Time to monetise strong CBM resource position

Green Dragon Gas 6 January 2016 Outlook

Green Dragon Gas

Time to monetise strong CBM resource position

Company update

Oil & gas

 

6 January 2016

Price

225.0p

Market cap

£351m

US$1.45/£

Net debt ($m) at 30 June 2015

84.3

Shares in issue

156.1m

Free float

20.4%

Code

GDG

Primary exchange

LSE

Secondary exchange

N/A

Share price performance

%

1m

3m

12m

Abs

(11.8)

(9.6)

(41.9)

Rel (local)

(10.5)

(7.9)

(40.7)

52-week high/low

412.6p

220.2p

Business description

Green Dragon Gas is one of the largest independent companies involved in the production and sale of CBM gas in China.

Next events

CS #15 evaluation

Early 2016

GSS gas processing stations complete and commissioned

End 2016

ODP approval (GCZ, GSS)

2016

RBL funding

End 2016

Analysts

Ian McLelland

+44 (0)20 3077 5756

Will Forbes

+44 (0)20 3077 5749

Green Dragon Gas is a research client of Edison Investment Research Limited

Green Dragon Gas (GDG) is tantalisingly close to realising a step change in production that would move it from a resource play to an established producer. Against a robust macro backdrop largely insulated from oil market volatility, we expect GDG to move profits into the black in 2016 as production increases beyond the 12bcf pa 2015 exit rate. Ongoing buildout of 53bcf pa of gas processing capacity at GSS should remove any capacity constraints in 2016/17. The coming months are also critical for the extensive 3P reserve base, with completion of the ongoing evaluation of Coal Seam #15. If successful, this could start to move 3P reserves into 1P/2P and lead to a development decision that would transform our RENAV from the current 679p/share. GDG is funded through end 2015; however, we estimate more than $100m will be required in 2016, climbing to $300-450m over 2017-19 to facilitate the company’s next push in production.

Year end

Revenue ($m)

EBITDA ($m)

PBT* ($m)

Debt ($m)

Net cash/ (debt)**($m)

Capex ($m)

12/13

62.2

4.5

(21.5)

(63.8)

(29.1)

(70.6)

12/14

33.8

11.4

(6.2)

(132.3)

(52.3)

(53.5)

12/15e

41.9

15.2

(0.2)

(133.7)

(106.9)

(52.7)

12/16e

85.0

42.7

23.1

(240.5)

(240.5)

(122.5)

Note: *PBT is normalised, excluding intangible amortisation, exceptional items and share-based payments; **Includes assumed RBL or equivalent funding.

Reserves and production uptick expected

We expect to see an uptick in 1P/2P reserves at end 2015 as more wells/reserves access infrastructure capacity. We expect GSS capacity to increase to c 23mcf pa by end 2015 as GDG’s partner, CUCBM, deploys $200m that will ultimately increase capacity to 53bcf pa. The end-2015 status should now remove any capacity constraints over 2016/17 as GDG increases production of current 2P reserves from a 2015 exit rate of 12bcf pa gross to c 40bcf pa gross over the next five years.

CS #15 evaluation critical to 3P commerciality

Less than 15% of GDG’s reserves are in the 2P category, with the majority of possible reserves likely to be in the deeper Coal Seam #15 (CS #15). GDG is drilling 11 wells during 2015 to evaluate the development potential of CS #15, which may result in more than a doubling of 2P reserves. This evaluation should complete around end year, and if successful we can start to expect to see migration of 3P reserves into 2P in early 2016 ahead of a development decision for CS #15.

Valuation: Large NAV upside, expect profit early 2016

Our DCF-based valuation continues to point to considerable upside at both the core NAV (£3.28/share) and RENAV (£6.79/share) level. We also anticipate GDG moving into profit in early 2016 and increasing EBITDA to c $80m by 2017, making the company highly attractive on a valuation multiple basis, as well as a resource (ie NAV) basis. We estimate GDG will require $110m of additional debt funding during 2016, but this will climb to c $300-450m over 2017-19 to maintain the growth trajectory in production and profits.

Investment summary
Company description: China CBM production play

GDG is uniquely focused on the exploitation of CBM resources in China. 427bcf of 2P reserves, and importantly 2.29tcf of 3P reserves, give it massive potential to drive production from current c 12bcf pa to firstly c 40bcf pa (from current 2P reserves) and on to 200bcf pa (with 3P upside).

$200m of third-party infrastructure (at no cost to GDG) will give it capacity to increase GSS production over the next four years to approaching 40bcf pa gross. GDG is also focused on optimising the pressure balancing of its producing well inventory to increase production that can reach external sales and reduce the need for external purchases for resale.

Beyond this, GDG needs to exploit 3P reserves to grow production that will, in part, require successful evaluation of the deeper Coal Seam #15. Results of this ongoing evaluation should be available on the conclusion of the 2015 reserves reporting cycle in early 2016.

Valuation: Robust NAV, multiples relevant from 2017

Based on developing reserves from only two of GDG’s PSCs (GSS, including GCZ, and GSN) we estimate a core NAV of £3.28 and RENAV of £6.79. This RENAV could grow at 30% CAGR assuming successful evaluation of CS #15 and development of the 3P reserves from these blocks.

This clearly offers resource investors large upside to the current share price. However, equally importantly, we expect GDG to be able to move EBIDTA up to approaching $80m in 2017, which will make it attractive to a wider group of investors, and allow attractive valuations to be derived from a valuation multiple basis.

We consider our valuation to be robust to external factors; despite a slowing of Chinese GDP growth we believe underlying fundamentals remain sound for Chinese gas prices, while short-term development delays would have only a modest impact on valuation.

