Diversified Gas & Oil — Cash flow protected in a low-price environment

DGO was admitted to AIM in February 2017 and has since invested more than $1.7bn in acquisitions, making it the largest conventional gas producer in Appalachia. Production is mainly natural gas (90% for FY19), but the company has some oil price exposure through natural gas liquids and condensate realisations. Group net production in Q120 averaged 94kboed from a year-end 2019 1P PDP reserve base of 563mmboe, with the portfolio largely focused on conventional production. The company’s strategy focuses on the continued acquisition and consolidation of both conventional and unconventional assets within its core areas of operation to drive down unit operating expense and expand margins, leading to stable cash flow generation. This is possible due to the company’s Smarter Well Management programme that has been able to keep its Legacy asset production stable without significant capital investment. A combination of stable production and an opportunistically hedged portfolio guarantees robust free cash flow (FCF) generation, allowing for shareholder returns in the form of dividend pay-outs and share buyback programmes even in the current low commodity price environment.

Our valuation is based on the NPV10 discounted value of the company’s production adjusted for net debt and overheads. We break down the assets into DGO Legacy assets (conventional, late-life, low-decline rate), the 2019 acquired assets (early-life assets) and the recent acquisitions of Carbon Energy and EQT assets. DGO also owns pipelines with related compressor stations, which is reflected in our discounted value for payments DGO receives for third-party use of services and midstream assets and respective operating costs in our valuation. We also include the hedging impact based on DGO’s latest available information on hedging volumes from 1 June 2020, as well as the impact of the 2020 share buyback programme and capital raise for the recent acquisitions. Our mid-case valuation stands at 125.4p/share.

DGO’s key drivers of FCF generation and dividends will be natural gas price realisations and lease operating costs (LOE). In this note we stress-test DGO’s ability to sustain its dividend at different commodity prices. We forecast a quarterly dividend payment of 3.50c resulting in an annualised 14.0c dividend in 2020, equating to an FY20e yield of 10.4% at the current share price. We also assume FCF is used to reduce net debt and gearing with net debt/EBITDA standing at 2.3x in FY20 following the recent acquisitions funded through an equity raise with net proceeds of $81.7m and $160m in debt. We believe DGO will continue to mitigate the impact of low gas price realisations by continuing with its opportunistic hedging strategy. DGO’s hedging portfolio encompasses c 81% of its natural gas production at $2.69/mmBtu in 2020 and 79% in 2021 at $2.62/mmBtu.

Key investment risks are the future prices of natural gas and oil liquids. Changes in commodity pricing may affect the value of DGO’s hydrocarbon reserves and operating cash flow beyond the current 24–36 months hedging portfolio, regardless of operating performance. DGO could also be affected by events outside of its control, including economic and political events that could lead to a continuous decrease in commodity prices. DGO also needs to maintain its low unit operating expenses as it grows its asset base. In 2019, the company went through a consolidation period and was able to decrease unit LOE while keeping G&A costs stable, demonstrating the increased synergies achieved from the integration of the acquired assets.

Since our initiation note in 2018, DGO’s strategy remains the same, entailing the acquisition of PDP reserves in/or around the Appalachian Basin and the maximisation of production and reserve recovery through the use of modern technology and operating practices. DGO continues to focus on targeting low-cost, low-decline production assets, with synergistic opportunities. Once acquired, the team deploys rigorous field-management programmes to optimise production and extend well lives, which combine with DGO’s low operating costs to improve margins. This growth strategy results in robust FCF generation, which allows for dividend pay-outs and share buyback programmes, debt reduction and safeguarding the company’s balance sheet.

