Preliminary Results 201226 March 2013
Audited Preliminary Results for the Year Ended 31 December 2012
Faroe Petroleum, the independent oil and gas group focused on oil and gas exploration and production in the Atlantic margin, Norway and the North Sea, announces its audited Preliminary Results for the year ended 31 December 2012.
- Maximising our potential through a balanced northern seas portfolio of outstanding exploration and appraisal opportunities, underpinned by high quality non‐operated Norwegian and UK production
- 2P reserves of 20.1 mmboe at 31 December 2012 (including East Foinaven1), 95% of which is associated with fields on production
- 2012 total average production of approximately 6,900 boepd (2011: 2,500 boepd average production). Including East Foinaven 2012 average production was approximately 7,200 boepd
- Exploration successes with discoveries in Butch and Rodriguez (post year‐end) in Norway mitigating an otherwise mixed year for exploration results
- Portfolio increased substantially to over 60 licences with 16 awards, with high equity stakes – UK: seven new licences, including three operatorships, Norway: eight new licences, including three operatorships (post year‐end), Iceland: frontier licence as operator
- Investment of £161.4 million (2011: £96.2 million) in development and exploration capital expenditure during the year funded from cash, cash flow and Norwegian tax rebate – £111.8 million pre‐tax (£35.5 million post‐tax) on exploration, £49.3 million development expenditure on producing fields
- Cash of £72.9 million (2011: £111.6 million) excluding restricted cash of £2.7 million (2011: £0.7 million)
- Doubling and extension of committed credit facilities (Reserve Based Lending and Norwegian Exploration) to US$425 million completed in year – both facilities substantially available at year end
- Turnover nearly doubled to £158.8 million (2011: £80.2 million)
- EBITDAX increased 135% to £96.0 million (2011: £40.9 million)
- Expensed exploration expenditure of £79.7 million (2011: £42.3 million) includes pre‐licence expenditure of £8.6million and write offs of £71.1 million
- Loss after tax of £5.2 million (2011: £47.4 million profit which included £40.0 million exceptional gain on disposal of Maria interest)
1 In 2012 the Company commenced reporting its own reserves estimates (as explained more fully on Page 12) and had no asset related impairments in the year. The Group’s 2P reserves at 31 December 2012 have been estimated at 18.9 mmboe. When including the reserves in East Foinaven (this transaction has an effective date of 1 January 2012 and is expected to complete in H1 2013) 2P reserves stand at 20.1 mmboe.
- 2013 capital expenditure of approximately £170 million, including around £120 million on exploration (pre‐tax rebate in Norway) and approximately £50 million on developments and producing fields – all fully funded – Provides shareholders with multiple opportunities for step‐change in value growth, Exciting exploration and appraisal programme continues, targeting substantial upside potential with five firm wells planned for 2013: four in Norway (Darwin, Snilehorn, Novus and Butch East), and one in UK (Perth appraisal), Preparing to operate the Novus exploration well on the Halten Terrace, Norway in H2 2013, Production to benefit from newly developed Hyme satellite field tied‐back sub‐sea to Njord, East Foinaven, when transaction completes, plus several further planned in‐fill wells
- Assessing opportunities to extend our exploration model into new areas over the medium term
- Active preparations to secure further licences in near‐term licensing rounds
- 2013 production guidance 7,000‐9,000 boepd
- Assessing potential to acquire further production to enhance tax efficient cash flow
Graham Stewart, Chief Executive, commented:
“This has been a particularly active year for the Company, with a dramatic boost to production, and cash flow, together with a steady, fully funded exploration programme. We have increased our portfolio significantly through a large number of licence awards, including our first award in Iceland, and outstanding results in the 2012 APA round in Norway and UK 27th Round.
“This success demonstrates Faroe’s ability to continue to deliver solid value for shareholders through the drill‐bit, licence awards and transactions; further differentiating ourselves and securing our position as one of the most active UK listed explorers. The considerable increase in cash flow from our production base, combined with healthy cash balances and debt facilities ensures we are well financed going forward.
‘’2013 kicked off with a significant discovery at Rodriquez, and our portfolio of exploration licences ensures Faroe has an exciting and material drilling programme ahead with five firm high impact exploration and appraisal wells planned; including the Darwin prospect in the Barents Sea and a continuing programme of production in‐fill wells. We look forward to an exciting period ahead.”
For further information please contact:
Faroe Petroleum plc
Tel: +44 1224 650 920
Panmure Gordon (UK) Limited
Callum Stewart/Adam James
Tel: +44 20 7886 2500
Oriel Securities Limited
Michael Shaw/Ashton Clanfield
Tel: +44 20 7710 7600
Billy Clegg/Edward Westropp
Tel: +44 20 7831 3113
The year delivered another busy period for the business, beginning and ending on a high, first with the Butch discovery and finally with the Rodriquez discovery, both of which are significant and with substantial upside. The Group had hoped for a repeat of the high exploration hit rates we achieved in 2010 and 2011, but we had a number of disappointing wells in 2012. It is important to acknowledge however, that such is the uncertain nature of exploration. The ongoing programme will test a variety of exploration plays, with a spread of risk and reward; this should be assessed on a portfolio basis, and with one of the largest in the UK and Norway, we remain confident with an overall discovery rate well ahead of the industry average.
Faroe has maintained a consistent strategy since inception, focused on creating exceptional shareholder value from portfolio exploration. Through prudent portfolio and financial management, the Company has at all times ensured that it has the necessary funding in place to participate with material stakes in a multi‐well exploration programme on a consistent and sustainable basis. Indeed, for the past three years all of the Company’s investments have been funded from cash, operational cash flow and Norwegian tax rebates. This largely self‐funding approach to our business model is one of Faroe’s great strengths particularly in these times of equity capital markets uncertainty.
