Diversified Gas & Oil — Mature US onshore production consolidation

DGO was admitted to AIM in February 2017 and since then has made six asset acquisitions, investing over $861m in mature onshore production in the Appalachian Basin. Production is predominately natural gas (87% on an oil-equivalent basis for FY19), but the company has some oil price exposure through natural gas liquid (NGL) and condensate realisations. Group net production at the end of July 2018 on inclusion of EQT was c 60kboed from a 1P PDP reserve base of 393mmboe with a conventional well inventory of approximately 50,000 producing locations. The company’s strategy focuses on the continued consolidation of both conventional and unconventional assets within its core areas of operation to drive down unit operating expense and expand margins. If gas prices rise materially from current levels, management retains the option of re-directing capital to organic growth – reducing well acre spacing and increasing recovery from DGO’s vast 6.5m net acreage position.

Our valuation is based on the NPV10 discounted value of the company’s US onshore gas production adjusted for net debt and overheads. At 138.1p/share, our valuation does not include option value for either further NAV accretive M&A or infill drilling. Our analysis suggests that risk/reward is skewed to the upside at the current share price. A downside scenario, assuming low gas price realisations and higher costs, drives a valuation of 100.4p/share (17% below the current share price), while we see potential for M&A and infill drilling to lead to material upside beyond our producing asset NAV of 138.1p/share (upside of 14% to the current share price) and high case NAV of 176.2p/share (upside 46%). Our modelling of a single mature conventional well location suggests DGO’s acquisition strategy has the potential to deliver strong returns if assets can be purchased at a discount to NPV10, and unit LOE reduced and abandonment expense deferred. Amassing a deep well inventory is key in ensuring unit costs and production declines can be effectively managed while being material for the group. Consolidation of mature unconventional well locations in addition to conventional within the Appalachian Basin provides an opportunity to sustain continued inorganic growth.

DGO has committed to returning c 40% of free cash flow (FCF) to shareholders, and we assume a dividend of 11.20c/share or a yield of 6.7% for FY19. The sustainability of this dividend will depend on DGO’s ability to manage LOE and underlying decline rates in the short term and potential growth likely driver by further asset acquisitions. DGO has utilised a combination of equity and debt to fund acquisitions and, critically, has secured a low cost of debt capital at Libor + 2.25–3.25%, while maintaining leverage at 1.1x net debt/EBITDA for FY19. We expect gearing to fall as excess FCF (post-dividend) is used to reduce debt utilisation. Under the company’s current borrowing base of $600m, management retains c $180m of headroom to fund acquisitions/organic investment.

Key investment risks are logistical rather than sub-surface related, in our view. DGO needs to retain tight control of unit operating expenses, access to mid-stream infrastructure and abandonment timing/costs. Management retains the option to return assets to landowners when sufficiently depleted to limit abandonment exposure and recent acquisitions come with material mid-stream infrastructure reducing pipeline access risks.

DGO’s strategy remains ‘acquire, produce, drill’. This entails the acquisition of proven developed producing (PDP) reserves within the Appalachian Basin; maximisation of production and reserve recovery through the use of modern technology and operating practices; and the execution of low-risk, low-cost infill drilling if rates of return are deemed to be attractive in the prevailing commodity price environment.

Since its admission to AIM in February 2017, DGO has made six acquisitions: three in 2017, two in Q118 and one in Q218; corresponding to a total investment of $861m. This is in line with the company’s strategy to leverage its position in the Appalachian Basin to capitalise on current market conditions and acquire mature producing assets in the region. Acquisitions have been funded through a combination of equity and debt, which comprises a five-year senior secured credit facility of up to $1bn from KeyBank and a syndicate of lenders. At completion of the EQT acquisition, we estimate that DGO has c $180m of debt available from a borrowing base of $600m to fund further acquisitions and ongoing capital requirements. Interest is benchmarked to Libor plus 2.25% to 3.25% depending upon utilisation. DGO’s access to capital and the relatively low-cost of debt provides it with a competitive advantage over smaller market entrants looking to establish a similar acquire and build strategy.