DGO has invested more than $1.7bn in acquisitions since its admission to AIM in February 2017, increasing production to 94.8kboed and reserves to 563mmboe by the end of 2019. 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 $1.5bn from KeyBank and a syndicate of lenders. The current facility has a borrowing base of $425m with a maturity date of July 2023 and an interest rate of 2.5% plus one-month Libor and is subject to a grid that fluctuates from 2.0–3.0% plus Libor based on utilisation. Borrowings under the company’s senior secured credit facility at 31 December 2019 were approximately $437m. DGO also entered into two securitised financing agreements of $200m each, with net proceeds being used to pay down the revolving credit facility. Both securitisations were granted investment grade by Fitch, with the first being rated BBB- (5.00% interest rate) and the second BBB (5.25% interest rate) reflective of improved asset coverage and the shorter amortising life of the note. 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 acquisitive growth coupled with effective mitigation of the natural decline of legacy assets, net production has increased from approximately 3kboed at the end of 2016 to c 94.8kboed at the end of 2019. DGO has managed to achieve operational synergies, reducing unit operating costs and extending the life of producing well stock.

Despite DGO’s progress in assimilating c 67,000 producing well locations, significant opportunities still exist to expand the company’s footprint in the Appalachia region. While the scale of acquisitions in 2019 did not match the transformational growth achieved in the prior year, DGO delivered a number of material and bolt-on transactions with the same strategic focus. The acquisitions of assets from HG Energy and EdgeMarc Energy enhanced and further diversified production, while two natural gas gathering system acquisitions helped expand the company’s midstream capabilities and enhance the financial synergies and operational efficiencies of the overall portfolio.

The integration of these assets is largely complete, and the producing wells are performing in line with management expectations. The HG Energy acquisition in April 2019 added a combined net daily production of over 20kboed from 107 unconventional producing wells. These unconventional assets represented the first wholly unconventional asset package DGO has acquired and demonstrated the stated objective of acquiring producing assets that offer synergistic opportunities for operational efficiencies, due to their similar productive profile and geographic proximity. In July 2019, DGO entered into a ‘stalking horse’ asset purchase agreement with EdgeMarc Energy for 12 producing unconventional Utica natural gas wells with associated production (c 99% gas) of approximately 7.7kboed and related facilities in Ohio; three drilled but uncompleted wells (DUCs); and undeveloped land containing deep Utica rights.

The EdgeMarc acquisition demonstrated DGO’s ability to identify unique opportunities and execute transactions on compelling valuation multiples that are in line with the company’s strategy. This was further supported by the update in November 2019, when DGO announced the sale of the non-producing assets – including the three DUCs to which no value had been allocated at the time of purchase – for a total of $10m. The transaction successfully monetised assets that were not in line with DGO’s core strategy and reduced the net cost of the 12 producing wells by c 20%.

In addition to expanding upstream production, DGO also completed the purchase of two separate natural gas gathering systems in Pennsylvania and West Virginia in September 2019. The assets, purchased from Dominion Gathering and Processing and Equitrans comprise c 1,700 miles of low-pressure wet and dry gas gathering pipelines together with compressors, measurement stations and related facilities and equipment. Combined with DGO’s existing southern midstream system, the company now owns and operates c 12,000 miles of natural gas gathering and transporting pipelines across the Appalachian Basin.

DGO recently announced it has concluded the acquisition of certain upstream and midstream assets in Appalachia from Carbon Energy Corporation and EQT Corporation. The gross purchase price stood at c $235m (Carbon: $110m, EQT assets: $125m), with a resulting net consideration of c $210m (Carbon: $98m, EQT assets: $112m) after customary purchase price adjustments with an effective date of 1 January 2020.

The Carbon Energy assets are located within DGO’s existing West Virginia, Kentucky and Tennessee footprint and include mature, low-decline conventional net daily 2019 adjusted production of c 9.1kboed (97% natural gas) primarily from c 6,100 net operated wells. The acquired assets also include an intrastate gathering pipeline of c 4,700 miles in West Virginia, which currently transports the majority of the production from Carbon’s Appalachia wells and provides additional third-party transportation revenue along with direct interconnects to higher-priced interstate pipelines. Two active natural gas storage fields that generate third-party storage revenue and greater control optionality for DGO are included in the midstream assets to be acquired. The assets come with a robust hedge portfolio that includes average NYMEX downside protection of approximately $2.60/mmBtu for a period of 18 months from the transaction effective date, representing c 75% of the asset’s 2019 produced volumes.