Financials: Moving to PAT profit in early 2016

We expect GDG to turn a post-tax profit from early 2016, and with debt funding, EBITDA to grow towards $80m in 2017. We also expect a steady increase in the ratio of gas recovered from producing wells and converting to sales (GDG is looking to move this from a historical average of c 35% to 50%+ by end 2015) that will increase margins. Medium-term funding requirements will be substantial, with c $110m of additional funds required in 2016, increasing to c $300-450m over 2017-19 to replace existing bonds and convertible debt (both maturing in 2017). GDG will be seeking this funding via RBL and we expect discussions to be ongoing.

Sensitivities: Things to consider

Sub-surface risk: More than half our RENAV is based on 3P reserves that are contingent (largely) on successful evaluation of the CS #15 development potential. We can expect to see early results of this evaluation in the end-2015 reserves update (around February 2016).

Finance risk: Long-term exploitation of GDG’s reserves will need access to asset-backed debt; however, GDG could scale back activities in 2016 if near-term debt capacity is reduced. Under this scenario, we estimate EBITDA of c $70m in 2017 (vs our base case of c $80m with debt available in 2016). Impact on NAV would be negligible.

Chinese demand risk: 2015 has seen a slowing in Chinese GDP growth. However, this is likely to have little impact on domestic gas demand and China remains committed to growing gas in the energy mix. Chinese gas prices remain unaffected by the drop in global crude prices.

Company description: Time to monetise

Green Dragon Gas (GDG) is a coal bed methane (CBM) -focused production, development and exploration company with assets in China. In total it has eight blocks over six PSCs; its GCZ block is in the greater Shizhuang South (GSS) PSC where GDG has a 60% interest (and an option to increase this to 70%). At GCZ (GDG 47% WI) GDG partners with Petrochina (a subsidiary of CNPC), while at all its other blocks it partners with CNOOC. GDG entered into the majority of its PSCs in 2003 with 30-year terms. However, due to challenges to title in 2012/13, which have since been fully resolved, the PSCs were extended by a further two years, ie until 2035.

Exhibit 1: GDG PSCs in China

Source: Green Dragon Gas

Reserves evolution: 1P/2P increases anticipated in 2015

At the end of 2014, GDG had 148bcf of net 1P reserves (all at GSS) and 427bcf of net 2P reserves (across GSS and GFC). However, the majority of the anticipated recoverable reserves remain in the 3P category, with 2.29tcf of 3P reserves booked at end 2014, most of these at GSS and in the GSN block immediately to the north.

These reserves are designated recoverable from a total original gas in place estimate of 25.2tcf across all blocks. It is worth noting that GDG has now used the same reserves auditor (Netherland, Sewell & Associates – NSAI) for more than 10 years and the latest reserves estimates represent the ninth consecutive upgrade in 1P reserve volumes and valuations since NSAI started to audit GDG’s assets.

Exhibit 2: GSS historical reserves migration

Source: Green Dragon Gas

While the 1P reserves growth has been impressive (33% CAGR 2008-14), growth has been consciously limited by GDG’s deliberate (and sensible) focus on monetisation rather than indiscriminately proving up the resource base. Exhibit 2 shows the evolution of what is effectively a corridor of activity at the company’s GSS block, as wells in a relatively tight pattern have been drilled close to available and to be commissioned infrastructure. However, with additional infrastructure being put into GSS as part of resolution of the PSC agreement with CUCBM in 2013/14 (see our November 2014 note for details), we expect the company’s 2015 wells to be more spread out and, by including previous exploration wells that can now access the increased infrastructure, there to be a distinct increase in 1P and 2P reserves. This will be confirmed in NSAI’s annual reserves report that, based on previous year timings, should be published in February 2016.

Monetisation focus in 2015; set to accelerate in 2016

GDG is looking to accelerate the roll-out of its production at GSS during 2015 and in particular, 2016. The company has historically sought 18bcf pa of gross production, and based on a nominal 250mmcf/d (approximately the average deliverability of LiFaBriC wells drilled to date) this would have been achieved from c 200 of its proprietary LiFaBriC wells. GDG had already drilled 66 LiFaBriC wells across GSS through to end 2014, hence it was nominally looking at an additional c 135 LiFaBriC wells to reach its short-term production target. However, the reality is that having agreed to work together and make use of the third-party wells drilled by CUCBM/CNOOC on the GSS and GCZ blocks, GDG and its partners are now looking to much more rapidly develop GSS. This development will involve the exploitation of 1,977 wells drilled across its blocks, the majority drilled by partners (Exhibit 3).

Exhibit 3: Well portfolio across GDG’s blocks

Source: Green Dragon Gas

In fact, GDG’s LiFaBriC wells only constitute 3% of the total well count available to GDG across its blocks. While we expect these wells to be more productive than the non-LiFaBriC wells, there is clearly scope for GDG and partners to exploit a unique well position to their advantage. CUCBM will largely benefit from the third-party wells due to accelerated cost recovery, although this also benefits GDG with CUCBM being incentivised to accelerate development of infrastructure across the block.

To accelerate the GSS development, GDG and its partners plan to increase gross gas processing capacity to 53bcf pa over 2015 to 2017. This will extend the corridor of production from the existing c 10bcf pa of capacity in the south and south-western corner of the block up to the north east and allow GDG to access the remainder of the 2P reserves (ie 400bcf net).

Exhibit 4: GSS infrastructure – existing and planned

Source: Green Dragon Gas

Latest timing for the construction of the additional gas processing capacity is shown in Exhibit 4. While it is not yet clear when this will be completed (either end 2016 or into 2017), in reality this is not critical to GDG as we expect there to be sufficient processing capacity from end 2015 to support even an accelerated drill programme across the GSS block.

