Egdon Resources — Focus on UK shale – a low-cost option

Egdon Resources is an independent E&P focused on oil and gas exploration and exploitation across proven basins in the UK, targeting a mix of conventional and unconventional resource. The company is debt free and benefits from carried interests across a number of its licence blocks. Egdon is looking to grow its unconventional resource exposure in Northern England, add reserves and resources through active drilling and maximise returns from its existing production portfolio through selective investment.

Our Egdon valuation is constructed of a risked net asset value for the company’s conventional asset portfolio and an indicative valuation for the company’s unconventional acreage based on a dollar per acre multiple derived from our probabilistic UK shale valuation model. Our conventional asset core value stands at 2.3p/share (including cash and net of G&A) and we include 10.5p/share for risked exploration and appraisal. Our indicative shale valuation stands at 105p/share based on a P50 risked $2,142/acre (see Exhibit 1).

Egdon had £4.1m of cash and no debt as of 31 January 2018. Management continues to invest in the company’s unconventional asset base while keeping risk capital to a minimum through existing cost-carry arrangements and farm-outs. The company’s 14.5% interest in Springs Road-1 is cost-carried by INEOS and Egdon is looking to farm-down equity to part fund exploration at North Kelsey and appraisal of the Endeavour/Resolution gas discovery.

Numerous studies have been conducted to quantify UK shale gas resources; these form the basis of our probabilistic UK shale valuation. Historic core wells and a vertical exploratory well at Preese Hall provide supportive data to suggest potential for commercial well pad economics. The Bowland shale is thermally mature for gas and benefits from very thick shale sections. Total organic content ranges from 1-7% in cored intervals, and Cuadrilla has demonstrated gas flow to surface at Preese Hall. Significant uncertainty remains over the level of overpressure, the impact of structural complexity on gas recovery and well type curves. Upcoming activity is aimed at reducing this uncertainty through further exploration and appraisal. Cuadrilla is drilling an exploratory well at Preston New Road and initial results from a 90-day flow test are expected in Q418. This will be followed by an extended well test, which should provide valuable data on the type curve for a fracture-stimulated horizontal well – a key determinant of well economics and valuation. Assuming strong gas flows, Cuadrilla may decide to connect the wells and sell gas to the local grid. A key input to our valuation is the 2.5km horizontal well probabilistic-type curve produced by consultancy Anderson Thompson – if actual type curves vary significantly from those predicted, this would have a material impact on valuation. We expect greater valuation certainty after the flow test results from Preston New Road.

Egdon Resources is an AIM-listed independent E&P focused on conventional and unconventional oil and gas exploration, development and production in the UK. Egdon produces c 100bbld in the UK, with a focus on appraisal of existing discoveries and low-risk conventional exploration. Unconventional exposure is through over 205,000 net acres of prospective shale acreage in the East Midlands, Bowland Basin and Cleveland Basin. In this note we focus primarily on the potential value driver presented by Egdon’s shale assets. An overview of the UK shale industry is shown in Appendix 1 on page 10.

Egdon has three stated strategic objectives:

UK shale dominates valuation

Our valuation is split between producing assets (including cash and net of G&A) at 2.3p/share and 10.5p/share for risked exploration and appraisal, which makes up our conventional RENAV of 12.8p/share. Below we show the valuation that would be ascribed to Egdon’s 205,000 net UK shale acres at multiples ranging from $500/acre (historic farm-outs including those of INEOS/Total in the Gainsborough Trough range from $614/acre to $2,200/acre). Our P50 probabilistic valuation stands at $2,142/acre.

Key activity that could drive the market to re-evaluate Egdon’s UK shale assets includes Cuadrilla’s initial flow test at Preston New Road (Bowland Basin) in Q418, and drilling of the IGas-operated Springs Road-1 (Gainsborough Trough) vertical well in H218. Conventional activity relevant to Egdon includes drilling at Biscathrope (5mmbo net), Holmwood (1.1mmbo net) and North Kelsey (5.2mmbo net) (subject to further farm out). Farm out of the Resolution/Endeavour gas discoveries could also provide greater certainty of appraisal timing.

