in the Perth field. Faroe is working closely together with Parkmead, operator of Perth, to bring the two fields forward to development as a single joint project, sharing the same production facilities and benefiting from economies of scale. These fully appraised fields have a combined total of nine wells drilled and are estimated to contain in place resources of over 270 mmbbls, with 62 mmbbls of oil estimated to be recoverable. In addition there is potential for the production facilities to serve as a hub for a number of other fields already discovered in the area. Faroe will look to establish the optimal monetisation route for this opportunity in the period ahead.

Production portfolio key to continuing success

The Company’s production portfolio remains core to the strategy. The producing assets have been selected for their upside potential, tax efficiency, debt capacity and limited abandonment cost exposure. Cash flow from production is the principal source of equity funding for the Company’s exploration investment programme. Our asset base was further strengthened and diversified during the year with two new fields, Hyme and Orca, being brought on production and the East Foinaven acquisition completing in August 2013. However, a prolonged shut‐in of Njord and the Hyme satellite from late July 2013 resulted in lower than anticipated average production. Following structural reinforcement work, Njord and Hyme are scheduled to be back on stream in the summer of 2014, returning estimated cash flows back up towards previous levels ahead of a redevelopment programme scheduled after a period of production.

Faroe is targeting potential asset acquisitions in its core areas in order to grow the production portfolio, with a focus on robustness, good upside as well as tax efficiency and other synergies.

Key focus on monetisation

The Company’s strategy has always focussed on avoidance of excessive capital exposure to development projects. Consequently, considerable effort goes into monetising projects, typically those progressing from exploration success through appraisal, ahead of development wherever appropriate, in order to ensure that single project investments are held in balance with the rest of the portfolio.

Our near‐term drilling programme has focussed exclusively on opportunities close to existing infrastructure, so‐called “infrastructure‐led” exploration. Such opportunities offer the real potential for early monetisation through, for example, conversion to proven reserves via fast‐track field development or trades such as our landmark Maria swap transaction with Petoro in 2011. In that transaction we swapped out of a discovery within 12 months and directly into production in the Brage, Njord and Ringhorne East fields in Norway. This transaction is regarded in the industry as a ground‐breaking deal in Norway, and we aim to replicate this transaction model in the future.

Reserves and contingent resources increased significantly

Fundamental to the business model, Faroe continues to focus efforts on converting prospective resources into contingent resources and in turn contingent resources into 2P reserves. The Company’s rapid growth in the key metrics of reserves and contingent resources and prospective resources continues. At 1 January 2014 we have generated internal estimates for 2P reserves at 27.2 mmboe, representing an increase of 35% over the year, and unrisked contingent resources at 73 mmboe representing an increase of 32% over the year. Additionally unrisked prospective resources in the Company’s exploration portfolio are independently estimated at 2.4 billion boe.

Firm portfolio and capital management fundamental to continuing success

Over many years, Faroe has built an exceptional portfolio. Our focus has throughout been on high‐grading exploration prospects to ensure we only drill the very best wells. While we have delivered an active and successful exploration programme, we have ensured at all times that our balance sheet remains strong. Furthermore, we have managed our equity and capital exposure with the utmost care in order to maximise returns and conserve cash. This is achieved through a continuous process of farm‐outs and farm‐ins involving exacting standards, peer reviews and tough economic thresholds. Faroe has benefitted from carries on many of its exploration wells to date, all secured by our own business development processes. Most recently we farmed out the Solberg and Novus wells, leaving us with significant equity participation, at 20% and 30% respectively, but paying a much reduced portion of well costs.

This same conservative approach to cash and capital management is applied across the portfolio from appraisal to development and right across the organisation. Faroe’s fundamental financial and commercial discipline has allowed it to build a strong business delivering one of the most exciting and high potential exploration programmes in the sector.

Appointment of new CFO

In July 2013 Jonathan Cooper was appointed to the Board as Chief Financial Officer, replacing Iain Lanaghan, and we are pleased to welcome Mr Cooper to the Board. Mr Cooper’s appointment strengthens further the team as we move into an exciting new phase of growth. We thank Mr Lanaghan for his diligence and hard work over the last four years, guiding the Company into a position of financial strength and sustainability.

Outlook is exciting with significant value catalysts

Our exploration team continues to deliver exciting opportunities in partnerships with some of the best companies in the industry. Our team are held in high regard by their peers and host authorities alike. We are very proud of this reputation which has contributed to our successes in winning many exciting new licences this year, as in previous years, providing future well opportunities for our drilling programme, and we aim to ensure we continue this trend in the years to come.