Through inorganic growth, net production has increased more than 1,900% from approximately 3kboed at the end of 2016 to c 60kboed at end-July 2018 and the number of producing wells reached approximately 50,000. DGO has managed to achieve operational synergies, reducing unit operating costs and extending the life of producing well stock.

As shown in Exhibit 3, DGO’s acquisitions have been executed at valuations ranging from 1.6x EBITDA to 3.9x, with the largest and most recent, EQT, at 3.5x EBITDA reflecting the higher margins being generated by liquid-rich well stock. Acquisitions have been accretive to EV-based multiple metrics with DGO trading at 6.5x EBITDA at the time of the EQT acquisition. We take a look at DGO’s historical transactions relative to where the group is trading and company’s US gas producer peer group in Exhibit 3 below.

Historical asset transactions have been conducted at a discount to DGO’s US E&P peer group average (we include gas-biased US onshore operators) on production and reserve base multiple metrics such as EV/boed and EV/1P.

Despite DGO’s progress in assimilating approximately 50,000 producing well locations, a significant opportunity exists to expand the company’s mature conventional footprint to include mature unconventional production, much of which is situated adjacent to existing well inventory.

Unconventional well locations in the Appalachia region continue to increase and as horizontal well stock matures, we expect larger players in the region to high-grade their asset portfolios and reduce exposure to less productive well stock. Public data suggest there are over 11,000 unconventional wells drilled in Pennsylvania alone.

Prior to our site trip, we questioned why sellers would divest of large asset packages at a discount to their after-tax NPV10. However, it became apparent how mature production required a different mindset and operational philosophy than that inherent within larger more bureaucratic organisations. Burdened with expensive fixed-cost structures designed to support unconventional drilling margins, low productivity wells rarely gain the attention of management in larger organisations and are prone to underinvestment and lack of attention, therefore becoming side-lined for divestment. For larger companies, the absolute return or NPV to be gained from operationally intensive management of mature production is deemed to be small relative to other opportunities competing for internal capital and resource. Divestment provides an opportunity to release capital and associated provisions with the opportunity to re-direct funds. This, in turn, creates an opportunity for smaller companies such as DGO that can dedicate human resource and capital to maximising recovery and extracting residual value from mature well stock.

The prevailing market conditions in the Appalachian Basin have created a compelling buyer’s market for well-capitalised operators wishing to expand their portfolio of mature, producing assets. The rapid expansion of unconventional activity on the Utica and Marcellus shale assets, the rights to which are ‘held by production’, means the mature, often conventional producing assets which routinely retain the rights to the unconventional assets held in deeper zones within the same leasehold have become non-core to larger industry players. As such, these parties are keen to monetise these wells that have reached their terminal decline rates, often already having paid back a multiple of their initial investment, allowing them to reinvest that cash flow into their active development programs. Enhancing the value from their perspective is the current offloading the related future abandonment liabilities to buyers who can maintain the conventional well production, which for wells in this region of the United States can be for 50+ years, while retaining the rights to the unconventional reservoirs they expect to develop at some point in the future. We believe this dynamic has enabled DGO to carve out a niche. Greater access to equity and debt capital than smaller landowners and appetite to extract residual returns from mature well stock has enabled DGO to amass a vast land position encompassing 6.5m net acres and approximately 50,000 producing well locations.

In the generic example below, we look at per-well returns that could be generated from the drilling of new conventional wells, essentially infill drilling across DGO’s acreage, then compare these to returns that could potentially be generated through asset acquisition. We expect management to focus on asset consolidation for the foreseeable future given the superior returns in the current commodity price environment. As it stands, we do not believe DGO is structured to carry out large-scale drilling operations, a strategy that would require the creation of an in-house drilling department to manage logistics, operations and sub-contractors. We could see DGO focusing on selected liquid-rich drilling opportunities present within the acquired EQT asset base – these provide superior returns to dry gas in the current commodity price environment.

