Operational update6 February 2014
Faroe Petroleum, the independent oil and gas company focussing principally on exploration, appraisal and production opportunities in Norway, the Atlantic margin and the North Sea, is pleased to provide a 2013 year‐end operational update.
Faroe Petroleum has built a significant and balanced portfolio of exploration, pre‐development and producing assets through a successful combination of licence applications, monetisation and acquisitions over many years. The Company’s high impact exploration drilling programme, targeting four to five material wells per annum on a diversified portfolio basis, has been funded by cash flow from production, cash reserves and the Norwegian exploration tax incentive scheme. The Company’s portfolio position in Norway is by far the largest of any UK independent E&P company.
Recent well results – two successes, one of which is already of commercial size
- Snilehorn (Faroe 7.5%) significant discovery (57 to 101 mmboe gross recoverable resource estimate) recently announced ‐ potential development as a satellite to the Njord production field
- Novus (Faroe 30% and operator) small discovery (6 to 15 mmboe gross recoverable resource estimate) announced January 2014 – commercial potential in combination with any future discoveries made in the immediate vicinity
High impact exploration continues – four wells drilling in coming months
- Butch East (Faroe 15%) commenced in December 2013
- Butch South West (Faroe 15%) to commence immediately after completion of Butch East
- Pil (Faroe 25%) commenced in January 2014
- Solberg (Faroe 20%) commenced in February 2014
Continued success of exploration licence awards
- Awarded 10 new prospective exploration licences, including two operatorships, under the 2013 Norwegian APA Licence Round
- These 10 licences equate to the largest number awarded in this APA round, equal with Centrica and Statoil
- Active preparations underway for Norwegian 23rd and UK 28th licensing rounds
Significant growth in 2P Reserves and Contingent Resources
- 2P Reserves at 1 January 2014 have been estimated at 27.2 million boe1 net to Faroe, representing an increase of 35% over the year
- Unrisked Contingent Resources (Unrisked 2C) at 1 January 2014 have been estimated at 73 million boe2 net to Faroe, representing an increase of 32% over the year
Production and development
- Total average economic production for the full year 2013 was approximately 6,059 boepd3
- Faroe Petroleum – Press Release – Page 1 of 8
- H2 2013 production was lower than expected due principally to the Njord and Hyme fields being shut in for repairs
- Work on the reinforcement project at Njord is expected to be completed, and production resumed in summer 2014
- For the long term development of the Greater Njord Area, the operator’s current base case assumes that after a period of production the facility will be brought to a yard for the hull to be either repaired or replaced
- Average full year 2014 production is consequently anticipated to be in the range of 4,000 – 6,000 boepd from all fields
- Faroe continues to seek value enhancing production acquisitions, looking to take advantage of market conditions to build reserves and cash flow
- 2013 year‐end cash position is anticipated to be approximately £40 million (unaudited)
- No debt drawn against the Reserve Based Lending facility
- 2013 exploration and appraisal capex was approximately £73 million (pre‐tax) and £25 million (post tax) and development and production capex approximately £32 million (unaudited)
- 2014 exploration and appraisal capex is estimated to be approximately £110 million (pre‐tax) and £35 million (post tax) and development and production capex approximately £25 million
- Farm‐out of Novus and Solberg wells together with the Norwegian tax rebates reduced capex significantly
Graham Stewart, Chief Executive of Faroe Petroleum commented:
“I am pleased to provide this operational update which clearly demonstrates that Faroe is maintaining its forward momentum in building a strong and high potential value portfolio in its core areas of Norway and UK. Our Norwegian position is the most significant of any UK independent E&P company, and it continues to add value and will provide exciting high impact wells for many years to come. I believe that our team is highly respected by industry and by the host governments. This position is reflected in our ability to grow as rapidly as we have in the face of stiff competition, culminating recently in the awards of 10 APA licences, putting us joint equal with Statoil and Centrica in this round.
“We now look forward to an exciting period ahead, with a programme of fully‐funded high impact exploration and appraisal wells planned, each with material equity stakes. Our sustainable exploration programme combined with the opportunity to grow significantly our production portfolio gives us the potential to generate very considerable value for shareholders.”