CNOOC is finalising its ODP for GSS (and the other CUCBM blocks) and GDG is understandably confident that this will proceed, given the investment it is already putting into GSS infrastructure. We have no visibility on the timing for the ODP but we expect the plan to be a major share price catalyst for GDG as it will endorse third-party support to GDG’s development plans and potentially increase the debt capacity available to the company.

Beyond the 2P reserves already being targeted at GSS, GDG is also planning the exploitation of 3P reserves that would conceivably require production increased to as much as 150bcf pa. This would clearly require additional gas processing capacity, although in the first instance GDG must complete its evaluation of the Coal Seam #15 that forms the majority of 3P reserves.

GSS/GSN upside: Coal Seam #15 exploitation critical

We expect GDG and its partners to continue to work diligently on existing operations. However, having proven its deployment of capital across GSS and GCZ, current activities at these blocks are likely to be relatively simple to replicate. We therefore expect the partnership to focus efforts more on exploration and development upside, both at GSS/GCZ and further afield.

By far the biggest upside that GDG will target to its existing 2P reserves is from CS #15, both in its GSS and in its GSN blocks. This is a coal seam that is c 80m below the currently producing Coal Seam 3 (CS #3), hence there is little incremental cost to GDG to re-enter and target this coal seam (Exhibit 5). However, this does not mean that exploitation of CS #15 is necessarily simple.

CS #15 sits below a large section of limestone that acts as an effective seal (Exhibit 6). GDG had previously thought that the seam trended deeper as it moved northwards (into the GSN block), which would have made exploitation to the north more difficult. However, the company now thinks this is not the case, which will aid exploitation assuming evaluation of CS #15 is successful. We note that because of the limestone, it will be important to avoid water breakthrough, while due to the proximity of the brittle limestone it will not be possible to frack the seam.

Exhibit 5: CS #3 and CS #15 cross-section

Exhibit 6: CS #3 and CS #15 geology

Source: Green Dragon Gas

Source: Green Dragon Gas

Exhibit 5: CS #3 and CS #15 cross-section

Source: Green Dragon Gas

Exhibit 6: CS #3 and CS #15 geology

Source: Green Dragon Gas

NSAI does not split out the distribution of reserves between CS #3 and CS #15; however, GDG has indicated that c 70% of GSS 3P reserves sit in CS #15. As such, cracking the code for CS #15 will be a big component of unlocking the upside potential from GDG’s 3P reserves (and corresponding company valuation).

GDG indicated in its 2015 interim results that 11 wells have been successfully drilled and logged in CS #15 in H115. The company has committed to completing this CS #15 evaluation programme by end 2015, with results likely to be published in the annual reserves update in February 2016, after which it will be in a position to take a development decision on CS #15. Initially, this is likely to be based on vertical CS #15 wells as these have been on test for longer than CS #15 LiFaBriC wells. This also means that the 2016 upgrade may be relatively modest until results of CS #15 wells are available and understood.

GDG farmed-out 10% of its interest in GSN to partner CUCBM in 2013 (reducing its interest from 60% to 50%) in return for an additional $100m infrastructure investment on the block. Assuming CS #15 evaluation is encouraging, we expect this infrastructure can be used to start to move the existing 706bcf of net 3P reserves into the 1P and 2P category.

Additional exploration: Well count continues to grow

GDG’s immediate priorities are most clearly to monetise its existing and growing well position at GSS, drill its 30 planned and funded LiFaBriC wells at GSS, complete its evaluation of CS #15, and look towards upgrading its reserves at GSN.

However, the company also continues to make modest progress in its exploration blocks, Fengcheng ('GFC'), Qinyuan ('GQY'), Shizhuang North ('GSN'), Panxie East ('GPX') and Baotian Qingshan ('GGZ'). At end H115, GDG had drilled 348 wells across these blocks. Including 1,367 legacy CUCBM (CNOOC) wells at GSS, this brings the overall well count to 1,977 across all blocks. GDG recently indicated that farm-out discussions are underway to accelerate development of some of its exploration acreage.

Downstream: Sales to production ratio to continue to improve

GDG’s gross production in H115 was 4.87bcf, split 2.76bcf from GSS and 2.11bcf from GCZ. However, only a small fraction of this feeds through to sales. In 2014, only 5% of the gas sold through GDG’s distribution arm came from its GSS block, the remaining 95% came from third-party wells, including from the adjacent GCZ block, acquired from third parties. In H115 GDG sold 2.65bcf of piped natural gas (PNG) from its GSS and GCZ blocks, with an additional 0.335bcf sold through compressed natural gas (CNG).

One of the key targets for GDG will be to increase the ratio of gas it sells from its own production and the overall sales to production ratio. We make our assumptions around this in the next section.

Production/sales outlook: Strong uptick expected

Assuming planned GSS gas processing capacity is added and successful exploitation of CS #15 across GSS and GSN, we expect a strong increase in gross production across GDG’s blocks through 2016-20 (Exhibit 7). Initially, this will likely focus on GSS, although in time GDG and its partners will be seeking to more readily exploit the GSN current 3P. As part of an April 2014 farm-out agreement, GDG’s partners are investing $100m on GSN infrastructure to start to develop these resources; hence we are comfortable building them into our production assumptions (subject to CS #15 evaluation being successful). We do not presently include any exploitation of resources from exploration blocks GFC, GQY, GPX and GGZ in these production assumptions.

Exhibit 7: Gross production assumptions

Source: Edison Investment Research. Note: Unrisked forecasts assume both successful exploitation of CS #15 and additional infrastructure investment across GSS and GSN.

Our production assumptions are clearly ambitious and we reiterate that they reflect an unrisked outlook. However, investors should also note that these are still well below NSAI's forecasts, which inform the reserves assumptions for the company. GDG does not publish the full NSAI report on an annual basis; however, based on the information provided in the company’s prospectus for its 2014 London Main market listing, we can see that our net production assumptions are still well below that of NSAI (Exhibit 8). In keeping with standard CPR practice, NSAI will not take into account the economic constraints of the company when proposing production profiles; this explains the marked difference between our and NSAI's assumptions.

