China Utilities 12 January 2018

China Gas

Gas in 2025: hedging & diversification key for distributors with their eyes on the prize

See important disclosures, including any required research certifications, beginning on page 111.

China Gas: 12 January 2018

Table of contents

Why is growth in natural gas consumption in China 1 5 inevitable? What are the core demand drivers behind solid 2 15 consumption growth of natural gas? 3 Can supply catch up with robust demand? 35

4 Does strong volume growth lead to strong profits? 43 Who stands ready to manage margin risks and 5 51 emerge as a winner? 6 Appendices 61

7 Company Section 72

ENN Energy 73

China Gas 79

Towngas China 85

China Resources Gas 89

Beijing Enterprises 95

China Suntien Green Energy 99

CIMC Enric 103

China Gas: 12 January 2018

Contributing Big volume, low tariffs: hedging and diversification key Daiwa Analysts:

China’s gas sector had a very strong 2017, with confirmation of a 7%-ROA cap for city- Dennis Ip, CFA gas distribution (excluding residential connection) and massive coal-to-gas (CTG) (852) 2848 4068 conversion of villages in “2+26” northern cities, leading to 30-105% share-price [email protected] appreciation for the China gas stocks under our coverage. Don Lau, CFA With only 6% of primary energy consumption from gas in China, vs. c.25% globally, gas (852) 2848 4469 [email protected] demand is not an issue. But as over 50% of the 320bcm of new demand in 2016-25 will be replacing cheap coal rather than expensive oil products, cost effectiveness is a bottleneck for the wider consumption of natural gas in China. Still, China is committed to clean up its air, and has adopted a radical approach by converting c.3m rural households

to gas in the “2+26” major northern cities in China in 2017 with a CNY16bn subsidy.

But, we see the CTG subsidy as unsustainable with more users in the future, and a tariff cut as inevitable. After the National Development and Reform Commission’s (NDRC) 8%- ROA and 7%-ROA cap (effective dates of January 2017 and July 2018, respectively) for cross-provincial transmission and city-gas distribution segments, we expect it to push further reforms in the gas sector in 2018-19, including liberalising the upstream and large- user retail market, and further lowering upstream cost and end-user tariffs by taking advantage of the low-cost spot-LNG market. In sum, we expect the national city-gas distributors’ unit gas sales dollar margin to fall by CNY3-5 cents pa, amid 20%/13% YoY volume CAGRs in 2016-20E/2020-25E, with the margin squeeze arising from:

1) ASP discounts offered to CTG customers; 2) Periodic review of distribution tariffs under the 7%-ROA cap policy; 3) Direct-supply threat from oil majors.

To offset the profit loss from declining distribution tariffs, especially during winter when market-based gas is at a significant premium, the China city-gas companies can either hedge along the supply-chain by adopting an integrated business model, with cheap LNG from upstream coupled with distributed-energy services for large retail users, eg, ENN Energy (ENN, 2688 HK, HKD51.5), or diversify to other unregulated businesses, such as rural connections, eg, China Gas (CGHL, 384 HK, HKD20.8). However, CGHL is trading at 14.7x 12-month forward PER, vs. 10.8x for ENN. After taking into account the risk-reward profile, we make ENN our top pick and upgrade our rating to Buy (1), and downgrade CGHL to Outperform (2). Given its limited hedging and diversification strategies, China Resources Gas (CRG, 1193 HK, HKD24.7) remains our least preferred city-gas distributor, and we maintain our Hold (3) call.

Also, we upgrade CIMC Enric (3899 HK), which looks set for resilient LNG equipment sales from 2018.

China city-gas distributors: hedging and diversification (H&D) exposure (CNYbn) 10 Net profit from H&D in 2020E 8 6 4 2 0 CGHL CRG ENN CGHL CRG ENN CGHL CRG ENN

2017E 2020E without H&D 2020E with H&D Source: Daiwa estimates and forecasts

3 Source: Source: NDRC, Daiwa estimates

[Need to mention here the company-level revisions to earnings, TPs, and ratings. Otherwise the reader has to go more than 70 pages in to find out what’s changing]

China Gas: 12 January 2018

Chapter 1

Why is growth in natural gas consumption in China inevitable?

China Gas: 12 January 2018

How far is China from Utopia?