Faroe has a very active programme with three wells currently drilling (Butch East, Pil and Solberg), with one further well (Butch South West) to spud when Butch East is completed. These wells follow the significant Snilehorn discovery (Faroe 7.5%) which exceeded expectations, and the smaller Novus discovery (Faroe 30%) which has commercial potential in combination with future discoveries in the immediate vicinity:
- Snilehorn (Faroe 7.5%) was announced as an oil discovery in November 2013. The size of the discovery as assessed by the operator Statoil is in the range 57 to 101 mmboe (net to Faroe c. 4 to 8 mmboe),substantially larger than the pre‐drill estimates. Work is ongoing to assess the need for appraisal of the discovery and to evaluate development options. Snilehorn has the potential to greatly increase the value of the Greater Njord Area (‘GNA’) which comprises Njord, Hyme, Snilehorn and further exploration opportunities within tie‐back distance, and has also de‐risked significant additional exploration opportunities within the PL348 licence
- Novus (Faroe 30% and operator) was announced as an oil and gas discovery on 27 January 2014. The preliminary volumetric gross estimate of the size of the discovery is 6 to 15 mmboe (net to Faroe 1.8 to 4.5 mmboe), which is below expectations and unlikely to be commercial on its own, but with good commercial potential in combination with any future discoveries made in the immediate vicinity
- Butch East (Faroe 15%) was spudded on 30 December 2013. The well is currently drilling, operated by Centrica in approximately 65 metres water depth in the Norwegian North Sea, close to significant existing infrastructure with the Ula, Tambar and Gyda fields all within tie‐back distances. Butch East is a follow‐up well to the 2011 Butch commercial oil discovery in excellent quality Jurassic Ula sandstone reservoir and is the first of a two well programme to test the eastern and south western sides of the large Butch salt structure
- Pil (Faroe 25%) commenced drilling on 20 January 2014. The well is operated by VNG and is targeting the Upper Jurassic Rogn formation sandstone which has proved to be an effective reservoir in the Shell operated Draugen field. The Pil prospect is located within tie‐back distance (33 kilometres) to the Njord production field in which the Company holds a 7.5% interest
- Solberg (Faroe 20%) spudded on 2 February 2014. The well is operated by Wintershall and will appraise the lateral extent and size of the Lower Cretaceous Rodriguez discovery announced in January 2013, where moveable hydrocarbons were discovered in the Lange formation. The operator’s gross preliminary volumetric estimate is in the range 19 to 126 mmboe. Faroe holds interests in several analogous targets with significant follow‐on potential, which should be largely de‐risked by success with the Solberg well
- Butch South West (Faroe 15%) will be drilled back‐to‐back, following the conclusion of the Butch East well. Similar to Butch East, the well will be drilled on the side of the large Butch salt structure to test the potential extension of the Butch Main discovery to the south west
New drilling commitment decisions are taken by Faroe on a rolling basis with more than 20 exploration opportunities currently in the process of being high‐graded for drilling decisions, which are expected to continue to deliver approximately four to five wells per annum. The prospects consist of new independent near‐field exploration targets in the Norwegian North Sea, frontier targets in both the Barents Sea and in the west of Shetland area and follow‐up targets, dependent on results from the ongoing drilling campaign.
Building on the Company’s outstanding results to date, Faroe continues to build its portfolio of exploration licences organically through its highly successful strategy of active participation in licensing rounds across its core areas.
- Norway APA: on 21 January 2014, Faroe announced 10 new exploration licences in the Norwegian 2013 APA Licensing Round, its largest single award to date and the largest number awarded in this APA round, equal in number with Centrica and Statoil (Faroe was awarded eight APA licences in 2013)
- Norway frontier: work has started on the Norwegian 23rd licensing round which will focus on the Barents Sea, where the Company has identified several prospective opportunities and recently submitted the maximum number of permitted block nominations
- UK: Faroe is actively preparing for the announced 28th licensing round where several exciting exploration opportunities have been identified
Reserves and Contingent Resources
The Company’s internal estimate of Proven and Probable (2P) Reserves at 1 January 2014, prepared in accordance with the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers, have been estimated at 27.2 million boe1 representing an increase of 35% over the year (20.1 million boe at 1 January 20133). The significant increase in 2P Reserves has been achieved principally through good production performance and the booking of the Glenlivet field as 2P Reserves.