EQT assets encompass c 900 net operated wells, with the majority of the wells being conventional vertical wells in West Virginia, and 67 horizontal producing wells in Pennsylvania, and associated midstream infrastructure. The acquisition includes a further 13 drilled and completed wells that are not yet connected to the gathering infrastructure, which have been excluded from the valuation. DGO has the optionality to connect the wells to the gas export facilities or monetise the wells in the same fashion as the EdgeMarc DUCs, and is currently evaluating both scenarios.

DGO intends to fund the purchase price through a combination of equity and debt. The company raised $81.7m net of expenses by placing 64,280,500 new shares at 108p/share, equal to a 1.6% discount to the closing of the company’s shares on 11 May 2020. The remainder is to be funded by the issuance of $160m gross through a senior secured 10-year term loan ($155m net of fees and a $3m interest and principal reserve account) with a 6.5% coupon secured by 100% working interest of certain acquired assets, underwritten by Munich Re Reserve Risk Financing, Inc. (MRRF).

We believe 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, especially in the current macroeconomic environment.

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. Management has highlighted several initiatives that have successfully reduced unit LOE for assimilated assets, including:

DGO’s Smarter Well Management programme continues to maintain strong production from its Legacy assets, which exceeded 70kboed in the last quarter of 2019. The continued optimisation of these assets has largely offset what would otherwise have been natural declines in production, for the seventh consecutive quarter in Q120. Acquired assets are often non-core to the seller and opportunities to optimise and workovers 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.

DGO operates c 67,000 wells and with that comes the responsibility of safely retiring end-of-life, non-productive assets. The company has been able to negotiate with state regulatory bodies and reach agreements on abandonment schedules, allowing DGO to manage the NPV of this liability and, where possible, extend well life. In 2019, DGO completed the plugging and abandonment of 105 wells at an average cost of $24,200 per well.

The Carbon Energy and EQT acquired assets are accompanied by state-level plugging agreements that are complementary to those DGO already has in place and do not possess any strict annual plugging requirements as wells may also be returned to production. The company does not anticipate material changes to its plugging programme or related liability as a result of the acquisitions.

In 2019, DGO expanded its midstream capacity to c 12,000 miles of natural gas gathering and transporting pipelines across the Appalachian Basin. The ability to control the flow of its natural gas production while simultaneously increasing market optionality and margins is a core aspect of DGO’s strategy and business model. The company’s expanding midstream results in increased third-party midstream revenues from tariffs charged and production volumes retained and sold, which together partially offset costs to operate the systems. It also allows for control of gas production flow through these systems, increasing optionality to reroute gas to sales points with higher realised prices and eliminates the risk of future rate increases to move gas on the systems, insulating DGO’s low operating cost structure.

The year 2020 is proving to be challenging for the oil and gas industry. In January, geopolitical events relating to Iran resulted in market instability, followed by the coronavirus outbreak and the Russia/Saudi Arabia oil price war. These disruptions to the supply/demand balance have already affected results in Q120, with the EIA on 11 March 2020 estimating oil demand in Q120 to be 0.9mmbod lower than in Q119. However, DGO’s production mix, with c 90% natural gas, and strong hedging portfolio provide strong defensive qualities and downside protection against the recent drop in oil and gas prices.

Historically, hedging has been part of DGO’s strategy, and the company reaffirms its focus on opportunities to protect future cash flows, especially in the current low gas price environment. Approximately 81% of DGO’s natural gas production is hedged at an average price of $2.69/mmBtu (HH was trading at $1.79/mmBtu on 8 June 2020) for 2020, while c 79% of production is already hedged for 2021 at an average price of $2.62/mmBtu. This type of preventive measure will allow DGO to protect its revenue stream for 2020/21 and generate sufficient cash for debt repayment and dividend distribution.

