16 Jan 2017
Acquisition of SNS Pipeline and Skipper Update
Independent Oil and Gas plc ("IOG" or the "Company") (AIM: IOG.L), the development and production focused Oil and Gas Company, is pleased to announce it has signed a Memorandum of Understanding (â€œMOUâ€) regarding the 100% acquisition of a currently disused pipeline in the Southern North Sea (â€œSNSâ€) for a nominal consideration. The pipeline will provide the proposed export route for its Southern North Sea assets. The Company also provides further results of the Skipper appraisal well drilled last year.
Acquisition of SNS Pipeline
The MOU contains exclusivity provisions until 28th February 2017. Discussions regarding the Sale and Purchase Agreement (â€œSPAâ€) are at an advanced stage and all parties are committed to completing this documentation and then concluding the acquisition at the earliest opportunity. The Company will assume operatorship of the pipeline at completion and the liability for future decommissioning.
Under the terms of the SPA, IOG would also acquire the associated onshore reception facilities. IOG plans to use this pipeline as the main export route for all of its SNS gas assets.
Upon acquisition of the pipeline, IOG will undertake an intelligent pigging inspection to ensure the pipelineâ€™s integrity for safe re-use. The Company then intends to re-commission it to enable evacuation of the gas from both the Companyâ€™s Blythe hub and Vulcan Satellites hub. This will require the installation of inter-field pipelines and tie-in points as is normal for any gas field development. With 300,000 million cubic feet per day (â€œMMcfdâ€) capacity, the pipeline could also accommodate export of the newly enlarged resources in the Harvey discovery, subject to further appraisal.
This acquisition is of great strategic importance as it provides an export route for the Companyâ€™s SNS gas development portfolio which IOG has acquired at low cost, mainly due to concerns over the ability to export the gas. Ownership and recommissioning of this pipeline will solve this issue, providing a direct export route for the Companyâ€™s gas assets into the UK market. By owning the gas assets and the export route 100%, IOG will benefit from clear control over the entire process from field to market. There may also be potential for third parties to use the pipeline in which case IOG would benefit from tariff income. This strategy is fully supported by the Oil and Gas Authority (â€œOGAâ€), is in line with the Maximising Economic Recovery principles and is incorporated in the draft Blythe Field Development Plan submitted to the OGA in December 2016.
By owning the pipeline, the Company will incur no transportation tariffs, thereby further improving the economics of the SNS gas assets. These developments will also benefit from recent stronger UK gas prices. The Company will need to agree and pay processing tariffs to the terminal operator in the normal way. There will be ample ullage through the pipeline and the terminal has capacity to receive in excess of 400 bcf of gas at rates up to 200 MMcfd for more than 20 years.
The consideration is for a nominal sum, with IOG agreeing to bear the liabilities for the future decommissioning of the pipeline and reception facilities.
The Company has received further results from the analysis of the oil samples retrieved from the Skipper appraisal well drilled in July/August last year. The oil has a high density of approximately 11 Â°API, a high viscosity and a high Total Acid Number. However, the Skipper oil is mobile in the very high permeability reservoir and is also mobile at ambient conditions thanks to its very low wax content. The Company is undertaking further technical and commercial evaluation, in particular building a reservoir model to simulate the oilâ€™s mobility in the reservoir. If a field development plan can be designed to enable the economic extraction of oil from the Skipper field, the oil properties will present a challenge for refining and marketability. Depending on where and when the oil is sold, the Company anticipates the crude would trade at a significant discount to the prevailing quoted Brent oil price.
The total cost of the Skipper appraisal well drilled in July/August 2016 was Â£10 million. As previously announced this has been part financed via loans and deferred payments which are due to be repaid at the end of 2017. The total loans and deferred payments drawn for this purpose was approximately Â£6.8 million and approximately Â£3.2 million has been paid in cash or shares. In line with IOGâ€™s business plan, the intention is to refinance or repay these loans in parallel with securing development funding for some or all of our SNS gas assets in 2017.
Mark Routh, CEO of IOG, commented:
This pipeline will be the cornerstone of our Southern North Sea portfolio which, subject to remediation, will enable us to deliver our approximately 0.5 trillion cubic feet of gas resources to the UK market. During a period of relatively low gas prices we have bought, at very attractive prices, quality assets which were considered effectively stranded. Subject to completion of the acquisition, full ownership and control of the export route creates significant value for the Company, especially given the recovery in UK gas prices. Owning our gas portfolio and export infrastructure 100% will enable us to accelerate both the development planning and funding processes.
The update on the Skipper crude quality has confirmed the earlier results and has provided us with some new data. The oil qualities are likely to be challenging, however given the oilâ€™s mobility in the reservoir we continue to explore the potential extraction and marketing options to deliver value from the asset.
We look forward to providing further updates on our portfolio in due course.
About Independent Oil and Gas:
IOG is an oil and gas company with established assets in the UK North Sea. The company's strategy is to deliver near term development and production assets in North West Europe, through its extensive technical and commercial expertise, whilst maintaining some exposure to exploration upside. The company is looking to grow both organically and through acquisition.
All of IOGâ€™s licences are owned 100% and operated by IOG.
Further information can be found on www.independentoilandgas.com
About the Vulcan Satellites:
The Vulcan Satellites consist of three fields, Vulcan East, Vulcan North West and Vulcan South, which hold independently estimated 2C resources of 77.4 BCF, 131.3 BCF and 112.0 BCF respectively, 320.7 BCF collectively. These fields lie in Block 49/21a (Licence P039), Block 49/21d (Licence P2122), Block 48/25b (Licence P130) and Block 49/21c (Licence P1915) in the UK sector of the Southern North Sea. They lie approximately 30-45km east of IOGâ€™s 100%-owned Blythe field and are considered ready for development with no further appraisal required. The Company is preparing Field Development Plans for these three fields which will form a gas hub. IOG has assumed liability for decommissioning a suspended well on Vulcan East, which in April 2015 was independently estimated to cost Â£3.0 million as part of a development campaign, based on prevailing rig rates at that time.
