Faroe Petroleum Plc Regulatory News (FPM)

RNS Number : 0121A

Faroe Petroleum PLC

21 March 2017

 

21 March 2017

FAROE PETROLEUM PLC

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

 

Final Results for the Year Ended 31 December 2016

 

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 2016.

Highlights

Operations - record production and reserves growth

· Strong production performance and significant reserves growth

o Total average economic production1 for 2016 at 17,395 boepd (2015: 10,530 boepd) - ahead of guidance mainly due to the newly acquired interests in the Norwegian Ula, Tambar, Trym and Oselvar producing fields which performed ahead of expectation

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

o Average economic operating cost per boe1 in line with prior year at $25 (2015: $23)

o 2P Reserves increased by 42% with closing reserves at 81.3 mmboe (2015: 57.4 mmboe) - reflecting the acquisition of further producing assets and positive reserves revisions on existing assets

· Exploration success, adding material 2C Contingent Resources

o 2C Contingent Resources were 90.9 mmboe (2015: 98.3 mmboe) - new high quality resources were added by the 2016 Brasse discovery, largely offsetting the reduction in resources following relinquishment and withdrawal from the Perth, Lowlander, Tornado and Solberg licences

o Norwegian North Sea drilling: significant Brasse oil and gas discovery (Faroe 50% and operator) estimated at 43-80 mmboe (gross) in good reservoir located near Brage and Oseberg production facilities - appraisal scheduled for summer 2017

o Norwegian Sea drilling: discovery on Njord North Flank (Faroe 7.5%) exploration well and side-track with estimated resource range 2-28 mmboe gross

o Norwegian Barents Sea drilling: dry well with the Kvalross frontier exploration well (Faroe 20%)

o Six APA licences awarded in Norway in January 2016 and one licence option (Faroe 100% and operator) located close to the producing Corrib field, awarded offshore Ireland in July 2016

Financial - equity fund raise and new 7-year Reserve Based Lending ("RBL") facility ensure robust balance sheet

· Unrestricted cash and net cash of £96.8 million at 31 December 2016 (31 December 2015: £91.5 million cash and £68.5 million net cash) - with no drawn RBL debt (2015: £23.0 million drawn)

· Raised £66.1 million, before expenses, in share placing and open offer in July and August 2016, to fund the acquisition from DONG of producing assets and accelerate the new Brasse discovery towards development

· New, four-year NOK1 billion Exploration Financing Facility ("EFF") and seven-year $250 million (and a further $100 million accordion) RBL facility secured in December 2016 on improved terms with existing and new lenders

· Revenue (excluding hedging gains) of £94.8 million (2015: £113.0 million) - reduction reflects lower accounting production (revenue from the acquired DONG assets between the effective date and completion date reduced the final cash consideration paid on 6 December 2016 from $70.2 million to a net $30.4 million)

· EBITDAX £25.8 million (2015: £60.4 million), includes realised hedging gains of £4.7 million (2015: £9.3 million) classified as Other Income - reflecting lower revenue, lower realised hedging gains and higher opex

· Loss after tax of £32.8 million (2015: £52.9 million) after pre-tax impairment charges of £2.8 million (2015: £45.1 million) and exploration write-offs of £29.9 million (2015: £83.6 million)

· Pre-tax exploration and appraisal capex of £47.5 million (£12.1 million post-tax) (2015: £61.9 million pre-tax, £14.8 million post-tax) and development and production investments (including acquisitions) of £32.8 million (2015: £38.7 million)

 

 

Outlook - high quality investment programme progressing to deliver material organic production growth

· FDP submitted on Oda oil field (Faroe 15%) and FDP submission on Njord Future Project, including Bauge development (Faroe 7.5%) scheduled for March 2017 - other pre-development projects being matured towards development decisions

· Investment programme to increase production from existing fields progressing - installation of gas lift and infill well programme of two wells on Tambar (Faroe 45%) being planned for 2017/18 and infill drilling re-commencing on the Brage field (Faroe 14.3%) in April 2017

· Development and production capex for 2017 is estimated to be approximately £90 million (2015: £32.8 million) -  funded from cash reserves, cashflow and RBL facility

· Production guidance for 2017 narrowed to 13,000-15,000 boepd (previous guidance 12,000-15,000 boepd), split 60% liquids and 40% gas - the decrease on 2016 reflects production interruptions due to infill drilling and other production enhancing work in 2017, Njord and Hyme temporary shut-in, and natural production decline

· Currently two firm exploration and appraisal wells in 2017 in Norway (Boné frontier exploration well and Brasse appraisal well) with potential for further additions, all benefiting from Norway's 78% exploration tax rebate

· Committed exploration and appraisal capex in 2017 estimated to be approximately £45 million pre-tax (£11 million post-tax) (2016: £12.1 million post-tax) - fully funded by existing cash and the EFF

· 90% of 2017 and 40% of 2018 expected post-tax gas production hedged at average floor of 41p/therm and 30% of 2017 post-tax oil production hedged at an average floor of $54 per barrel

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

 

 

Graham Stewart, Chief Executive of Faroe Petroleum, commented:

"2016 was transformational for Faroe with the acquisition of a significant Norwegian portfolio of producing assets which doubled Group production and added material reserves, the material Brasse discovery in Norway, and a successful £66 million equity fund raise. Production from our UK & Norwegian portfolio averaged approximately 17,395 boepd in 2016, and we increased our 2P reserves base by 42% to 81 mmboe.  Ending the year with a significant cash position of £97 million and a new undrawn seven year Reserve Based Lending facility of $250 million puts Faroe in a strong position.