We see Egdon’s most valuable asset as its exposure to the UK shale sector, despite current uncertainty around commerciality. Egdon’s shale position comprises of over 205,000 net acres across the East Midlands (including Gainsborough Trough), the Bowland Basin and Cleveland Basin. With an enterprise value of $15m, the market is clearly implying very little in terms of option value for Egdon’s shale acreage should shale be proven commercial in the UK. This is despite historical UK onshore transaction values ranging from $300-$3,000/acre and Edison’s P50 probabilistic shale valuation of $2,142/acre as extracted from our recent report on AJ Lucas and shown below.

One can attempt to rationalise why the market does not ascribe value to the company’s net shale position. However, it is also possible to see how this view could change dramatically and relatively quickly.

Common reasons or sensitivities cited for not ascribing value for shale include:

We believe the market is overestimating risk and should be ascribing some form of risked value to UK shale assets for the following reasons.

We flag that our shale valuation at $2,142/acre does not take into consideration the political risks. Leading political parties maintain opposing views on the net benefits of UK shale extraction. The current incumbent believes shale will provide a significant benefit in terms of employment, security of energy supply and will support a renewable energy transition. However, the current leader of the Labour party has been vocal about banning the practice of fracking. Investors need to be aware of political risks and the importance of central government in the role of supporting the UK shale sector.

We assume a two-year planning cycle for well pads, but we do not see extended planning processes as a major influence on value. We assume that companies have visibility on the duration of planning processes and submit applications according to this expected timeline. A more cohesive planning process is likely to be required to ensure timetables and processes are consistent across UK local councils and planning authorities.

Timing is a key determinant of cash flow, especially when we discount shale gas assets using a relatively punitive 15% cost of capital. If we were to discount our $2,142/acre unit valuation by a further two years to reflect the fact that the company is only at an advanced stage of planning application and appraisal at IGas-operated Springs Road and Tinker Lane, we would arrive at a net valuation at c $1,500/acre, which would be significantly above that implied by the current share price (implied value is zero assuming Egdon conventional value is in line with Edison estimates).

Surface access will limit resource recovery; however, technological advances have enabled companies to maximise recovery from a relatively small surface footprint. It is widely expected that a well pad (around the size of two football pitches) will be sufficient for the drilling of 30 to 40 long lateral wells into different stratigraphic intervals (up to 2.5km with 100 frack stages) depending on localised shale thickness. We do not assume resource limitations due to land access restrictions in our analysis over and above those applied by British Geological Society (BGS) in the society’s calculation of gas initially in place (GIIP) in our shale gas valuation. More complex analysis would involve looking at licence-specific surface access limitations, planning complexities and shale thickness to take a view on accessible GIIP.

Whilst we assume shales and acreage valuations are consistent across the BGS study are, it is possible that differences in net shale thickness, surface access and structural complexity will lead to ‘sweet-spots’ that offer better returns than more peripheral acreage. The Gainsborough Trough, Egdon’s core area, located to the east of the Pennines, benefits from less structural complexity than the Bowland Basin to the west (albeit thinner shale sections).

We estimate a 67.2% chance of commercial success based on the modelled inputs in our shale model. A key determinant of value is our probabilistic type curve, which is based on comprehensive analysis carried out by the consultancy Anderson Thompson. Flow tests from Preston New Road in late 2018 will provide further certainty on achievable type curves and per-well economics.

Egdon is fully carried for the appraisal phase of its share of operations at Springs Road by INEOS. Large-scale development of UK shale assets will require a material capital influx, we would expect a company the size of Egdon to either sell its acreage position to a larger, better capitalised entity or farm-down – we assume 50% value dilution in our base case to reflect a potential farm-down. However, we recognise that dilution will largely be driven by the success or otherwise of the current UK shale appraisal activity. We note that historic farm outs including INEOS/Total in the Gainsborough Trough range from $614/acre to $2,200/acre.