Faroe Petroleum has, through its highly successful application process, increased its number of licences to approximately 60. The Group has steadily grown to become one of the most successful applicants in the UK, Norway and recently Iceland. During the last year we secured a total of 16 new licences, our greatest award success to date. It is notable that many of the new licences have been granted with Faroe as operator, and in partnership with some of the world’s leading industry players, such as Eon, Statoil and Total, as well as the Norwegian State‐owned oil company Petoro AS.
As Faroe grows in size, so must the materiality of our exploration drilling programme. In order to deliver a growing high impact exploration programme into the future, we have commenced a process of assessing the potential for participation in new positions beyond our current geographic footprint, where we may expect to drill attractive frontier exploration wells in the medium term. Such expansion, if executed, would be designed to capitalise on our technical strengths, experience and competitive edge and would target play types similar to our existing assets.
In exploration we had an exciting programme in 2012 with a total of seven wells drilled, two of which were significant successes, Butch and Rodriguez (completed post year‐end), both in Norway. Technical discoveries were also made on T‐Rex and Cooper. Cooper is the subject of continuing work to assess the merits of a second well on the block. Although it did not find hydrocarbons, Clapton, the Group’s first Norwegian well as operator, was drilled successfully, on budget and safely – an important achievement for the Company.
During 2012 Faroe matured its asset base, building on the low cost exclusive acquisitions and swaps from 2011 and earlier. By making significant investments in its existing development and production assets the Company has further enhanced its high quality non‐operated UK and Norwegian oil and gas production portfolio. These investments included the fast‐track sub‐sea development of Hyme and infill wells on Njord, Brage and Ringhorne East. Faroe now has a strong cash position, greatly enhanced cash flows from its production, boosted by currently high and stable oil prices, significantly increased committed debt facilities and access to Norway’s unique and highly attractive exploration tax rebate system. Faroe can therefore confidently continue its programme of high impact exploration and in‐fill wells while pursuing its aggressive growth plans.
Iain Lanaghan is leaving the Board in 2013 after four years as Group Finance Director. He has overseen a significant strengthening of the Company’s cash flow and balance sheet, including the formation of a strong international bank group to provide US$425 million of committed bank facilities. I would like to take this opportunity to thank Iain for all his diligent and hard work in guiding the Company into its position of financial strength and sustainability and wish Iain all the best for his future. The search for a replacement is well advanced and an announcement of the new appointee will be made in the near future.
Faroe’s strong reputation and technical excellence has allowed us to pursue and deliver growth in some of the most sought after oil and gas plays in the world. In addition we have built a highly profitable production portfolio to generate the cash flow we need to fund our wells. This has been achieved through focus, professionalism and a commitment to long term partnerships with some of the leading companies and Governments in the world of oil and gas.
Faroe Petroleum has a truly outstanding team of professionals who are deeply committed to creating value and achieving material success for our shareholders. We intend to take full advantage of our capabilities and strong growth platform going forward and are confident of delivering outstanding success in the years ahead.
CHIEF EXECUTIVE’S REVIEW
I am pleased to announce the audited results for the year ended 31 December 2012, a year of significant progress. The year saw a period of growth and consolidation across the portfolio of exploration, appraisal and production. Faroe’s focused portfolio exploration strategy, now largely self‐funded, continues to serve us well and we now occupy a very strong position from which to grow.
Strategy – clear and focused
Pursuing a portfolio exploration business model mitigates exploration risk and increases the probability of success by drilling a significant number of high impact wells every year. We have built solid foundations in the three main elements of our business model; exploration (application, licence awards, prospect maturation, discovery); monetisation (appraisal, sale, swap/trade into production); and financing (cash reserves, cash flow, debt facilities and tax efficiency). Each of these areas commands substantial attention and resource for the business cycle to perform optimally. As demonstrated over the years, we focus on monetising our discoveries in the near term wherever we can in order to realise value, generate cash flow, and maintain a good portfolio balance, without excessive financial exposure to a single asset.
Over the years we have built a balanced, world class portfolio of assets in the Atlantic margin, the North Sea and Norway, where we have secured material interests in approximately 60 licences. Our core areas are among the most sought after exploration plays in the world, and, in addition to the North Sea and Norwegian Sea, include areas that are under‐explored (the Barents Sea and the Atlantic margin) and un‐ explored (Iceland). The Company’s exploration portfolio is directed towards high impact wells in both near‐ field (close to existing infrastructure) and frontier positions. The vast majority of our licences have been won through licence rounds, having been successful year after year in competitive licensing rounds in the UK, Norway, Faroe Islands and now Iceland. A throughput of new prospects is continuously worked up and matured to deliver a sustainable and active programme of high impact wells across a multitude of exciting and diverse exploration plays. In this way we ensure our model is sustainable, with the aim of drilling four or more high impact wells every year, and delivering high value growth for shareholders.
We have chosen to build a strong production portfolio to generate tax efficient cash flow to fund our exploration and appraisal programme, which is an enviable position, setting us apart from a number of E&P companies. This model has worked very well for us such that our entire 2012 drilling programme, encompassing exploration, appraisal and development wells was funded from a combination of existing cash, operational cash flow and Norwegian tax rebates.
Faroe Petroleum has been particularly active on the Norwegian Continental Shelf, recognised in recent years as one of the most important and successful exploration provinces in the world. In the past two years giant new oil field discoveries were made, most notably Skrugard and Havis, representing a breakthrough for exploration in the Barents Sea, and Avaldsnes and Aldous (now known as Johan Sverdrup) on the Utsira High in the Norwegian North Sea. Combining Norway’s under‐explored oil and gas potential with its unique tax refund system, designed to encourage exploration by shielding explorers from 78% of exploration costs, Faroe is well placed to achieve great success there. This tax regime allows us to hold much larger equity positions in wells than would be possible in the UK or elsewhere.
At the same time we have continued to build one of the largest exploration acreage positions among UK independents in the West of Shetland area, where we have several material large frontier well opportunities, including the Grouse and Aileen prospects.
In Iceland, we have chosen to build a position in the northerly waters to the south of Norwegian owned Jan Mayen Island. The main attraction is the very large prospect sizes there, but also the expectation that, like Greenland and the Barents Sea, this area will attract the attention of the major oil companies seeking high impact exploration opportunities in frontier virgin basins.
