29 March 2016

FAROE PETROLEUM PLC

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

Final Results for the Year Ended 31 December 2015

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 2015.

Highlights

Operations - strong production performance and reserves growth

·      Strong production performance and low operating costs

o  Total average economic production1 for 2015 at 10,530 boepd (2014: 9,106 boepd) - with Faroe's main fields performing above expectations

o  Balanced product mix of approximately 58% liquids and 42% gas

o  Average operating cost per boe reduced by approximately 30% to $23 (2014: $33) - improvement due to a combination of higher volumes, improved cost efficiencies and a weaker Norwegian krone

o  Acquisition of additional interests in Blane and Enoch, announced in September 2015, strengthening our tax-efficient UK production base

·      Significant reserves growth

o  2P Reserves increased by 88% with closing reserves at 57.4 mmboe (2014: 30.6 mmboe) - mainly reflecting the transfer from 2C Contingent Resources of the significant Pil and Butch oil fields

o  2C Contingent Resources decreased to 98.3 mmboe (2014: 109.1 mmboe) - due to the reclassification of Pil and Butch fields to 2P Reserves, partly offset by the Boomerang discovery and the increased interest in South East Tor, all in Norway

·      Exploration programme adding 2C Contingent Resources

o  An oil discovery of 13-31 mmboe (net to Faroe 3-8 mmboe) made on the Boomerang well in September 2015, adding to the 2014 Pil and Bue discoveries; the second of the two Pil follow-up wells, Blink, was dry

o  The Portrush and Bister wells were announced as dry while the Skirne East (Shango) well was a small gas discovery, all in Norway

o  Five APA licences awarded in Norway in January 2015. Award of a further six new exploration licences, including two operatorships, under the 2015 APA licensing round was announced on 20 January 2016

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

·      Cash and net cash of £91.5 million and £68.5 million respectively at 31 December 2015 (31 December 2014: £92.6 million cash and £69.6 million net cash) - with £23.0 million ($33.0 million) drawn against the £155 million ($225 million) Reserve Based Lending facility

·      Revenue (excluding hedging gains) of £113.0 million (2014: £128.8 million) - reduction reflects lower commodity prices, partly offset by increased production

·      EBITDAX £60.4 million (2014: £59.1 million) - includes realised hedging gains of £9.3 million (2014: £0.5 million) classified as Other Income

·      General and administrative expenses reduced - net charge in the Income Statement 44% lower at £3.7 million (2014: 6.6 million)

·      Loss after tax of £52.9 million (2014: £55.0 million) after pre-tax impairment charges of £45.1 million (2014: £38.5 million) and exploration write-offs of £83.6 million (2014: £131.7 million)

·      Pre-tax exploration and appraisal capex of £61.9 million (£14.8 million post-tax) (2014: £87.2 million pre-tax, £23.0 million post-tax) and development and production investments (including acquisitions) of £23.1 million (2014: £48.3 million)

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

·      2016's exploration and appraisal programme continues, fully-funded from existing resources

·      Three exploration wells scheduled for 2016 (Kvalross well announced as dry in February 2016) all of which benefit from Norway's 78% exploration tax rebate

·      2016 exploration and appraisal capex is estimated to be approximately £50 million pre-tax (£12 million post-tax) and development and production capex for 2016 is estimated to be approximately £20 million

·      Production guidance for 2016 of 7,000-9,000 boepd, split 55% liquids (oil and condensate) and 45% gas

·      80% of 2016 and 50% of 2017 expected post-tax gas production hedged at average floor of 45p/therm and 22% of H1 2016 post-tax oil production is hedged at an average floor of $50 per barrel.

·      Well positioned to capitalise on market conditions to add value through further selective value-enhancing asset acquisitions

Graham Stewart, Chief Executive of Faroe Petroleum, commented:

"2015 was another year of growth and good progress for Faroe despite a backdrop of significantly lower commodity prices.  We delivered our exploration drilling programme safely and under budget, adding further material 2C resources, and doubled our 2P reserves in high quality assets, principally in Norway.  Our diverse North Sea production portfolio also outperformed expectations, averaging 10,530 boepd with lower unit operating costs of $23 per boe, down by 30% from the previous year.