"With our hub area focus, centered principally around the Ula, Njord and Brage areas, Faroe is now in position for a major growth phase as we take advantage of low industry costs and invest across our core assets in 2017 and beyond. We believe that we have the asset base to reach our stated goal of 40-50,000 boepd organically within the next five years, with robust economics even at low commodity prices. We will also continue to seek to capitalise on our strong financial position to pursue further consolidation opportunities on the Norwegian and UK continental shelves, while maintaining our focus on high impact exploration and appraisal drilling."

 

 

For further information please contact:

 

Faroe Petroleum plc Graham Stewart/Jonathan Cooper	Tel: +44 1224 650 920
Stifel Nicolaus Europe Limited Callum Stewart/Nicholas Rhodes/Ashton Clanfield	Tel: +44 20 7710 7600
RBC Capital Markets Matthew Coakes	Tel: +44 20 7653 4000
FTI Consulting Edward Westropp/Kim Camilleri	Tel: +44 20 3727 1000

 

 

CHAIRMAN'S AND CHIEF EXECUTIVE'S STATEMENT

In an otherwise difficult and challenging market due to low oil prices, the Company successfully doubled its production and increased 2P reserves by 42% during the year. With new discoveries and maturing existing discoveries, Faroe now has a portfolio of significant production and development, pre-development, appraisal and exploration projects, centered around our core hubs of Brage, Njord and Ula. These projects can realise substantial value, particularly in a rising commodity price environment and should continue to lower the Company's operating costs in the medium term. Faroe's successful exploration track record has added significant value last year and over many years, and exploration will continue to be a core element of the business. The Company successfully entered into a new seven-year Reserve Base Lending (RBL) credit facility and a new four-year Exploration Finance Facility (EFF) in December 2016, both with improved terms. With year-end net cash of £97 million and an undrawn RBL, Faroe is particularly well placed to pursue growth both organically and through potential new acquisitions.

Consistent strategy is delivering results

Faroe's strategy is to grow value from its reserves and resources through monetising exploration and appraisal successes, participating in selective development projects and pursuing value accretive asset transactions; all of which we have a strong track record in. This strategy, underpinned by cash flow from good quality production assets, a strong balance sheet and rigorous financial discipline, has delivered exceptional results for Faroe, creating a strong platform for continued growth, and is benefiting from significant sector-wide cost reduction. The Group continues to pursue its successful exploration strategy and has built a substantial prospect inventory for future wells, all funded from cash flow and Norwegian fiscal incentives.

Successful acquisition of Norwegian production portfolio and oversubscribed share issue

In July 2016, Faroe announced the acquisition of four producing assets in the Norwegian North Sea from DONG for a consideration of $70.2 million at an effective date of 1 January 2016. The acquired assets, two of which are operated, added 2P developed reserves of 19.8 mmboe together with 2C resources of 11.1 mmboe, and accounted for 56% of Faroe's average economic production in 2016. The deal also includes tax balances of $109 million. Completion of the acquisition occurred on 6 December 2016, with a total net consideration payable of $30.4 million after adjustments for cashflow between the effective and completion date. The acquisition creates a new strategic hub for Faroe, centred around the Ula platform (Faroe 20%) - already a host for the producing Blane (Faroe 30.5%), Tambar (Faroe 45%), and Oselvar (Faroe 55%) fields and the Oda field development (Faroe 15%). As well as the strategic nature of the deal, the acquired assets have a material and complementary impact on production, reserves, resources, cash flow and debt capacity. Having assessed a large number of potential acquisition opportunities in recent times, this portfolio of assets stood out as an excellent strategic fit, with substantial upside, and delivering material multi-faceted synergies.

In parallel with the acquisition, the Company raised £66 million (before expenses) of equity capital in a significantly oversubscribed share placing and open offer. The share issue ensures that Faroe continues to take advantage of growth potential within our portfolio in a capital efficient manner, taking advantage of upside opportunities and progressing pre-development projects towards monetisation while maintaining balance sheet strength.

Production portfolio performing well and 2P reserves up significantly

The Company's tax efficient production portfolio remains core to Faroe's strategy and is a principal source of funding. Following the acquisition of the DONG assets, Faroe delivered net average economic production of 17,395 boepd in 2016 with an average economic opex per boe of $25. Faroe's production is spread across a balanced portfolio of assets with a production split of which approximately 75% in Norway and 25% in the UK. With record high production, the production portfolio generated EBITDAX for the Group of approximately £65 million (including EBITDAX from the DONG assets from effective date of 1 January 2016).

2P reserves were estimated at 81.3 mmboe at 1 January 2017, which is an increase of 42% over the year and represent reserves replacement of approximately five times. The significant increase is a result of both the acquisition of producing assets from DONG and positive reserve revisions across the portfolio. 

Development and pre-development projects progressing well

Faroe's successful exploration programme has delivered a number of commercial discoveries which are now progressing towards development. Consequently, there is real potential for Faroe to benefit from material near and medium term organic growth in production and cash flow from its existing portfolio.

On the shallow water Centrica-operated Oda oil field development project (Faroe 15%), an FDP was submitted in December 2016. Oda has estimated gross reserves of 46 mmboe in an excellent reservoir and will be developed as a subsea tie-back to Ula (Faroe 20%). Gross plateau production is expected to be 35,000 boepd with first oil in 2019.