Exploration performance – growing activity
The year was a particularly active year of exploration drilling for us with Butch, T‐Rex, Kalvklumpen, Cooper, Clapton and Rodriguez being drilled in Norway, and North Uist being drilled in UK, West of Shetland, and Spaniard in UK Central North Sea. Butch delivered a very exciting new discovery with light oil in excellent quality reservoir sands. It also delivered a new play with significant appraisal and exploration follow up potential, and further wells scheduled for H2 2013 and H1 2014, with the intention of proving up more resource ahead of a development decision. The T‐Rex well in Norway’s Halten Terrace was Faroe’s first well targeting a new play type in Cretaceous reservoirs. The well confirmed the presence of oil but in a thinner than expected reservoir interval. We have since the year‐end announced success in the Cretaceous on the Rodriguez well and this may represent a significant breakthrough for this new play type. While the Kalvklumpen well in the North Sea encountered excellent reservoirs, no hydrocarbons were encountered. However, an extensive data gathering programme was undertaken, and despite this initial disappointment, the data indicate good follow up potential in this and adjacent licences. Clapton was Faroe’s first well as operator in Norway, and the Company demonstrated its ability to operate both safely and successfully, delivering a well without serious incident, on schedule and on budget.
The Cooper well in the Norwegian Sea encountered hydrocarbons but none were flowed to surface in the subsequent drill stem test. Despite this, further technical work is being carried out on the Cooper well results with a view to potentially drilling a further well on the licence in a better location. Operations on the North Uist well in the West of Shetlands basin are finally being brought to a close and an announcement of the results is expected in the near future.
Faroe’s drilling programme has achieved a high success rate and many significant discoveries. This performance has not only served to validate the corporate strategy but has also enabled successful execution of several asset deals where discoveries have been exchanged for cash or material, long‐life production assets. The ability to monetise the exploration portfolio is key to the Company’s business model and, with multiple high‐impact prospects planned to be drilled over the months and years ahead, we would fully expect to see further value‐accretive deals completed in due course.
Licence applications – high success rate
As a fundamental feature of our business model, the addition of new licences through licence rounds in 2012 and the start of 2013 exceeded expectations. The Company was awarded a total of 16 new licences: seven in the UK 27th Round (three of which are operated); a further eight new licences in the 2012 Norwegian Awards in Predefined Areas (“APA”) Licence Round (three of which are operated); and a frontier licence in Iceland (as operator) each with high equity levels. The majority of these were generated by our own in‐house team and the high number of awards in very competitive rounds further demonstrates the level of confidence held in the Company by the respective host authorities.
Production portfolio – balanced with good upside
In 2011 Faroe completed the landmark swap transaction with Petoro (Norwegian State oil and gas company) of its 30% share in the Maria oil field discovery in Norway for Petoro’s interests primarily in three high quality producing oil and gas fields, Brage, Njord and Ringhorne East. Faroe’s entire portfolio of producing assets (which also includes the UK fields Blane and Schooner) generated average production in 2012 of around 6,900 boepd, with around 68% oil and 32% gas and condensate. This significant increase in average production from 2,500 boepd in 2011 provides the Group with far greater cash flow than ever before. This low cost production (opex per boe was US$34 in 2012 compared to a realised average oil price of US$113 per barrel, and an overall average realised price per boe of US$95) benefits significantly from carried forward tax losses in the UK and capital allowances in Norway.
Following the growth of our production portfolio, we have the complementary route to add significant potential value in our producing fields through active in‐fill drilling, field tie‐backs and near field exploration programmes. During the year £49.3 million was invested in further development and extending production in these fields. In particular, there was significant investment in the Hyme sub‐sea development, which came on stream in February 2013, and is expected to deliver around 10 to 15% of Faroe’s production volumes in 2013. In September 2012 the Group announced the acquisition from Marubeni of a 10% share in East Foinaven (together with a 0.5% interest in the West of Shetland Pipeline System) with an effective date of 1 January 2012 and completion is expected in the coming period. The cashflows from East Foinaven will be sheltered from UK tax due to the carried forward tax losses.
Finances – strong and tax efficient
The Group is in a strong financial position with 2012 year‐end unrestricted cash of £72.9 million, net of short term borrowings, a robust cash generating production base and significant debt capacity (Faroe has up to US$250 million of committed reserve‐based lending and up to NOK 1 billion of committed Norwegian exploration facilities). The Company also aims to utilise its UK tax loss position against its future UK production revenues to ensure that tax on profits is minimised and the value of existing and near‐term production barrels is maximised. This position is enhanced by strong cash flows from production in the UK and Norway, supported by continuing strong commodity prices. The combination of cash, operational cash flows and available debt facilities are expected to fund the Group’s planned exploration, appraisal and development programme while also providing headroom for growth.
Outlook – active drilling and more deals
A steady programme of exploration drilling throughout the years ahead is in prospect. Further advances are planned in building our production portfolio and from our strong financial position we plan to continue to win attractive new licences from which to generate further prospects for future drilling. As a central component of our model, Faroe will also continue to prioritise the monetisation of discoveries and seek to capitalise on attractive new growth opportunities.
Specifically, 2013 capital expenditure plans will be significant at approximately £170 million in total, including around £120 million on exploration (pre‐tax rebate in Norway) and approximately £50 million on producing fields. These investments are all fully funded from existing cash, operational cash flow, and Norwegian tax rebates. This programme will provide shareholders with five wells planned for the remainder of 2013: four in Norway (Darwin, Snilehorn, Novus and Butch East), and one in UK (Perth appraisal well). The Novus exploration well in the Norwegian Sea, will be operated by Faroe and is scheduled for Q4 2013.
The Hyme field came on stream in February 2013 with net production in 2013 expected to be approximately 1,200 boepd. In addition several in‐fill wells are planned for 2013 on the Njord, Brage, Ringhorne East and Schooner fields. 2013 production is expected to be 7,000‐9,000 boepd.