"We stated a year ago that we would aim to run a cash-neutral budget for 2015 and we are pleased to end the year with cash of £91.5 million (2014: £92.6 million) after drilling five exploration wells and acquiring further interests in the Blane and Enoch production assets in the UK.  This outcome is testament to the quality of our portfolio and our consistently prudent financial management, in what remains a very difficult market.

"Looking ahead to 2016, the business is in a good position to face the continuing challenges of our industry and to seek to capitalise on our relative financial strength as we pursue attractive consolidation opportunities in our core areas on the UK and Norwegian continental shelves."

^[1] Economic production in 2015 includes production from the recently acquired interest in Blane field (12.5%) from 1 January 2015 (the effective date). Accounting production excludes production between the effective date and date of completion on 5 November 2015. Accounting production in 2015 was 10,252 boepd (2014: 6,579 boepd).

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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 2015. The aim for the year was to continue our exploration-led/production-backed strategy whilst preserving our cash reserves and a healthy balance sheet.  With an active exploration programme consisting of five wells and persistently low commodity prices, this was a challenging objective and we are therefore pleased to report a closing cash balance of £91.5 million compared to £92.6 million at the close of 2014.  This was achieved as a result of strong production performance, reduced operating costs, averaging $23/boe in 2015, a fall in the value of the Norwegian Krone, commodity hedging gains, and generally prudent financial management and cost reductions. 

While low commodity prices currently look set to continue for some time, Faroe's robust balance sheet and a diversified high-quality portfolio together put the Company in a relatively strong position.

Market conditions

Having started 2015 at $57 per barrel, the Brent oil price ended the year at $37.  The decline from mid-2014, when the oil price peaked at $115 per barrel, is even more significant.  Oil prices declined further in January 2016, falling below $30 per barrel.  Since these lows, prices have strengthened with Brent averaging $33.6 in February and exceeding $40 per barrel in March.  With oil demand continuing to increase and production slowing down, most analysts are forecasting a supply-demand balance by the end of 2016 or early 2017, after which global oil inventories should start drawing down and many are seeing the recent uptick in oil as the start to a more sustained recovery.  Gas prices also declined throughout the course of 2015, with the UK spot price falling from 49p per therm at the start of 2015 to 33p per therm at year end.  The outlook for the gas market is bearish with increased LNG exports from Australia and North America expected to exert downward pressure on European gas prices.

Despite the current low commodity prices, many fields globally are continuing to produce at peak levels in order to maximise cash flow, even though many are loss making.  New developments are becoming more difficult to justify economically, resulting in large cuts in investment in developments as well as exploration and appraisal drilling, which, in turn, will constrain future oil production.  Consequently the cost of rigs and field developments has fallen sharply in recent times, paradoxically making this an economically compelling time to invest.    

AIM-quoted E&P stocks had another very poor year with the AIM Oil & Gas Index falling by 42% throughout the course of the year. This compared to a 5% rise in the AIM All Share Index.  The Oil & Gas stocks suffered from low commodity prices, a dearth of exploration successes, extremely low levels of takeover activity and increasing concerns about companies' balance sheets and their ability to fund upstream developments or exploration programmes.  Resources stocks in general remained out of favour with UK investors and are likely to do so until there is a sustained improvement in commodity prices.

Faroe's response to market conditions

Market conditions have sharpened our focus on preserving cash with particular attention being paid to four key cost saving areas:  Company overheads; the exploration licence portfolio; operating costs on producing fields; and capital investment.  Company overheads were reduced in 2015 with further reductions planned in 2016; we have rationalised our exploration portfolio down from 50 licence areas at the end of 2014 to 33 at the end of 2015, with further targeted licence relinquishments and withdrawals planned in 2016; on our operated Schooner and Ketch gas fields in the UK, an initiative was taken in 2015 by Faroe to share helicopter and marine services with Eni in neighbouring fields, an initiative which is generating savings for both operators, and; in our Brage field in Norway, the partnership has agreed a drill-stop from January 2016.  Our operator partners have been implementing significant cost reductions across the portfolio and more cost saving actions are to come.  This is a continuous process and while we are satisfied with the progress made so far in all areas, much more can and must be done.

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 of £55.6 million at December 2015, further improving the cash flow from production.  With the acquisition of further interests in Blane and Enoch completed in November 2015, the Company expects to utilise fully its UK carried forward tax losses over the next few years.  We welcome the UK Budget announcement made by the UK Chancellor on 16 March 2016 concerning the reduction of the supplementary tax charge from 20% to 10%.