We remain committed to our strategy and business model, with a clear focus on exploration and appraisal, with substantial equity stakes in Norway, the North Sea and Atlantic Margin, underpinned by production.

Faroe is better positioned now than ever before to take advantage of emerging growth opportunities in our focussed geographic area in order to become an increasingly significant player in this region. On behalf of the Board we would like to thank the whole Faroe team for their commitment, enthusiasm and hard work as we look forward to an exciting period ahead together.

John Bentley
Chairman

Graham Stewart
Chief Executive

REVIEW OF ACTIVITIES
Faroe Petroleum’s focus is on exploration, appraisal and production opportunities in Norway, the Atlantic margin and the UK North Sea. The Company has built a substantial portfolio in these areas over many years, and in 2013 and the beginning of 2014 new valuable assets have been added through a combination of exploration discoveries, acquisitions and licence awards.

Exploration

Portfolio overview

In the most recent licence round in Norway, the 2013 Awards in Pre‐defined Areas (APA) licensing round, the Company was awarded 10 new licences, taking the total number of exploration assets to 44, of which 33 are in Norwegian waters, 10 in the UK and one in Iceland. This extensive portfolio is being actively managed whereby exploration prospects are constantly being high‐graded with the aim of generating a high quality drilling programme. During recent years, Faroe’s portfolio approach has generated four to five exploration wells per year, and this trend is expected to continue. 2013 was an active year of drilling with four wells being completed in the year and a further two well spuds towards the end of the year.

Norway is an attractive exploration province where large new discoveries continue to be made. Norway also provides a substantial tax incentive for exploration activity with an annual tax refund of 78% of exploration expenditure. This incentive has proved successful both in terms of the number of exploration wells being drilled, which has increased significantly during the last few years, and in the exploration success rates. Among the most important recent discoveries are the Johan Castberg field in the Barents Sea, which represented a breakthrough in an area where Faroe already has a strategic position, and the Johan Sverdrup discovery, a giant oil discovery in the Norwegian North Sea, which proved that very large discoveries can still be made in the mature areas in the North Sea, also an area where Faroe is very active.

Faroe’s Norwegian portfolio 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 and in the Dreki Area of Iceland, and contains a considerable breadth of risk profile and maturity. Faroe holds 16 exploration licence areas in the Norwegian North Sea, 13 in the Norwegian Sea and four in the Barents Sea, including PL716 Dazzler (Faroe 20%) awarded in June 2013. Dazzler is operated by Eni, one of the most successful explorers in the Barents Sea, and involves a drilling commitment targeted for late 2015. Faroe has also started work on Norway’s forthcoming 23rd Licence Round, which will be entirely dedicated to the Barents Sea area, including the newly opened South East Barents area.

In November 2013 Faroe announced a significant oil discovery on the Snilehorn prospect in the Norwegian Sea and in March 2014 another discovery, also in the Norwegian Sea in the vicinity of the Njord facility, was announced on the Pil well. Faroe has now made six significant discoveries in Norway. The four latest discoveries, Pil, Snilehorn, Rodriguez and Butch are all near to infrastructure.

The UK Atlantic Margin, where the Company has six exploration licence areas, remains an area of continued focus for the Company. Since 2009, Faroe has drilled six exploration wells in the Atlantic Margin, of which two were discoveries with a further two technical successes. Faroe’s diversified portfolio, with several promising exploration plays, is expected to generate a number of drilling targets in the coming years. In the Central North Sea the Company holds four exploration licences and is focussing on areas around the Perth/Lowlander fields and other opportunities close to existing infrastructure.

Drilling operations

Of the four well results announced in 2013, three were discoveries. Snilehorn was a commercial discovery and adds important new resources in the Njord‐Hyme area, Rodriguez was a discovery with significant economic potential, which is currently being tested by the Solberg appraisal well, while North Uist was a discovery which is unlikely to be commercial on a standalone basis. Darwin did not encounter commercial quantities of hydrocarbons but provides valuable data for potential further exploration in this strategically important area in the Barents Sea.

Rodriquez & Solberg: The gas condensate discovery in Rodriguez in licence PL475 (6407/1‐6S) on the Halten Terrace in the Norwegian Sea was announced in January 2013. The well encountered net pay in the Lower Cretaceous Lange formation, which was interpreted as being at the edge of the reservoir’s lateral extent. The significance of the new discovery and the potential breakthrough in understanding the Lower Cretaceous in this area triggered the immediate planning of the Solberg appraisal well (Faroe 20%), to assess the extent of the discovery. The Solberg well spudded in February 2014 and drilling operations are ongoing.