Going forward we plan to apply our skills, knowledge and know‐how to strengthen further our presence in our core areas and, if appropriate, extend these into new geographies to continue the generation of a strong future drilling programme. We will at all times focus on opportunities which capitalise on our technical and commercial strengths. With a robust balance sheet, strong cash flows and an excellent and strongly motivated team, we look forward to the period ahead with great excitement.
REVIEW OF ACTIVITIES
Faroe Petroleum remains focused on delivering exploration success in its core areas in the North Sea (UK and Norway), Norwegian Sea, Barents Sea (Norway) and Atlantic margin supported by and financed largely by its production assets. The Company possesses considerable detailed knowledge and expertise in each of these areas, which was clearly demonstrated last year by the successful licence awards both in the UK and Norway. The Company is also focussing on new Arctic frontier regions which contain high impact exploration opportunities such as in Iceland, where a new large exploration licence was won. The Company continues to build a balanced portfolio of exploration, appraisal, development and production assets with significant emphasis on the delivery of a high impact exploration and appraisal drilling programme.
Exploration – Norway
During the seven years since Faroe Petroleum established its presence in Norway, the Company has consistently been amongst the most successful in the various licence rounds. In the 2011 APA round, announced in January 2012, this was again demonstrated when Faroe won seven new licences, including operatorship of three licences, and in the 2012 APA round, announced in January this year, Faroe won a further eight licences, three of which as operator. Out of a total of 47 companies which submitted applications in the 2012 APA round, only three companies won more licences. The current portfolio extends from the shallow water region in the south, across the Norwegian North Sea, the Norwegian Sea and into the arctic region of the Barents Sea, and contains an excellent variety of low risk exploration and appraisal assets as well as high impact frontier assets. The licences are at various stages of maturity, which generates an active high quality drilling programme.
There has been a considerable increase in exploration activity in Norway in recent years with many new players competing for acreage and an increasingly high number of exploration wells being drilled. 2012 saw the arrival in Norway of Cairn Energy and Tullow Oil through the acquisitions of Agora Oil & Gas and Spring Energy respectively. Exploration activity in Norway has been very successful with high discovery rates and some of the largest oil discoveries in the world during the last few years including the billion barrel Johan Sverdrup discovery (formerly known as Aldous and Avaldsnes) in the middle of the Norwegian North Sea and the Skrugard and Havis oil discoveries in the Barents Sea, which represent a breakthrough in a new petroleum province.
The Group has had a good track record of success in Norway. Since 2010 the Group has drilled eight wells and made four discoveries. Three of these discoveries, Fogelberg, Butch and the most recent Rodriguez, are being progressed with further appraisal planned ahead of development decisions, and the Maria discovery was successfully swapped with Petoro for producing assets in Norway.
The Butch discovery well (Faroe 15%) drilled in late 2011/early 2012 found a light oil in an excellent quality reservoir on the north‐west side of a large salt structure. The discovery is located in 66 metres of water depth in the Norwegian North Sea close to the Ula and Gyda fields. Centrica as the operator has started working on a development plan for the Butch discovery and, in parallel, is also planning two further exploration wells to be drilled towards the end of this year and early 2014 on the untested south‐western and eastern sides of the same large salt structure. The well planning work is being carried out in parallel with the development planning to allow the latter to be fast tracked, irrespective of the outcome of the two additional exploration wells.
The Kalvklumpen well (Faroe 20%) in the Northern North Sea was drilled at the beginning of the year and found excellent reservoir at both target levels but did not encounter hydrocarbons. After incorporating the Kalvklumpen results and new information from other wells, the understanding of the petroleum system in this area is improving and several promising new targets have been identified.
The results of the T‐Rex well (Faroe 30%) were announced in March. The well found oil, but unfortunately encountered a thinner than expected reservoir section. T‐Rex was the first well to target the high potential Cretaceous play in this area and data from the well provided an important calibration point for further evaluation and de‐risking of other prospects on this play type including the Rodriguez discovery, the results of which were announced in January 2013. Moveable hydrocarbons were discovered in the Lower Cretaceous sandstone layers in the Lange formation, which contain an estimated gas condensate column of over nine metres net pay. Wintershall as operator estimates the preliminary size of the discovery at between 19 and 126 million barrels of recoverable oil equivalent (net to Faroe Petroleum approximately 6 to 38 mmboe). This is the first exploration well drilled on the Rodriguez licence PL475 and further appraisal will be required to establish the lateral extent and size of this discovery.
In addition to the Rodriquez discovery, Faroe Petroleum already has the Fogelberg gas discovery also in the Norwegian Sea, which is being matured towards a development decision to coincide with gas export capacity becoming available in the Norwegian pipeline system in a few years time. In this context, it is noted that the Norwegian Authorities have recently proposed a significant reduction in gas transportation tariffs for new gas field developments in Norwegian waters. This proposal is now in a consultation process and, if introduced, this change to tariffs would significantly improve project economics both of Fogelberg and Rodriguez.
In June Faroe announced the result of the Norwegian North Sea Clapton exploration well which was drilled on the side of the Mode Dome salt diapir (Faroe 40% and operator). Whilst the well encountered the primary chalk reservoir on prognosis, it did not contain hydrocarbons of producible quantities. It is worth noting that this well, which was Faroe Petroleum’s first operated well in Norway, was drilled successfully on budget and on schedule.
The results of the Cooper well (Faroe 30%) were announced in August. Oil was encountered in a 59 metres gross section within the Garn Formation and 10 metres gross section within the Ile Formation. A drill stem test to evaluate the potential productivity was undertaken although surprisingly, and unlike other wells in the area, no hydrocarbons flowed to surface. A large amount of data was collected and work continues to resolve why the Garn formation is tight in the Cooper well and whether this is likely to be a local or a field wide reservoir phenomenon.