Exhibit 8: Net production assumptions vs NSAI

Source: Edison Investment Research

Drilling schedule

Our assumptions are based on historical well performance and a realistic schedule for drilling out its PSCs, assuming that infrastructure and CS #15 both progress to plan. This is shown in Exhibit 9.

Our models reflect a drilling schedule of 60 LiFaBriC we lls at GSS from 2016 (compared with 30 being drilled in 2015) until 2P reserves are produced. We anticipate development of GSN from 2017 with an evolving drilling campaign up to a peak of 160 LiFaBriC wells/year by 2020. Current GSS 3P reserves are assumed to migrate to 1P and 2P over 2015-17 (mainly proving up of CS #15) and will be developed from c 2020 onwards. We do not anticipate any substantial third-party drilling beyond the wells already drilled at GSS and GCZ.

Exhibit 9: LiFaBriC drilling schedule – Edison assumptions

Source: Edison Investment Research

Sales to production ratio

In addition to building production, GDG is also focused on converting an increasing percentage of this production into sales. Over 2015 the company has achieved a ratio of its GSS production reaching the processing facility metering point of c 35%, although it is looking to grow this to 50% by year end (Exhibit 10). This will primarily be achieved by improving the pressure balance of its wells across the gas infrastructure, negating inefficiencies in gas flow from wells reaching the metering stations.

Exhibit 10: 2015 GSS sales/production ratio – actual and GDG guidance

Exhibit 11: GSS sales/ production ratio – Edison long-term assumptions

Source: Green Dragon Gas

Source: Edison Investment Research, Note: Edison assumptions only – no company guidance

Exhibit 10: 2015 GSS sales/production ratio – actual and GDG guidance

Source: Green Dragon Gas

Exhibit 11: GSS sales/ production ratio – Edison long-term assumptions

Source: Edison Investment Research, Note: Edison assumptions only – no company guidance

Longer-term, we assume that GDG will continue to improve the efficiency of its well network, slowly building this percentage to c 85% (we show our assumptions in Exhibit 11). We consider this to be a maximum sales/production ratio as GDG will require some of its gas production to be used for fuel.

Macro environment continues to support growth

China’s 12th Five Year Plan (2011-15) involved a series of initiatives to increase gas production and consumption targets from current levels (Exhibit 12), including increasing gas in the primary energy mix from 4% (2010) to 8% (2015) and above 10% by 2020. This plan has resulted in strong incentives from the Chinese government to promote domestic gas production and in particular CBM, including partial deregulation of the CBM market, doubling of central government subsidies (from $0.9/mscf to $1.8/mscf), beneficial tax treatments and priority treatment of CBM for pipeline and power station access.

Against this backdrop, GDG has consistently reiterated its confidence in a strong regulatory environment, both to protect and grow domestic gas prices/economics, and to ensure there is a captive market for its CBM gas production. We highlight the recognition and protection the company has had from Chinese authorities to historical challenges to its PSC titles as strong evidence of this.

Exhibit 12: Chinese economic and energy/gas consumption indicators vs other major producers/consumers

Source: Green Dragon Gas

However, on the demand side of the equation we would highlight the recent slowdown in Chinese GDP growth, with reported quarterly GDP growth in Q315 of 6.9% the lowest the country has seen since Q109. This may put some pressure on gas demand; however, the overwhelming fundamentals of continued GDP growth, above GDP gas demand (estimated to be 3% above GDP over 2015-20) and an increasing share of gas in the energy mix should give investors confidence that demand and prices for GDG’s gas should remain strong.

This has been reflected in the price assumptions GDG has provided to NSAI for its reserves reports, as shown in Exhibit 14. We assume a more conservative deck in our base case valuations, reflecting previous assumptions of actual well prices (2014 $10.87/mscf) inflated at 9% pa until reaching import price parity (ie LNG) that we estimate would be achieved in 2018.

Exhibit 13: Historic gas prices vs Brent

Exhibit 14: Edison assumed wellhead gas prices vs GDG/NSAI

Source: Green Dragon Gas, Bloomberg

Source: Green Dragon Gas, NSAI, Edison Investment Research

Exhibit 13: Historic gas prices vs Brent

Source: Green Dragon Gas, Bloomberg

Exhibit 14: Edison assumed wellhead gas prices vs GDG/NSAI

Source: Green Dragon Gas, NSAI, Edison Investment Research

Management and shareholders

GDG continues to be particularly tightly held for such a well-established company, with c 80% of the shares held by chairman and CEO Randeep Grewal, and long-time investment partner Chandler Corporation. These two shareholdings have been broadly consistent since Q113, with only a slight adjustment when the two main holders sold 1.5% of the shares in July 2014 to aid liquidity.

As such, liquidity remains particularly low with quarterly volumes of only c 2.3m shares traded on average over the last two to three years (0.025% daily) (Exhibit 15). However, this has not stopped some institutions building positions in the thin open market, most notably Aberdeen Asset Managers and Fidelity, which have built 5.99% and 3.69% positions respectively in the company by end-June 2015.

Exhibit 15: GDG share price and liquidity

Source: Bloomberg, Edison Investment Research

In addition to founder, chairman, CEO and majority shareholder Randeep Grewal, GDG has recently bolstered its management team with a COO and CAO.

Jorg Kohnert, President and COO, joined Green Dragon Gas in September 2015. Mr. Kohnert worked for more than 20 years in executive management, operational, and commercial roles for Shell International in the Netherlands, Syria, the UK, Iran, Oman, India, Indonesia, China, Nigeria and Cameroon. He has also been managing director for Addax Petroleum and general manager for Glencore International.