Consistent strategy

Faroe's strategy is to build shareholder value through the monetisation of exploration success, growth in reserves and resources derived from successful exploration and appraisal drilling and targeted M&A activity.  This consistent strategy and business model, underpinned by good quality low operating cost production, a relatively robust balance sheet and strong financial discipline means that Faroe is well placed in the current challenging environment.

During the year, the Company achieved a very significant reserves increase of 88% year on year, with 2P Reserves standing at 57.4 mmboe at 1 January 2016 (1 January 2015: 30.6 mmboe).  The 2C Contingent Resources decreased by 10% in the same period, on 1 January 2016 standing at 98.3 mmboe compared to 109.1 mmboe a year earlier.  The growth in 2P Reserves corresponds largely with the reduction in 2C Contingent Resources, due mainly to the transfer of Pil and Butch volumes from 2C to 2P.  The Boomerang discovery and an increased equity interest acquired in South East Tor in 2015 have compensated, in part, for the reduction in 2C resulting from the organic transfer of Butch and Pil 2C to 2P.   Since 2008 the Group has increased its 2P Reserves by 56.2 mmboe, from 1.2 mmboe at 1 January 2009, mainly as a result of exploration successes which subsequently have either been matured or monetised through swap transactions.

High quality production portfolio

The Company's diverse and high quality production portfolio remains core to our strategy.  In terms of production volumes and opex per boe, 2015 was a record year for Faroe, with average economic production for 2015 of 10,530 boepd, an increase of 16% on 2014, and opex per boe of $23, ensuring healthy operating cashflows.

Our latest production acquisition was announced in September 2015 when Faroe entered into an agreement to acquire an additional 12.5% of the Blane oil field from Roc Oil (Europe) Ltd for a total consideration of £10.6 million, taking Faroe's equity in the Blane field to 30.5%.  Blane offers significant upside potential in the form of increasing reserves and production.  The transaction is also tax efficient, accelerating the rate at which Faroe can use its tax existing losses in the UK.

After producing above expectation during 2015, in response to the need to extend the Njord and Hyme production facility life (the Njord Future Project), by strengthening the structure and modifying the topsides, production from the Njord and Hyme fields in Norway will be suspended in the summer of 2016.  Statoil, the operator, is now progressing plans for the Njord Future Project which, as well as bringing back on stream the Njord and Hyme fields, includes development of the significant Snilehorn field and potentially other discoveries in the area.  The Njord Future Project, with estimated reserves of around 200 mmboe gross, aims to capitalise on the current market conditions through material cost reductions in order to maximise the economic value of this important project.

Faroe's production is spread across a balanced and high quality portfolio of assets with a fairly even split between Norway and UK and between liquids and gas.  Approximately 80% of post-tax gas production is hedged in 2016 and 50% in 2017 at prices averaging 45p/therm, substantially above the current forward curve.  Approximately 22% of post-tax oil production is hedged in H1 2016 with an average floor of approximately $50 per barrel. 

Exploration programme continues but fewer wells expected

Faroe's exploration focus is predominantly in Norway.  Having a broad portfolio of licences to high-grade and mature towards drilling is essential for the Company and Faroe remains committed to its cost-effective business model of winning exploration licences through licensing rounds to provide constant feedstock for a sustained drilling programme.  Faroe won five licences in Norway at the beginning of 2015 and a further six were awarded in Norway in January 2016.  As part of a continuous process of managing our portfolio and high-grading prospects, a number of licences have also been relinquished; Faroe had 33 exploration licence areas at the end 2015 compared to 50 at the end of 2014.