Also in August, Faroe acquired a 12.5% share in licence PL531 in the Barents Sea, containing the Darwin prospect on which drilling commenced in March 2013. The prospect consists of a large closure at multiple levels located on the Veslemøy High in the frontier western part of the Barents Sea approximately 60 to 80 kilometres to the south west of the recent breakthrough oil discoveries on Skrugard and Havis. Faroe also holds two other very large exploration licences in the Barents Sea located between the Total operated Norvarg gas discovery to the East and the large Skrugard and Havis oil discoveries to the West. On the Samson Dome licence (Faroe 20%), a new 3D seismic dataset is being interpreted while in the Kvalross licence (Faroe 40%) a large new 3D seismic survey was acquired this summer and is currently being processed. Both these licences are being matured towards drilling decisions.
Exploration – UK
The Atlantic margin is a considerable oil and gas province and contains some of the UK’s largest producing oil fields; Clair, Foinaven and Schiehallion. Significant new development projects include the Laggan‐ Tormore gas project, which is the first gas development in this area and the installation of new gas export infrastructure has led to increased interest in exploration for gas. New tax incentives for deep water developments were introduced by the UK Government early last year and this has further stimulated exploration and development activity. The planning of Chevron’s Rosebank project is underway, which is expected to lead to further activity and installation of new deep water infrastructure in the area.
The Atlantic margin remains an important focus area for Faroe Petroleum. The Company currently holds one of the largest acreage positions in the Atlantic margin which includes ten licences, of which six are operated by Faroe, covering over 5,000 km2. The portfolio is diversified with several promising and independent exploration plays being pursued in parallel which are expected to generate an active programme of exploration drilling in the coming years. Since 2009, the Company has drilled five exploration wells in the Atlantic margin of which three were discoveries.
Operations on the BP‐operated North Uist exploration prospect (Faroe 6.25%) are in the final stages. Drilling of this deep‐water well commenced in March 2012, but due to extensive drilling related technical issues, significant delays have been experienced. The North Uist well is targeting a very large structure to the north of the Rosebank discovery. To manage the high cost of this well, Faroe secured a financial carry of a portion of the well cost, and retained a relatively small 6.25% licence equity.
The Grouse prospect (Faroe 50% and operator) is a very large structural prospect with an exciting seismic anomaly indicating the possible presence of light hydrocarbons. The prospect is located on the northern part of the Corona Ridge in post basalt Eocene layers. An electromagnetic survey was acquired over the prospect during the summer and the final evaluation of the prospect is in progress ahead of a drilling commitment decision.
In July 2011 the Company drilled an exploration well on the Fulla prospect which found the Clair and Whiting reservoir sands oil‐bearing. Extensive technical work was undertaken to establish the resource potential and assess a means of economically developing the Fulla discovery in conjunction with the 1980 Freya discovery, located immediately to the south in the adjoining Block 206/10a. The results of this work confirmed both relatively poor quality oil and a smaller than expected resource size and accordingly this acreage has been relinquished.
In the Central North Sea, south of the Perth field, on Block 15/21a Faroe participated in the Spaniard exploration well (Faroe 8.4%) with Premier as operator. While the well was not a success, Faroe’s costs were fully carried.
In October, Faroe announced that it had been awarded seven new exploration licences in the UK’s 27th Offshore Licensing Round one of which has since been incorporated within the Grouse P.1853 licence.
In the Atlantic margin, the Glenfarclas (Faroe 33.34%), Dunvegan (Faroe 50%) and Ribbon (Faroe 50%) traditional licences contain a combination of large structural and stratigraphic traps of Palaeocene and Cretaceous age. The new licences are located along the flanks of the Faroe‐Shetland basin in an emerging exploration play where several gas discoveries have already been made including Faroe’s Glenlivet discovery and Total’s Edradour discovery. Faroe was awarded operatorship of the Glenfarclas and Dunvegan licences. Faroe was also awarded an extension of the existing Grouse licence (Faroe 50%) allowing for the entire prospect to reside within Faroe‐held acreage.
Faroe Petroleum was awarded two new licences in the Central North Sea. Fulmar B is a new traditional licence operated by Endeavour Energy (Faroe 33.3%), located on the southern margin of the Central Graben, and contains a number of leads both at Palaeocene and Jurassic levels. In the Greater Perth Area, Faroe was awarded the Birnam traditional licence (Faroe 33.33%) with Parkmead as operator. This licence is located in the Outer Moray Firth, north east of the Perth oil field, in which the partnership already holds an interest and contains an attractive Upper Jurassic prospect. The Company was also awarded the Pinsent licence (Faroe 50%) on the western edge of the Northern North Sea Viking Graben, to the north of the BP operated Bruce field. This traditional licence operated by RWE Dea, is targeting a new Palaeocene play.
Exploration – Iceland
In December Faroe Petroleum announced a provisional exploration licence award in the Dreki area on the Icelandic Continental Shelf in the Icelandic 2nd Licensing Round. The licence (Faroe 67.5% and operator) is extensive, encompassing seven licence blocks located to the south of the Jan Mayen Ridge, which in turn is located inside the Arctic Circle to the north east of Iceland.
The new offshore licence is located to the south of the Jan Mayen Island, on a ridge which forms part of the Jan Mayen micro continent. This micro continent lies between the conjugate margins of both East Greenland and the Norwegian Continental Shelf, where several giant oil and gas fields have been developed. Recent samples taken from the seabed within the northern part of the new licence area have indicated the presence of both Mesozoic sedimentary rocks and a working hydrocarbon system. These are key components associated with many of the oil accumulations found in offshore fields in Norway and the UK.
The award of the licence was ratified in January 2013 and Faroe Petroleum has mapped several very large structures within the licence area and will now set about de‐risking these prospects with the agreed work programme.
Production and Development
Over 2012, excluding production generated from the acquisition of East Foinaven which is yet to complete, Faroe produced a net average 6,900 boepd of oil and gas derived principally from the Njord, Brage and Ringhorne East fields in Norway and the Blane field in the UK. Smaller contributions to production came from the Glitne and Jotun fields in Norway, as well as the Schooner, Topaz and Wissey gas fields in the Southern Gas basin in the UK.