Tim Eastmond, CAO, joined Green Dragon Gas in September 2015. Mr Eastmond worked at PwC from 1993-2015 in its London, Moscow, Aberdeen and Houston offices. Prior to joining Green Dragon Gas, he was a senior director with PwC and had been based in the London office since 2004, undertaking a placement in Moscow from 2008-11.

Sensitivities: Issues to consider

GDG is at a critical point in its evolution. The company is potentially on the cusp of a dramatic uptick in production and profitability that would move it from predominantly a resource play to a serious production company. However, investors should recognise that there remain a number of uncertainties that could still affect this transformation:

Sub-surface risk: The importance of successful evaluation of CS #15 should not be underestimated, as it will potentially open up for development the majority of 3P reserves at GSS and possibly the same at GSN. More than half of our valuation is based on these 3P reserves and hence problems with developing CS #15 would be a major setback for GDG. However, investors can take heart from the fact our core NAV is still well above current share price levels, which is based uniquely on established CS #3 production.

Finance risk: In our financials section, we explore the requirement for asset-backed debt to fully exploit the company’s current reserves. Ultimately, GDG may need to demonstrate partner-backed development plans to fully secure this debt, and this in turn would need GDG’s partners to have secured ODP approval. However, given the size of 1P reserves and the fact that CUCBM infrastructure capex is being deployed, we would expect GDG to advance RBL discussions with banks ahead of ODP approval and possibly secure transition finance via this route. If ODP is not approved or RBL is delayed, it may be necessary for GDG to extend the period that it is incurring higher costs of capital. Investors can use the sensitivity tables to discount rate later in this report to assess this risk; however, in general we believe that one to two years of the company carrying a more expensive capital structure would not significantly affect the long-term valuation. Equally, a pause in development drilling in 2016 would have only a minor impact on EBITDA and NAV, with our forecast 2017 EBITDA falling to c $70m (from c $80m). Any pause in development drilling would have minimal impact on NAV valuations.

Chinese demand risk: Earlier in this report we have discussed the recent slowdown in Chinese GDP growth. GDG is confident that the underlying fundamentals of gas demand in China remain strong and that the prices available are likely to remain robust. We include an analysis of valuation sensitivity to wellhead gas price later in this report (Exhibit 18). We conclude from this that the company would offer upside to the current share price at gas prices above $11/mscf on a core NAV basis (NPV10), while successful evaluation of CS #15 would result in substantial upside irrespective of the realised gas price.

Valuation: Excellent growth potential if monetised

In keeping with our previous coverage, we value GDG on a discounted cash flow (DCF) basis. We currently only value the reserves (2P and 3P) at GSS, GCZ and GSN where there is ongoing development activity. Eventually we would expect to also value the company’s exploration blocks (GFC, GQY, GSN, GPX and GGZ) as these are further appraised.

Our base assumptions include an inflating wellhead gas price until import price parity is reached (Exhibit 14) and a 10% discount rate. Consistent with our previous notes, we assume a 10-year life for existing vertical wells with a 7% decline rate, while for LiFaBriC wells we assume a 16-year life with flat production rates of 250mcf/d over the forecast period. This drives our core NAV and RENAV of £3.28 and £6.79/ share respectively (Exhibit 16).

Exhibit 16: GDG fundamental valuation

Asset

 

 

 

 

Recoverable reserves/ resources

 

Net Risked

Value per share

Country

Diluted WI

Catalyst

CoS

Gross

Net

NPV/mcf

value

Risked

 

%

 

%

bcf

bcf

$/mcf

$m

/share

Net (Debt) Cash end 2015 est.

 

 

 

 

 

 

-106.9

-0.47

SG&A

 

 

 

 

 

 

 

-30.0

-0.13

GSS 2P

China

60/70%

 

70%

524.6

366.0

3.2

814.1

3.60

GCZ

China

47%

 

70%

63.1

29.6

3.1

65.3

0.29

Core NAV

 

 

 

 

587.7

395.7

 

742.5

3.28

GSN

China

50%

 

30%

1410.8

705.4

2.1

438.0

1.94

GSS 3P upside

China

70%

 

20%

1283.3

898.3

2.0

355.9

1.57

RENAV

 

 

 

 

3,281.7

1,999.4

 

1,536.4

6.79

Source: Edison Investment Research. Note: *GDG has an option to increase GSS WI to 70%; **all reserves at GSN currently in 3P. Valuation for GSS and GSN 3P will largely depend on success of CS #15 evaluation.

By far the largest uncertainty to this valuation is the evaluation of CS #15, results of which we expect GDG to announce with its annual reserves update in February 2016. This is a key catalyst that could start to de-risk the value that we currently have ascribed to both GSN and GSS 3P (more than half our RENAV valuation).

Assuming this is successful and the assets are developed (and de-risked) in accordance with our model assumptions, we would expect our RENAV to move up quickly (see Exhibit 17). This equates to a c 30% CAGR through 2020, reflecting the excellent value creation potential from GDG’s portfolio if it can effectively monetise its reserves.

Exhibit 17: Value evolution through time

Source: Edison Investment Research. Note: Only includes de-risking and monetisation of GSS and GSN; no allowance for GFC, GQY, GSN, GPX and GGZ.

Sensitivities: Discount rate and gas price

In addition to the uncertainties over monetisation schedule and CS #15 in particular, the most material sensitivities to our valuation are gas price and discount rate. For investors who wish to make different assumptions to ours, we provide the following table (Exhibit 18) to show the impact of these two parameters on our current core NAV and RENAV. This can also be used to assess the potential valuation if GDG is either unsuccessful with its exploitation of CS #15 or if the company has to incur more expensive costs of capital for longer than planned.