DGO recently announced that, despite the current challenging environment, normal operations continue, with little to no impact from COVID-19. The company has been deemed a provider of ‘essential services’ in all states it operates in and is therefore authorised to continue operating on an unrestricted basis. Despite this, DGO continues to monitor the situation to safeguard the wellbeing of its employees and of the local communities, often in rural locations. This has allowed DGO to maintain stable production during this period, which alongside low operating costs and robust hedging mitigate the impact of low commodity prices and underpin steady cash flows, profitability and the ability to maintain its dividend.

The company has been providing support to the communities in which it operates during these difficult times, with contributions to food banks in the states of West Virginia, Kentucky, Pennsylvania, Ohio, Virginia and Tennessee.

DGO’s growth over the past few years has brought the company to a natural strategic step of moving to the premium listing segment of the Official List and admission to trading on the Main Market of the LSE on 18 May 2020, and subsequent cancellation of admission of ordinary shares trading on AIM. DGO initially announced its intention to move to the Main Market in September 2019. This move should improve trading liquidity and the valuation of DGO due to potential inclusion in the FTSE and other indices and provide access to a greater number of institutional investors who regularly trade in the shares of companies listed on the Main Market.

David E Johnson, non-executive chairman, has enjoyed a long and successful career in the investment sector. He has worked at a number of leading investment houses as both an investment analyst and a manager and more recently in equity sales and investment management. During his career he has worked for Sun Life Assurance, Henderson Crosthwaite and Investec Securities, where he became head of sales and executive director of Investec Investment Bank. Mr Johnson joined Panmure Gordon & Co in 2004 where he worked until 2013, as head of sales from 2006 and then head of equities from 2009. Mr Johnson joined Chelverton Asset Management in 2014 where he was responsible for the group’s private equity investments. Mr Johnson is a non-executive director of Bilby, a holding company providing a platform for strategic acquisitions in the gas heating and general building services industries, and Chelverton Equity Partners, an AIM-listed holding company.

Robert ‘Rusty’ Russell Hutson, Jr, chief executive officer. Founder and CEO of DGO, Rusty Hutson Jr was born and raised in West Virginia and is the fourth generation of his family to immerse himself in the oil and gas industry. He graduated from Fairmont State College (West Virginia) with a degree in accounting and holds a CPA licence (Ohio). Before founding DGO 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. After years of refining his strategy, Rusty and his team took DGO public in 2017. He continues to lead his team and expand the company’s footprint throughout the Appalachian Basin, with a rapidly growing portfolio. Rusty remains focused on operational excellence and creating shareholder value.

Bradley Grafton Gray, chief operating officer. Before 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. Mr Gray has a BSc degree in accounting from the University of Alabama and holds a CPA licence (Alabama).

Eric Williams, chief financial officer, 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 $40m to over $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. Eric has a BSc degree in accounting from Samford University, an MSc degree in accounting from the University of Alabama and is a licensed CPA (Alabama).

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

Over the past decade, natural gas production in the Appalachian region has grown faster than pipeline capacity, driving up the regional differential relative to HH. 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 expanded, 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 to meet demand from LNG exporters on the southern coast. Pipeline capacity constraints and transport tariffs drive the differential between the Appalachian region gas hub pricing and HH with DGO realised natural gas prices in 2019 c $0.2/mcf lower than the year average for HH at $2.66/mcf. This is an improvement over 2018 where the difference between DGO realised gas prices and HH stood at $0.5/mcf. As mentioned above, DGO’s increased midstream portfolio allows the company to optimise gas sales points and take advantage of increased realised prices.