Darwin: In March 2013 the Company participated in the drilling of the Darwin wildcat exploration well in the frontier western part of the Barents Sea in licence PL531 (Faroe 12.5%). The well did not encounter movable hydrocarbons but an extensive data set was collected which will allow further evaluation and de‐risking of this extensive, emerging exploration area.

North Uist: The result of the BP‐operated North Uist exploration well (213/25c‐1V) (Faroe 6.25%) in the UK Atlantic margin was announced in April 2013 after several months of delay caused by technical challenges. The well encountered gas condensate in the main target formation which was found to be of varying reservoir quality. To manage the typically higher well costs in this region, Faroe secured in advance a financial carry of a portion of the well costs through farm out arrangements. On a standalone basis, the North Uist discovery is unlikely to be commercial. The remaining partners, with Nexen as the new operator, are focussing on the evaluation of exploration opportunities in and around the licence.

Snilehorn: In November 2013 the Company announced the Snilehorn discovery (Faroe 7.5%) in the Norwegian Sea. The main bore (6407/8‐6) encountered significant columns of excellent quality oil in the Ile, Tilje and Triassic Grey‐Beds formations. A side‐track well (6407/8‐6A) was drilled which also encountered significant oil columns in the Melke, Ile and Tilje formations. The Snilehorn discovery, which was significantly larger than the pre‐drill estimates, is located only four kilometres from the Hyme oil field and approximately 20 kilometres from the Njord field. The discovery, which is still being evaluated, adds considerable resources to the Njord and Hyme development area and has also de‐risked several additional prospects in the PL348 licence, which are currently being evaluated as targets for further exploration drilling in the area.

Novus: The results of the Faroe‐operated Novus exploration well 6507/10‐2S (Faroe 30%) were announced in January 2014. The well encountered gas and oil in high quality Garn formation but the Ile and Tilje formations were water wet. The preliminary estimate of the size of the discovery indicates that Novus is unlikely to be commercial on a standalone basis, and the data collected is now being used to refine the analysis and de‐risk the remaining prospects in the licence. The Company farmed down its interest in the Novus licence from 50% to 30%, on a cost carried basis, significantly reducing Faroe’s costs.

Pil: The most recent well results to be announced were on the Pil well (Faroe 25%) in Norway which the Company farmed into in February 2013. The VNG‐operated Pil exploration well spudded in January 2014 in Licence PL586 in the Norwegian Sea and in March 2014 the Company announced that a discovery had been made with a 135 metre oil column and 91 metre gas column in excellent reservoir. A drill stem test is currently underway with a view to drilling a side‐track well to test the lateral extent of the discovery. The Pil prospect is located within tie‐back distance (33 kilometres) of the Njord platform in which the Company holds a 7.5% interest. The primary target was within the upper Jurrassic Rogn formation sandstone, which has proved to be an effective reservoir in the producing Draugen field, located 60 kilometres to the north east. The Pil discovery has de‐risked further prospectivity within the licence, which is being assessed for future drilling.

Butch: December 2013 saw the spudding of the first of the two back‐to‐back Butch wells, Butch East and Butch South West (Faroe 15%) in the Norwegian North Sea. This programme follows the 2011 Butch main well which encountered a significant presence of light crude oil in the Upper Jurassic reservoir of the Ula formation. Drilling operations on the Butch East well are continuing.

Licence rounds

Faroe has built its portfolio of exploration licences largely through active participation in licensing rounds across its core areas. In Norway, prospective acreage is made available to industry on a yearly basis in the APA licensing rounds in addition to the numbered licensing rounds in frontier areas, which typically take place every second year. Faroe continues to be one of the most successful participants in the Norwegian rounds and in the latest APA round, announced in January 2014, the Company’s award of 10 licences was matched only by Statoil and Centrica. UK licensing rounds have in recent years taken place every second year.

In January 2013, the Company was awarded eight new licences in the 2012 APA round, three of which were awarded to Faroe as operator. The new licences included new stand‐alone near field prospects in the Norwegian North Sea which are being covered by new high quality 3D seismic, follow up prospects in the Butch area as well as new acreage in the Norwegian Sea.

Faroe has built a strategic position in the Barents Sea in recent years and in June 2013 the Company was awarded a further licence in the area, taking the total number of licences in the Barents Sea to four. Licence PL716 (Faroe 20%) contains the Dazzler prospect, which is located 90 kilometres to the north west of the Johan Castberg oil discovery and which is targeted for drilling in 2015.

In January 2014, Faroe was awarded 10 licences in the 2013 APA round. The Company is the operator of two of the licences. The licences are situated in the North Sea and the Norwegian Sea and build on the Company’s significant knowledge in these areas. The award of 10 licences is the largest to date for the Company in a single round.

