Diversified Gas & Oil — Maximising value from enlarged portfolio

2019 was a transformative financial year for DGO, during which it completed four acquisitions for a total consideration of approximately $1bn. These included the entire share capital of Alliance Petroleum Corporation and assets from CNX Resources, EQT Corporation and Core Appalachia. The company became one of the largest conventional gas producers in Appalachia and the largest AIM-listed producer. DGO increased its production from 6.6kboed in FY17 to 41.0kboed in FY18 (+500%), increased company-adjusted EBITDA to $146m, while maintaining a healthy balance sheet with year-end 2018 net debt of $481m down to $451m as of 28 February 2019. We expect gearing to fall materially in FY19 in the absence of further acquisitions – we forecast year-end 2019 net debt/EBITDA of 1.6x.

Exhibit 1 below provides our updated forecasts for FY19 and FY20, which reflect DGO’s FY18 reported results and a small change to our underlying commodity price assumptions. Our 2018 estimates were in line with the FY18 results presented by the company. The biggest difference was observed in reported EBITDA, which includes a gain on acquisitions of $173m. FY18 Edison normalised EBITDA of $145m was in-line with the company-adjusted EBITDA of $146m which excludes one-off items associated with acquisitions in addition to non-cash acquisition gains. Our adjusted EBITDA for FY19 decreases by 1% to $241m and by 3% in FY20 to $219m, with both forecasts excluding potential uplift from M&A.

DGO reaffirmed its intentions to pursue the acquisition of value-accretive, low-risk, long-life, low decline rates to enhance free cash flow per share. Opportunities also exist to enhance EBITDA and margins through ‘self-help’ including the reduction of unit operating costs, optimisation of production operations and by assiduous management of previously overlooked assets. DGO’s net acreage has grown to approximately 7.8m acres. Meanwhile, opportunities exist to continue to consolidate mature conventional production in Appalachia, where we see a growing opportunity set in the areas of mature unconventional gas and coal-bed methane (CBM).

Over the past decade, natural gas production in the Appalachian region has grown faster than pipeline capacity, driving down the regional discount relative to Henry Hub. More recently, an increased pipeline capacity and associated infrastructure has led to the narrowing of differentials and lower price seasonality, benefiting Appalachian producers.

Marcellus gas production has been a catalyst for activity in the midstream sector, with supplementary gas pipeline capacity taking gas molecules to meet demand from LNG exporters on the southern coast. The EIA expects US LNG exports to increase from 1.9bcfd in 2017 to 5.1bcfd by the end of 2019, in addition to 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 discount of c $0.32/mcf.

Overall, the long-term fundamentals for US natural gas pricing and regional differentials remain one of increasing supply and demand. As can be seen in Exhibits 5 and 6 below, natural gas underground storage in both the US east and south central regions is at a five-year low, supporting lower differentials for DGO. Also, since the acquisition of the midstream assets, DGO gained optionality that allows the company to redirect gas to more favourable markets, avoiding regional capacity constraints and achieving higher realised prices, as can be seen in the shift in volumes in Exhibit 4. DGO also has approximately 75% of its production hedged for the next three years and is largely protected from short-term gas price volatility. However, DGO received relief from banks to allow management the discretion to decrease the hedged volumes so DGO can be more flexible and opportunistic. DGO may choose to hedge as liquidity improves in order to receive better pricing given current backwardation in the forward strip.

Our oil and gas base case price assumptions are provided in the table below and include our assumed average realised gas price differential relative to Henry Hub. In our base case, we assume WTI in line with EIA forecasts for 2019 and 2020 at $56.13/bbl and $58.00/bbl respectively, rising to $70.00/bbl long term (2022). For Henry Hub we assume a gas price of $2.95/mcf in 2019, $2.91/mcf in 2020 and $3.10/mcf long term (2022). Prices are inflated by 2.5% from 2022.

Since our last note in January 2019, DGO has completed two important agreements on abandonment with the states of Kentucky and Pennsylvania. It now has plugging and abandonment agreements in place in the primary states in which the company operates. Key terms reached with the state of Kentucky, where DGO operates approximately 7,500 wells, include plugging 25 non-producing wells in 2019 and a minimum of 20 non-productive wells per annum from 2020 until 2023. During the same 2020–2023 period, the company will plug or return to production at least 50 wells per annum, of which up to 30 wells per annum can be previously non-productive wells that DGO places back into production. DGO will post a $1.5m bond to the benefit of the state of Kentucky, which the state will release following DGO’s fulfilment of its obligations under the five-year agreement.