Note that the gas price assumptions here only include a 2.5% pa inflation assumption rather than an accelerated inflation assumption to import price parity, as per our standard valuation assumptions.

Exhibit 18: Core NAV and RENAV sensitivity to discount rate and gas price

Core NAV

Discount Rate

RENAV

Discount Rate

Gas price/ $mscf (2015)

8%

10%

12%

14%

16%

Gas price/ $mscf (2015)

8%

10%

12%

14%

16%

8

1.48

1.08

0.76

0.50

0.30

8

3.28

2.34

1.63

1.10

0.70

9

1.93

1.47

1.09

0.79

0.55

9

4.25

3.12

2.28

1.64

1.15

10

2.39

1.86

1.43

1.09

0.81

10

5.22

3.91

2.92

2.17

1.59

11

2.85

2.25

1.77

1.38

1.06

11

6.19

4.70

3.57

2.71

2.04

12

3.31

2.64

2.10

1.67

1.32

12

7.16

5.49

4.22

3.24

2.49

13

3.77

3.03

2.44

1.96

1.57

13

8.13

6.27

4.86

3.78

2.94

14

4.23

3.42

2.78

2.25

1.83

14

9.10

7.06

5.51

4.32

3.39

Source: Edison Investment Research. Note: Gas price assumptions include a 2.5% pa inflation assumption but are not adjusted for import price parity, ie cannot be compared directly with base case price deck used in Exhibit 16.

Relative valuation: AAG Energy now an interesting comparable

Until recently, it was difficult to assess the value of GDG’s assets on a relative basis to other companies. In previous research, we had compared EV/resource multiples for GDG against Far Eastern Energy (OTC micro-cap), Great Eastern Energy (LSE integrated CBM player but in India) and Sino Gas and Energy (ASX-listed but upstream only), but all of these companies are very different to GDG. However, this is now possible with the recent listing of AAG Energy Holdings on the Hong Kong stock exchange (ticker code 2686).

AAG has CBM assets in the southern Qinshui Basin and, like GDG, partners with both CUCBM and Petrochina. The company’s Panzhuang concession has already received ODP approval and, due to being marginally more advanced than GDG’s GSS block, is more profitable. However, a wider analysis of AAG’s assets, acreage and resource base shows that GDG remains significantly undervalued on key metrics such as EV/acreage and EV/3P plus prospective resources.

Exhibit 19: Comparison AAG Energy vs Green Dragon Gas

Metric

AAG Energy

GDG

EV ($m)

507

593

EBITDA ($m) (H115 annualised)

89

14

1P reserves (bcf)

82

148

2P reserves (bcf)

625

427

3P reserves (bcf)

1029

2290

2C resources (bcf)

9

23

Best estimate prospective resources (bcf)

52

1607

Acreage (sq km)

966

7567

Developed acreage (sq km)

31

25

Comparables

EV/EBITDA

5.7

43.9

EV/ 2P

0.81

1.39

EV/3P plus prospective

0.47

0.15

EV/acreage

0.52

0.08

Source: Company accounts, NSAI, Edison Investment Research

We would not want to draw too much from comparisons with only one other company, especially being listed on an exchange that does not have many oil and gas companies. However, it does give investors sight of what multiples may be achieved (eg EV/EBITDA) once GDG and its partners start to build on the 2P reserve base.

Financials: Debt requirements still substantial

GDG’s financial performance continues to improve, albeit H115 was still loss-making with the company reporting a total net loss of $1.4m for the period. This compares with a normalised loss in 2014 of $5.7m (the H115 results are clean and therefore comparable with 2014’s normalised loss).

The company is on a trajectory to start to break even from a post-tax profitability perspective by end 2015; we estimate this could increase to c $20m in 2016 and c $60m in 2017. However, the true potential of GDG’s resource position is only likely to be seen in financial performance when 3P reserves at GSS and GSN are migrated to 1P and 2P and then into production. We reiterate that this scenario is contingent on successful evaluation of CS #15.

Debt requirements

Not surprisingly, the immediate challenge for GDG is how to fund the activity that will generate the improvements in profitability and cash flow. We see this as a multi-stage process, which will require the company getting through a number of key investment stages, and will incorporate debt funding and farm-out of exploration acreage.

2016: Immediate requirements

We estimate that GDG will have had sufficient funds to complete its 30-well LiFaBriC drilling programme in 2015. However, in 2016 the company will need an additional c $110m of funds to maintain and accelerate its drilling trajectory at GSS, based on our base case drill programme (Exhibit 9). This also includes an assumption that GDG will exercise an option to increase its interest in GSS from 60% to 70%, triggering a $13m H216 payment.

Funding for 2016 will depend on a number of outcomes. We expect GDG will seek full RBL that will fund the ongoing drill programme. However, given the size of 1P reserves and the fact that CUCBM infrastructure capex is being deployed, we would also expect GDG to advance RBL discussions with banks ahead of ODP approval and the company could possibly secure transitional RBL finance via this route.

If ODP is not approved or RBL is delayed, it may be necessary for GDG to extend the period in which it is incurring higher costs of capital or pause its development programme for 2016. Investors can use the sensitivity tables to discount rate later in this report (Exhibit 18) to assess this risk; however, in general we believe that one to two years of the company carrying a more expensive capital structure would not significantly affect the long-term valuation. Equally, a pause in development drilling in 2016 would have only a minor impact on EBITDA and NAV, with our forecast 2017 EBITDA falling to c $70m (from c $80m). Any pause in development drilling would have minimal impact on NAV valuations

Our 2016 forecast debt requirements come in addition to a forecast end-2015 cash position of $27m, which is being funded from $86m of 10% bonds (4.5% discount end to end) and $48m of convertible debt ($9.34 conversion price, 7% coupon).