Faroe aims to build on its recent licensing round success and work has started on the Norwegian 23rd licensing round which will focus on the Barents Sea, where the Company has identified several prospective opportunities and recently submitted the maximum number of permitted block nominations. In the UK, Faroe is preparing for the announced 28th licensing round where several exploration opportunities have been identified for potential applications.

Production and Development

Production

During the year to December 2013, Faroe’s net average economic production was 6,059 boepd (including production from East Foinaven from 1 January 2013) with most of the production coming from the Njord, Hyme, Brage and Ringhorne East fields in Norway and the Blane and the East Foinaven fields in the UK. The Company also holds smaller production interests in the Jotun field in Norway, and the Schooner, Topaz and Orca gas fields in the UK Southern Gas basin. Average production was impacted by the unscheduled extended shut‐down of the Hyme and Njord fields in the second half of 2013.

During Q2 Faroe’s net production levels were at a record level, at just above 10,000 boepd, following Hyme coming on stream in late February. However, in July 2013 production from the Njord and Hyme fields was shut down for a period of scheduled repair and maintenance. During this shut down period and as a result of a new refined structural element model, it was concluded that the deck structure of the Njord A floating facility needed to be reinforced before production could recommence. The work on the reinforcement project is in progress and Statoil’s expectation as operator is that this will be completed and production at the Njord and Hyme fields resumed in the summer of 2014.

Considerable resources remain in the Greater Njord Area with estimated 2P and 2C Resources of over 170 mmboe gross. These include developed volumes that can be produced from the existing wells on Njord and adjacent Hyme fields, further in‐fill drilling in the Njord field, development of the North West Flank rich gas and condensate accumulations and development of the recently announced significant Snilehorn oil discovery. In addition, the Pil oil and gas discovery in Licence PL586 is within tie‐back distance to Njord and there is also substantial additional prospectivity that is being matured with a view to further exploration drilling in the near term. The discoveries on Snilehorn and Pil have de‐risked prospectivity in the area and work is underway to identify and fast‐track drilling opportunities.

Due to continued weight restrictions, Njord A will be without a drilling facility unless further strengthening of the substructure is undertaken. As a result, and in light of the considerable remaining resources in the Greater Njord Area, the Njord partnership is evaluating a number of scenarios for the long term further development of the area. The objective is to prepare a robust plan to re‐establish development drilling in the Njord field and generate maximum value and reserves exploitation from the long term development of these material hydrocarbon resources. The scenario evaluation work will be followed by front‐end engineering studies and with the final concept selection expected in 2015. For the long term development, the operator’s current base case assumes that, following a period of production mentioned above, the Njord A facility will be brought to a yard for the hull to be either repaired or replaced.

The Brage field has performed well in 2013. Wintershall took over as operator from Statoil, as planned, from October 2013 and equities between Brage Unit and Brage Sognefjord have been equalised, resulting in Faroe acquiring an additional 0.85% equity in Brage Sognefjord to bring its ownership in the unitised Brage Field to 14.26%. Wintershall has started work to high‐grade and rank the portfolio of infill drilling targets and two new production wells are underway which are planned to be brought on stream in Q2 and Q4 2014.

The Ringhorne East field (Faroe 7.8%) continued to perform well in 2013 with all four production wells delivering at stable rates. The Blane field (Faroe 18%) also produced at excellent rates during the year but average production suffered as a result of a shut down on the BP‐operated Ula host platform as a result of compressor failure. The compressor was replaced quickly and stable production has recommenced. In August 2013 the Company completed the previously announced acquisition of a 10% non‐operated interest in the East Foinaven oil field. The acquisition has boosted oil production in the UK where the Company has carried forward tax losses to set against profits from production.

In the Schooner field (Faroe 6.9%) drilling on the Schooner in‐fill well 44/26a‐SAM was completed resulting in new production towards the end of 2013. Also, the Orca gas field in the UK Southern Gas basin was under development during the year with first gas produced in December 2013.

Discoveries and Appraisals

The Glenlivet development project is underway with submission of the Field Development Plan being planned for 2014 by the operator, Dong. Export capacity has been secured through the gas infrastructure in the west of Shetland area, which is currently being installed as part of the Laggan‐Tormore project.

During 2013, in two separate transactions, Faroe acquired 100% of the Lowlander discovery. Faroe is working together with Parkmead as operator of Perth (Faroe 34.62%) to bring the two fields forward to development together as a joint project sharing the same production facilities and thereby benefiting from economies of scale. Both Perth and Lowlander have been fully appraised. Pending the preparation of an economic joint field development plan, Faroe has not yet classified its net share of these resources as Proven and Probable (2P) Reserves. In addition there is the potential that the production facilities for a joint field development could serve as a hub for a number of other fields including analogous accumulations already discovered in the area. This project has the potential to create significant near term value. Faroe’s position in the Perth area also includes licence P1933 (Birnam, Faroe 33.33%) which is being progressed towards a drilling decision.