In recent years, thanks to more comprehensive and stricter emission regulations, air pollution is easing in China, especially after the implementation of the New Environmental Law in 2015, the first amendment in 25 years, which introduced severe punishments and more importantly offered greater enforcement power to the environmental bureau. As a result, for 2017, China looks set to achieve most of its targets set in the Air Pollution Prevention and Control Plan (大氣污染防治行動計劃 or 大氣十條), a key action plan to mitigate air pollution for 2013-17.

China: objectives set in the Air Pollution Prevention and Control Plan Items (µg/m3) Actual level in 2013 Actual level in 2016 Target in 2017 Diff (%) Likelihood to achieve National concentration of PM10 in urban areas 97 82 87 -6% High Concentration of PM2.5 in Beijing-Tianjin-Hebei area 106 71 80 -11% High Concentration of PM2.5 in Yangtze River delta 67 46 54 -14% High Concentration of PM2.5 in Pearl River delta 47 32 40 -20% High Concentration of PM2.5 in Beijing 90 73 60 22% High

Source: MEP, Daiwa

War against air pollution: just the end of round one While we acknowledge that China has done much to combat the air pollution problem, there is still a long way to go if it is to achieve its desired level of air quality. If we use PM2.5 concentration as a proxy to reflect the extent of air pollution, China still lags well behind the rest of the world — its PM2.5 concentration was more than 30% higher than the world’s average in 2015, not to mention the difference versus developed economies in the West, like the US and EU. In terms of China’s own benchmark, only 25% of Chinese cities passed air quality standards in 2016, with the PM2.5 concentration in the core Beijing-Tianjin-Hebei (BTH) area still 100% higher than the acceptable level. As a result, China is still paying a heavy social cost for its air pollution. According to the Health Effects Institute, an independent research organisation studying the health effects of air pollution based in Boston, 1.1m citizens died due to heavy PM2.5 exposure in China in 2015, representing one-fourth the total number of deaths arising from PM2.5.

2015 PM2.5 concentration comparison China: % of cities that pass the air quality standard

(µg/m3) 100% 70 58 60 80%

50 44 60% 40

30 40% 25% 20 15 22% 8 20% 10% 10 4% 0 0% 2013 2014 2015 2016 China EU US World Average Source: World Bank Source: MEP

China: PM2.5 concentration in BTH area Numbers of deaths due to PM2.5 exposure in 2015 (µg/m3) (m) 120 106 3.0 2.8 100 93 2.5 77 80 71 2.0 60 1.5 40 1.1 1.0 20 0.5 0.3 0 0.1 2013 2014 2015 2016 0.0 PM2.5 concentration Acceptable level China EU US Rest of the world Source: MEP Source: Health Effects Institute

China Gas: 12 January 2018

Don’t underestimate China’s determination to combat air pollution

In our view, given the heightened health awareness of its citizens, China’s government will continue to prioritise the task of curbing air pollution going forward in order to maintain social stability, especially in densely populated areas and industrial clusters, including the BTH region, Yangtze River delta region, and the Pearl River delta region. Indeed, the government has continued to roll out new polices and emphasise its reduction targets. For example, in 1H17, the Ministry of Environmental Protection (MEP) launched an air pollution prevention plan (京津冀及周邊地區 2017 年大氣污染防治工作方案) specifically for 2 municipalities and 26 cities (2+26) in the BTH region which clearly defines targets and timelines on restricting the use of coal, diesel vehicles, and the incineration of waste. More importantly, the plan has implemented a much stricter pollutant emissions standard (於京津冀及周邊地區執行大氣污染物特別排放限值) in order to meet local air-quality goals. We believe the launch of air pollution prevention policies, rising financial support, and stricter enforcement of the overall environmental protection law, as indicated by a sharp increase in the number of environmental crime cases filed and the penalty amounts, demonstrate the country’s determination to put air pollution prevention at the top of its agenda.