Faroe has been one of the most active explorers in Norway in recent years, with a drilling programme averaging four exploration wells per annum over the last five years.  Five wells were drilled in 2015, of which the Boomerang well was a successful discovery.  As E&P companies, with whom Faroe partners, are looking to reduce expenditure due to continuing low commodity prices, it is expected that the number of exploration wells drilled by Faroe will also be lower than in recent years.  In 2016 Faroe plans to participate in three wells, all in Norway.  The first of these, Kvalross in the Barents Sea, spudded in January 2016; unfortunately the well was not a discovery, as announced on 24 February 2016.  However, the well was drilled safely and significantly below the budget cost.  Planning is ongoing in the Faroe-operated Brasse licence, with an exploration well scheduled to be drilled in the summer for which the Transocean Arctic drilling rig has been contracted on very competitive terms, minimising the net after-tax well cost to Faroe.  Brasse is an exciting prospect within tie-back distance to either the Brage or the Oseberg platforms, if a discovery is made.  In H2 2016, the Njord partnership (Faroe 7.5%), led by operator Statoil, is planning to drill a new prospect on the North Flank of Njord, in close proximity to the main field.  If successful, the exploration well will add further volumes to the Njord Future project.

Outlook

With a relatively strong balance sheet and cash flow from low-cost and partly hedged production assets, Faroe has built solid foundations on which to continue building its producing portfolio.  This is planned to be achieved through a combination of maturing our existing assets and taking advantage of potential consolidation opportunities, through acquisitions and asset swaps.  Faroe aims to continue its active exploration programme albeit with fewer wells targeted in 2016 and 2017.  We look forward to drilling our operated Brasse well in the summer whilst continuing to high-grade the most prospective drilling targets from our exploration portfolio for future wells.

These are undoubtedly challenging times, but times of uncertainty create opportunity, and while we are taking all necessary measures to withstand the test of continuing low commodity prices, Faroe intends to take full advantage of its unique platform to deliver growth in the coming period.

REVIEW OF ACTIVITIES

Faroe Petroleum's principal focus is on creating shareholder value through exploration, appraisal, development, production and M&A activities offshore Norway and the UK.  The Company continued to manage and high-grade its extensive portfolio in 2015 resulting in further successful licence round applications, an active drilling programme, maturing of discoveries towards development and enhancing production.  Net economic production averaged 10,530 boepd in 2015, an increase from 9,106 boepd last year and 2P Reserves almost doubled from 30.6 mmboe at the beginning of 2015 to 57.4 mmboe at the beginning of this 2016.

Production portfolio

Total average economic production for the full year 2015 exceeded the upper end of guidance at 10,530 boepd (2014: 9,106 boepd), of which approximately 58% was liquids and 42% gas.  The main fields in Faroe's portfolio performed above expectation in 2015, which led to the upward adjustment of production guidance announced in November 2015, and ultimately an outcome which exceeded revised guidance.  With an average operating cost of $23/boe in 2015, Faroe's production portfolio was cash generative even in the low commodity price environment.

In the Brage field (Faroe 14.26%), the investment in two new infill wells was very successful, adding further production capacity and contributing to a reduction in unit operating costs.  The next drilling campaign on the Brage field is in preparation and is expected to commence in 2017.

The acquisition of additional interests in the Blane and Enoch fields was completed in November 2015, increasing the Company's interests to 30.5% in Blane and 13.86% in Enoch.  The deal boosts Faroe's oil production and improves tax efficiency by accelerating the utilisation of carried forward tax losses.

Following excellent performance in 2015, production from the Njord and Hyme fields (Faroe 7.5%) will be temporarily suspended from the end of May 2016 after which the Njord A and B facilities are planned to be towed to shore to prepare the facilities for life extension - the Njord Future Project.  The planning of Njord Future Project is ongoing with concept selection scheduled for mid-2016 and a final investment decision and Field Development Plan submission expected in early 2017.  It is expected that the Njord Future Project, which includes the Njord and Hyme fields, development of the Snilehorn field, and potentially further fields in the area, will take approximately three years from when the project is sanctioned before the facility is back on production. This important project will seek to take full advantage of the significant cost reductions in the market today to maximize economic value and return on investment. 

The Schooner and Ketch fields (Faroe 60% and operator) delivered stable production during 2015 and  various cost reduction measures have been implemented to improve profitability; these measures include the logistic sharing initiative, covering the sharing of helicopters, vessels and accommodation, with the neighbouring Eni-operated  Hewitt platform. The Schooner and Ketch fields tie back to the Theddlethorpe Gas Terminal in Lincolnshire.   Discussions are ongoing with the terminal operator to extend the lives of the terminal and other infrastructure to allow the continued production of Schooner and Ketch and the others fields in the catchment area with remaining economic potential.  The longevity of these fields is dependent upon a recovery in market prices and continued access to the infrastructure.      