1 January 2014
For the first time the Company also publishes its internal estimate of Unrisked Contingent (2C) Resources which at 1 January 2014 has been estimated to be 73 million boe2 representing an increase of 32% over the year (56 million boe at 1 January 2013):
|Unrisked Contingent Resources
1 January 2014
The significant increase in 2C Resources over the year is principally a result of:
- inclusion of the gas condensate volumes in Solberg following the successful Rodriguez/Solberg exploration well in January 2013;
- inclusion of the Snilehorn oil and gas volumes following the successful exploration well in November 2013; and
- acquisition of 100% of the Lowlander asset, which adds substantial discovered and fully appraised volumes to the combined Perth and Lowlander development.
The increase in 2C Resources resulting from these exploration successes and acquisitions more than compensates for the reduction in 2C Resources due to the transfer of Glenlivet from 2C Resources to 2P Reserves.
Faroe as operator of Lowlander (Faroe 100%) is working together with Parkmead as operator of Perth (Faroe 34.62%) to bring the two fields forward to development together as an attractive joint project sharing the same production facilities and thereby benefiting from economies of scale. Both Perth and Lowlander have been fully appraised, with a combined total of nine wells drilled on the fields. Together the fields are estimated to contain STOIIP of 270 million barrels, with 62 million barrels of oil estimated to be recoverable, of which 22 million barrels are attributable to Lowlander4. In addition there is the potential that the production facilities for a joint field development could serve as a hub for a number of other fields including analogous accumulations already discovered in the area.
The Company, together with Parkmead, intends to continue the technical work programme focused on optimising the development solution for the fields and reaching commercial agreement for a joint development.
Total average economic production for the full year 2013, of approximately 6,059boepd3 was impacted by the unscheduled extended down time experienced at the Njord and Hyme fields (Faroe 7.5%) in the second half of 2013 (see Njord Update section below).
In the Brage field (Faroe 14.26%), Wintershall took over as operator from Statoil, as planned, from October 2013 and has started work to high‐grade and rank the portfolio of infill drilling targets. Two new production wells are underway and are planned to be brought on stream in Q2 and Q4 2014.
In December 2013, a new asset was added to Faroe’s production portfolio as the operator GdF Suez brought the Orca gas field (Faroe 3.24%) on stream. The field, which straddles the UK and Dutch sectors of the North Sea and which is only the second such cross‐border gas development between these two countries, has been developed with three wells.
No major investments are expected in 2014 on the other three principal fields ‐ Ringhorne East (Faroe 7.8%), Blane (Faroe 18%) and East Foinaven (Faroe 10%), which are expected to continue to produce at stable rates during 2014.
As previously announced in November 2013, production and drilling operations have been suspended temporarily from the Njord and Hyme fields to allow for the deck structure of the Njord A floating facility to be reinforced after the operator Statoil carried out a detailed analysis of the facility’s structural integrity. The work on the reinforcement project is in progress and the operator’s expectation is that this will be completed and production at the Njord and Hyme fields resumed in the summer 2014. However, due to continued weight restrictions, Njord A will be without a drilling facility unless further strengthening of the substructure is undertaken.
Considerable resources remain in the GNA with estimated 2P and 2C Resources of over 170 mmboe gross. These include developed volumes that can be produced from the existing wells on Njord and adjacent Hyme fields, further in‐fill drilling in the Njord field, development of the North West Flank rich gas and condensate accumulations and development of the recently announced significant Snilehorn oil discovery. In addition, the Pil well is currently being drilled within tie‐back distance and there is also substantial additional prospectivity that is being matured with a view to further exploration drilling in the near term. In particular several attractive opportunities have been de‐risked in licence PL348, following the successful Snilehorn well.
On this basis and as previously reported, the Njord partnership is evaluating a number of scenarios for the long term further development of the GNA. The objective is to prepare a robust plan to re‐establish development drilling in the Njord field and generate maximum value and reserves exploitation from the long term development of these important hydrocarbon resources. The scenario evaluation for the GNA is expected to reach its conclusion by mid‐2014, followed by a one year front‐end engineering study and with the final concept selection in mid‐2015. For the long term development of the GNA, the operator’s current base case assumes that, following the period of production mentioned above, the Njord A facility will be brought to a yard for the hull to be either repaired or replaced.