DGO’s business model and strategy is based around the acquisition of non-core assets within the Appalachian Basin. Our analysis below shows the point-forward NPV10 for a single conventional gas well location. We assume that ‘Operator 1’ drills the well, which it then looks to divest once the wells have rolled off peak production and their hyperbolic declines to arrive at a terminal decline rate whereby the wells no longer contribute meaningfully to their consolidated production. Instead, they can monetise the wells and transfer the future abandonment cost to operators who will extend the life of the wells through a variety of initiatives that reduce operating expenses while maintain production on shallow decline. For our generic gas well, the return that can be generated by DGO through this strategy is 15% to 45% largely dependent on acquisition cost. Returns generated by DGO will also be sensitive to gas price realisations, LOE and abandonment cost and timing.

In Q218, we conducted a site visit to DGO’s asset base in Pennsylvania; this provided us with a valuable insight into the company’s assets, operational practices and consolidation potential. DGO’s assets stretch across the gas-rich Appalachian region and include mature conventional production as well as unconventional Marcellus gas production.

We believe that DGO’s approach and corporate structure put it in a unique position to continue to consolidate US onshore conventional and unconventional assets and maximise resource recovery from assimilated well stock. Competition for assets in the company’s core areas is limited as larger operators continue to divest mature well stock and smaller players lack scale as well as the access to capital to compete.

While the oil and gas majors continue to pursue the simplification and standardisation of operational and field development practices, we believe DGO takes a contrasting approach, devoting resource to scrutinise and maximise the value of each operated well location. This bespoke approach has enabled DGO to increase average production rates from mature wells and reduce unit costs, driving a significant improvement in unit netback.

DGO employs approximately one well tender per 100 wells. As the company increases well density through future acquisitions, it expects the well-to-well tender ratio to increase by securing more wells in existing locations. This cost-saving improvement is realised primarily by route optimisation, which reduces driving time between wells and will reduce overall operating expense. Well tenders and production foremen have significant responsibility and autonomy, with accountability for well pad economics and the authority to deploy small capital improvements that generate quick payback.

Management has highlighted several initiatives that have successful reduced unit LOE for assimilated assets, these include:

Acquired assets are often non-core to the seller and opportunities to optimise and workover have often been overlooked. While the NPV to be generated from such activities is small, IRR is higher and payback quick. Scale is key in ensuring absolute value is material for DGO and its shareholders.

Below are a couple of examples of how DGO extracts residual returns from mature well stock, through redeploying existing equipment and bespoke management of individual wells to ensure production rates are maximised. Top-tier producing wells across DGO’s producing 50,000 well stock attract the most oversight from well tenders, with production supervisors incentivised to focus on returns on maintenance capex rather than just incremental volumes. In the field, we saw a couple of examples of DGO’s approach to asset management in practice. A challenge for DGO will be ensuring unit LOE can be maintained despite declining production. Several approaches are likely to help in this regard including the use of SCADA instrumentation to enable remote well oversight and possibly also remediation.

Venturi plungers are used across a large number of DGO’s mature conventional well stock to reduce casing pressure by removing water from the bottom of the wells’ production tubing. The timing at which Venturi plunger runs are initiated has a direct impact on average daily flow rates. To optimise well maintenance, DGO employs numerous well tenders to regularly attend to and adjust systems such as this to maximise flow rates. Production supervisors manage the deployment of well tenders to well locations to maximise the return on well maintenance/modification expenses.

At a well location we visited, a spare gas compressor unit that was unused was deployed to a well location to reduce wellhead pressure and increase gas flow rates. The installation cost of the small compression unit was minimal and payback was achieved in a matter of days after including compressor-running costs. The NPV impact of minor modifications such as these is assessed and managed at the field level.

DGO expects to apply a similar operating philosophy across the group. However, we expect best group-wide best practices to evolve as the company assimilates recent acquisitions.