About the Blythe Hub:
The Blythe hub licences comprise Blythe, Elgood, Hambleton, Truman and Harvey.
The Blythe gas discovery in the Rotliegendes Leman formation straddles Blocks 48/22b and 48/23a in the Southern North Sea in licence P1736. The Blythe Leman reservoir needs no further appraisal and has independently verified 2P reserves of 34.3 BCF (6.1 MMBoe). (Source: ERC Equipoise Competent Personâ€™s Report (â€œCPRâ€) dated September 2013.) The Blythe licence has been extended to 31 December 2017. The Company submitted a draft field Development Plan to the Oil & Gas Authority in December 2016. Subject to completion of the pipeline acquisition, the Company intends to submit the full field development plan on a combined Blythe and Elgood development in the first half of 2017.
Gas tested to surface from three separate intervals in the Carboniferous beneath the Blythe Leman gas discovery from one of the Blythe discovery wells, 48/23-3 drilled by Arco in 1987. The maximum rate achieved was 0.9 MMcfd from an unstimulated vertical test. (Source: End of well report 48/23-3 â€“ November 1987.) This was deemed uncommercial at the time, before the advent of horizontal multi-fracture stimulated wells. Further technical work including seismic reprocessing and remapping needs to be completed to evaluate this potential resource to refine the gas-in-place estimates which are between 70 BCF and 310 BCF. (Source: Tullow Oil 48/23a Relinquishment Report â€“ May 2009.)
Oil has flowed to surface from the naturally fractured Zechstein Carbonates in the Hauptdolomit formation above the Blythe Leman gas discovery from two wells. Well 48/22-1 drilled by Burmah in 1966 flowed 39Â° API oil at rates up to 2,000 barrels per day (Source: Composite well log 48/22-1 â€“ October 1966) and well 48/23-3 drilled by Arco in 1987 at flowed 38Â° API oil at a maximum rate of 1,128 barrels of oil a day. (Source: End of well report 48/23-3 â€“ November 1987.) The extent of the structure and potential oil resources in the Hauptdolomit remains unknown. Previous estimates considered that the mapped closure was probably small. Oil-in-place has been estimated between 2 MMBbls and 4 MMBbls. (Source: Tullow Oil 48/23a Relinquishment Report â€“ May 2009.) Further evaluation and re-mapping is continuing now that a development will proceed on the main Blythe gas discovery.
IOG has a 100% working interest in licence P2085 to the east of Blythe (Blocks 48/23c & 48/24b) which was awarded in the 27th licensing round. Recent 3D seismic reprocessing and remapping by Beagle Geoscience Limited has led to an improved understanding of the complex faulting that exists in the overlying strata. Based on this work, the internal management probabilistic estimates of the P90/P50/P10 gas initially in place for Harvey are 77/176/403 BCF and probabilistic estimates of the P90/P50/P10 resources are 44/113/290 BCF.
IOG is now considering committing to a firm appraisal well on Harvey which would be required before a reservoir model could be built and a development plan could be prepared. If an appraisal well was to be drilled successfully and Harvey was subsequently developed, the Company believes that it could be tied back to the same pipeline as the Blythe and Vulcan Satellite hubs.
IOG has a 100% working interest in licence P2260 awarded in the 28th licensing round to the west of Blythe containing the Elgood discovery (Block 48/22c). Elgood was drilled by Enterprise Oil in 1991 and tested gas to surface at 17.6 MMcfd but was not progressed by Enterprise due to size and gas prices at that time.
IOG is now working on the development plan for Elgood to be submitted in conjunction with the Blythe field development plan and will commission a CPRâ€Ž to confirm the resources over this area. Based on the work undertaken by Beagle, the internal management probabilistic estimates of the P90/P50/P10 gas initially in place for Elgood are 26/35/48 BCF and probabilistic estimates of the P90/P50/P10 resources are 15/22/31 BCF.
The probabilistic Gas Initially in Place and resources estimates for IOGâ€™s SNS portfolio of Blythe, Elgood, Harvey and the Vulcan Satellites are as follows:
|SNS Portfolio||Gas Initially in Place||Estimated resources|
|Vulcan North West||184||215||251||112||131||153|
This does not include other discoveries that may be sub-commercial, or potential additional resources that could be recovered from the carboniferous sections or other undrilled prospects in the SNS portfolio.
The Skipper oil discovery is in Block 9/21a in the Northern North Sea in licence P1609. IOG owns 100% of the Skipper licence P1609 and is the Operator. In July/August 2016 the Company successfully drilled its first operated appraisal well and retrieved oil samples, in order to design the optimum field development plan. Skipper has independently verified gross 2C resources of 26.2 MMBbls. Following the results from the appraisal well, IOG managementâ€™s estimates of the oil in place in the Skipper reservoir are minimum/most likely/maximum 119.3/142.6/168.3 MMBbls. Recovery factor estimates will be revised during the full field reservoir simulation studies which are now underway.
Competent Personâ€™s Statement:
In accordance with the AIM Note for Mining and Oil and Gas Companies, IOG discloses that Mark Routh, IOG's CEO is the qualified person that has reviewed the technical information contained in this announcement. Mark Routh has an MSc in Petroleum Engineering and has been a member of the Society of Petroleum Engineers since 1985. He has over 35 years' operating experience in the upstream oil and gas industry. Mark Routh consents to the inclusion of the information in the form and context in which it appears.