In Norway, work is ongoing to mature the Fogelberg (Faroe 15%) and Butch Main (Faroe 15%) discoveries towards Field Development Plan submissions. On Fogelberg, Centrica the operator, is working towards field development to coincide with availability of transportation capacity in the Åsgard production and transportation system, which will allow gas to be transported from the Norwegian Sea to Continental Europe. Good progress has been made on the development concept of the Butch Main discovery which has moved ahead in parallel with the planning of the wells on Butch East and Butch South West.

Reserves and Resources

The Company’s internal estimate of Proven and Probable (2P) Reserves at 1 January 2014, prepared in accordance with the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers, has been estimated at 27.2 million boe representing an increase of 35% over the year (20.1 million boe at 1 January 2013). The significant increase in 2P Reserves has been achieved principally through good production performance and the booking of the Glenlivet field as 2P Reserves.

Reserves
1 January 2014
Liquids
(mmbbls)
Gas
(bcf)
Total
(mmboe)
Total
1 January 2013
(mmboe)
Norway 12.5 31.6 17.7 15.5
UK 3.6 34.9 9.5 4.6
Group 16.1 66.4 27.2 20.1

In February 2014, the Company published its internal estimate of Unrisked Contingent (2C) Resources for the first time. At 1 January 2014 2C Resources were estimated to be 73 million boe representing an increase of 32% over the year (56 million boe at 1 January 2013):

Unrisked Contingent Resources
1 January 2014
Liquids
(mmbbls)
Gas
(bcf)
Total
(mmboe)
Total
1 January 2013
(mmboe)
Norway 18 98 35 34
UK 36 18 38 22
Group 54 116 73 56

The significant increase in 2C Resources over the period is principally a result of:

The increase in 2C Resources resulting from acquisitions and the Solberg and Snilehorn discoveries more than compensates for the reduction in 2C Resources due to the transfer of Glenlivet from 2C Resources to 2P Reserves. The Pil discovery was made after 1 January 2014 and has not been included in 2C Resources.

FINANCE REVIEW

Overview
The year saw considerable investment in exploration drilling and development capex and the acquisitions of the East Foinaven producing field and a 100% interest in the Lowlander field, both in the UK. The Group generated cash flow from operations excluding tax during the year of £74.7 million, which, together with the Norwegian exploration financing facility, funded all exploration and development capital expenditure. The Group ended the year in a strong cash position with £40.6 million of unrestricted cash (31 December 2012: £72.9 million). The Company had no debt at the year end other than utilisations under the exploration financing facility which are more than covered by the Norwegian tax receivable due at the end of 2014.

Income statement
Revenue was £129.4 million (2012: £158.8 million). This represents a 19% decline compared to 2012 revenue, predominantly due to Njord and Hyme being shut‐in since July 2013. Cost of sales, including depreciation of producing assets, was £76.5 million (2012: £97.0 million). There was a gross impairment charge on Hyme totalling £2.1 million (2012: £nil) triggered by the additional capital expenditure anticipated on the Njord A platform based on the operator’s current base case scenario (see Review of Operations for details). The net impairment on Hyme, after taking taxation into consideration, was £0.4 million. The gross profit for the year, after the impairment charge, was £50.9 million (2012: £61.8 million) a decrease of 18% on last year; EBITDAX for the year decreased 16% to £80.5 million (2012: £96.3 million), again due primarily to Njord and Hyme being shut‐in since July 2013.

Exploration and evaluation expenses for the year were £22.2 million (2012: £79.7 million). This includes pre‐ award exploration expense (£6.9 million) and write‐offs of licence‐specific exploration and evaluation expenditure on previously capitalised licences where active exploration has now ceased (£15.4 million). The pre‐award exploration expense included costs incurred in licence rounds. The licences which were relinquished and written off during the year included PL414 (Kalvklumpen), PL507 (Tetrao), PL534 (Samson Dome), PL592 (Grayling), P1851 (Balblair) and P1852 (Ardbeg), together with other smaller write‐offs over several exploration assets.

The Group’s reported profit before tax was £10.0 million (2012: £29.0 million loss). Profit after tax was £14.1 million (2012: £5.2 million loss). The improved profit before and after tax year‐on‐year is due primarily to the lower exploration write‐offs in the year ended 31 December 2013.