Average full year 2016 production is expected to be in the range of 7,000-9,000 boepd from all fields, which includes production from the Njord and Hyme fields until the end of May 2016, in accordance with plans for the Njord Future Project.

Pre-development projects

Following a series of successful exploration wells over recent years, Faroe now has three important projects in Norway progressing towards development: the Snilehorn discovery, which forms part of the Njord Future Project; the Butch field; and the Pil, Bue and Boomerang fields.   Collectively these projects are of great significance and, with development costs expected to fall significantly as a result of sustained low commodity prices, these projects have the potential to add considerable value to Faroe in the coming years.

Snilehorn (Faroe 7.5%): the operator (Statoil) has selected a two-well subsea tie-back to Njord A as the selected concept for the Snilehorn development.  It is envisaged that a water injection well can be drilled from the Hyme template into the Snilehorn reservoir and thereby provide a cost efficient development solution for Snilehorn.  The terms of a tie-in agreement with Njord have been negotiated, making the Snilehorn development an important element of the Njord Future Project. 

Butch (Faroe 15%): the Butch development plan passed Concept Selection stage in 2015 and the Front End Engineering and Design project is progressing to plan. The field is planned to be developed as a subsea tie-back to the BP-operated Ula oil field. The investment decision and Field Development Plan submission to the Norwegian authorities are currently planned for Q4 2016. Estimated capital expenditure has come down with further cost reductions targeted as the project starts the tendering processes.

Pil (Faroe 25%): a project feasibility report was submitted to the Norwegian authorities in 2015 confirming three economic development options: a subsea tie-back development to Njord; a subsea tie-back development to Draugen; or a stand-alone development based on a leased FPSO.  During 2016 work will continue to mature the project towards a Concept Selection decision.

Exploration

Portfolio overview

For several years, the Company has been among the most successful independents in winning prime quality exploration acreage in Norwegian waters.   In January 2015, the Company was awarded five new licences in Norway.  At the year end, the exploration and appraisal portfolio consisted of a total of 33 licence areas, decreased from 50 at the end of 2014, following a continuous programme of active management, relinquishments and high-grading. In January 2016, a further six new licences were awarded in Norway in the Awards in Predefined Areas (APA) licensing round. Five wells were drilled in 2015, all in Norway, and the 2016 drilling programme contains three exploration wells.

The Company's principal exploration focus is in 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 eight exploration and appraisal licence areas in the Norwegian North Sea, 13 in the Norwegian Sea and three in the Barents Sea.

At the year-end Faroe held nine licence areas in the UK and Ireland.  Of these, four are in the UK Central North Sea where the Company's focus has been around the undeveloped Perth-Dolphin-Lowlander fields and a few other near-field opportunities.  In 2016 the Company will withdraw and relinquish the two exploration licences held in the West of Shetland area (P1190 Tornado and P2011 Dunvegan). In October 2014 the Company was awarded three new licence options in Ireland located in the southern margin of the North Celtic Sea basin.  The objective in this area is to exploit reprocessing technology at very low cost to de-risk a number of prospect opportunities ahead of making any significant further cost commitments.

Drilling operations

The Skirne East (Shango) exploration well was located in the Norwegian North Sea in licence PL627, adjacent to the producing Skirne Field, and commenced drilling in March 2015.  The well encountered a net gas-bearing reservoir section estimated at 10 metres thickness in the Middle Jurassic Hugin formation, confirming hydrocarbons at the same reservoir level as in Skirne.  Reservoir properties were found to be excellent.  The preliminary resource estimate for the Skirne East discovery is in the range of 3 to 10 mmboe gross (0.3 to 2.0 mmboe net to Faroe). Due to the size of the discovery it is unlikely to be developed as a separate development project and the costs associated with the well have been written off in 2015. The current focus in the area is to mature a prospect near Shango to drillable status. If successful, the prospect has the potential to make Shango a part of a possible economic development project. 

The Bister well, located in the Norwegian Sea in licence PL348C adjacent to the 2013 Snilehorn discovery and  the producing  Hyme field,  started drilling in May 2015.  The well and side-track found reservoir of similar quality to Hyme and Snilehorn but failed to encounter hydrocarbons.  Valuable data was secured and the licence contains several further promising exploration targets, which are currently being evaluated.