In June 2016 production was suspended as planned on the Njord and Hyme fields (Faroe 7.5%), and the Njord production facility was towed to shore for upgrade and life-extension work. Work is ongoing to strengthen and upgrade the facility and modify the topsides in order to materially extend its operating life and accommodate the Bauge (previously Snilehorn), as well as other tie-backs; production start-up is scheduled for 2020. The FDP on the Njord Future Project is expected to be submitted in March 2017 and approved before the summer.

During 2017 work will continue to mature the significant Pil discovery (Faroe 25%) towards development, following the selection of a sub-sea tie-back to the Njord production hub. The formal concept selection and FEED was committed to in February 2017 and project sanction is expected around year-end 2017.

Exploration success

Three exploration wells were drilled in 2016 of which two were discoveries. The first well, which commenced in January 2016, was on the Norwegian Barents Sea Kvalross prospect (Faroe 40%). Whilst the well was unsuccessful it was drilled significantly below budget, taking advantage of the current rig market and Norwegian tax rebates.

In May 2016 drilling commenced on the Faroe-operated Brasse well (Faroe 50%) in the Norwegian North Sea immediately south of the producing Brage oil field (Faroe 14.3%) and east of the producing Oseberg field. This led to a significant discovery with good oil and gas bearing reservoirs encountered in the main wellbore and in a subsequent side-track well. Gross recoverable hydrocarbons are estimated to be in the range of 43-80 mmboe. With a 50% interest and its close proximity to existing infrastructure, Brasse is one of Faroe's most significant discoveries to date. In January 2017, the Company committed to a follow-up appraisal well on the Brasse licence which is expected to be drilled in mid-summer 2017. Work has begun to assess options for taking this important asset forward towards early development as a subsea tie-back.

The final well in 2016 was the Njord North Flank (Faroe 7.5%) exploration well in the Norwegian Sea. The initial well encountered oil and gas and a subsequent side-track encountered gas. Preliminary gross estimates indicate a range of 1.9 to 28.3mmboe. This new Greater Njord Area discovery builds on Faroe's significant position in this prolific core area.

Outlook

Faroe is now a full cycle E&P company with a balanced and diverse portfolio of exploration, development and production assets. The Company's consistent focus on exploration has delivered high-quality discoveries over several years and the maturing and monetising of several of these discoveries now form an increasing part of our growth model. The materially reduced cost structure resulting from the oil price downturn offers the real attraction of locking in low costs and attractive economic returns. The timing, at the bottom of the cycle, is therefore right for Faroe to participate in a number of these projects, namely the Njord Future Project, the Oda development and the Pil concept selection. The Brasse discovery is also set to become a major project and underlines the material size, diversity and economic attractiveness of our projects which together have the potential to transform the value of the Company in the coming few years.

While the markets remain challenging for the sector there are early signs of improved market conditions, evidenced by the recent improvement in oil prices following the lows of January 2016, albeit uncertainty in future prices remains. The combination of Faroe's strong balance sheet, new banking facilities, profitable production at low oil prices, continuing exploration programme focus and an outstanding portfolio of pre-development projects means that we are well positioned to grow materially in the near future in order to deliver our goal of becoming a leading independent pan-North Sea E&P company.

Faroe's exploration team has recently been awarded two prizes in Norway, the Rystad Gullkronen 2017 Explorer of the Year Award and the Norwegian Petroleum Society Award. The awards are testament to the quality and achievements of our exploration team and we are proud of their recognition. With Faroe's internal resources further strengthened by the addition last year of a number of experienced key members of the DONG operating team, we fully intend to take advantage of opportunities to grow materially our value in the period ahead.

 

 

 

John Bentley	Graham Stewart
Chairman	Chief Executive

 

 

 

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.  In 2016 the Company delivered a three well exploration drilling programme, matured several discoveries towards development and significantly enhanced its production portfolio. Net economic production averaged 17,395 boepd in 2016, an increase from 10,530 boepd last year and 2P Reserves increased from 57.4 mmboe at the beginning of 2016 to 81.3 mmboe at the year end.

Production portfolio

Total average economic production for 2016 was within the enhanced guidance at 17,395 boepd (2015: 10,530 boepd), of which approximately 58% was liquids and 42% gas. This record high was the result of a combination of production from the Company's pre-existing portfolio, which benefited from Njord and Hyme production up to the end of May 2016, along with production from the newly acquired interests in the Norwegian Ula, Tambar, Trym and Oselvar producing fields. With an average economic operating cost of $25/boe in 2016, Faroe's production portfolio was cash generative notwithstanding the relatively low commodity price environment.

In May 2016, production from the Njord and Hyme fields (Faroe 7.5%) was suspended and the Njord A and B facilities were subsequently towed to shore to prepare the facilities for life extension, the Njord Future Project. The FDP is expected to be submitted in March 2017 with production from these fields scheduled to recommence in 2020.

In July 2016, the Company announced the acquisition of interests in four significant new producing fields: Ula (20%), Tambar (45% in Tambar and 37.8% of Tambar East), Oselvar (55%), and Trym (50%). Faroe became the operator of both Oselvar and Trym, with subsea installations tied back to the Ula field in Norway and the Harald field in Denmark respectively. The four new fields performed above expectation in 2016 delivering approximately 9,810 boepd net to the acquired interests enabling the Group to more than double its expected production over the year.