Faroe has two fields in development: the Hyme field in Norway which came on stream in late February 2013 and the Orca field in the UK which is due on stream late 2013/early 2014. In addition, fields that are progressing in the appraisal phase and towards developments include Butch and Fogelberg in Norway, Glenlivet and Tornado in the west of Shetland and Perth in the UK Central North Sea.
During 2012 the Njord field (Faroe 7.5%) underwent a significant upgrade and development work programme, which included riser replacements, a low pressure project, preparations for the North West flank development and the tie‐in of the Hyme satellite development project. The programme which involved shutting down production for extensive periods was exacerbated by unscheduled interruptions in the final quarter of 2012.
In the Brage field (Faroe 14.25%) production was interrupted for two weeks in July due to an oil workers strike but otherwise continues to produce with high uptime. The drilling of new infill wells continued in the first half of 2012, but as planned, drilling was halted temporarily in order to carry out maintenance and upgrades to the drilling equipment to allow for the drilling of long reach wells in 2013.
The Ringhorne East field (Faroe 7.8%) has produced at stable rates during the first half of the year. The first of two long reach infill wells targeting un‐drained oil identified on 4D seismic was completed and came on stream at the end of July.
The Glitne field (Faroe 9.3%) is approaching the end of field life and, following an unsuccessful in‐fill well in early 2012 drilled by operator Statoil, work has commenced on planning the decommissioning of the field. Faroe is capped for a large part of the decommissioning cost through an agreement with DONG, and the remainder of this cost can be offset against income from production on other Norwegian fields for tax purposes.
The Blane oil field (Faroe 18%) located in the Central Graben on the border between the UK and the Norwegian sector has continued to outperform expectations during the year, from a reservoir and well performance perspective, despite an extended period of downtime in the second half of the year resulting from an incident on the third party host platform Ula.
On the Glenlivet discovery (Faroe 10%) west of Shetland, concept selection was carried out on this material gas discovery, made in 2009. It is expected that activity on the asset will now go on hold for a period, pending availability of near term firm capacity in the third party export infrastructure, ahead of a field investment decision which is expected ahead of 2016.
The Tornado discovery (Faroe 10%) contains significant gas resources and an oil rim in a high quality reservoir. Work continues with various field owners in the area on a joint development and export solution for these resources.
On Fogelberg (Faroe 15%), the operator is working towards field development to coincide with availability of transportation capacity in the Åsegard production and transportation system, which will allow for the gas to be transported from the Norwegian Sea to the European continent. As referred to above, if approved, the proposed significant reduction in gas transportation tariffs for new Norwegian gas field developments would significantly improve project economics.
In the UK Central North Sea the Perth oil field (Faroe 34%) is being matured towards field development by the operator, Parkmead. The group has decided that further appraisal of the asset is required prior to a field investment decision, and an appraisal well is scheduled to be drilled late in 2013. In February 2013 Faroe announced the acquisition of a 50% interest in the Lowlander field which is fully appraised and located 16kms from the Perth field (Faroe 34.62%). The acquisition creates the potential for an attractive joint Perth/Lowlander development as the collective volumes in these fields are significant, considering their central location in the UK North Sea
As production and reserves are an increasing area of focus, during 2012 the Company took the decision to report internal reserves estimates for the first time. From now on, the Company will report its estimates of Proven plus Probable (2P) reserves as part of this Review of Activities. These estimates are made according to the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers and are typically in line with or slightly below those estimates performed by a Competent Person whose results have historically been reported by the Company.
31 December 2012
All reserves, apart from the volumes associated with the Orca gas field in the UK, are from fields currently in production. The UK reserves do not include volumes associated with the East Foinaven field (the transaction is expected to complete H1 2013) which is estimated to contain 1.2 million barrels of oil equivalent net to Faroe which when added to the existing reserves total 20.1 million barrels of oil equivalent.
2012 was a period of considerable activity for the Group, with an extensive investment in development and production, the exploration programme and the winning of a significant number of new licences. The Group generated cash flow from operations during the year of £77.2 million, which, together with the Norway exploration facility, funded all exploration expenditure and most development capital expenditure, ending the year in a strong cash position with £72.9 million of unrestricted cash (31 December 2011: £111.6 million).
Revenue was £158.8 million (2011: £80.2 million). This is a significant increase on last year, reflecting in particular the full year effect of acquisitions made in 2011 of the Brage, Njord, Ringhorne East and Jotun fields in Norway, and benefiting from continuing high oil prices. Cost of sales, including depreciation of producing assets, was £97.0 million (2011: £52.2 million), giving a gross profit for the year of £61.8 million (2011: £28.0 million) – a significant increase from previous years. EBITDAX for the year more than doubled to £96.0 million (2011: £40.9 million).
Exploration expenditure for the year was £79.7 million (2011: £42.3 million). This expenditure includes pre‐ award exploration expenditure (£8.6 million) and write‐offs of licence specific exploration and evaluation expenditure on previously capitalised licences where active exploration has now ceased (£71.1 million). The pre‐award exploration expenditure included costs incurred in licence rounds. The licences which were relinquished and written off during the year included T‐Rex, Clapton and Fulla/Freya together with other smaller write‐offs over several exploration assets.
The Group’s reported loss before tax was £29.0 million (2011: £14.3 million profit). Loss after tax was £5.2 million (2011 Profit: £47.4 million due principally to the exceptional gain of £40.0 million on the disposal of Maria).
In line with Group business policy approximately 43% of UK oil and gas sales in 2012 were hedged, with hedging losses of £0.6 million (2011: £0.3 million).
The Group has entered into hedging arrangements covering approximately 52% of 2013 and 39% of Q1 2014 (post tax) total expected oil production, predominantly in the UK, but has also commenced hedging of Norwegian production. These are a combination of zero cost collars and put options with floors predominantly at US$90 per barrel.