Hedging
In line with Group policy approximately 52% of oil and gas sales in 2013 were hedged, with hedging costs of £1.3 million (2012: £0.6 million).

The Group has entered into hedging arrangements covering approximately 47% of 2014 and 24% of Q1 2015 total expected oil production (on a post tax basis). The hedging arrangements are a combination of zero cost collars and put options with floors predominantly at US$90 per barrel.

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 exploration and appraisal 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 £ rebate, thereby maximising equity leverage in Norwegian exploration wells and minimising the need to farm down to third parties. From an exploration and appraisal perspective, the Norwegian tax system therefore ensures a very cost effective fiscal environment in which to explore for hydrocarbons.

The amount of tax receivable at 31 December 2013 was £23.9 million (2012: £48.5 million) which is the tax refund on exploration expenditure in Norway net of taxable profits generated by the Norway producing assets. The refund will be received in December 2014. The tax credit in the Income Statement was £4.1 million (2012: £23.8 million) being the tax receivable of £23.9 million, offset by an increase in deferred tax liabilities of £20.4 million and further adjusted for amounts underprovided in the prior year (£0.3 million) and foreign exchange differences (£0.3 million).

At December 2013 the Group had unrelieved tax losses in the UK of £77.9 million (2012: £75.4 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.

The UK Government announced in the 2013 Budget that it will sign Decommissioning Relief Deeds (DRD) with all companies which might potentially have to incur decommissioning liabilities, thus providing greater certainty over the level of tax relief that will be available for decommissioning expenditure. These measures will allow companies to move to post‐tax decommissioning guarantees, removing a major fiscal risk for operators in the UK North Sea which, in turn, could release assets for sale and funds for investment. The Company signed a DRD with the UK Government in March 2014.

Balance sheet
Development and production investments of £48.5 million excluding decommissioning asset additions (2012: £49.3 million) were made in the year. These mainly relate to the acquisition of East Foinaven, investments in the Hyme and Orca developments, and the drilling of in‐fill wells at Schooner, Njord and Brage.

Exploration and evaluation investments of £73.0 million (2012: 111.8 million) were made in the year. These mainly related to drilling the Rodriguez, Darwin, Snilehorn and Novus wells in Norway (reflecting costs before the 78% Norwegian tax rebates), the North Uist well in the UK, and the acquisition of Lowlander discovery in the UK. After exploration write‐offs in the year of £15.4 million (2012: £71.1 million), intangible exploration and evaluation assets increased by £40.4 million to £185.8 million (31 December 2012: £145.1 million). Net assets increased during the period to £235.6 million (31 December 2012: £231.7 million).

Cash flow
Closing cash was £40.6 million (31 December 2012: £72.9 million). The reduction is due largely to funding of the exploration programme, investment in development and production assets, acquisitions and finance costs, offset by production cash flows and cash flows from the exploration financing facility.

Faroe Petroleum benefits significantly from a revolving credit facility of NOK 1,000 million for provision of 75% of its eligible net exploration costs on a cash flow basis, such that only 25% of eligible exploration expenditure in Norway is funded from Company equity going forward. The borrowings under the exploration financing facility are repaid when the tax rebate is received in December of the year following the related expenditure. In December 2013 the Company received the tax rebate for 2012 of £44.2 million, most of which was used to repay the 2012 utilisations of the exploration financing facility.

The Group also has a secured US$250 million (approximately £155.0 million) reserve based lending facility which is substantially available, for both debt and issuance of letters of credits. At the year end there were no amounts payable under this facility (2012: £7.3 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 2014 is forecast to be up to £140 million. The Board does not recommend payment of a dividend.

Group Income Statement
for the year ended 31 December 2013
2013
£000
2012
£000
Revenue 129,387 158,792
Cost of sales (76,451) (97,008)
Asset impairment (2,072)
Gross profit 50,864 61,784
Net gain on disposal of exploration and evaluation assets 77 1,657
Exploration and evaluation expenses (22,233) (79,742)
Administrative expenses (7,737) (9,282)
Operating profit/(loss) 20,971 (25,583)
Finance revenue 1,208 2,672
Finance costs (12,155) (6,080)
Profit/(loss) on ordinary activities before tax 10,024 (28,991)
Tax credit 4,050 23,813
Profit/(loss) for the year attributable to equity holders of the parent 14,074 (5,178)
Earnings/(loss) per share – basic (pence) 6.6 (2.4)
Earnings/(loss) per share – diluted (pence) 6.0 (2.4)