China: major policies/events on air pollution prevention since 2016 Date Policy/event Description Jan-16 New Air Pollution Prevention Law The Law requires local government and agencies to budget for financial resources to combat air pollution. Local governments and agencies also need to review progress of key air pollution prevention missions periodically. Also, it specifies that environmental treatment targets should be as important as economic goals Dec-16 Environmental Protection Tax Law The Law replaces the old waste treatment tariffs with environmental taxes and allows local government to adjust the taxes upward according to their situation, with the old tariffs being the lower limit. In other words, waste treatment charges have been raised Dec-16 Implementation of Comprehensive The policy aims to reduce the emission of eight heavy-polluting industries including steel, coal-fired power, Emission Target for Industrial and cement by the end of 2017 Polluting Sources Jan-17 Amendment on the Evaluation The weighting of environmental protection and resources preservation have become much higher than that Metrics for Government Officials of GDP on the evaluation of local government officials Mar-17 2017 Report on the Work of the Premier Li emphasised the government’s determination to improve air pollution problem with specific Government targets (eg, 3% emission reduction for sulfur dioxide and nitrogen oxides) Mar-17 2017 Air Pollution Prevention Plan The policy restricts the use of coal, diesel vehicles, and the incineration of waste in the 2+26 cities in the for BTH and surrounding areas BTH area

Source: Chinabaogao.com, Daiwa

China: central government air pollution China: no. of environmental non-compliance prevention fund cases filed (CNYbn) ('000) 12 11.2 160 10.6 138 9.8 140 10 120 103 8 100 73 6 5 80 66 60 4 40 2 20 0 0 2013 2014 2015 2016 2013 2014 2015 2016 Source: MEP Source: MEP

China Gas: 12 January 2018

China: penalties arising from environmental non-compliance (CNYm) 800 700 600 500 400 300 200 100 0 Gansu Guizhou Henan Jiangsu Shaanxi Shandong Shanghai Sichuan Tianjin Yunnan Zhejiang

2014 2016

Source: CAAC

Price reform to facilitate adoption of natural gas

Reduction in coal consumption is still the key to win the war

Based on research conducted by the Health Effects Institute, coal burning is the major source of outdoor PM2.5 in China, accounting for 40% of emissions, followed by non-coal industrial activities and transportation. Hence, to effectively ease air pollution in China, the government needs to push harder to reduce coal consumption, as coal represented 62% of China’s primary energy mix in 2016. As a clean source of energy, natural gas has been selected by the government as one of the primary substitutes for coal going forward, as China plans to boost the share of natural gas in its primary energy mix from 6.2% in 2016 to 8.3-10% in 2020 as outlined in the 13th Five- Year Plan (FYP, 2016-20), implying a c.13% 4-year CAGR in terms of volume — much faster than the 9.6% CAGR registered from 2011 to 2016. To achieve such an aggressive target, other than via administrative measures, such as the setting up of no-coal zones, China has to incentivise the adoption of natural gas by improving the economics of natural gas relative to those of coal, which is 60% cheaper.

China: sources of PM2.5 China: primary energy mix 100% Others 20% 80% Coal-burning 40% 60%

Biomass 40% combustion 69% 68% 68% 66% 15% 64% 62% 20%

0% Transportation Industrial(non- 2011 2012 2013 2014 2015 2016 15% coal) Coal Hydropower Natural gas Nuclear energy Oil Renewables 10% Source: Health Effects Institute, Note: as of 2013 Source: BP

China: fuel heating cost comparison CNY/MJ 0.18 0.16 0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00 Coal Natural gas Natural gas Natural gas LNG LPG CNG Diesel Gasoline Electricity (residential) (C&I non- (C&I CTG) (vehicle) (vehicle) CTG) Source: Wind and Daiwa estimates; note as at end-2017

China Gas: 12 January 2018

Encouraging progress on price liberalisation to improve the attractiveness of natural gas

In order to make natural gas a more favourable option to end-users, the government has initiated price reform in the gas market based on the core thesis of “liberalising both ends of the value chain while regulating the midstream” (放开两头、管住中间). In other words, China aims to liberalise both upstream and downstream prices through a market mechanism which is based completely on supply and demand. For the midstream transmission and distribution networks, which are natural monopolies, tariffs will be determined on a cost-plus basis, where operators will be allowed to make a reasonable return on asset (ROA). So far, China has already achieved certain milestones on price reform, especially on the regulation of midstream T&D tariffs.