We include Egdon’s conventional asset base in our valuation but note that producing assets remain a relatively small part at 2.3p/share (including cash and net of G&A). This includes the Wressle development, which has incurred numerous delays due to rejected planning applications.

We see greater conventional value in the company’s exploration and appraisal portfolio, in particular its interest in the appraisal of the Endeavour/Resolution gas discovery and appraisal of the BP Biscathorpe oil discovery which make up the bulk of our RENAV. The focus of this note is on Egdon’s shale gas assets. However a full valuation breakdown is provided below including producing assets and risked E&A.

Key sensitivities for Egdon’s conventional asset portfolio include underlying commodity price, the timing of Wressle development, and E&A activity at Biscathrope and Resolution/Endeavour. Our unconventional valuation is driven by a probablistic model where key drivers include type curve (IP rate and EUR), well costs and underlying gas prices.

Mark Abbott – managing director: Mark is an experienced geophysicist and founding director of Egdon Resources. He graduated Nottingham University of Nottingham in 1985 with a degree in exploration sciences (geology/ geophysics/mining engineering). He worked for the British Geological Survey from 1985 to 1992 in the UK and overseas. Between 1992 and 1996 he worked in the International Division of British Gas Exploration and Production and was employed by Anadarko Algeria Corporation from 1996 to 1997. He is a council member of UKOOG and a trustee of the UK Onshore Geophysical Library. He is also a director of MA Exploration Services and Bishopswood Pavilion.

Jerry Field – technical director: Jerry has over 30 years’ oil industry experience in small-to-medium sized E&P companies (including Weeks Petroleum, Triton, Ranger, Canadian Natural Resources, Toreador and Northern Petroleum). Jerry has a breadth of experience of exploration in Europe, Africa, the Middle East and the Indian subcontinent and has spent a much of his career working in Egdon’s core areas of the UK onshore and France.

James Elston – commercial and business development director: James has 25 years’ experience in industry, banking and consulting. As CEO of TSX-V listed Realm Energy International in 2009/10, he drove the company’s acquisition of a significant acreage position for shale gas and tight oil in Europe following in-depth basin-by-basin technical review and ranking. He spent an initial five years working onshore E&P as an engineer at NAM in the Netherlands.

Martin Durham – exploration director: Martin graduated from the University of Wales in 1978 with a BSc degree in geology and also holds a MSc degree in petroleum geology from Imperial College, London (1982). Martin has significant industry experience gained through companies including the Louisiana Land and Exploration Inc, LASMO, Eni and Northern Petroleum. During this time, he has held senior technical and management roles for exploration and field development projects. Martin was founding director of Union Jack Oil, a position he held until his appointment to Egdon in September 2014. Martin is a Fellow of the Geological Society and in 2012 he was awarded Honorary Life Membership of the Petroleum Exploration Society of Great Britain.

Martin Brooks – HSE and Production Manager: Martin worked in various industries in the implementation and management of specific production, health, safety and environmental mechanisms and ensuring compliance with ISO14001, prior to joining Egdon in 2007. He now has over seven years’ experience of managing onshore oil and gas production activities including commissioning the Kirkleatham gas field development. He oversees Egdon’s planning and environmental permitting for the company’s UK onshore drilling activities and is also responsible for developing and implementing the company’s HSE management systems at both corporate and site-specific levels.