The Brage field (Faroe 14.3%) infill well programme is progressing to plan, including targets defined on 4D seismic and with detailed planning ongoing. Mobilisation for the first well will begin in April 2017 with the aim of bringing new production on stream in 4Q 2017.

On the Tambar field (Faroe 45%), planning continues for installing gas lift on two existing wells and an infill well programme of two wells which is expected to be sanctioned during 2017 and executed in 2017/18. Production from Tambar is expected to increase markedly due to the increase in the number of producing wells once the work is completed, and the Ula hub operating costs are also set to benefit from new production from Tambar.

During the first months of 2017 production has performed above expectation at approximately 15,200 boepd (from 1 January to 14 March 2017); average production in March 2017 (from 1 to 14 March) was approximately 16,100 boepd. Trym is producing unconstrained and the risk of being curtailed by the Harald host facilities appears to have been reduced. On this basis, we have narrowed the 2017 production guidance to 13,000-15,000 boepd (previously 12,000-15,000), split approximately 60% liquids and 40% gas. The forecast reduction in production, compared to 2016, reflects a combination of factors: the Njord and Hyme fields not being on production; production interruptions in some fields due to planned infill drilling and other work to boost future production; potential capacity constraints on the Trym field; as well as natural decline in field production rates.

Development and pre-development projects 

The Company currently has three important projects in Norway in either the development or pre-development phase: the Oda field (formerly Butch); the Njord Future Project including the Bauge field (formerly Snilehorn); and the Pil field (incorporating the Bue and Boomerang discoveries).

Oda (Faroe 15%): this field is to be developed by operator Centrica as a subsea tie-back to the AkerBP-operated Ula oil field (Faroe 20%). The FDP, which involves the drilling of two production wells and one water injection well, was submitted to the Norwegian authorities in December 2016. This subsea tie-in will reuse the existing Oselvar infrastructure (Faroe 55% and operator) and facilities on the Ula platform. Production from Oselvar will cease in 2018 in order to tie in Oda and allow production to commence. The Oselvar owners will be compensated for early cessation of production and for use of the Oselvar equipment - Faroe will be a net beneficiary of this payment. Estimated capital expenditure for the Oda development has been reduced to around NOK 5.4 billion (Faroe £82 million), with production scheduled to commence in 2019.

Njord Future and Bauge (Faroe 7.5%): the Njord Future Project including the Bauge development has been approved by the partnership and the FDP will be submitted to Norwegian Authorities in March 2017. Njord is being upgraded to a field life up to 2040. The project involves upgrading the Njord A production facility and the Njord B storage facility, bringing 12 existing wells back on stream and the drilling of 10 new wells. The Bauge field will be developed as a two-well subsea tie-back to Njord and with a possible future water injection well drilled from the Hyme template, thereby providing a cost efficient development solution for the field. It is envisaged that first oil from Bauge will coincide with production recommencing on Njord and Hyme in 2020.

Pil (Faroe 25%): in November 2016, the joint venture partners approved the concept of a subsea development tied back to the Njord platform (Faroe 7.5%). In February 2017 this project entered the Front End Engineering Design (FEED) stage and FDP is expected to be submitted by end of 2017.

Exploration and Appraisal

Licensing Rounds

In January 2016, Faroe was awarded six new prospective exploration licences including two operatorships under the 2015 Norwegian APA licence round. Three of the licences are located in the Norwegian Sea and three in the Norwegian North Sea including the Rungne Prospect in the Brage area and the Katie Prospect close to the Ula Field. In January 2017, a further four new licences were awarded in Norway under the 2016 APA licensing round, including an extension to the Brasse discovery, and two operatorships.

In July 2016, Faroe was awarded Licensing Option 16/23 (Faroe 100% and operator), in the Slyne/Erris Basin in Ireland, approximately 15 kilometres east of the producing Corrib gas field (operated by Shell), which came on-stream at the end of 2015. The Company sees considerable exploration potential in this licence option and has recently executed a farm-out agreement with Nexen. Under the terms of the farm-out agreement, upon completion which is also subject to regulatory consent, Nexen will take over operatorship of this licence and an 80% working interest (Faroe 20%) and in return will meet the full costs of the associated work programme including any acquisition of seismic data and the drilling of an exploration well.

Faroe's principal exploration focus remains in Norway, which continues to attract a large number of players due to the very significant resource potential, as well as substantial tax incentives whereby 78% of exploration expenditure can be reclaimed annually, combined with regular annual licensing rounds and access to low cost data.

E&A drilling operations

At the beginning of 2016 Faroe participated in the drilling of the Wintershall-operated Kvalross well in the Barents Sea in Licence PL611 (Faroe 40%). Whilst good quality sands were encountered in the Kvaltann prospect they were found to be water wet and in the main Kvalross target, hydrocarbon shows were observed, but not in good quality reservoirs.

In July 2016, Faroe announced the significant Brasse oil and gas discovery (Faroe 50% and operator) in the Norwegian North Sea. Total gross volumes of recoverable hydrocarbons have been estimated by the Company to be 28-54 mmbbls of oil and 89-158 bcf of gas; a total of 43-80 mmboe in aggregate. The Brasse discovery is located within tie-back distance to existing infrastructure: 13 kilometres to the south of the Brage field platform (Faroe 14.3%), 13 kilometres to the east of the Oseberg Sør field platform, and 13 kilometres to the south east of the Oseberg field platform. Well planning is underway for a firm appraisal well in the summer of 2017 with the potential for a further well in order to appraise the field ahead of a development decision expected in 2018.