We value DGO using a conventional NAV approach based on the NPV10 of the company’s producing assets minus overheads and net financial liabilities. A full breakdown of our NAV is provided in Exhibit 13.

Asset-level valuations are carried out based on state-specific fiscal terms, basis differentials and costs. We also include an abandonment schedule of 100 wells per year until 2035, and 1,000 wells per year beyond 2035 across the portfolio, and abandonment costs of $24,000 per well in line with estimates provided in the company’s H118 results, EQT acquisition prospectus and US onshore industry averages.

As mentioned earlier in this note, we do not include an incremental value for M&A potential or infill drilling. However, it is important to recognise that management has created material value for shareholders through asset acquisition at attractive valuations. While the Appalachian Basin has a finite level of conventional asset opportunities, we see a growing opportunity in the unconventional sector, where larger players are looking to recycle cash from mature unconventional producers into high-return drilling opportunities. Also not included in our valuation is the infill drilling opportunity present on existing leases, if DGO elects to reduce average well acre spacing and maximise resource coverage from its existing land position.

We value DGO’s existing assets with a relatively high level of confidence, based on booked reserves and known fiscal terms. Key areas of uncertainty are realised commodity prices, applied discount rate and costs as shown in Exhibit 11. The value on M&A upside potential or risked infill drilling NPV is far less certain but is likely to be more than zero. While one could attempt to subscribe an element of option value to both M&A and infill drilling, we have decided against this approach. Instead, we have stress-tested our base case valuation to the downside and the upside to formulate high and low value scenarios (see Exhibit 12). We see a 46% upside from the current share price in the event of higher gas prices and lower LOE and abandonment costs. Disproportionally, we see just 17% downside from the current share price in the event of lower gas prices, higher unit and decommissioning costs. We conclude that the risk/reward of investment for shareholders is skewed to the upside, and materially skewed to the upside if one were to include M&A and infill option value.

DGO has acquired a vast 6.5m net acre position, paying minimal value beyond PDP cash flows. While it is difficult to quantify the value of the company’s infill drilling opportunity, we expect management to assess the potential of its acquired leasehold once it has had the opportunity to work up quick payback optimisation opportunities such as workovers. High liquid yield drilling opportunities present with the acquired EQT asset portfolio (e.g. Lower Huron inventory) may provide a good starting point. Beyond this, DGO expects to establish type curves using modern drilling and completion techniques, reassess drilling costs and work up a drilling programme that offers a competitive return on capital relative to less capital-intensive opportunities.

We include a discounted value for payments DGO receives for third-party use of services and mid-stream assets in our valuation – currently estimated at c $12m pa or $118m in our NAV. We note that DGO has over 6,400 miles of pipeline and 59 compressor stations, which have spin-out optionality and the potential to secure DGO a competitive advantage when assessing future deals in the region.

The NAV table below provides a breakdown of our valuation by asset, using data available in the company’s last published prospectus and CPR as well as state public sources.

Exhibit 14 breaks down our valuation by asset class showing where our base case core NAV is relative to the current share price.

Key drivers of DGO’s valuation are assumed gas price and LOE. The table below provides a base case valuation sensitivity to these key drivers. Our base assumes a long-term (2022) gas price of $3.10/mcf and LOE of $4.52/boe both inflated by 2.5% thereafter.

Some in the market have also questioned DGO’s net abandonment liabilities, given the company’s depth of mature well stock. We assume an abandonment schedule of 100 wells per year until 2035, and 1,000 wells per year beyond 2035 across the portfolio, and an abandonment cost of $24,000 per well in line with estimates provided in the company’s H118 results, EQT acquisition prospectus and US onshore industry averages. Potentially offsetting the impact of these costs is the lower number of wells per year required to satisfy the regulators in the state in which DGO operates. We have also stress-tested our valuation for changes in per-well abandonment cost and compared cost relative to historic actual costs to increase our comfort in our valuation approach. We do not see decommissioning costs and the pace at which decommissioning occurs (we assume 100 wells per year until 2035, and 1,000 wells per year beyond 2035) as a key driver, unless costs or timing vary materially from our base case assumptions. We have also analysed publicly available data on abandonment cost estimates for over 8,100 wells in Pennsylvania. These data are below and show a low P50 cost estimate per well of $8,941 and high P50 cost estimate of $18,536, which is materially below our assumed abandonment costs but in line with DGO CPR assumptions.