China: natural gas reform timeline

Jul 18 2018-20 Jul 13 Apr 14 Dec 15 Jun 17 New gas Further Introduced the net-back Opened gas Jul 15 PetroChina Jan 17 ROA for city distribution liberalising of pricing system; Pegged infrastructure SHPGX merged pipeline CQPGX gas tariff taking city-gate gas incremental gas price to to third-party establishment assets into one establishment distribution effect prices refinery oil products access pipeline company capped at 7%

Opening up Apr 15 Nov 15 Feb 14 Nov 16 Jan 17 2018-20 gas sources Merged Cut city-gate tariff by Opened gas Fujian became ROA for long-distance 2018-20 incremental CNY 0.7/m3; Encouraging pipelines to pilot province for transmission pipeline Spinning off of gas price with introduced price direct supply Liberalising third-party trial liberalisation operator capped at 8% pipeline assets existing gas celling 20% above for big C&I prices access of city-gate price goes into effect from oil majors price benchmark users

Source: Daiwa

1. Opening-up of upstream sources. The existing long-distance transmission pipelines are owned by the three oil majors, with CNPC being the largest, controlling over 70% of the pipeline network and 90% of the underground storage facilities. As a result, the oil majors can dominate the entire natural gas supply market by restricting external use of their pipelines. In order to liberalise natural gas prices, China is reshaping the market by introducing more sources of supply through: 1) opening up the pipelines to more upstream suppliers by spinning-off the pipeline assets of the oil majors, and 2) boosting LNG imports by granting third-party access to existing LNG terminals and facilitating the construction of new LNG terminals by private parties. For the pipeline asset spin-off, CNPC has already consolidated its pipeline subsidiaries under a single umbrella. Hence, we expect a majority of the pipelines to become independent soon. As for LNG terminals, while third-party access to existing LNG terminals are still limited at this point as oil majors are reluctant to allow third-party access (to do so would increase the difficulty for oil majors to sell their LNG purchased through their expensive long-term take-or-pay contracts), we see a rising number of terminals controlled by new entrants under construction and planning. Based on the prevailing Asian LNG spot prices, we estimate that the all-in LNG import cost is c.CNY0.1/m3, or c.5% cheaper than the average city-gate tariffs of coastal provinces during the non-heating season. With more diversified sources of supply, China hopes to see stronger competition in the upstream market and hence lower wholesale prices.

China: key events in transmission pipeline network spin-off Date Event Jun-13 CNPC formed a JV with Taikang Asset Management and Guolian Fund and a injected 50% stake of PetroChina West Pipelines Company into the JV Apr-15 CNPC announced its plan to sell its 100% stake of PetroChina Eastern Pipeline Company Nov-15 CNPC sold 50% of its stake in Central Asia-China gas pipelines to CNIC Nov-15 CNPC set up PetroChina Pipelines Company Dec-15 CNPC consolidated its gas pipeline assets under PetroChina Pipelines Company, with 72.3% ownership with other 11 shareholders owning the rest Dec-16 CNPC opened up its West-to-East transmission pipeline to Guanghui Energy, the first third-party access to PetroChina pipelines May-17 The State Council published opinions on deepening the Oil and Gas Reform which clearly stipulates the gradual spin-off of existing cross- province and intra-province pipeline networks and opening-up of third-party access

