Green Dragon Gas — Update 20 February 2017

GDG remains a differentiated E&P given its relative insensitivity to the oil price. Development and production costs remain low relative to peers (c $1.3m per completed LiFaBriC well; opex costs <$1/mcf life of field) and margins are high on a unit basis. Ten years of audited reserves growth help demonstrate resource quality and depth, partly de-risked by production and sales from GSS and GCZ. GDG also benefits from continued government support through energy policy subsidies. This includes the specific mention of CBM and GDG’s key assets, GSS and GCZ, in the Chinese government’s five-year plan. The plan states the intention to increase the natural gas share of the country’s energy mix from 6% to 13% by the end of the decade and to obtain 85% of energy from domestic sources. Inclusion of GSS and GCZ in the government’s five-year plan has the potential to open up access to domestic debt markets as state-owned banks provide liquidity to support the plan.

GDG’s last published reserves assessment report (RAR) remains on the basis of rapid exploitation of the company’s reserve base delivering a 1P net valuation of NPV10 $1,227m (based on a well-head gas price prior to subsidy of $10.37/mcf in 2016 increasing to $12.6/mcf by 2020). To realise this value, GDG needs to step up the pace of development drilling, infrastructure build-out and ultimately gas sales.

In the immediate term, we expect gas sales to benefit from the introduction of wellhead screw compression across existing LiFaBriC well stock. We believe this to be a prudent use of GDG’s funds given current capital constraints – maximising gas sales from existing well stock and closing the gap between production capacity and actual sales. Over the medium term, we believe gas sales growth will be driven by GDG’s ability to drill-out its wider reserve base and in this note we run sensitivities around the pace of LiFaBriC drilling.

Our GDG valuation explores three cases, which assume a range of funding and drilling assumptions:

In our analysis, we present group cash flow and EBITDA profiles consistent with each scenario. However, it is important to note that, in line with GDG’s accounting policy, we assume revenues will be booked on a working interest basis rather than an entitlement basis (on completion of the ongoing audit of CNOOC-operated areas of blocks GSS and GSN). Due to a material proportion of existing production coming from legacy CNOOC wells, this is not fully reflected in GDG’s cash flow from operations post-CNOOC cost recovery, hence cash conversion1 is expected to remain low until CNOOC recovers legacy costs. The timing of CNOOC cost recovery varies from case to case, but is an important consideration for investors valuing GDG on the basis of free cash flow or NAV.

In this case, we assume GDG does not drill any new wells across its asset portfolio but addresses production optimisation opportunities. These include wellhead compression and connecting existing well-stock to gas pipeline infrastructure. As of December 2016, only 568 wells of a total of 2,037 wells were connected to infrastructure and selling gas. Under this scenario we forecast that net gas sales rise over the medium term, generating material net free cash flow; however, only 28% of the GSS 2P reserve base is monetised. In this case, we estimate that GDG will require $15-20m of additional funding in the short term to fund small capital items such as compression, together with G&A and debt commitments. Under this scenario, we see gross GSS sales gas exceeding 11bcf, generating material revenues and EBITDA net to GDG. Cash generation and cash conversion are low due to a large percentage of production generated by CNOOC legacy wells and related cost recovery. We expect CNOOC cost recovery in 2026 based on our forecasts. As can be seen in Exhibit 2 below, we see a drop in cash conversion in 2022 after GDG fully recovers its cost pool, and then a step up in 2026 once CNOOC has recovered legacy costs.

Our valuation in the minimal capex case for the GSS asset is $136m, assuming a well-head gas price (including subsidy) of $7.5/mcf in 2017 rising to $10.5/mcf by the end of the decade. This asset valuation helps underpin current net debt and G&A; however, for equity holders to realise material value from GDG’s CBM resource base, we believe a material investment in new GDG LiFaBriC wells is needed. This would ensure maximum 2P reserve recovery prior to the 2035 PSC expiry.

In our base case valuation, we assume GDG receives GSS ODP approval in 2017, opening up access to the RBL debt market. We assume attained RBL debt capacity is in addition to the company’s existing $50m convert (due 2020) and $88m corporate bond due November 2017 – for which we assume a maturity extension.

We feel that it is reasonable to assume that GDG will be able to access the RBL debt market for the producing GSS asset and its 47% interest in GCZ – the availability of RBL for Chinese CBM has been demonstrated by AAG Energy receiving a $250m RBL loan for development funding from a consortium of banks including HSBC, Bank of Communications, Standard Chartered Bank, Société Générale and Crédit Agricole in 2015. We see uncertainty around the exact timing of GSS ODP approval but note that there is precedent of Sino-foreign cooperative CBM projects being approved in China; the first such project was AGG’s Panzhuang CBM concession, which was approved for development in 2011, with AAG Energy and CUCBM each holding a 50% stake.

In order to calculate the RBL debt capacity of GDG’s GSS block, we make a number of assumptions in order to determine the borrowing base. Key assumptions are:

After imposing a maximum drilling rate cap of 100 LiFaBriC wells per year in our analysis, our RBL funded drilling schedule for GSS is as outlined in Exhibit 4. Under this scenario, GDG recovers 100% of its GSS gross 2P reserve base of 788bcf. Our analysis suggests that GDG may require a capital injection in early 2017 in order to fund G&A and a limited LiFaBriC well programme ahead of ODP approval and RBL debt access.

In our base case, we see gross GSS sales rising to 60bcf by 2024, with material cash flow (post cost recovery) net to GDG. Cash conversion rises rapidly from 2023, as GDG benefits from a larger LiFaBriC well-stock from which it receives its full 60% of net cash flow and CNOOC fully recovers legacy costs.