In this section, we compare DGO to a number of its US onshore gas biased peers, looking at where the company trades on comparative multiples including EV/1P, EV/kboed, P/CF FY2018e and 2019e, and RLI. DGO trades at a discount to the majority of its gas biased peers on reserve and production metrics, but at a premium on short-term cash flow metrics. FY18 cash flows only include a part year contribution from EQT – at 3.5x FY19 cash flow DGO is more in line with the peer group average on this metric. We note that DGO is a London listed mid-cap whereas the peer-group is made up of US listed E&Ps, which are typically valued on a combination of prospective P/CF metrics and NAV by US analysts. Our DGO prospective cash flow per share forecasts do not include any incremental upside from further M&A, which is a key component of the company’s growth strategy.

The exhibits below look at correlations between valuation and growth and yield metrics. We see some reasonable correlations despite the lack of data points in the peer group. DGO trades at a small premium to the group based on forecast cash flow growth and production growth as shown relative to the trendlines below.

DGO pays a substantially higher dividend than the peer group average with all peers yielding less than 1%, relative to DGO’s 4.8% in FY18. DGO also has a significantly higher reserve life index (FY18 production relative to last reported 1P reserves), with the market placing greater value on current production rather than depth of reserve base.

Over the past decade, natural gas production in the Appalachian region has grown faster than pipeline capacity, driving up the regional differential relative to Henry Hub. More recently, an increased capacity to deliver gas to regional markets has narrowed the price spread, but a seasonal pattern in price differential remains, with Dominion South pricing showing a widening price spread in the summer months. As infrastructure in the region is built out, differentials are narrowing and price seasonality is reducing, benefiting Appalachian producers.

Growing Marcellus gas production has driven activity in the midstream sector with numerous gas pipelines under construction taking gas molecules to meet demand from LNG exporters on the southern coast (the EIA expects LNG exports to increase from 1.9Bcf/d in 2017 to 3.0Bcf/d in 2018 and ramp up to 5.5Bcf/d by the end of 2019) as well as natural gas exports to Mexico (pipeline capacity to Mexico has tripled since 2010). Pipeline capacity constraints and transport tariffs drive the differential between the Appalachian region gas hub pricing and Henry Hub, which stands at a DGO volume-weighted average c $0.4–0.5/mcf.

The differential between Dominion South in southwestern Pennsylvania and Henry Hub fell materially in 2017 as the Equitrans expansion of the Ohio Valley Connector and the Rockies Express Pipeline capacity enhancement project provided incremental capacity. In June 2018, the Rover’s interconnector near Detroit was completed, increasing takeaway capacity from southwest Pennsylvania and further narrowing the Dominion South price spread. The Transco Atlantic Sunrise project, expected to be completed by the end of 2018, will connect natural gas production centers in northeastern Pennsylvania and is expected to narrow price spreads between the northern hubs and Henry Hub.

A further 20 pipeline projects are planned, and as such we expect the DGO realised gas differential to remain close to current levels at c $0.5/mcf. Under existing debt arrangements, DGO hedges this differential with swap arrangements.

The table below highlights several major projects pending construction, filed with the Federal Energy Regulatory Commission (FERC) that will add further pipeline capacity in the Appalachian region – the projects in the table below make up a total of over 2,400mmcfd of incremental pipeline capacity.

Edison’s oil and gas base case price assumptions are provided in the table below and include our assumed realised gas price differential relative to Henry Hub. In our base case, we assume WTI in line with EIA forecasts for 2018 and 2019 at $67.03/bbl and $67.36/bbl respectively, rising to $70.00/bbl long-term (2022). For Henry Hub we assume a gas price of $3.10/mcf in 2018, $3.23/mcf in 2019 and $3.10/mcf long-term (2022).