Source: EEO, Daiwa

China Gas: 12 January 2018

China: existing and upcoming LNG terminals Starting Controlled by oil Current/designed LNG sources (countries / Status Location Province Owner date majors? capacity (m tonne) companies) 2006 In-operation Dapeng Guangdong CNOOC (35%), BP (30%), Shenzhen Gas (10%), others (25%) Yes 6.8 Australia 2008 In-operation Putian Fujian CNOOC (60%), Fujian Investment & Development (40%) Yes 6.3 Indonesia 2009 In-operation Yangshan Shanghai Shenergy (55%), CNOOC (45%) Yes 3 Malaysia, BP, Australia 2011 In-operation Dalian Liaoning CNPC (75%), Dalian Port (20%), Dalian Construction Investment Yes 6 Qatar, Australia, Iran (5%) 2012 In-operation Ningbo (I) Zhejiang CNOOC (51%), Zhejiang Energy (29%), Ningbo Power (20%) Yes 3 CNOOC, Shell, BP 2012 In-operation Rudong Jiangsu CNPC (55%), Pacific Oil & Gas (35%), Jiangsu Guoxin Yes 6.5 Qatar, Australia Investment (10%) 2012 In-operation Dongguan Guangdong JOVO Group No 1 Indonesia, Malaysia 2013 In-operation Zhuhai Guangdong CNOOC (50%), Yudean (25%), Guangzhou Development (25%) Yes 3.5 Qatar, Australia 2013 In-operation Nanjiang Tianjin CNOOC Yes 2.2 2013 In-operation Caofeidian Hebei Kunlun Energy (51%), Beijing Enterprise Holding (29%), Hebei Yes 6.5 Qatar, Australia, Iran Gas (20%) 2014 In-operation Hainan Hainan CNOOC Yes 3 Qatar, Australia 2014 In-operation Qingdao Shandong Sinopec Yes 3 Papua New Guinea 2016 In-operation Jieyang Guangdong CNOOC Yes 2 Qatar 2016 In-operation Beihai Guangxi Sinopec Yes 3 2017 In-operation Qidong Jiangsu Guanghui Energy No 0.6 Malaysia, Qatar, US 2017E Under- Diefu Guangdong CNOOC (70%), Shenzhen Energy (30%) Yes 4 construction 2018E Under- Zhoushan Zhejiang ENN No 3 Chervon, Total Group construction TBC Under- Nanjiang Tianjin Sinopec Yes 3 construction TBC Under- Ningbo (II) Zhejiang CNOOC Yes 3 construction TBC Under- Chaozhou Guangdong Sinopec, Huanfeng Yes 1 construction TBC Approved Wenzhou Zhejiang Sinopec Yes 3 TBC Approved Shenzhen Guangdong CNPC Yes 3 TBC Planning Rizhao Shandong Royal Golden Eagle No 2 TBC Planning Penglai Shandong Datong Reciprocity and Baota Petrochemical No 2.6 TBC Planning Lianyungang Jiangsu Huadian No 3 TBC Planning Shantou Guangdong Guangdong Yudean No 3 TBC Planning Zhangzhou Fujian CNOOC Yes 3 TBC Planning Binhai Jiangsu CNOOC Yes 3 TBC Planning Yantai Shandong Poly-GCL Petroleum, Yantai Port No 3 TBC Planning Zhoushan Zhejiang Hebei Energy No 3 Total as of 2017 60

Source: Companies, Daiwa

China: all-in LNG import cost vs. city-gate tariffs in coastal region during non-heating season (CNY/m3) 2.2

2.08 2.08 2.09 2.1 2.06

2.0 1.9 1.9 1.91 1.88 1.88 1.88 1.9

1.8

1.7 All-in import Guangdong Shanghai Liaoning Zhejiang Jiangsu Tianjin Hebei Shandong Guangxi LNG cost Source: NDRC, Daiwa estimates; note: as of end-2017

2. T&D regulation. In October 2016, the NDRC issued a notice to cap the ROA of long-distance transmission operators at 8%, together with detailed guidelines on cost calculation, effective from January 2017. After finishing the review of cost materials submitted by the pipeline operators, the NDRC announced plans to cut the tariffs of the 13 long-distance transmission pipelines in the country by 15% on average based on the 8% ROA threshold in late August 2017. Afterwards, the tariffs will be subject to periodic review to reflect the change in operating costs and utilisation. Similarly, for downstream distribution, the NDRC published a notice to cap the ROA at 7%, effective from July 2018. While it is not in effect yet, some provinces like Hunan have already finished their consultation with local stakeholders and rolled out their own regulations based on the NDRC’s notice. Regarding province-level or city-level short-distance transmission pipelines, although the

China Gas: 12 January 2018

NDRC has not set a specific return cap, it has encouraged local governments to propose their own return caps with reference to the cost-plus-reasonable-return principle. For example, Fujian province has set the return cap on province-level short-distance transmission pipelines at 8% with a utilisation threshold of 75%, and we expect other provincial governments to roll out their return caps gradually. As a result, the whole natural gas T&D network should be subject to the return regulation not later than 2018-19, on our estimates, which should markedly lower overall T&D charges.