The Portrush well, located in the Norwegian Sea in licence PL793 south of the Njord field commenced drilling in August 2015 and whilst the targeted  reservoir  was present no hydrocarbons were encountered.  This well was drilled at very low cost, benefiting from significantly reduced rig rates.

The follow-up campaign for the 2014 Pil discovery in licence PL586 commenced in June 2015 with the spudding of the Boomerang exploration well (Faroe 25%). Pil is located approximately 30 kilometres to the south west of the producing Njord field (Faroe 7.5%). The exploration well targeted prospective resources in the Upper Jurassic reservoirs analogous to the Pil, Bue and Draugen field reservoirs.  The main well bore encountered a 26 metre gross Upper Jurassic Rogn sandstone with moveable oil.  Preliminary estimates of gross recoverable volumes in the discovery range between 13 and 31 mmboe.

The second follow-up well, targeting the Blink prospect, commenced drilling in September 2015.   The objective of the well 6406/12-5S was to test a possible extension of the Pil discovery towards the north.  The well encountered a 557 metre gross section of Upper Jurassic sandstone following a technical side-track but the reservoir did not contain hydrocarbons.   

Since the year-end the Company has drilled the Kvalross well in the Barents Sea (Faroe 40%) in licence PL611 to the south of OMV's significant Wisting and Hanssen oil discoveries.  The well tested two independent targets: the Kvalross prospect within the Lower Triassic Klappmyss formation; and the Kvaltann prospect within a Mid-Late Triassic Snadd formation channel.  Good quality sands were encountered in the Kvaltann prospect but were found to be water-wet.  In the main Kvalross target hydrocarbon shows were observed, but not in good quality reservoirs.

Relinquishments and withdrawals

Due to lower commodity prices, stricter decision criteria are being applied by the Company for the retention of licences and commitment to further work and expenditure in our assets.  In the near term, this will result in a reduction in the number of licences in the portfolio, and those licences that have been retained will be economically more robust.  During 2015 we withdrew from or relinquished 17 exploration licences.   Since the year-end the Company has also agreed to withdraw from the Tornado licence (Faroe 7.5%), UK west of Shetland and consequently the book value was written off in 2015.  The Company also plans to relinquish the Solberg and Rodriquez licences (Faroe 20%) in Norway; in both these cases, the decisions to withdraw are a result of a combination increasing licensing fees together with a low probability of progressing these assets to become economically viable developments. The Company continues to monitor all of its pre-development assets and will not hesitate to withdraw from any which cease to have a reasonable expectation of creating value in the near to medium term.

Reserves & Resources

Reserves

The Company's internal estimate of Proven and Probable (2P) Reserves at 1 January 2016, 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 57.4 mmboe (1 January 2015: 30.6 mmboe) - increasing reserves by 88% over the year.  This significant increase is mainly a result of the transfer from 2C Resources to 2P Reserves on the significant Pil and Butch fields, both of which were discovered by Faroe Petroleum. 

The Company's 2P reserves have increased by 56.2 mmboe from 1 January 2009 to 1 January 2016 - as shown in the graph below.

http://www.rns-pdf.londonstockexchange.com/rns/3242T_-2016-3-28.pdf 

Contingent Resources

At 1 January 2016, 2C Resources were estimated to be 98.3 mmboe representing a decrease of 10% over the year (109 mmboe at 1 January 2015).  Again, this reduction was largely as a result of the transfer of Pil and Butch volumes from 2C Resources to 2P Reserves.  The 2015 Boomerang exploration discovery (Faroe 25%) and the increased interest in the South East Tor field (Faroe 85% and operator) compensate substantially for the transfer of Pil and Butch from 2C Resources to 2P Reserves.

FINANCE REVIEW

Overview

Faroe has sought to adjust to a low commodity price environment - this is a major challenge for Faroe as it is for the rest of the industry globally, particularly the small E&P companies.  In 2015 we ran a cash-neutral budget, closing the year with £91.5 million cash compared to £92.6 million at the close of 2014.  Falling oil and gas prices and an active exploration drilling programme of five wells made our target of a cash-neutral budget particularly challenging but through strong production performance, reduced operating and overhead costs, and significant gains on oil and gas hedges our target was achieved. At the year end £23.0 million of debt was drawn under the reserve based lending facility, unchanged from 2014, resulting in net cash at year end of £68.5 million (2014: £69.6 million). 