The acquisition of assets from EQT in June 2018 significantly increases DGO’s exposure to WTI, with produced NGLs highly correlated to movements in WTI. Pro forma reserves composition post-EQT is 89% natural gas, 8% NGL and 3% oil. NGLs are typically sold at Mont Belvieu (Gulf Coast pricing) or a 45% discount to WTI. We assume this discount remains static in our commodity price forecasts.

Robert Marshall Post: non-executive chairman: Mr Post joined DGO in 2005 as 50% owner with Mr Hutson Jr and has served as the non-executive chairman since August 2017. Before joining DGO, Mr Post owned and operated an overhead crane company for 20 years.

Robert ‘Rusty’ Russell Hutson, Jr: chief executive officer: Founder and CEO, Rusty Hutson Jr was born and raised in West Virginia, and is the fourth generation in his family to immerse himself in the oil and gas industry. He graduated from Fairmont State College (WV) with a degree in accounting and earned his CPA License (Ohio). Prior to founding Diversified Gas & Oil in 2001, Rusty spent 13 years steadily progressing into multiple leadership roles at well-known banking institutions such as Bank One and Compass Bank. His final years in the banking industry were spent as CFO of Compass Financial Services.

Bradley Grafton Gray: finance director and chief operating officer: Prior to joining the company in October 2016, Mr Gray held the position of senior vice president and CFO for Royal Cup, a US-based commercial coffee roaster and wholesale distributor of tea and other beverage related products. Prior to Royal Cup, from 2006 to 2014 Mr Gray worked in the petroleum distribution industry for the McPherson Companies and held the position of executive vice president and CFO.

Eric Williams: chief financial officer: Mr Williams joined DGO in July 2017 from Callon Petroleum. During Eric’s more than seven-year tenure with Callon, the company grew significantly from a market capitalisation of US$40m to over US $3.5bn, successfully transforming itself from a deep-water asset focused company to an onshore, pure-play horizontal drilling operator in the Permian Basin. Mr Williams began his career in PwC’s Birmingham, Alabama audit practice and prior to his time at Callon served in various roles including internal audit with a focus on Sarbanes Oxley implementation and compliance, controllership and financial reporting for several US publicly traded companies.

The operation of mature well stock has associated operational rather than subsurface uncertainties and risks, which DGO looks to constrain and minimise. We discuss several of these company-specific operational risks and mitigation strategies below. The two key sensitivities are gas prices and LOEs:

DGO is a profitable producer and low-cost operator generating FCF for distribution to shareholders and meeting debt obligations.

DGO’s dividend policy is to return c 40% of FCF to shareholders, and management expects to sustain quarterly dividends close to the current 2.8c/share. Key drivers of FCF and dividends will be gas realisations and LOE, as under the company’s current mode of operation maintenance and drilling capex spend is minimal. Short-term FCF has the potential to fall if DGO enters an extensive drilling phase.

Below we provide our FCF forecasts based on our underlying commodity price assumptions. We forecast a dividend of 11.2c/share in 2019, equating to a yield of 6.7% at the current share price. We also assume FCF is used to reduce net debt and gearing with net debt/EBITDA falling from a forecast 3.1x in FY18 to just 1.1x in FY19e and 0.6x by FY20e in the absence of further acquisitions. In reality, DGO’s balance sheet is likely to evolve to incorporate further consolidation within its core areas of operation. DGO benefits from attractive financing terms with its corporate facility priced at Libor plus 2.25–3.25% depending on utilisation.

Exhibit 32 below shows the impact of our lower gas price and higher-cost valuation scenario on dividend yield – under this scenario dividends would be maintained close to our base case 6.7% for FY19. In our base case we assume management sustains the quarterly payout at 2.8c/share, and in high and low cases, pays out 40% of FCF including short-term tax benefits (we recognise that management may elect to exclude short-term tax shields from the calculation of FCF for the purposes of the dividend).