Group statement of other comprehensive income
for the year ended 31 December 2013
2013
£000
2012
£000
Profit/(loss) for the year 14,074 (5,178)
Items that may be reclassified subsequently to profit or loss:
Exchange differences on retranslation on foreign operations net of tax
(12,351) 2,758
Items not to be reclassified subsequently to profit or loss:
Actuarial gains/(losses) on defined benefit pension plans net of tax
(84)
Total comprehensive income/(loss) for the year 1,723 (2,504)

Company statement of other comprehensive income
for the year ended 31 December 2013
2013
£000
2012 £00
(Loss)/profit for the year (7,995) 3,040
Total comprehensive (loss)/income for the year (7,995) 3,040

Group Balance Sheet
at 31 December 2013
2013
£000
2012
£000
Non‐current assets
Intangible assets 185,805 145,104
Property, plant and equipment: development & production 139,100 133,359
Property, plant and equipment: other 806 768
Financial assets 13 13
325,724 279,244
Current assets
Inventories 4,890 4,887
Trade and other receivables 60,740 55,392
Current tax receivable 23,897 48,473
Cash and cash equivalents 40,591 72,891
130,118 181,643
Total assets 455,842 460,887
Current liabilities
Trade and other payables (52,988) (41,944)
Financial liabilities (20,993) (51,249)
(73,981) (93,193)
Non‐current liabilities
Deferred tax liabilities (98,242) (87,021)
Provisions (47,450) (48,586)
Defined benefit pension plan deficit (555) (391)
(146,247) (135,998)
Total liabilities (220,228) (229,191)
Net assets 235,614 231,696
Equity attributable to equity holders
Equity share capital 21,269 21,239
Share premium account 206,303 205,971
Cumulative translation reserve (3,798) 8,069
Retained earnings 11,840 (3,583)
Total equity 235,614 231,696

Company Balance Sheet
at 31 December 2013
2013
£000
2012
£000
Non‐current assets
Property, plant and equipment  135 161
Financial assets  188,335 168,711
Investments in subsidiary undertakings  38,768 37,549
 227,238 206,421
Current assets
Trade and other receivables  129 170
Cash and cash equivalents  4,758 31,059
 4,887 31,229
Total assets  232,125 237,650
Current liabilities
Trade and other payables  (1,207) (1,021)
Total liabilities  (1,207) (1,021)
Non‐current liabilities
Provisions  (89)
 (89)
Total liabilities  (1,296) (1,021)
Net assets  230,829 236,629
Equity attributable to equity holders
Equity share capital  21,269 21,239
Share premium account  206,303 205,971
Retained earnings  3,257 9,419
Total equity  230,829 236,629

Group cash flow statement
for the year ended 31 December 2013
2013
£000
2012
£000
Profit/(loss) before tax  10,024  (28,991)
Depreciation, depletion and amortisation  27,605  34,494
Exploration asset write off  15,362  71,081
Gain on disposal of asset  (77)  (1,657)
Asset impairment  2,072
Fair value of share based payment  3,275  3,386
(Increase)/decrease in trade and other receivables  (5,348)  4,460
Increase in inventories  (3)  (518)
Increase in trade and other payables  11,208  5,172
Currency translation adjustments  (342)  (1,977)
Expense recognised in respect of equity‐settled share based payments  (362)
Interest received  (866)  (695)
Interest and financing fees  12,155  6,080
Tax rebate/(payment)  44,237  (13,671)
Net cash generated in operating activities  118,940  77,164
Investing activities
Purchases of intangible and tangible assets  (121,990)  (162,052)
Proceeds from sale of intangible assets  77  1,657
Interest received  866  695
Net cash used in investing activities  (121,047)  (159,700)
Financing activities
Proceeds from issue of equity instruments of the  362  –
Company Net proceeds/(repayments) from borrowings  (24,301)  50,607
Payment for buyback of share options  (818)  –
Interest and financing fees paid  (4,623)  (3,742)
Net cash (outflow)/inflow from financing activities  (29,380)  46,865
Net decrease in cash and cash equivalents  (31,487)  (35,671)
Cash and cash equivalents at the beginning of the year  72,891  111,589
Effect of foreign exchange rate differences  (813)  (3,027)
Cash and cash equivalents at the end of the year  40,591  72,891