Revenue, including realised hedging gains, averaged $47 per boe (2014: $71 per boe) after taking account of £4.6 million overlift (2014: £18.4 million), included in revenue and cost of sales.  The negative impact of the fall in revenue per boe, due to the continued fall in commodity prices during the year, was partly offset by a fall in opex per boe which fell from $33.5 per boe in 2014 to $22.5 per boe in 2015.  DD&A per boe was reduced by $6.0 to $15.1 boe (2014: $21.1 boe) mainly as a result of higher production in 2015 and the effect of 2014 impairments.

Income statement

Revenue for the year was £113.0 million (2014: £128.8 million).  Cost of sales, including depreciation of producing assets, but before impairment charges, was £99.8 million (2014: £102.8 million).  Pre-tax impairment charges of £45.1 million (post-tax £26.7 million) (2014: £38.5 million and £29.2 million pre- and post-tax respectively) were incurred, primarily on Blane, Schooner and Ketch in the UK and Njord and Hyme in Norway. The main reason for the impairments is the significant decline in the oil and gas prices.  These impairment charges resulted in a gross loss for the year of £32.0 million (2014: £12.5 million).  However, EBITDAX for the year increased to £60.4 million (2014: £59.1 million) with strong production performance and lower operating costs offsetting falling commodity prices.  Realised hedging gains of £9.3 million (2014: £0.5 million) are classified as other income and are included in EBITDAX.

Pre-tax exploration and evaluation expenses for the year were £89.5 million (post-tax: £22.0 million) (2014: £139.4 million and £47.2 million pre- and post-tax respectively).  This includes pre-award exploration expenses of £6.0 million and write-offs of licence-specific exploration and evaluation expenditure of £83.5 million on previously capitalised licences where active exploration has now ceased.  The exploration costs which were written off during the year related to relinquished licences and unsuccessful well costs on PL611 (Kvalross), PL475D (Rodriguez/Solberg), PL793 (Portrush), PL627 (Shango), PL586 (Blink), PL348B (Bister), P324 (Lowlander) and P1190 (Tornado) along with other exploration costs on a number of licences.

The Group's reported loss before tax was £122.3 million (2014: £165.8 million).  Loss after tax was £52.9 million (2014: £55.0 million). 

Hedging

In line with Group policy approximately 57% of post-tax production was hedged in 2015, of which 40% were oil sales and 76% were gas sales, with realised hedging gains, net of cost, of £9.3 million (2014: £0.5 million). The cost incurred for the 2015 hedges was £1.3 million (2014: £1.0 million). 

At December 2015, the Group had entered into hedging arrangements covering approximately 65% of 2016 and 50% of 2017 total expected gas production (on a post-tax production basis) and 5% of expected oil production.  The gas hedging arrangements are predominantly put options with floors between 45 and 50 pence per therm.  The oil hedging arrangements are swaps and zero cost collars with an average strike price of $63 per barrel.  Unrealised hedging gains for these open hedge contracts for the year were £10.6 million (2014: £6.1 million) 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 (2014: £1.5 million).

Further gas and oil hedges have been undertaken in 2016 following which 80% of post-tax gas production is hedged in 2016 and 22% of post-tax oil production is hedged in H1 2016.  The Company continues to monitor the commodity market and aims to extend the current hedging programme, particularly for oil, at opportune moments taking a layered approach to its hedging strategy.

Faroe is subject to taxation under two regimes in Norway, namely: offshore where a special tax of 53% is applied, and; onshore where the standard corporation tax rate is 25%. Hedging gains fall only within the onshore regime and hence the concept of hedging "post-tax production" which implies that in order to be fully hedged in Norway on a post-tax basis, approximately 29% of pre-tax barrels need to be hedged.