Norwegian tax rebates for exploration
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 net exploration and appraisal expenditure in the form of a rebate the following year. The Company can also borrow under its Norway exploration facility a significant portion 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 2012 was £48.5 million (2011: £53.7 million payable less £40.4 million overseas tax credit resulting in £13.3 million payable). The prior year was unusual in that Norwegian tax was payable, reflecting greater taxable profits on the assets obtained from Petoro compared to the exploration costs in Norway.
The tax credit in the Income Statement was £23.8 million (2011: £33.2 million). The 2012 tax credit mainly consists of an overseas tax credit of £48.5 million, with an increase in deferred tax liabilities of £24.0 million.
The overseas tax credit of £48.5 million consists of the tax refund on exploration expenditure in Norway net of taxable profits generated by producing assets. The refund will be received in December 2013.
At December 2012 the Group had unrelieved tax losses in the UK of £75.4 million (2011: £66.2 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 2012 and 2013 UK Budget announcements boosted a number of areas in which the Company is active. For the Company’s West of Shetland exploration programme there is the potential to benefit from a new £3 billion field allowance for deep water field developments (those located in more than 1,000 metres water depth and with reserves in excess of 180 mmboe) and for smaller fields there is expected to be an increase both to the threshold, to 45 mmboe (from 20 mmboe), and to the amount of the allowance, to £150 million (from £75 million). The Government also announced in the 2013 Budget that it will sign Decommissioning Relief Deeds 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.
Development and production investments of £49.3 million excluding decommissioning asset additions (2011: £36.9 million) were made in the year. These mainly relate to investment in the Hyme development in Norway, and the drilling of in‐fill wells at Njord, Brage, and Ringhorne East.
Exploration and evaluation investments of £111.8 million (2011: 59.2 million) were made in the year. These mainly related to drilling the T‐Rex, Kalvklumpen, Cooper, Clapton, and Rodriguez wells in Norway (reflecting costs before the 78% Norwegian tax rebates), and North Uist in the UK. After exploration write‐offs in the year of £71.1 million (2011: £39.0 million), the intangible exploration and evaluation assets increased by £45.5 million to £145.1 million (31 December 2011: £99.6 million). Net assets increased during the period to £231.7 million (31 December 2011: £230.8 million).
Closing cash was £72.9 million (2011: £111.6 million). The reduction is largely due to funding of the exploration programme, investment in development and production assets, and payment of 2011 Norwegian tax, offset by production cash flows and cash flows received from new borrowings.
The Norwegian fiscal regime is designed to encourage oil and gas exploration, and it repays 78% of eligible costs in the year following the expenditure. 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. During the year the Group doubled the size of the committed facility, extended the facility by one year to 2015, and enlarged the bank group. This arrangement makes it possible to make greater investments in Norway exploration than would be possible elsewhere. In December 2012, a tax rebate of £48.5 million (December 2011: £13.3 million payable) was receivable in Norway, and £43.8 million (31 December 2011: £nil) was payable under the Norwegian exploration financing facility.
The Group also has a secured, substantially available but largely undrawn US$250 million (approximately £155.0 million) reserve based debt facility. During the year the Company doubled the size of the committed facility, extended it by one year to 2017, and increased the number of banks in the bank group. At the year end £7.4 million was payable under this facility (2011: £nil).
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 all the planned capital expenditure (exploration and development/production) for a number of years. The capital expenditure for 2013 is forecast to be up to £170 million.
|Group Income Statement
for the year ended 31 December 2012
|Cost of sales||(97,008)||(52,238)|
|Net gain on disposal of exploration and evaluation assets||1,657||39,956|
|Exploration and evaluation expenses||(79,742)||(42,337)|
|Operating (loss) / profit||(25,583)||15,761|
|(Loss) / profit on ordinary activities before tax||(28,991)||14,250|
|(Loss) / profit for the year attributable to equity holders of the parent||(5,178)||47,407|
|(Loss)/earnings per share – basic (pence)||(2.44)||22.3|
|(Loss)/earnings per share – diluted (pence)||(2.44)||20.1|
|Group statement of other comprehensive income
for the year ended 31 December 2012
|(Loss)/profit for the year||(5,178)||47,407|
|Exchange differences on retranslation on foreign operations net of tax||2,758||(1,102)|
|Actuarial (losses)/gains on defined benefit pension plans net of tax||(84)||423|
|Total comprehensive (loss)/gain for the year||(2,504)||46,728|
|Company statement of other comprehensive income
for the year ended 31 December 2012
|Profit/(loss) for the year||3,040||(7,091)|
|Total comprehensive income/(loss) for the year||3,040||(7,091)|
|Group Balance Sheet
at 31 December 2012
|Property, plant and equipment: development & production||133,359||104,705|
|Property, plant and equipment: other||768||406|
|Trade and other receivables||55,392||59,852|
|Current tax receivable||48,473||–|
|Cash and cash equivalents||72,891||111,589|
|Trade and other payables||(41,944)||(36,772)|
|Current tax payable||–||(13,325)|
|Deferred tax liabilities||(87,021)||(64,256)|
|Defined benefit pension plan deficit||(391)||(308)|
|Equity attributable to equity holders|
|Equity share capital||21,239||21,239|
|Share premium account||205,971||205,971|
|Cumulative translation reserve||8,069||5,311|
|Company Balance Sheet
at 31 December 2012
|Property, plant and equipment||161||92|
|Investments in subsidiary undertakings||37,549||35,089|
|Trade and other receivables||170||145|
|Cash and cash equivalents||31,059||68,124|
|Trade and other payables||(1,021)||(1,077)|
|Equity attributable to equity holders|
|Equity share capital||21,239||21,239|
|Share premium account||205,971||205,971|
|Condensed Group Cash Flow Statement
for the year ended 31 December 2012
|(Loss) / profit before tax||(28,991)||14,250|