Net cash flow increases rapidly (cash conversion moves towards 75%) once CNOOC has fully recovered its cost balance; we currently forecast that this will occur in 2023 in our base case.

Key assumptions that we make in our base valuation are as below:

As can be seen in the table above, our base case NPV12.5 valuation is 227p/share (net of liabilities). Our 12.5% cost of capital is based on the assumption that GDG utilises a combination of high-yield debt (current coupon 10% on convertible), RBL debt, equity and farm-out. We believe a 12.5% cost of capital is a reasonable assumption for through-cycle cost of capital, but we provide a sensitivity to discount rate in our valuation tables. GDG may be able to access lower-cost domestic debt now that GSS and GCZ are included in the government’s five-year plan and we intend to revise our cost of capital assumptions once GDG has secured additional funds.

Our valuation (net of liabilities) is highly levered to GDG’s ability to fund the drill-out of its reserve base. In our final scenario, we look at the sensitivity of core value (2P net of liabilities) to drilling intensity. Unsurprisingly, we see the greatest GDG group valuation when GSS gas recovery is maximised prior to 2035 licence expiry. We believe that GDG needs to drill 60-80 wells per year to maximise resource recovery in the 2P case, while close to 330 wells would need to be drilled per year to fully exploit GSS 3P reserves. At a cost of $1.3m per LiFaBriC well, this would amount to a gross cost of $78m to $104m per annum in the 2P case. Including risked recovery of 3P CBM reserves (higher well-density) this could rise to in excess of 435p/share RENAV. Finally, if we were to include an intensive drilling programme on GCZ and GSN, this has potential to rise to in excess of 591p/share RENAV.

GDG’s ability to fund accelerated drilling activity will be key in maximising resource recovery and shareholder value. As shown in Exhibit 12, if drilling rates enable full recovery of GSS 2P reserves, valuation increases dramatically.

Potential sources of funding include equity, corporate debt, RBL debt (post ODP approval), industry farm-ins and asset sales. In our base case, we assume that GDG accesses the RBL debt market post GSS ODP approval in 2017. Additional injections of capital, over and above our base case, have the potential to significantly increase this pace of drilling being NAV accretive.

As well as exploitation of GDG’s reserve base, we see potential for the company to create incremental value for shareholders through the farm-down or sale of acreage that remains in the early stages of exploration/monetisation (blocks GFC, GQY, GPX, GGZ). We conservatively do not include these assets in our valuation at this point in time and crystallisation of value for these assets would be incremental to our RENAV. The timing of a farm-down or asset sale is of the essence as GDG looks to explore, appraise and monetise this resource base prior to 2035 licence expiry.

In addition to updating our operational inputs, in this note, we also consider the impact of lower oil prices on GDG’s long-term revenue potential. GDG’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 (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 GDG’s realised gas prices to move towards LNG price parity over time (2020 vs previous assumption of 2023) and at a lower absolute gas price than was previously assumed. Our latest model now assumes that current realisations ($7.5/mcf as a blended average of CNG and PNG prices) will remain until 2018, beyond which it will track towards Chinese LNG import price parity. The IEA expects 2021 Chinese gas demand of 320bcm; and 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 these are not included in our base case price assumptions.

In 2016, for the 10th year running GDG reported an increase in 1P and 2P reserves across its blocks as it continued to migrate reserves and resources from the 3P and prospective categories into 1P/2P (Exhibit 18). This is largely a function of GDG drilling additional wells across GSS, increasing the acreage across which CBM reserves can be allocated. With an ongoing focus on infrastructure development across GSS and GSN, including installation of an additional c 30bcf pa of gas processing over the next one to two years at GSS, we would expect these reserves to continue to increase, even with relatively modest drilling programmes.

While the reserves increase is indeed impressive, GDG is aware that the real challenge for the company is recovering the maximum quantity of gas within the defined 20-year production licence it has for each of its blocks following ODP approval. The company currently has 84% of its reserves booked against only 5% of its land position.

The most significant exploration and appraisal activity in recent months has been the successful drilling of GDG’s first LiFaBriC well into Coal Seam 15. This was an important well as GDG had to demonstrate it could drill into the deeper coal seam, while not intersecting the adjacent water-bearing limestone and drawing in water. In its results presentation, GDG reported CS15 as containing 1.2tcf of gas in place (GIP), hence the potential impact on 1P and 2P reserves is significant, although it remains too early to understand how quickly the recoverable gas within CS15 can be commercially exploited. Coal seam 15 will be produced through existing GSS/GCZ surface infrastructure, hence reducing full-cycle development costs. GDG believes that it may even be able to use/extend existing well bores in order to minimise associated drilling costs.

Beyond CS15, GDG has presented its work programme for the remaining exploration blocks, namely GGZ, GQY, GFC and GPX. The most advanced of these is GGZ where the company drilled eight vertical exploration wells in 2015, producing from six of these to test commerciality. GDG is seeking to move to reserves evaluation and development plan preparation in 2017 at GGZ.

Our short-term forecasts change materially from our last published outlook note (January 2016) due to several modelling assumptions, including: realised gas prices, LiFaBriC type curves, financing assumptions and timing of ODP approval. Our core base case NAV falls from 328p/share to 227p/share as a result. We note that 80p/share of the change is driven by our lower gas price assumptions.

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 base case forecasts are predicated on GDG achieving GSS/GCZ ODP approval in 2017 and getting access to an RBL borrowing base as discussed previously in this note. Without additional funding, our short-term forecasts are likely to be significantly below our base case forecasts and we flag this as a key investment risk.