Warmer temperatures than normal this winter reduced demand for heating and put downward pressure on HH prices at the beginning of the year. However, the EIA forecasts that natural gas prices will begin to rise at the end of the second quarter of 2020. This increase is anticipated as associated natural gas production is expected to decline from US onshore production. The COVID-19 pandemic resulted in decreased demand for oil in the US, leading to a crash in the WTI benchmark. The low demand and low oil price realisations led the EIA to reduce the forecast for rigs and wells being drilled onshore US. The unprecedented effects of COVID-19 on the level of drilling activity, as many producers have already announced plans to reduce capital spending and drilling levels, will have an impact on oil production and consequently associated natural gas production. The EIA announced in May 2020 it expects US dry natural gas production will average 89.8bcfd in 2020 (92.2bcfd in 2019), with monthly production falling from an estimated 93.1bcfd in April 2020 to 85.4bcfd in December 2020. Natural gas production is expected to decline the most in the Appalachian and Permian regions. In Appalachia, current low natural gas prices are discouraging producers from engaging in natural gas-directed drilling, and in the Permian region, low oil prices reduce associated gas output from oil-directed wells. DGO is not affected in the same manner as other Appalachian gas producers due to the nature of its low-decline, late-life wells that do not require additional drilling to maintain output levels. The EIA forecasts 2021 natural gas production to average 84.9bcfd, rising in the second half of 2021 in response to higher prices. The EIA forecasts that HH natural gas spot prices will average $2.12/mcf in 2020 then increase in 2021, reaching an annual average of $3.20/mcf because of lower natural gas production compared to 2020.

Exhibit 7 provides DGO’s reported 2019 figures and our updated forecasts for FY20 and FY21. Our FY19 production forecast was in line with DGO’s results for the year. Our FY20 production estimate increases to 100.0kboed to account for Carbon Energy and EQT assets’ contribution for the year. As a result of improved operating metrics, we have also updated our assumptions to reflect DGO’s latest base LOE, production taxes, G&T, G&C and G&A per boe. Our FY20 oil and gas price assumptions, based on the latest EIA estimates, fell by 7% for HH and 37% for WTI; however, EIA forecasts a pick-up in HH pricing for FY21, resulting in a 22% increase versus our previous note. Revenues and FCF for the near term are offset by the hedging portfolio, where c 81% of natural gas production is protected at a floor of $2.69/mmBtu ($2.79/mcf) for 2020 and c 79% at c $2.62/mmBtu ($2.72/mcf) for 2021.

In this note we have also revised down our long-term HH assumption of $3.10/mcf in 2022 to reflect current natural gas prices. We present three scenarios

Given the current commodity price volatility, we will continue to monitor market conditions closely and may revisit these assumptions in due course.

We value DGO using a conventional NAV approach based on the NPV10 of the company’s producing assets minus overheads and net financial liabilities. The NAV table below, Exhibit 8, provides a breakdown of our valuation by asset, using latest data published by the company as well as state public sources.

We break down the assets into DGO Legacy assets (conventional, late-life, low-decline rate), the 2019 acquired assets (early-life assets) and the recent acquisitions of Carbon Energy and EQT assets. DGO pipelines with related compressor stations are also reflected in our discounted value for payments DGO receives for third-party use of services and midstream assets and respective operating costs – currently estimated at an NAV of $49.0m. We also include the hedging impact based on DGO’s latest available information on hedging volumes from 1 June 2020, as well as the impact of the 2020 share buyback programme and the recent equity raise for the Carbon Energy and EQT assets acquisitions.

Exhibit 9 breaks down our valuation by asset class showing where our base case core NAV sits relative to the current share price. Our valuation suggests the market is not fully valuing DGO’s 1P PDP reserves of 684mmboe (562mmboe + 122mmboe from Carbon Energy and EQT assets acquisition reserves) or its third-party revenues from midstream assets and may be overestimating the NPV of decommissioning liabilities.

Key drivers of DGO’s valuation are the gas price and LOE. Our mid-case assumes a long-term (2022) gas price of $2.94/mcf based on a 2020 $2.80/mcf and short-term gas assumptions based on the EIA short-term energy outlook of $2.12/mcf for FY20 and $3.20/mcf for FY21. Our consolidated LOE assumption is $3.09/boe as per DGO’s expectation post-incorporation of Carbon Energy and EQT assets. Our base LOE assumption excludes gathering and transport, SG&A and production taxes. The table below provides a base case valuation sensitivity to these key drivers.