2017-19: GSS 2P development requirements

Moving into 2017-19, GDG is going to need to access more substantial levels of debt to complete development of reserves at GSS (LiFaBriC drilling) and prepare for the development of GSS and GSN 3P reserves. The company will also need to refinance the current $86m bonds and $48m convertibles due to mature in November 2017 and June 2017, respectively. As such, we see a peak debt requirement over 2017-19 of c $450m. This number could also be substantially higher if GDG and its partners choose to accelerate the development of GSN and the GSS 3P reserves.

Once again, the most logical funding route for this would be RBL, although it is far more likely (than the situation in 2016) that this will be a straightforward process, assuming ODP has been secured by this time (something we think is highly likely during 2016). Once the development plans are approved, we see a comfortable level of economic capacity available to underpin the RBL debt requirements (normally secured on 1P reserves and reduced commodity price basis).

2020 onwards: 3P development

We phase our models to show 3P development from GSN and GSS accelerating from 2020 onwards. This would allow GDG to fund development of these more substantial resources from cash flow. GDG may be tempted (with its partners) to accelerate development of these resources and this remains a possibility; however, this would require additional funding over and above our 2017-19 assumptions. Our base case assumptions would show GDG debt free by early 2026.

Dividend capacity

Given the strength of GDG’s forecast operating margins, we expect the company will look to offer dividends in time. Management may seek to accelerate this but we would prefer to see the company put itself on a stable footing with comfortable debt headroom before committing to dividend payments. This would likely mean that dividends could be paid from c 2018 or 2019.

Over the life of the PSCs in our valuation models, we estimate that cash flow could deliver dividends of up to $4/share on an annualised basis, although this would subject the balance sheet to uncomfortably large levels of gearing. Dividends of up to $1/share should be comfortably accommodated from 2019 onwards, assuming GDG is able to develop GSS and GSN as per our base case assumptions.

Exhibit 20: Financial summary

 

 

US$m

2013

2014

2015e

2016e

2017e

2018e

December

 

 

IFRS

IFRS

IFRS

IFRS

IFRS

IFRS

PROFIT & LOSS

Revenue

 

 

62.2

33.8

41.9

85.0

122.2

204.2

Cost of Sales

(26.5)

(13.5)

(13.8)

(28.7)

(27.6)

(39.5)

Gross Profit

35.6

20.3

28.2

56.3

94.6

164.7

EBITDA

 

 

4.5

11.4

15.2

42.7

80.4

149.9

Operating Profit (before amort. and except.)

(9.3)

5.9

12.6

36.1

75.5

139.1

Intangible Amortisation

0.0

0.0

0.0

0.0

0.0

0.0

Exceptionals

(13.3)

(30.1)

0.0

0.0

0.0

0.0

Other

0.0

0.0

0.0

0.0

0.0

0.0

Operating Profit

(22.6)

(24.2)

12.6

36.1

75.5

139.1

Net Interest

(12.2)

(12.0)

(12.7)

(13.0)

(21.7)

(25.3)

Profit Before Tax (norm)

(21.5)

(6.2)

(0.2)

23.1

53.9

113.7

Profit Before Tax (FRS 3)

(34.8)

(36.3)

(0.2)

23.1

53.9

113.7

Tax

0.5

0.5

(2.5)

(10.3)

(20.4)

(36.5)

Profit After Tax (norm)

(21.0)

(5.7)

(2.6)

12.7

33.5

77.2

Profit After Tax (FRS 3)

18.8

(37.5)

(3.0)

12.7

33.5

77.2

Average Number of Shares Outstanding (m)

139.3

156.1

156.1

156.1

156.1

156.1

EPS - normalised (c)

 

(0.0)

(0.0)

(0.0)

0.0

0.0

0.0

EPS - normalised and fully diluted (c)

(0.0)

(0.0)

(0.0)

0.0

0.0

0.0

EPS - (IFRS) (c)

 

0.0

(0.0)

(0.0)

0.0

0.0

0.0

Dividend per share (p)

0.0

0.0

0.0

0.0

0.0

0.0

Gross Margin (%)

57%

60%

67%

66%

77%

81%

EBITDA Margin (%)

7%

34%

36%

50%

66%

73%

Operating Margin (before GW and except.) (%)

N/A

17%

30%

42%

62%

68%

BALANCE SHEET

Fixed Assets

 

936.8

1,321.2

1,368.2

1,484.0

1,568.7

1,657.9

Intangible Assets

3.8

3.1

34.6

132.6

132.6

132.6

Tangible Assets

930.8

1,315.5

1,331.3

1,349.1

1,433.8

1,523.0

Investments

2.2

2.5

2.3

2.3

2.3

2.3

Current Assets

 

46.3

103.2

76.5

83.7

119.7

199.8

Stocks

0.1

0.1

0.9

1.3

1.2

1.8

Debtors

11.5

23.1

48.8

82.4

118.5

198.0

Cash

34.6

80.0

26.8

0.0

0.0

0.0

Other

0.0

0.0

0.0

0.0

0.0

0.0

Current Liabilities

 

(126.0)

(22.2)

(40.5)

(57.1)

(54.8)

(78.2)

Creditors

(95.6)

(22.2)

(40.5)

(57.1)

(54.8)

(78.2)

Short term borrowings

(30.4)

0.0

0.0

0.0

0.0

0.0

Long Term Liabilities

 

(210.3)

(662.8)

(667.9)

(774.7)

(864.2)

(932.8)

Bonds

0.0

(85.1)

(85.9)

(85.9)

0.0

0.0

Long term debt (RBL or eq.)