Egdon’s short-term financials are largely driven by the timing of conventional projects and output from key producing fields such as Ceres. Volatility in earnings can be expected as a result, especially as fields are shut-in permanently or temporarily. Production guidance for FY18 is set at 100bopd – 110bopd; we see production reaching 160bopd for FY19, including a stronger contribution from Ceres, and currently assume Wressle first oil in FY20 (late CY19). Production volumes remain small, and as discussed earlier in this note, we believe the key value proposition for shareholders lies in the company’s net UK shale exposure and conventional E&A. Appraisal activity at Springs Road, where Egdon has a 14.5% equity interest, is carried by INEOS. Meanwhile, management expects to farm down equity at key appraisal projects such as Endeavour/Resolution ahead of drilling in 2019.

At end January 2018 Egdon had cash of £4.1m, which we expect to cover anticipated costs (post farm-down) alongside cash flow from operations through to end 2019. Investors should be aware of potential for further dilution if Egdon chooses to raise equity capital to fund ongoing G&A costs beyond 2019. Alternative financing options may become available contingent on success of current UK shale exploration/appraisal activity and the appraisal of key assets such as Biscathorpe, North Kelsey and Resolution/Endeavour.

Our long-term oil price assumption stands at 70$/bbl Brent (CY22) and we use short-term EIA assumptions of 62$/bbl Brent in CY18 and CY19.

Thick organic rich Carboniferous shales extend across Europe from Poland in the east and through The Netherlands and the Southern North Sea to the Irish Sea in the west. This Namurian and Visean basin is present onshore in the UK in several sub-basins in Northern England and Southern Scotland. Conventional fields have produced gas across Europe with these Carboniferous shales as source rock. This Carboniferous source is exceptionally rich in the UK sourcing both conventional oil and gas fields. Shale drilling in the UK has been concentrated in the western portion of the Bowland sub-basin in Lancashire, one of a number of rift basins formed by crustal extension in the UK between late Devonian/Dinantian times.

The Bowland Basin is one of the largest basins in the area and continues westwards beneath the East Irish Sea, where conventional gas fields Hamilton, Douglas and Lennox have produced c 4-5 TCF to date. The key stratigraphic interval within the basin is the Bowland-Hodder shale, which extends across a large area of central Britain and is of Visean to early Namurian age. The gas bearing shale section is in excess of 6,000ft and is intensely naturally fractured in the Bowland Basin. BGS/DECC estimated in 2013 that the Bowland –Hodder unit contains P50 gas in place of 1329 TCF.

The Bowland-Hodder is made up of the Upper Bowland, Lower Bowland and Hodder Mudstone. The Upper Bowland consists of laterally continuous, organic rich zones dominated by clastic deposits with occasional thin sandstones and dolomitized limestones. The Lower Bowland is much thicker and is a highly variable formation comprising a wide range of lithologies, with calcareous mudstones, siltstones and sandstones being relatively abundant. Fewer wells have been drilled into the Lower Bowland, so that its regional continuity is unclear. In its 2013 Carboniferous Bowland Shale Gas Study, BGS/DECC assigned 264 TCF to the Upper Bowland and the remaining 1065 TCF to the lower unit.

The Carboniferous rocks are overlain by Permo-Triassic sediments. The Manchester Marl in the Permian is effectively a Zechstein sequence that forms a regional seal between the Carboniferous and the shallow water aquifers in the Sherwood Sandstone Group (SSG). Within Cuadrilla’s PEDL 165 licence, the UK Environment Agency has assessed the water in the SSG to the west of the Woodsfold Fault to be highly saline and therefore undrinkable, based on water samples from the Kirkham geothermal test hole. To the east of the Woodsfold Fault, the water in the SSG is fresh and considered to be the second most important groundwater aquifer in England after the Chalk. Cuadrilla views the risk of aquifer contamination as low - the depth of the interval to be fracked is several thousand feet below existing aquifers.