|Depreciation, depletion and amortisation||34,494||12,887|
|Exploration asset write off||71,081||38,993|
|Gain on disposal of asset||(1,657)||(39,956)|
|Fair value of share based payment||3,386||2,909|
|Decrease/(increase) in trade and other receivables||4,460||(27,464)|
|Increase in inventories||(518)||(3,724)|
|Increase in trade and other payables||5,172||14,277|
|Currency translation adjustments||(1,977)||(977)|
|Interest and financing fees paid||6,080||3,834|
|Tax (payment) / rebate||(13,671)||28,070|
|Net cash generated in operating activities||77,164||41,775|
|Purchases of intangible and tangible assets||(162,052)||(96,217)|
|Proceeds from sale of intangible assets||1,657||53,103|
|Net cash used in investing activities||(159,700)||(41,790)|
|Net proceeds/(repayments) from borrowings||50,607||(17,575)|
|Issue of ordinary share capital||–||40|
|Interest and financing fees paid||(3,742)||(4,393)|
|Net cash inflow / (outflow) from financing activities||46,865||(21,928)|
|Net decrease in cash and cash equivalents||(35,671)||(21,943)|
|Cash and cash equivalents at the beginning of the year||111,589||132,150|
|Effect of foreign exchange rate differences||(3,027)||1,382|
|Cash and cash equivalents at the end of the year||72,891||111,589|
|Condensed Company Cash Flow Statement
for the year ended 31 December 2012
|Profit / (loss) before tax||3,040||(7,091)|
|Fair value of share based payment||926||1,514|
|(Increase) / decrease in trade and other receivables||(24)||175|
|Decrease in trade and other payables||(57)||(579)|
|Currency translation adjustments||(2,929)||1,109|
|Inter‐Company Service Charge Uplift||(120)||(195)|
|Interest and financing fees paid||3||–|
|Investment write down||–||2,355|
|Net cash used in operating activities||(2,264)||(3,330)|
|Purchases of property, plant and equipment||(110)||(44)|
|Loans to subsidiary undertakings||(38,277)||(52,185)|
|Net cash used in investing activities||(37,845)||(51,588)|
|Issue of ordinary share capital||–||40|
|Net cash (outflow) / inflow from financing activities||(3)||40|
|Net decrease in cash and cash equivalents||(40,112)||(54,878)|
|Cash and cash equivalents at the beginning of the year||68,124||124,524|
|Effect of foreign exchange rate differences||3,047||(1,522)|
|Cash and cash equivalents at the end of the year||31,059||68,124|
1. The financial information set out above does not constitute the Company’s financial statements for the years ended 31 December 2012 or 2011. The financial information is derived from the financial statements for 2012 prepared in accordance with IFRS. The auditors have reported on the 2012 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. The calculation of loss per ordinary share is based on the loss of £5,178,000 at 31 December 2012 (2011: profit £47,407,000) and the weighted average number of ordinary shares outstanding of 212,385,353 (2011: 212,382,662). All of the potential ordinary shares are anti‐dilutive and as a result, the diluted loss per share is equal to the basic loss per share for 2012.
4. Post balance sheet events:
- Hyme Development Onstream – On 26 February 2013, the Company announced that production commenced on the Statoil operated Hyme oil field in the southern part of the Norwegian Sea. This field ties back to the Njord A platform, which is located 19 kilometres away; Faroe holds a 7.5% interest in the Hyme field. The operator estimates that the Hyme field contains approximately 30 mmboe (net to Faroe 2.25 mmboe), predominantly oil, and expects the field to extend the production life of the Njord field to beyond 2020. The development has been delivered on schedule and on budget of approximately NOK 4.5 billion (Faroe net share approximately £37.5m). Faroe has funded its share of the development costs from cash flow generated from its producing interests. It is expected that the field will generate between 10‐15% of the Company’s estimated 2013 daily production.
- Rodriguez Discovery – On 31 January 2013, the Company announced that further results from the Rodriguez exploration well in PL475 (6407/1‐6S) (Faroe 30%) confirmed a significant gas condensate discovery in the Lower Cretaceous interval. The Operator’s preliminary volumetric estimates of the size of the discovery are between 19 and 126 mmboe recoverable (net to Faroe c.6‐38 mmboe). This is the first exploration well drilled on the Rodriguez license PL475 and further appraisal will be required to establish the lateral extent and size of this discovery.
- Norwegian Exploration Licence Awards – On 16 January 2013, the Company announced that it has been awarded eight new prospective exploration licences, including three operatorships, under the 2012 Norwegian APA Licence Round on the Norwegian Continental Shelf. These included two licences in the Northern North Sea, five licences in the North Sea and one licence in the Halten Terrace Area of the Norwegian Sea.
- Commencement of drilling on Darwin – On 4 March 2013 the Company announced that the Repsol operated high impact wildcat Darwin exploration well (7218/11‐1) (Faroe 12.5%), acquired from Talisman Energy Norge AS in August 2012, had spudded. The Darwin prospect is located on the Veslemøy High in the frontier western part of the Barents Sea. Multiple targets have been identified on 3D seismic and this well will test the main Darwin prospect and contribute towards further de‐risking of the large upside potential in the remainder of the licence area.
- Lowlander Acquisition – On 27 February 2013 the Company announced that it has entered into an agreement with Talisman Sinopec to acquire a 50% interest in UK Licence P.324, block 14/20c containing the Lowlander oil discovery. Lowlander is fully appraised and the field has sour characteristics, similar to those of the Perth Field (Faroe 34.62%), which is located 16 kilometres from Lowlander. The work programme will include a joint Perth/Lowlander development study.
- Pil Acquisition – On 27 February 2013 the Company announced that it has acquired a 25% interest in Norwegian Licence PL586 containing the Pil prospect which is located within tie‐back distance (33 kilometres) to the producing Njord field (Faroe 7.5%). An exploration well is scheduled to be drilled on this prospect in the first half of 2014.
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
|bcf||billion cubic feet|
|boe||barrels of oil equivalent|
|boepd||barrels of oil equivalent per day|
|EBITDAX||Earnings before interest, taxation, depreciation, amortisation and exploration expenditure (gross profit plus depreciation on producing assets)|
|mmboe||million barrels of oil equivalent|