For production to be at the higher end of the 2014 guidance range (4,000‐6,000 boepd), Njord and Hyme will need to recommence production in the summer as planned and the other assets perform in line with expectations.
For further information please contact:
Faroe Petroleum plc
Graham Stewart CEO
Tel: +44 1224 650 920
Helge Hammer, COO
Tel: +47 5121 5120
Panmure Gordon (UK) Limited
Katherine Roe/Callum Stewart/Adam James
Tel: +44 20 7886 2500
Oriel Securities Limited
Michael Shaw/Ashton Clanfield
Tel: +44 20 7710 7600
Edward Westropp/Georgia Mann
Tel: +44 20 7831 3113
1 Faroe took the decision in 2012 to report internal reserves estimates. The reserves estimates provided in this operational update are Faroe’s own estimates.
2 Faroe’s internal assessment of Contingent Resources at 1 January 2014 is compared in the table to Senergy’s assessment of Contingent Resources at 1 January 2013.
3 2013 reserves and production includes East Foinaven. Faroe receives the economic benefit for the full year of production from 1 January 2013 from East Foinaven but will only account for production from the completion date on 8 August 2013
4 Senergy Competent Persons Report
Bjørn Berntsen, Asset Manager Norway of Faroe Petroleum and a Petroleum Engineer (MSc. in Petroleum Engineering from University of Trondheim), who has been involved in the energy industry for 22 years, has read and approved the production, development, reserves and resources technical disclosure in this regulatory announcement
Andrew Roberts, Group Exploration Manager of Faroe Petroleum and a Geophysicist (BSc. Joint Honours in Physics and Chemistry from Manchester university), who has been involved in the energy industry for more than 25 years, has read and approved the exploration and appraisal disclosure in this regulatory announcement.
Notes to Editors
The Company has, through successive licence applications and acquisitions, built a substantial, diversified portfolio of exploration, appraisal, development and production assets principally in Norway, the Atlantic margin and North Sea. Faroe Petroleum has extensive experience working with major and independent oil companies and its joint venture partners include BP, Centrica, DONG, Eni, E.ON Ruhrgas, GDF, OMV, RWE Dea, Statoil and Wintershall.
The Company’s licence portfolio provides considerable spread of risk and reward, encompassing over 60 licences. Faroe has a very active drilling programme ahead and it currently has interests in four principal oil and gas production fields in the UK and Norway, including interests in the Blane oil field in the UK, and interests in the Njord, Brage and Ringhorne East fields in Norway, which collectively produced on average 6,059 boepd (economic production) in 2013.
In January 2013 Faroe announced a significant discovery in the Rodriguez prospect located on the Halten Terrace, in the Norwegian Sea. The discovery was made in the Lower Cretaceous, and led to the decision to fast‐track drilling of the Solberg well which is currently drilling. In November 2013 Faroe announced the Snilehorn oil discovery in the Norwegian Sea in close proximity to the Hyme and Njord fields and in January 2014 announced the smaller Novus discovery.
Norway operates a tax efficient system which incentivises exploration, through reimbursement of 78% of costs in the subsequent year.
Faroe Petroleum is quoted on the AIM Market of London Stock Exchange plc with offices in Aberdeen, Stavanger and London. The Company is funded from cash reserves and cash flow, and has access to an undrawn $250 million borrowing base facility, with a fully funded drilling programme through 2014. Faroe has highly experienced technical teams who are leaders in the areas of seismic and geological interpretation, reservoir engineering and field development, focused on creating exceptional value for its shareholders.
|“APA”||awards in pre-defined areas|
|‘best estimate”||an estimate representing the best technical assessment of projected volumes. Usually the P50 value. For Contingent Resources, the term of best estimate is denoted as 2’C|
|“boe”||barrel of oil equivalent|
|“Contingent Resources”||Those quantities or petroleum estimates, 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.|
|“mmboe”||millions of barrels of oil equivalent|
|“net”||the portion that are attributed to the equity interests of Faroe|
|‘Proved + Probable Reserves” or “2P”||those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sun 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|
|“reserves”||reserves are those quantities or petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status|
|“STOIIP”||stock tank oil initially in place|
|“unrisked”||without incorporating the probability of failure|