In October 2016, Faroe announced the Njord North Flank-2 oil and gas discovery (Faroe 7.5%) located immediately north of the Njord field (Faroe 7.5%). The well and subsequent side-track targeted Middle and Lower Jurassic sandstone reservoirs of the Ile and Tilje formations. The resources in these discoveries are estimated to be in the range 2mmboe to 28mmboe (0.1mmboe to 2.1mmboe net to Faroe).

The 2017 drilling programme currently contains two firm exploration and appraisal wells. The first of these is the Boné well (previously Dazzler) (Faroe 20%), in the Barents Sea. Drilling of Boné commenced in January 2017 and the Company recently announced that the well was dry. The second 2017 well is a follow-up appraisal, with potential for a second appraisal well back to back, on the Brasse licence in mid-2017. Further potential wells are being matured for late 2017 or early 2018 including a potential well on the newly-awarded Brasse extension (Faroe 50% and operator), a well on the Norwegian Sea Aerosmith licence (Faroe 20%) and the recently awarded Goanna licence in the Norwegian North Sea (Faroe 30%).

 

Reserves & Resources

Reserves

The Company's internal estimate of Proven and Probable (2P) Reserves at 1 January 2017, 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 81.3 mmboe (1 January 2016: 57.4 mmboe) - increasing reserves by 42% over the year. The significant increase (reserves replacement of approximately five times) is a result of both the acquisition of interests in the Norwegian Ula, Tambar, Trym and Oselvar producing fields and positive reserve revisions.

 

2P Reserves	Gas (bcf)			Liquids (mmbbls)			Total (mmboe)
	Norway	UK	Group	Norway	UK	Group	Group
1 January 2016	63.1	19.9	83.0	39.3	4.3	43.6	57.4
Revisions	7.2	(0.5)	6.7	5.4	(0.8)	4.6	5.7
Acquisitions	27.2	-	27.2	15.2	-	15.2	19.8
Transfer from 2C	21.3	-	21.3	1.3	-	1.3	4.8
Production	(10.8)	(5.1)	(15.9)	(3.2)	(0.5)	(3.7)	(6.4)
1 January 2017	108.0	14.3	122.3	58	2.9	60.9	81.3

 

Contingent Resources

At 1 January 2017, 2C Resources were estimated to be 90.9 mmboe representing a decrease of 7.5% over the year (1 January 2016: 98.3 mmboe) reflecting the addition of new resources from the 2016 Brasse discovery and the reduction in resources associated with the respective withdrawal and relinquishment of interests in the Perth, Lowlander, Tornado and Solberg licences.

2C Contingent Resources	Gas (bcf)			Liquids (mmbbls)			Total (mmboe)
	Norway	UK	Group	Norway	UK	Group	Group
1 January 2016	133.3	17.6	150.9	32.4	40.7	73.1	98.3
Revisions	15.2	-	15.2	8.7	-	8.7	11.2
Acquisitions	28.9	-	28.9	6.1	-	6.1	11.0
Disposals	(27.0)	(17.6)	(44.6)	(1.3)	(40.7)	(42.0)	(49.4)
Discoveries	21.5	-	21.5	21.2	-	21.2	24.7
Transfer to Reserves	(21.3)	-	(21.3)	(1.3)	-	(1.3)	(4.8)
1 January 2017	150.6	-	150.6	65.8	-	65.8	90.9

 

FINANCE REVIEW

Overview

During the year, Faroe acquired a package of interests in producing assets for $70.0 million, which after working capital adjustments, resulted in a cash payment of £24.7 million on completion. In parallel, Faroe raised £66 million gross proceeds from an equity placement and subsequent open offer. These funds were raised to fund the acquisition and ongoing exploration and pre-development programme. In December 2016, Faroe secured a new $250 million RBL facility, with a further $100 million accordion, a 7 year maturity on an amortising schedule from January 2020 and a NOK1 billion EFF with maturity on 31 December 2019. At the year end, there were no drawings under the RBL facility (2015: £23.0 million) following repayment of the facility during 2016. The year end net cash position was £96.8 million (2015: £91.5 million, £68.5 million net). In addition, restricted cash of £11.8 million relating to prepaid transportation and abandonment costs are included in Trade and Other Receivables.

Revenue, including realised hedging gains, averaged $42 per boe (2015: $47 per boe) after taking account of £7.0 million overlift (2015: £4.6 million), included in revenue and cost of sales. Accounting opex per boe was $312 in 2016 compared to $23 in 2015 reflecting a lower accounting production base, Njord and Hyme opex post production suspension and a one-off cost associated with an infrastructure upgrade. DD&A per boe was reduced by $5.2 to $9.9 boe (2015: $15.1 boe) mainly as a result of 2015 and 2014 impairments.

Income statement

Revenue for the year was £94.8 million (2015: £113.0 million). Cost of sales, including depreciation of producing assets, but before impairment charges, was £96.7 million (2015: £99.8 million). Pre-tax impairment charges of £2.8 million (post-tax £0.8 million) (2015: £45.1 million and £26.7 million pre- and post-tax respectively) were incurred on Schooner and Enoch in the UK and Jotun in Norway. The Group made a gross loss for the year of £4.7 million (2015: loss £32.0 million). EBITDAX for the year decreased to £25.8 million (2015: £60.5 million) due to a combination of lower accounting production, lower commodity prices and increased accounting opex/boe. Realised hedging gains of £4.7 million (2015: £9.3 million) are classified as other income and included in EBITDAX.