In Pennsylvania, DGO operates c 23,000 wells, corresponding to approximately 40% of all DGO’s wells. Reaching a 15-year agreement (extendable to 20 years) with the state authorities is a significant milestone, which brings clarity and assurance to DGO’s asset retirement obligations and commitments for the short and medium term. Key terms reached with the state of Pennsylvania include plugging a minimum of 20 wells per annum and either returning to production or plugging an additional 30 wells, representing a total of 50 wells per annum for the next 15 years. DGO will also assess all of its wells by 2024 and provide an initial report in 2021 followed by a final assessment in 2024, listing the wells it intends to return to production and those it intends to plug. Similar to the state of Kentucky, DGO will post a $7m bond to the benefit of the state of Pennsylvania, which the state will release following DGO's fulfilment of its obligations under the agreement.

In Exhibits 8 and 9 below, it is possible to see the difference between Edison, DGO and third-party decommissioning assumptions and the impact on NPV. Our P&A schedule and cost assumptions remain the same as in our last valuation. We assume 125 wells are retired per year until 2035 and 1,000 per annum thereafter, broadly in line with the agreements reached between the company and state regulators. At an initial P&A cost of $24,000 per well, inflated 2.5% per year, this results in a 30-year NPV10 of $99m. DGO recently updated internal P&A assumptions, which assume the retirement of 105 wells per year in the first five years, followed by 140 wells per year until year 15, and 1,100 wells annually onwards. Taking into consideration DGO’s P&A average cost per well, per state and the number of wells it operates in each state, we estimate a weighted average P&A cost of $24,240 per well. If we were to use DGO’s abandonment schedule and a $24,240 P&A cost, inflated at 2.2% per annum, this would result in an NPV10 of $102m. This NPV is unlikely to correspond exactly with DGO’s internal estimated liability as there are likely to be differing assumptions on the timing of abandonment of high-cost/deep well locations. Third-party valuation is based on an external valuation conducted in September 2018 before the Core Appalachia acquisition and before the recently announced agreements with state authorities.

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 10, using data available in the company’s last published prospectus and CPR, as well as public sources. We include the abandonment schedule, mentioned earlier in this note, of 125 wells per year until 2035, and 1,000 wells per year thereafter across the portfolio, and abandonment costs of $24,000 per well in line with estimates provided by the company and US onshore industry averages.

We do not include any 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. 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. The value of M&A upside potential or risked infill drilling NPV is uncertain but likely more than zero.

We also include a discounted value for payments DGO receives for third-party use of services and midstream assets in our valuation – currently estimated at c $26m pa or $215m in our NAV. We note that DGO has over 10,500 miles of pipeline and more than 50 compressor stations, which give it access to processing facilities and higher liquids volumes, resulting in higher realised prices and unit costs improvement.

Exhibit 11 breaks down our valuation by asset class showing where our base case core NAV sits relative to the current share price. The waterfall below suggests that the market is not fully valuing DGO’s 1P PDP reserves (474m boe), nor its third-party revenues from midstream assets, and may be overpricing the NPV of decommissioning liabilities.

Key drivers of DGO’s valuation are 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 $5.06/boe (LOE excludes gathering and transport, SG&A and production taxes), both inflated by 2.5% thereafter.

Our oil and gas base case price assumptions are in line with the EIA’s latest forecasts for 2019 at $56.13/bbl, rising to $70.00/bbl long term (2022). For Henry Hub, we assume a gas price of $2.95/mcf in 2019 and $3.10/mcf long term (2022).

As mentioned above, DGO’s key drivers of FCF and dividends will be gas realisations and LOE, since under the company’s current mode of operation maintenance and drilling capex spend is minimal.

Below we provide our net debt, net debt/EBITDA and FCF forecasts based on our underlying commodity price assumptions. We forecast a quarterly dividend payment of 13.6c/share in 2019, equating to a yield of 8.8% at the current share price. We also assume FCF is used to reduce net debt and gearing with net debt/EBITDA falling from 1.6x in FY19 to 1.3x by FY20e (management target a 2-2.5x net debt/adjusted EBITDA leverage ratio) in the absence of further acquisitions. In November 2018, DGO closed on a $1.5bn five-year senior secured credit facility, with an initial borrowing base of $725m priced at Libor plus 2.75–3.25% depending on utilisation. Undrawn debt capacity provides visibility on debt funding for future acquisitions.