Faulting in the basin tends to a follow NE –SW trend. Within Cuadrilla’s PEDL 165 licence area the key faults are the Woodsfold fault and the Thistleton Fault. The Woodsfold fault is a major N-S fault with displacements up to 6,000ft in the Permian and Sherwood Sandstone and was the eastern boundary of the Elswick Graben in Permian times. The western boundary of the Elswick Graben is formed by the smaller Thistleton fault, which stops at the Permian anhydrite. The Thistleton fault sits around 3.5km to the east of Cuadrilla’s 2010 well, Preese Hall-1, while the Woodsfold fault is 9.4km from Preese Hall-1. A second type of faulting exists within the Bowland Shale, which is known to be heavily fractured and faulted. However, these faults are relatively small and are contained within the Bowland (Exhibit 7).

Shale basins in the UK are significantly smaller in area relative to their North American counterparts, but tend to be much thicker. In addition, North American shale regions are simple continuous structures, while the UK basins are structurally more complex, consisting of small fault bounded basins that can be significantly faulted. The entire prospective area of the Bowland – Hodder shale was assessed by BGS/DECC to cover c 14,000km2, athlough this area also includes the Blacon, Gainsborough, Widmerpool, Edale and Cleveland basins in addition to the Bowland. Although shale thickness is greater in the UK basins, this can vary over relatively short distances, in contrast to US shale play thickness which is uniform over large distances. The Bowland Basin is considered to be most analogous to the Barnett, Marcellus and Fayetteville shales in the US.

Techniques for successfully drilling and stimulating shale gas wells have evolved across the US largely on a trial and error basis. While the UK shale plays will benefit from these advances in technology, operators will still need to go through a learning curve of their own to optimise results. Under the terms of its licence to drill in the Bowland, Cuadrilla has had to specify the chemicals and the volumes to be used prior to drilling the wells and this cannot be changed during the current drilling programme. By contrast, in the US, companies can alter these parameters once the well has been drilled and data has been gathered, allowing the flexibility to be reactive to well results in designing optimal fracking programmes.

The US experience also highlights that there can be a substantial difference between high and low producing wells within a play. Exhibit 11 shows observed production curves from the Barnett shale, where the top 20% of field production is driven by 7% of the wells. High producing wells are thought to be those where the fracture stimulation successfully connects to a pre-existing fracture network. In the UK it may take some time and experience to be able to tap into these higher producing sweet spots.

The criteria required to define a successful shale gas play have been developed by the USGS in relation to the analogous shale gas plays in the US. These criteria are divided into those that are considered essential, and those that are desirable.

On this basis, initial indications are promising for a successful shale gas play in the Bowland Shale. The Bowland shale is of a thickness and depth to satisfy the criteria, while results from the first shale gas well in the Bowland Basin, Preese Hall-1, have demonstrated that the Bowland Shale is thermally mature for gas. The total organic content (TOC) has been found to vary through the stratigraphy, with the highest values found within the Bowland Shale. The average TOC was 2.65% with a range of 1% to 7% in the cored intervals. The data on kerogen type is less clear. The presence of humic material indicates Type III, however Type I/II is implied at the top of the sampled section. The Bowland is more intensely structured than the shale plays in North America; however, the presence of 3D seismic over 100km2 of PEDL 165 will allow wells to be drilled away from existing faults. This structural complexity reduces to the east of the Pennines in basins such as the Gainsborough Trough. A key desirable characteristic that is not currently known is the level of overpressure, if any, that exists in the Bowland. The minerology of the Lancashire Bowland shale has been analysed using x-ray diffraction of shale core samples from the Preese Hall well, and has confirmed that both the Upper and Lower Bowland shales are well suited to hydraulic fracturing. This is due to the highly siliceous matrix and low overall clay content. Cuadrilla recently retained consultancy Anderson Thompson to produce a probabilistic-type curve for the Bowland shale based on available data and the consultancy’s specialist knowledge of the Permian, Eagle Ford, Bakken, Marcellus and Montney shale in North America. The result of this analysis is shown in Exhibit 13, with the predicted P50-type curve for a 2.5km horizontal well. We use this type curve as well as the P10 and P90 range associated with this curve in our probabilistic UK shale valuation.