Pre-tax exploration and evaluation expenses for the year were £33.5 million (post-tax: £14.8 million) (2015: £89.5 million and £22.0 million pre- and post-tax respectively). This includes pre-award exploration expenses of £3.6 million and write-offs of licence-specific exploration and evaluation expenditure of £29.9 million on previously capitalised licences where active exploration has now ceased. The exploration costs which were written off during the year related to P218 (Perth), PL611 (Kvalross), PL753 (Zircon), PL660 (Blackmore), 14/1-3 (Celtic Sea Licences), PL794 (Rosapenna) and PL792 (Slynge) along with other exploration costs on a number of licences.

Expensed administration costs in 2016 were £10.2 million (2015: £3.7 million). The increase is primarily due to increased IFRS2 share based payments charge (mostly non-cash) and other employment cost, fees in relation to the acquisition of Norwegian assets and to the time-writing charge out rate for 2015 being adjusted during 2016.

The Group's reported loss before tax was £61.5 million (2015: £122.3 million). Loss after tax was £32.8 million (2015: £52.9 million).

Hedging

In line with Group policy approximately 56% of post-tax production was hedged in 2016, of which 11% related to oil sales and 82% related to gas sales, with realised hedging gains, net of cost, of £4.7 million (2015: £9.3 million). The cost incurred for the 2016 hedges was £1.0 million (2015: £1.3 million).

At December 2016, the Group had entered into hedging contracts covering approximately 83% of 2017 and 11% of 2018 total expected gas production (on a post-tax production basis) and 30% of expected oil production. The gas hedging contracts are put options and swaps with floors between 30 and 46 pence per therm. The oil hedging contracts are put options with an average strike price of $54 per barrel. Unrealised hedging losses for the open hedge contracts for 2016 were £1.4 million (2015: gain £10.6 million) based on mark-to-market calculations and are recognised as derivative financial liabilities (2015: assets). The unrealised hedging losses (2015: gains) are shown as Other Expenses/(Income) in the Income Statement, net of hedging costs of £2.6 million (2015: £1.5 million).

Further gas and oil hedges have been undertaken in 2017 following which 92% of post-tax gas production is hedged in 2017, 32% of post-tax oil production is hedged in 2017 and 38% of post-tax gas production is hedged in 2018. 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 cost rebate, meaning that for every £1 spent the Government will return 78p of eligible expenditure in the form of a rebate in the following year, to the extent it is not offset against current year profits from producing assets. Through the EFF, Faroe can borrow 96% of the 78p per £1 rebate, thereby maximising equity leverage in Norwegian exploration and minimising the need to farm down. The Norwegian tax system therefore ensures a cost-effective fiscal environment in which to explore, and also cushions the cash impact of falling oil prices, as lower profits from production result in an increased tax rebate.

The amount of tax receivable at 31 December 2016 was £41.8 million (2015: £35.2 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 November 2017. The tax credit in the Income Statement was £28.7 million (2015: £69.4 million) and consisted mainly of the Norway tax receivable, and origination of timing differences of £11.3 million.

Development capex in Norway is depreciated on a straight-line basis over six years for tax purposes. In addition, an uplift of 21.6% can be offset against the 53% special tax. The uplift is taken on a straight-line basis over four years. This means that close to 90% of capex spend is recovered through the tax system. At December 2016, Faroe had carried forward tax capex balances of £74.3 million and carried forward capex uplift of £37.2 million in Norway. In addition, at December 2016, Faroe had carried forward tax losses in Norway of £17.3 million and £12.5 million for corporation tax and special tax respectively. At December 2016 the Group had unrelieved tax losses in the UK of £54.1 million which are available indefinitely for offset against future taxable profits.

In December 2016 the Company had a deferred tax asset of £122.1 million in respect of carried forward tax losses, capex balances and uplifts in the UK and Norway, net of other temporary differences. In 2015, the deferred tax asset was £32.4 million and deferred tax liabilities were £19.9 million.

Balance sheet

Exploration and evaluation investments of £47.5 million (post-tax: £12.1 million) (2015: £61.9 million pre-tax, £14.8 million post-tax) were made in 2016. These investments mainly relate to the Brasse and Kvalross wells in Norway. After exploration write-offs of £30.0 million (2015: £83.6 million), the intangible assets increased by £33.9 million to £107.4 million (2015: £73.5 million). Net assets increased during the year to £246.6 million (2015: £192.4 million).

Development and production investments of £8.1 million (2015: £13.6 million) were made in the year, excluding acquisitions, mainly on Njord and Oda. The Group acquired interests in a package of interests in producing fields from Dong E&P Norge AS for a cash consideration of £24.7 million. Following DD&A and impairments, development and production assets increased by £46.8 million to £157.4 million (2015: £110.6 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 2016 the Group had decommissioning provisions of £267.1 million (2015: £85.9 million). The increase in the provision is mainly due to additional provisions on acquired assets. Most of the decommissioning expenditure is scheduled to be incurred from 2020 to 2040.

