G3 Exploration — Accelerated monetisation of production assets

In our view, the most important catalyst for G3 Exploration in 2018 is the company’s restructuring and Hong Kong listing. Management has put forward an indicative timetable as outlined below.

Management intends to list the company’s main producing assets (GSS and GCZ) on the Hong Kong stock exchange, creating a new company, YieldCo. It is intended that new YieldCo shareholders would introduce fresh capital into the company to fund growth while free cash flow would be distributed to all YieldCo shareholders. Management expects this liquidity event to enable the redemption of G3 Exploration’s Nordic and GIC bonds ($138m in total). This in turn would enable G3E Exploration to use the remaining capital to appraise the six blocks in line with work commitments under existing licence agreements (outlined later in this note).

Management expects first gas from the GGZ block and plans to file an overall development plan (ODP) for GGZ block in 2019. Activity will also include exploration at GFC and GPX before non-prospective acreage is relinquished. Key work commitments are as outlined below:

GFC Block – Greka BV (G3E) is operator with a 49% participating interest.

GQY Block Area A – operated by CUCBM with Greka GQY BV participating in a 10% interest.

GQY Block Area B – Greka GQY BV is operator with a 60% participating interest, CUCBM has 40%.

Phase I: extended to 8 September 2018 and involves the drilling of five vertical wells, four pairs of horizontal wells and production from 10 wells. Total gross cost is estimated at $9.12m.

Phase two: extends to 14 April 2019 and involves the drilling of three wells, one pair of horizontal wells and the filing of a reserve report for certification from 15 wells. Total gross expenditure is estimated at $2.54m.

GPX Block – Greka GPX BV is operator with a 60% interest.

Given the above, we estimate a total net G3 Exploration planned capital budget of $35.4m.

For G3 Exploration to redeem outstanding debt and fund this work programme and G&A in 2018 we estimate that $173m will need to be returned to G3 Exploration from the Hong Kong listing of YieldCo. Management expect the company to place c.$200m of new debt against the GDG asset base, and release $175m to G3E to satisfy this $173m spend.

GCZ ODP approval

On October 3rd 2018, NDRC approved the ODP for the GCZ block in which G3E currently has a 47% participating interest. The ODP area has 294bcf of gas in place with estimates of recoverable gas of 176bcf. 114 wells have been drilled on the acreage of which 85 wells are selling gas. The ODP includes the drilling of an additional 147 production wells, with gross production capacity of 6.35bcf/year and development costs are estimated a c.US$55m over the next two years from 4Q18. As of December 2017, NSAI estimated a future NPV10 of US$72m in 1P and US$154m in 2P.

Chinese CBM asset transactions

In May 2018, Sino Gas & Energy Holdings agreed to a A$530m cash takeover offer from US private equity firm Lone Star. Sino Gas net 1P reserves at 31 December 2017 were 384bcf and 2P reserves 578bcf and 2C resources of 899bcf. This equates to an EV/2P value of US$0.73/bcf and EV/(2P+2C) of US$0.28/bcf.

In April 2018, Liming holding limited made an offer to acquire part of the shares of AAG Energy at a market value of c US$752m (EV c US$833m). Based on AAG Energy’s net December 2017 2P reserves this equates to US$1.35$/bcf EV/2P (we do not have 2C resource figures for AAG).

It is currently difficult to estimate the capital available in the YieldCo (new equity and debt) to fund drilling activity and for distribution, but visibility should increase once management have listed GDG in 2019. This remains the case as per our last published detailed valuation in 2017. We will look to update our valuation after G3 Exploration has published an IPO prospectus and timetable. We note that the NSAI valuation (31 December 2017) of GSS 2P gas reserves stands at $1.385bn and GCZ $155m. We do not believe that this incorporates the impact of capital constraints and the relative high cost of equity capital in the current market for small-cap E&P.

In the absence of further information on which to value G3 Exploration, we refer investors to our last published valuation range as per below. In our last published note, we produced three valuation scenarios. Case 1 based on the company having capital constraints and minimal capex spend, a mid-case assuming RBL debt capacity for GSS and GCZ and a blue-sky high case, assuming no capital constraints and early monetisation of the company’s resource base.

A full breakdown of our NAVs and underlying assumption is provided in the last detailed valuation note referred to above.

Future financial forecasts are highly dependent on G3 Exploration’s equity stake in the intended Hong Kong YieldCo and funding available for exploration and appraisal activity across both companies.

We see significant uncertainty in our short-term forecasts, which are to a large extent driven by the pace and success of well optimisation and drilling activity. Our previously published base case forecasts are predicated on G3 Exploration achieving GSS/GCZ ODP (project code approved in 2017), gaining access to an RBL borrowing base, or alternative sources of capital. We do not believe it is prudent to provide new financial forecasts until the structure of the company’s Hong Kong listing is clear.

G3 Exploration’s gas price is largely driven by domestic policy; however, we expect that in the medium term, domestic regulated pricing will trend towards LNG import price parity. A reduction in the National Development Reform Commission’s (NDRC) wholesale price of natural gas in November 2015 of c $3.1/mcf was prompted by a fall in oil and LPG prices and was intended to increase the price competitiveness of natural gas relative to other fuel sources. This was offset by China increasing the cash subsidy for CBM producers from $0.87/mcf to $1.31/mcf. Despite subsidy support, we expect G3 Exploration’s realised gas prices to move towards LNG price parity over time. Our latest model now assumes that current realisations ($7.5/mcf as a blended average of CNG and PNG prices) will remain in 2018, beyond which it will track towards Chinese LNG import price parity. The IEA expects 2021 Chinese gas demand of 320bcm; import dependency rising from c 30% today to over 40% by the end of the decade. The supply gap will be filled by increasing LNG and piped imports as well as higher-cost sources of domestic supply such as shale. Based on Brent crude of $72.6/bbl by 2020, IHS estimates an LNG delivered cost (including transport) of just under 10$/mcf. Our modelled gas price assumptions rise from $7.5/mcf, including subsidies, in 2016 to $10.5/mcf by 2020. We note that additional CBM subsidies are possible over this time frame, but are these not included in our base case price assumptions.