DGO operates within the Appalachian Basin, onshore in the northeast US. The basin covers an area of c 120m acres, underlying ten states, and has been a major producer of oil and gas from conventional vertical wells since the late 19th century. However, it has only come to prominence following the shale gas reserves discovery in 2009, known as the Marcellus Shale. Since then, the primary target of the Appalachian for most oil and gas companies has been the horizontal drilling of the Marcellus and Utica shale formations. DGO’s main focus remains on conventional production from vertical wells.

The depositions for the Appalachian Basin are the erosional sediments from the once Acadian Mountains into the lower basin. The basin was limited to the west by an uplift in rock formation from the Late Ordovician and through the Devonian period known as the Cincinnati Arch. As the mountains eroded, the sediment was deposited in the basin with alternating layers of carbonates, limestones, sandstone, siltstone and shale intervals. As a result of these geological events, the Appalachian Basin is very thin to the west and very thick to the south and east, varying from 1,500ft to 8,000ft thickness.

DGO’s conventional wells, which comprise the vast majority of its current portfolio, are at shallow depths ranging from 2,200ft to 6,000ft (averaging c 4,000ft), with current production coming from the Devonian and Silurian ages. In Ohio, producing formations include the Berea, Bradford, Gants, Gordon, Rose Run and several other sands; however, the majority of the state production comes from the Clinton Sand. It is believed the Clinton Sand was formed as a nearshore deposit in the Silurian time. Its average depth is approximately 5,200ft, with depths ranging from 3,500ft to 6,000ft and a thickness of 150ft to 200ft with net productive pays ranging from 10ft to 100ft. The majority of production in Pennsylvania and West Virginia is from Devonian and Mississippian formations. In Pennsylvania, the major productive formations include the Balltown, Bayar, Bradford, Elk, Fifth, Sheffield Speechley, Tiona and Warren, and in West Virginia include the Alexander, Balltown, Benson, Big Injun, Big Lime, Elk, Fifth, Gordon, Riley and Warren. In general, the thickness for these reservoirs ranges from 5ft to 25ft for any individual zone, with a cumulative net sand thickness ranging from 40ft to 100ft.

The Marcellus Shale is a Devonian age formation, but due to its low porosity and extremely low permeability, has not been considered a major drilling target until 2009. Vertical wells in the Marcellus produce low volumes over a long life. Since 2009, through horizontal drilling the Marcellus has received a great deal of attention for its extremely high production rates, large estimated ultimate recovery volumes, and the statistical repeatability of the producing wells. Very large hydraulic fracture treatments are needed to make these commercial.

Drilling and completion operations are relatively straightforward with a low risk, due to the geology and extensive mapping of the formations, and consequently low cost with wells costing approximately $200,000. The producing wells are mature and expected to produce for 40–50 years with low-decline rates, averaging 3–5% per year with a low water content. Several of these wells are completed in multiple formations and production is commingled in the wellbore, therefore there is a potential upside for most of these wells because they may have additional productive formations up-hole from the existing producing formations and may allow for future completion opportunities and revenues.

The EQT acquisition includes a gathering and compression system consisting of approximately 6,400 miles of pipeline and 59 compression stations in Kentucky, Virginia and West Virginia. These pipelines gather gas from EQT assets along with third-party gas from different operators in the region and deliver the aggregated volumes to Langley, Kentucky. Third-party access to EQT midstream facilities has been generating stable revenues of approximately $9m a year. Approximately 100mmcfd of gas from EQT assets is exported to Langley for NGLs processing. Once the NGLs are separated from the gas stream, the dry gas can be exported to multiple interconnections through the Big Sandy pipeline maximising its pricing and value. The value of mid-stream assets in our valuation is reflected in the netback DGO receives for its gas sales, which would otherwise be higher if they were reliant on third-party infrastructure.