Company cash flow statement
for the year ended 31 December 2013
2013
£000
2012
£000
(Loss)/profit before tax (7,995) 3,040
Depreciation charges 60 42
Fair value of share based payment 1,669 926
Decrease/(increase) in trade and other receivables 39 (24)
Increase/(decrease) in trade and other payables 187 (57)
Currency translation adjustments 6,721 (2,929)
Expense recognised in respect of equity‐settled share based payments (362)
Inter‐company service charge uplift (140) (120)
Interest received (3,032) (3,145)
Interest and financing fees 1 3
Net cash used in operating activities (2,852) (2,264)
Investing activities
Purchases of property, plant and equipment (34) (111)
Loans to subsidiary undertakings (16,720) (38,276)
Interest received 128 542
Net cash used in investing activities (16,626) (37,845)
Financing activities
Proceeds from issue of equity instruments of the Company 362  –
Interest paid (1) (3)
Payment for buyback of share options (603)  –
Net cash (outflow) / inflow from financing activities (242) (3)
Net decrease in cash and cash equivalents (19,720) (40,112)
Cash and cash equivalents at the beginning of the year 31,059 68,124
Effect of foreign exchange rate differences (6,581) 3,047
Cash and cash equivalents at the end of the year 4,758 31,059

Notes

  1. The financial information set out above does not constitute the Company’s financial statements for the years ended 31 December 2013 or 2012. The financial information is derived from the financial statements for 2013 prepared in accordance with IFRS. The auditors have reported on the 2013 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. Taxation:
    2013
    £000
    2012
    £000
    Current taxation
     Current overseas tax credit 23,897  48,473
     Amounts under/(over) provided in previous year 251  (165)
     Total current tax credit 24,148  48,308
     Deferred taxation
     Origination of temporary differences (20,433) (23,986)
     Total deferred tax charge (20,433) (23,986)
     Foreign exchange differences
     Differences arising from the use of year end and average exchange rates 335  (509)
     Total foreign exchange differences 335 (509)
     Total tax credit in the Income Statement 4,050  23,813
  4. Post balance sheet events:Pil spud and initial results
    On 21 January 2014 it was announced that the VNG‐operated Pil exploration well 6406/12‐3S (Faroe 25%) had spudded. On 6 March 2014 it was further announced that the Pil well (6406/12‐3S) had encountered a gross hydrocarbon‐bearing reservoir section with approximately 135 metres of oil and 91 metres of gas in the Jurassic reservoir of the Rogn Formation. Preliminary results based on extensive coring, wireline logs and pressure data show that the well has encountered oil and gas in reservoir sands with a very high net to gross ratio.Norwegian exploration licence awards
    On 22 January 2014, the Company announced that it has been awarded ten new prospective exploration licences, including two operatorships, under the 2013 Norwegian APA Licence Round on the Norwegian Continental Shelf. These include one licence in the Northern North Sea, four licences in the North Sea, four licences in the Halten Terrace Area of the Norwegian Sea and one licence in the exploration area east of the giant Ormen Lange field in the North Sea.Novus well results
    On 27 January 2014 the Company announced the results of Faroe‐operated exploration well 6507/10‐2S, which spudded on 11 November 2013. 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 and the preliminary volumetric estimate of the size of the discovery is between 6 and 15 mmboe equivalents recoverable gross, net to Faroe 1.8 to 4.5 mmboe.Solberg spud
    On 3 February 2014 the Company announced the spudding of the Wintershall‐operated Solberg appraisal well 6407/1‐7 (Faroe 20%). The Solberg prospect is located in the APA 2007 license PL475 on the Halten Terrace in the Norwegian Sea four kilometres north‐east of the Tyrihans field and eight kilometres south‐east of Faroe’s significant Maria discovery (2010). The well will assess the lateral extent and size of the Lower Cretaceous Rodriguez discovery announced by Faroe in January 2013, where moveable hydrocarbons were discovered in sandstone layers in the Lange formation.
  5. Copies of the full 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

Bjørn Berntsen, Asset Manager Norway of Faroe Petroleum and a Petroleum Engineer (MSc. in Petroleum Engineering from University of Trondheim), who has been involved in the energy industry for 22 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

“APA” awards in pre‐defined areas
“bcf” billions of standard cubic feet
“boe” barrels of oil equivalent
“boepd” barrels of oil equivalent per day
“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
EBITDAX earnings before interest, taxation, depreciation, amortisation and exploration expenditure (gross profit plus depreciation and impairment on producing assets)
“net to gross ratio” the total amount of pay footage divided by the total thickness of the reservoir interval
“net to Faroe” the portion that is attributed to the equity interests of Faroe
“PL” production licence
“Proved Reserves” or “1P” those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term ‘reasonable certainty’ is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate
 “Proved + Probable Reserves” or “2P” when added to 1P, those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than 1P but more certain to be recovered than 3P. 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
 “Proved + Probable + Possible Reserves” or “3P” when added to 2P, those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than 2P. The total quantities ultimately  recovered have a low probability of exceeding the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate
“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
 “STOIIP”  stock tank oil initially in place