Cash flow

Closing cash was £96.8 million (2015: £91.5 million). Net cash at the year end was £96.8 million (2015: £68.5 million). In addition, restricted cash of £11.8 million relating to prepaid transportation and abandonment costs are included in Trade and Other Receivables. Faroe benefits significantly from a revolving credit facility of NOK 1,000 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 EFF borrowings are repaid when the tax rebate is received in November of the year following the related expenditure. In November 2016 the Company received the tax rebate for 2015 of £40.3 million, most of which was used to repay the 2015 utilisations of the EFF.

The Group also has a secured US$250 million (approximately £203.0 million) reserve based lending facility which is available for both debt and issuance of letters of credit. At 31 December 2016 the calculated borrowing base amount was £108.1 million, of which £nil was drawn (2015: £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 2017 is forecast to be approximately £135 million.

 

 

 

Group Income Statement for the year ended 31 December 2016	2016 £'000	2015 £'000
Revenue	94,779	112,980
Cost of sales	(96,666)	(99,838)
Asset impairment	(2,823)	(45,108)
Gross loss	(4,710)	(31,966)
Other (expenses)/income	(8,412)	13,867
Exploration and evaluation expenses	(33,468)	(89,537)
Administrative expenses	(10,189)	(3,718)
Operating loss	(56,779)	(111,354)
Finance revenue	6,423	909
Finance costs	(11,139)	(11,855)
Loss on ordinary activities before tax	(61,495)	(122,300)
Tax credit	28,686	69,382
Loss for the year	(32,809)	(52,918)
(Loss)/earnings per share - basic (pence)	(10.5)	(19.7)
(Loss)/earnings per share - diluted (pence)	(10.5)	(19.7)

 

 

 

 

 

 

Statement of Other Comprehensive Income for the year ended 31 December 2016	2016 £'000	2015 £'000
Loss for the financial year	(32,809)	(52,918)
Exchange differences on retranslation foreign operations net of tax	21,855	(1,503)
Total comprehensive loss for the year	(10,954)	(54,421)

 

 

 

Group Balance Sheet at 31 December 2016	2016 £'000	2015 £'000
Non-current assets
Goodwill	7,744	-
Intangible assets	107,376	73,521
Property, plant and equipment: development & production	157,428	110,594
Property, plant and equipment: other	611	503
Financial assets	-	12
Deferred tax asset	122,055	32,398
	395,214	217,028
Current assets
Inventories	10,456	5,922
Trade and other receivables	63,063	27,964
Current tax receivable	41,764	35,195
Financial assets	-	10,621
Cash and cash equivalents	96,769	91,515
	212,052	171,217
Total assets	607,266	388,245
Current liabilities
Trade and other payables	(53,900)	(32,418)
Current taxation payable	(31)	(689)
Financial liabilities - reserve based lending facility	-	(23,000)
Financial liabilities - Norway exploration financing facility	(35,845)	(32,776)
Financial liabilities - other	(1,383)	-
	(91,159)	(88,883)
Non-current liabilities
Deferred tax liabilities	-	(19,888)
Provisions	(269,469)	(87,118)
	(269,469)	(107,006)
Total liabilities	(360,628)	(195,889)
Net assets	246,638	192,356
Equity attributable to equity holders
Equity share capital	36,453	26,824
Share premium account	315,580	262,453
Cumulative translation reserve	17,740	(4,055)
Retained earnings	(123,135)	(92,866)
Total equity	246,638	192,356

 

 

Condensed Group Cash Flow Statement for the year ended 31 December 2016	2016 £'000	2015 £'000
Loss before tax	(61,495)	(122,300)
Depreciation, depletion and amortisation	23,369	38,447
Exploration asset write off	29,908	83,569
Unrealised hedging gains	13,095	(4,580)
Asset impairment	2,823	45,108
Fair value of share based payments	4,408	1,916
Movement in trade and other receivables	(24,478)	2,768
Movement in inventories	(4,534)	(1,580)
Movement in trade and other payables	22,865	(1,896)
Currency translation adjustments	(5,814)	1,587
Expense recognised in respect of equity settled share based transaction	-	(67)
Investment revenue	(609)	(909)
Interest and financing fees paid	11,139	10,268
Tax rebate	44,729	40,284
Net cash generated in operating activities	55,406	92,615
Investing activities
Purchases of intangible and tangible assets	(79,447)	(84,585)
Proceeds from sale of intangible assets	-	1,300
Investment revenue	609	909
Net cash used in investing activities	(78,838)	(82,376)
Financing activities
Proceeds from issue of equity instruments	66,901	138
Issue costs	(4,145)	-
Net (repayments)/proceeds from borrowings	(19,931)	(9,908)
Interest and financing fees paid	(4,225)	(5,322)
Net cash (outflow)/inflow from financing activities	38,600	(15,092)
Net (decrease)/increase in cash and cash equivalents	15,168	(4,853)
Cash and cash equivalents at the beginning of year	91,515	92,571
Effect of foreign exchange rate changes	(9,914)	3,797
Cash and cash equivalents at end of year	96,769	91,515

 

 

Group Statement of Changes in Equity at 31 December 2016	2016 £'000	2015 £'000
Loss for the period	(32,809)	(52,918)
Other comprehensive (loss)/gain	21,855	(1,503)
Total comprehensive loss for year	(10,954)	(54,421)
Issue of ordinary shares	66,901	138
Share based payments	2,480	1,245
Buy back of share options	-	(67)
Share issue costs	(4,145)	-
Net movement in shareholders' funds	54,282	(53,105)
Opening shareholders' funds	192,356	245,461
Closing shareholders' funds	246,638	192,356

 

 

Notes

1. The financial information contained in this announcement for the years ended 31 December 2016 and 2015 does not constitute statutory financial statements within the meaning of Section 435 of the Companies Act 2006. An unqualified audit opinion was expressed on the statutory accounts for the years ended 31 December 2016 and 2015. This unqualified opinion did not contain a statement under either s498(2) or s498(3) of the Companies Act 2006.The statutory accounts for the year ended 31 December 2015 have been submitted to the Registrar, whereas, the statutory accounts for the year ended 31 December 2016 are yet to be submitted to the Registrar.