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 P/CF, EV/EBITDA, FCF yield and net debt/EBITDA for FY20e. On a P/CF FY20e multiple, DGO trades at 3.38x, a premium compared to its peers with more than 75% natural gas production in its production mix at 2.36x. We believe this premium is justified by DGO’s cash flow certainty for FY20 and FY21 (FCF yield FY20e 26%) due to its highly hedged portfolio book and its 10.4% dividend yield (at the current share price). On an EV/EBITDA basis for FY20e we observe that DGO trades at 5.47x, in line with a peer average of 5.30x. The combination of these two factors reflect DGO’s lower debt levels versus its peers, with DGO trading at net debt/EBITDA FY20e of 2.31x while peers trade at average of 3.36x. 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. Also, c 80% of DGO production is conventional whereas its peers with more than 75% natural gas in the production mix are mostly unconventional, capital-intensive, shale gas producers. Our DGO forecasts do not include any incremental upside from further M&A, which is a key component of the company’s growth strategy.

In Exhibit 15 we provide a peer group valuation as at 8 June 2020.

DGO’s key drivers of FCF and dividends will be natural gas realisations and LOE. Below we provide our net debt and net debt/EBITDA based on our underlying commodity price assumptions. We forecast a quarterly dividend payment resulting in an annualised 14.0c dividend in 2020, equating to an FY20e yield of 10.4% at the current share price. We also assume FCF is used to reduce net debt and gearing with net debt/EBITDA standing at 2.3x in FY20, following the recently announced acquisitions, (management targets less than 2.5x net debt/adjusted EBITDA leverage ratio) and falling to 2.0x in FY21. We believe DGO will continue to mitigate the impact of low gas prices realisations by continuing with its opportunistic hedging strategy, as it did for 2020.

Although the market has been observing lower HH prices, the redetermination of DGO’s senior secured credit facility in January 2020 reaffirms a $650m borrowing base following the successful $200m securitisation financing in November 2020 and demonstrates the lenders have confidence in DGO’s ability to reduce its debt even at current commodity prices. The current facility has a borrowing base of $425m with a maturity date of July 2023, an interest rate of 2.5% plus the one-month LIBOR and is subject to a grid that fluctuates from 2.0–3.0% plus LIBOR based on utilisation. Borrowings under the company’s senior secured credit facility at 31 December 2019 were approximately $437m. In April 2020 DGO completed its second $200m securitisation financing, with net proceeds being used to pay down the revolving credit facility. These securitisations provide a low cost of debt with investment grade rating (higher than that of the issuing parent company) due to a bankruptcy-remote structure. The covenants are more flexible, being tied only to the assets being securitised and not on a corporate level. For the Carbon Energy and EQT assets acquisitions DGO raised $81.7m net of expenses by placing 64,280,500 new shares at 108p/share, equal to a 1.6% discount to the closing of the company’s shares on 11 May 2020. The company intends to fund the remaining consideration by the issuance of $160m gross through a senior secured 10-year term loan ($155m net of fees and a $3m interest and principal reserve account) with a 6.5% coupon secured by 100% working interest of certain acquired assets, underwritten by Munich Re Reserve Risk Financing, Inc. (MRRF).

DGO has distributed regular and increasing dividends to shareholders since 2017. Management targets shareholder returns of c 40% of FCF. In Exhibit 17 we show that at a 10% discount to our current commodity price assumptions and a constant annual dividend estimate of 14.0c, FY20 and FY21 maintenance capex and cash dividends are covered by cash from operations. We have stress-tested our model for commodity prices and observed that we would have to see an average realised price of $1.38/mcf in 2020 and $2.56/mcf 2021 for cash from operations to just about cover current capex and dividend assumptions. However, as already been mentioned, DGO’s floor hedge price for 2020 is $2.69/mmBtu ($2.79/mcf) and $2.62/mmBtu ($2.72/mcf) for 2021.

Exhibit 19 provides a test to DGO’s dividend sustainability until 2025 under our different modelled scenarios. We observed that under our mid-case scenario, assuming dividend pay-outs remain constant, cash dividends would account for c 40% of generated FCF from 2022, in line with the company’s current dividend policy. In our low-case scenario this would increase to c 50% of FCF from 2022.