Diversified Gas & Oil — Post-acquisition valuation update

On 27 March 2019, DGO announced the acquisition of 107 gross producing unconventional gas wells in Appalachia with combined 2018 net production of approximately 21kboed and PDP reserves of 92mmboe for a total purchase price of $400m, from HG Energy. The acquired assets are located in Pennsylvania (56 wells) and West Virginia (51 wells), and the consideration is to be funded through a combination of $234m of new equity (151.5m new shares at 117p/share) and a drawdown under DGO’s existing RBL facility. As at 28 February 2019, the amount drawn down by DGO was $455m from a borrowing base of $725m. Edison estimates leverage would remain below a target range of 2.0–2.5x at 1.7x net debt to FY19e adjusted EBITDA, and FY19 net debt to PDP PV10 of 28%. New shares from the equity placing are to be admitted for trading on 18 April 2019.

The acquired asset base of 107 wells includes an inventory with an average well age of five years and average production per well of 196boed (1.2mmscfd). Given the limited number of wells, associated plugging & abandonment (P&A) liability is small at an NPV10 of c $300k. Operating costs are significantly lower than DGO’s existing portfolio and the integration of the assets does not require incremental G&A. Acquired unconventional wells open a new opportunity for DGO within the basin, reinforcing DGO’s positioning not only as a conventional, but also as an unconventional gas player in the region. The acquired assets are located close to existing operations suggesting the potential for operational synergies. Management has not quantified potential synergies, but expects immediate benefits from the consolidation of transportation expense, with fixed cost spread over an increased production base, and elimination of redundant marketing. DGO will also benefit from seller-financed capital projects, which include two recently completed wells and upgraded compression.

Comparing the acquisition of the HG Energy assets to DGO’s historical transactions, it appears to be broadly in line with the previous deals at EV/flowing barrel of $19.0kboed, but at a premium on the basis of EV/1P PDP reserves at $4.4/boe. Based on EV/trailing EBITDA it is priced at a discount to DGO’s previous acquisition of Core Appalachia at 6.4x, but at a slight premium to prior acquisitions made earlier in 2018 and through 2016/17. This is likely to be due to the high productivity of the wells being acquired, which drives relatively low unit opex ($4.49/boe), limited associated decommissioning liability at c $300k NPV10 and favourable differentials averaging $0.38/mmBtu.

Exhibit 3 provides our updated forecasts for FY19, FY20 and introduces our FY21 forecasts. The integration of the HG Energy assets into our model leads to an increase in annualised production of approximately 18% for FY19, which rises to 79.8kboed. The acquired assets produce virtually 100% gas compared to DGO’s existing production mix, which has liquids content, hence the slightly lower realised price per boe compared to prior forecasts. EBITDA and free cash flow (FCF) increase by 25% and 27% reflecting the lower unit operating costs of the consolidated assets and consolidation of central functions included within unit G&A. Acquired asset lease operating expense (base LOE) per boe is $0.50 and $1.01 (before production taxes and gathering and transport, G&T) for the Pennsylvania and West Virginia assets, respectively; this is below DGO’s pre-acquisition asset LOE of $4.17/boe. Our forecasts exclude the potential uplift from further M&A opportunities. We have also updated our short-term commodities assumption based on an EIA gas price forecast of $2.92/mcf in 2019 and $2.88/mcf in 2020, representing a 1% decrease in relation to our previous valuation.

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 4, using data available in the company’s last published prospectus and Competent Person’s Report (CPR), as well as public sources, with net PDP reserves for DGO’s pre-acquisition assets updated to 474mmboe as per the 2018 annual report. In this valuation, we show a breakdown between DGO pre-acquisition assets and the newly acquired assets. 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 do not include any incremental value for M&A potential or infill drilling in excess to the latest acquisition. However, it is important to recognise that management has created material value for shareholders through the acquisition of assets at attractive valuations and is constantly evaluating possible inorganic growth opportunities in Appalachia that can enhance FCF per share. The value of M&A upside potential or risked infill drilling NPV is uncertain but likely more than zero.

Exhibit 5 breaks down our valuation by asset class showing where our base case core NAV sits relative to the current share price. The waterfall suggests that the market is not fully valuing DGO’s 1P PDP reserves (566mmboe = 474mmboe DGO pre-acquisition + 92mmboe HG Energy), nor its third-party revenues from midstream assets, and may be overpricing the NPV of decommissioning liabilities.

Key drivers of DGO’s valuation are the gas price and LOE and these do not change after the acquisition. 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).

Our oil and gas base case price assumptions are in line with the EIA’s latest forecasts for 2019 at $58.80/bbl, rising to $70.00/bbl long term (2022). For Henry Hub, we assume a gas price of $2.92/mcf in 2019 and $3.10/mcf long term (2022).

As mentioned earlier in this note, DGO will fund the $400m consideration for HG Energy assets with the combination of net proceeds from its $234m placing ($225m net of fees) and a draw under its $1.5bn KeyBank credit facility. Subject to approval at the 17 April general meeting, the shares will be admitted to AIM on 18 April. The new shares represent around 21.8% of the enlarged share capital.

As at 28 February 2019, the amount drawn down by the company was $455m, as per the HG Energy assets acquisition presentation, from a borrowing base of $725m and DGO expects to draw $159m from the revolving credit facility to fund the acquisition. DGO anticipates a downward purchase price adjustment associated with the operating cash flow between effective date and close, estimated at $16m, which would lead to a total purchase cash consideration of $384m after adjustments.

On conclusion of the acquisition, the amount drawn from the borrowing base is expected to total $614m, leaving c $111m of debt capacity available at close. However, management expects the transaction to provide c $200m of incremental borrowing base capacity, resulting in post-acquisition liquidity of more than $300m, which will provide liquidity for further bolt-on acquisitions.

DGO’s existing $1.5bn KeyBank senior secured facility has an interest rate of Libor +2.25/3.25% based upon utilisation, and has a borrowing base determined by the value of DGO’s PDP reserves.

We expect the transaction to be accretive to FCF/share for FY20 (+8%) with the potential to support an increased dividend payout – management indicates the potential for a post-acquisition annualised payment of 16.0c/share. Assuming management increases the quarterly dividend to 4.00c/share, we forecast an FY19 dividend yield of 9.5% at the current share price.

Below we take a look at the short-term sustainability of DGO’s dividend. Our current forecasts suggest ample FCF to pay a 16.0c/share dividend, fund sustaining capex and reduce leverage at realised gas prices well below strip. Hedging of up to 75% of FY19 gas production and over 50% in FY20 also provides strong visibility of short-term cash generation. Longer-term sustainability of the dividend will be driven by DGO’s ability to manage fixed unit LOE as production declines, in addition to prevailing US gas prices and regional price differentials. Unconventional wells have the benefit of greater production per well location in comparison to DGO’s legacy conventional assets; therefore we see potential for DGO to reduce unit LOE in the short term as it pursues further unconventional acquisitions. Based on current Edison expectations for realised gas prices and unit costs, we believe DGO is able to sustain a 16.0c/share dividend as well as cover sustaining capex through to the middle of the next decade.