2. No dividend is proposed.

3. Cost of sales analysis

	2016	2015
	£000	£000
Operating costs*	40,671	38,866
Commercial tariffs*	24,524	15,932
Depreciation, depletion and amortisation	22,994	38,019
Overlift in the year	6,985	4,620
Other cost of sales*	1,492	2,401
Total cost of sales	96,666	99,838
* included in the opex per boe metric

4. Other (expense)/income analysis

	2016	2015
	£000	£000
Realised hedging gains*	4,683	9,287
Unrealised hedging gains	(13,095)	4,580
Total other (expense)/income	(8,412)	13,867
* included in the revenue per boe metric and EBITDAX

 

5. Earnings before interest, tax, depreciation, amortisation and exploration expenses

	2016	2015
	£000	£000
Revenue	94,779	112,980
Realised hedging gains	4,683	9,287
Operating costs	(40,671)	(38,866)
Commercial tariffs	(24,524)	(15,932)
Overlift in the year	(6,985)	(4,620)
Other cost of sales	(1,492)	(2,401)
EBITDAX	25,790	60,448

 

 

6. Taxation

	2016	2015
	£000	£000
Current taxation
Overseas tax credit	41,764	35,272
UK tax	(214)	(392)
Current tax credit	41,550	34,880
Amounts under/(over) provided in previous year	195	(187)
Total current tax credit	41,745	34,693
Deferred taxation
Origination of temporary differences	(11,316)	34,594
Not provided in earlier years	75	175
Total deferred tax (charge) / credit	(11,241)	34,769
Foreign exchange differences
Differences arising from the use of year end and average exchange rates	(1,818)	(80)
Total foreign exchange differences	(1,818)	(80)
Total tax credit in the Income Statement	28,686	69,382

7. Post balance sheet events:

Norwegian exploration licence awards

On 18 January 2017, the Company announced that it has been awarded six new prospective exploration licences, 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 licence awards.

Boné exploration well in Norway Barents Sea

On 15 March 2017, the Company announced that drilling on 7183/12-2 Boné exploration well on licence PL716 (Faroe 20%) had reached target depth and had encountered water bearing reservoir in the primary target. The well, operated by Eni Norge AS, will be plugged and abandoned.

 

Licence option 16/23 farm-out

In March 2017, the Company executed a farm-out agreement with Nexen for Licence Option 16/23 in Ireland. Under the terms of the farm-out agreement, upon completion which is subject to regulatory consent, Nexen will take over operatorship of this licence and an 80% working interest (Faroe 20%) and in return will meet the full costs of the associated work programme including any acquisition of seismic data and the drilling of an exploration well

8. 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

 

 

 

Estimates of reserves and resources contained in this announcement were 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.

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 30 years, has read and approved the exploration and appraisal disclosure in this regulatory announcement.

The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014, and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations.

 

Glossary

"APA"	awards in pre-defined areas
"Bcf"	billions of standard cubic feet
"boe"	barrels of oil equivalent
"boepd"	barrels of oil equivalent per day
"Contingent Resources or 2C"	those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are a class of discovered recoverable resources
"DD&A"	Depreciation, depletion and amortisation
"EBITDA"	earnings before interest, taxation, depreciation and amortisation
"EBITDAX"	earnings before interest, taxation, depreciation, amortisation and exploration expenditure (gross profit plus realised hedging gains, depreciation and impairment on producing assets). Management review EBITDAX on each of the producing fields as a measure of performance.
"Economic Production"	production to which the Company has an economic entitlement. It includes production between the effective (economic) date and the completion date of an acquisition. Accounting production excludes all pre-completion production.
"EFF"	Exploration financing facility
"FDP"	field development plan
"FEED"	Front end engineering design
"mmbbls"	million barrels
"mmboe"	million barrels of oil equivalent
"net cash"	cash and cash equivalents less financial liabilities excluding the balance of the Exploration Financing Facility which is directly linked to the Norway tax rebate (disclosed as tax receivable in the balance sheet)
"post-tax production"	29.3% of Norway production and 100% of other production, being a notional volume of production, taking into account the fact that in Norway, hedging gains are taxed at corporation tax only of 25%, whilst operating profits are taxed at corporation tax and special corporation tax of 53% (a combined rate of 78%) which in effect means that in order to achieve 100% hedge protection in Norway, 29.3% of Norway volumes are required to be hedged
"Proved Reserves" or "1P"	those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term 'reasonable certainty' is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate
"Proved + Probable Reserves" or "2P"	when added to 1P, those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than 1P but more certain to be recovered than 3P. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate
"Proved + Probable + Possible Reserves" or "3P"	when added to 2P, those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than 2P. The total quantities ultimately recovered have a low probability of exceeding the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate
"reserves"	reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status

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