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 2015 the Group had unrelieved tax losses in the UK of £55.6 million (2014: £68.0 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.  It is likely that the UK tax losses will be utilised in the coming years and a deferred tax asset of £30.0 million relating to the carried forward tax losses in the UK was recognised in 2014. In March 2015 it was announced that the supplementary corporation tax ('SCT') in the UK was reduced from 32% to 20% with effect from 1 January 2015 which necessitated a reduction in the recognised deferred tax asset of £5.0 million, which was expensed in the Income Statement in 2015.  A further 10% reduction in SCT was announced in March 2016 and the net impact on the deferred tax asset following the latest SCT reduction will be £6.0 million, which will be recognised in the 2016 accounts.  The deferred tax asset at 31 December 2015 relating to UK tax losses was £32.4 million.

The amount of tax receivable at 31 December 2015 was £35.2 million (2014: £45.8 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 2016.  The tax credit in the Income Statement was £69.4 million (2014: £110.8 million) and consisted mainly of the Norway tax receivable, and origination of timing differences of £34.8 million.

Balance sheet

Exploration and evaluation investments of £61.9 million (post-tax: £14.8 million) (2014: £87.2 million pre-tax, £23.0 million post-tax) were made in the year.  The E&E investments mainly related to drilling the Shango, Portrush, Bister, Blink and Boomerang wells in Norway.  After exploration write-offs in the year of £83.5 million (2014: £131.7 million), the intangible assets decreased by £54.8 million to £73.5 million (2014: £128.3 million). Net assets decreased during the year to £192.4 million (2014: £245.5 million). 

Development and production investments of £13.6 million (2014: £22.6 million) were made in the year, excluding acquisitions.  The Group acquired interests in Blane and Enoch from Roc Oil (Europe) Ltd for £10.6 million and determined that this was the fair value of the assets and liabilities acquired, fully attributable to the Blane field.  Following DDA and impairments, development and production assets decreased by £27.8 million to £110.6 million (2014: £138.4 million).

The Group recognises the discounted cost of decommissioning when obligations arise.  The amount recognised is the present value of the estimated future expenditure determined by local conditions and requirements, net of any amounts carried by third parties.  At 31 December 2015 the Group had decommissioning provisions of £85.9 million (2014: £77.1 million).  The increase in the provision is mainly due to changes to existing provisions and additional provisions on acquired assets.

Cash flow

Closing cash was £91.5 million (2014: £92.6 million).  Net cash at the year end was £68.5 million (2014: £69.6 million). 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 2015 the Company received the tax rebate for 2014 of £40.2 million, most of which was used to repay the 2014 utilisations of the EFF.

The Group also has a secured US$225 million (approximately £155.0 million) reserve based lending facility which is available for both debt and issuance of letters of credit.    At 31 December 2015 the calculated borrowing base amount was £53.5 million, of which £23.0 million was drawn (2014: £23.0 million).

With a combination of the current cash in the business, cash flow from producing assets and 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 2016 is forecast to be up to £70 million.  

Notes

1.            The financial information set out above does not constitute the Company's financial statements for the years ended 31 December 2015 or 2014. The financial information is derived from the financial statements for 2014 prepared in accordance with IFRS.  The auditors have reported on the 2015 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.            Other income analysis

5.            Taxation

6.            Post balance sheet events:

Norwegian exploration licence awards

On 20 January 2016, the Company announced that it has been awarded six new prospective exploration licences, including two operatorships, under the 2015 Norwegian APA Licence Round on the Norwegian Continental Shelf.  Due to the nature of the oil and gas industry it is not possible to quantify the financial effect of these license awards.

Kvalross exploration well in Norway Barents Sea

On 24 February 2016, the Company announced the results of the two independent targets where good quality sands were encountered in the Kvaltann prospect but were found to be water-wet and in the main Kvalross target hydrocarbon shows were observed, but not in good quality reservoirs.  No commercial discovery has been made.  The costs of this well are included in the £83,569,000 exploration asset write  off.

UK tax rate change

The Chancellor of the Exchequer of the United Kingdom announced in his Budget Statement on 16 March 2016 that the rate of supplementary charge tax (SCT) will be reduced from 20% to 10% with effect from 1 January 2016.  The reduction in SCT will affect the carrying value of the Group's deferred tax liability; reducing the rate at which fixed assets and other temporary differences will reverse and also reducing the rate at which UK ring fence losses will be relievable in the future.  It is estimated that, following the reduction in SCT, the deferred tax liability will reduce by £0.3 million and the deferred tax asset will reduce by £6.3 million, resulting in a net reduction in the recognised deferred tax asset of £6.0 million.

7.            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