0.0

0.0

0.0

(106.8)

(329.9)

(398.6)

Convertible debt

(33.4)

(47.2)

(47.8)

(47.8)

0.0

0.0

Deferred Tax Liabilities

(163.9)

(163.5)

(163.5)

(163.5)

(163.5)

(163.5)

Other long term liabilities

(13.0)

(367.0)

(370.7)

(370.7)

(370.7)

(370.7)

Net Assets

 

 

646.8

739.3

736.3

736.0

769.5

846.7

CASH FLOW

Operating Cash Flow

 

22.5

0.7

14.5

14.9

21.7

56.8

Net Interest

(5.4)

(5.4)

(11.9)

(13.0)

(21.7)

(25.3)

Tax

0.0

0.0

0.0

0.0

0.0

0.0

Capex

(70.6)

(53.5)

(52.7)

(122.5)

(89.6)

(100.1)

Acquisitions/disposals

60.0

(0.1)

0.0

(13.0)

0.0

0.0

Equity financing and convertible debt

0.0

42.4

0.0

0.0

0.0

0.0

Dividends

0.0

0.0

0.0

0.0

0.0

0.0

Other

0.0

(40.0)

0.1

0.0

0.0

0.0

Net Cash Flow

6.6

(55.9)

(50.0)

(133.6)

(89.5)

(68.6)

Opening net debt/(cash)

39.8

29.1

52.3

106.9

240.5

329.9

HP finance leases initiated

4.4

(0.7)

(0.6)

0.0

0.0

0.0

Other

(0.3)

33.4

(4.0)

0.0

0.0

0.0

Closing net debt/(cash)

 

29.1

52.3

106.9

240.5

329.9

398.6

Source: Company data; Edison Investment Research

Contact details

Revenue by geography

1 Berkely Street London W1J 8DJ United Kingdom +44 (0)20 7016 9830 Website http://www.greendragongas.com/

Contact details

1 Berkely Street London W1J 8DJ United Kingdom +44 (0)20 7016 9830 Website http://www.greendragongas.com/

Revenue by geography

Management team

Chairman and CEO: Randeep Grewal

President and COO: Jorg Kohnert

Mr Grewal founded the business of the Greka Group in 1997, having previously been chairman and chief executive officer for Horizontal Ventures, an oil and gas horizontal drilling technology company that became a subsidiary of Greka in September 1997. Mr. Grewal has a BSc in mechanical engineering from Northrop University.

Mr Kohnert joined Green Dragon Gas in September 2015 as president and COO. Mr Kohnert worked for more than 20 years in executive management, operational, and commercial roles for Shell International in the Netherlands, Syria, the UK, Iran, Oman, India, Indonesia, China, Nigeria and Cameroon. He has also been managing director for Addax Petroleum and general manager for Glencore International.

CAO: Tim Eastmond

CFO: Alfred Yan

Mr Eastmond joined Green Dragon Gas in September 2015 as chief accounting officer. Mr Eastmond worked at PwC from 1993-2015 in its London, Moscow, Aberdeen and Houston offices. Prior to joining Green Dragon Gas, he was a senior director with PwC and had been based in the London office since 2004, undertaking a placement in Moscow from 2008-11.

Mr Yan joined Green Dragon Gas in May 2007 as chief financial officer. Prior to joining Green Dragon Gas, Mr Yan was chief financial officer at Chinese People Gas Holdings from 2005-07, handling group financial management, corporate finance and compliance. From 2002 to 2005, Mr Yan was financial controller at True Seating Concepts. From 1994 to 2001, Mr. Yan held various positions at Deloitte Touche Tohmatsu, KPMG & BDO.

Management team

Chairman and CEO: Randeep Grewal

Mr Grewal founded the business of the Greka Group in 1997, having previously been chairman and chief executive officer for Horizontal Ventures, an oil and gas horizontal drilling technology company that became a subsidiary of Greka in September 1997. Mr. Grewal has a BSc in mechanical engineering from Northrop University.

President and COO: Jorg Kohnert

Mr Kohnert joined Green Dragon Gas in September 2015 as president and COO. Mr Kohnert worked for more than 20 years in executive management, operational, and commercial roles for Shell International in the Netherlands, Syria, the UK, Iran, Oman, India, Indonesia, China, Nigeria and Cameroon. He has also been managing director for Addax Petroleum and general manager for Glencore International.

CAO: Tim Eastmond

Mr Eastmond joined Green Dragon Gas in September 2015 as chief accounting officer. Mr Eastmond worked at PwC from 1993-2015 in its London, Moscow, Aberdeen and Houston offices. Prior to joining Green Dragon Gas, he was a senior director with PwC and had been based in the London office since 2004, undertaking a placement in Moscow from 2008-11.

CFO: Alfred Yan

Mr Yan joined Green Dragon Gas in May 2007 as chief financial officer. Prior to joining Green Dragon Gas, Mr Yan was chief financial officer at Chinese People Gas Holdings from 2005-07, handling group financial management, corporate finance and compliance. From 2002 to 2005, Mr Yan was financial controller at True Seating Concepts. From 1994 to 2001, Mr. Yan held various positions at Deloitte Touche Tohmatsu, KPMG & BDO.

Principal shareholders (at 30 June 2015)

(%)

GDGH (Randeep Grewal)

55.85

Chandler Corporation

23.72

Aberdeen Asset Managers

5.99

GIC Private

3.70

Fidelity Worldwide Investment

3.69

Companies named in this report

AAG Energy, Far Eastern Energy, Sino Gas and Energy, Great Eastern Energy

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Frankfurt +49 (0)69 78 8076 960

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60325 Frankfurt

Germany

London +44 (0)20 3077 5700

280 High Holborn

London, WC1V 7EE

United Kingdom

New York +1 646 653 7026

245 Park Avenue, 39th Floor

10167, New York

US

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