China: announced return regulation on natural gas T&D sessions T&D sessions Return cap Effective date Cross-province transmission 8% ROA with 75% utilisation threshold. The tariffs are subject to regular review every three 1-Jan-17 years Province-level and city-level Not specific cap yet but the NDRC encourages referencing the 8% ROA cap of the long- N/A transmission distance transmission City distribution 7% ROA with a maximum transmission loss of 4%. The tariffs are subject to regular review 1-Jul-18 every three years

Source: NDRC, Daiwa

3. Adoption of market-based pricing. To enhance the level of price discovery, China has set up two national natural gas exchanges, namely the Shanghai Petroleum and Gas Exchange (SHPGX) and the Chongqing Petroleum and Gas Exchange (CQPGX), in which downstream users like LNG factories can directly transact with upstream suppliers like CNPC. In September 2017, SHPGX went a step further and introduced competitive bidding for piped natural gas, with the transaction price largely driven by market demand and supply. With more transactions going through the exchanges, natural gas tariffs will be more market-based while the government-mandated city-gate tariffs will become less indicative over time. In 2017, SHPGX targets to complete 50bcm of transactions, representing 64% YoY growth and c.20% of annual national consumption.

China: gas price liberalisation timeline since 2011 Date Major Events Dec-11 Set up Price Reform Pilot Programme in Guangdong and Guangxi to change the regulation focus from well-head prices to city-gate prices and change the pricing mechanism from cost-plus to net-back pricing which is referenced on competing fuels like heating oil and LPG Jun-13 Rolling out net-back pricing mechanism across the nation. In the beginning, it only applies to the incremental volume while the city-gate tariffs of existing volume are adjusted in three steps. Sep-14 Fully liberalising the city-gate tariffs of imported LNG and unconventional natural gas Apr-15 Unifying the city-tariffs of existing volume and incremental volumes Apr-15 Liberalising the city-gate tariffs for direct-supply (except for use in fertiliser industry) Jul-15 Establishment of SHPGX, the first national natural gas exchange in China, to facilitate market-based pricing Nov-15 Cutting the national city-gate prices greatly by 0.7/m3 to reflect the plunging oil prices; allowing supplier to adjust prices upwards by a maximum of 20% above the benchmark city-gate price based on market conditions Oct-16 Capping ROA for long-distance transmission pipeline operators at 8% effective from January 2017 Nov-16 Fujian becomes the pilot province for complete liberalisation of city-gate price Nov-16 Liberalising the city-gate tariffs for direct-supply of natural gas used as fertiliser feedstock Jan-17 Establishment of CQPGX, the second national natural gas exchange in China Jun-17 Capping ROA for city-gas distributors at 7% (only applicable to gas distribution business) effective from July 2018 Sep-17 SHPGX launched competitive bidding for piped natural gas

Source: NDRC, Daiwa

China Gas: 12 January 2018

Robust consumption to be unleashed

Given that T&D fees account for c.60% of gas non-residential retail tariffs on our estimates, we concur that the government’s curb on the return of the T&D network operators will effectively reduce the cost burden borne by the core end-users of natural gas and boost the economics of natural gas compared with coal. Indeed, if we assume a 15% reduction (same as the level of cuts in cross-province tariffs in September 2017) in provincial transmission tariffs and a 10% cut (our base case assumption) in distribution tariffs upon the first round of tariff review by provincial development and reform commissions (DRCs) and local price bureaux in 2018, we estimate that the end non-residential retail tariff will drop by 8% (including the effect of the pass-through of the cross-province tariff cut). To put things into perspective, as an industrial fuel (the second-largest behind coal in China), we estimate natural gas will see its cost per effective heat value improving to 2.4x that of coal, from 2.7x beforehand, as a result of the first round of the T&D cut, which should be completed by end-2018.

China: cost per effective heat value comparison among major fuel for industrial use Coal Diesel Natural gas Natural gas after T&D cut Energy content per unit (MJ/kg, MJ/L, MJ/cm) 29 38 36 36 CNY/MJ 0.02 0.16 0.08 0.07 Heating efficiency 70% 80% 90% 90% Cost per heating unit vs Coal (x) 2.7 2.4 Cost per heating unit vs Diesel (x) 0.4 0.4

Source: Frost & Sullivan, NBS , Daiwa estimates

While we understand that natural gas is still a more expensive source of fuel compared with coal, we do see the price gap narrowing over time, on the back of: 1) the higher procurement cost of coal, as China is promoting the replacement of cheaper scattered coal with more expensive briquette (the price is 100% higher), 2) the government’s increasing subsidies on gas usage, and 3) a continued reduction in natural gas well-head prices and T&D tariffs (see Chapter 4) as price reform continues. In total, we expect the average non-residential gas retail tariff to decline by 30% from CNY3.0/m3 in 2016 to CNY2.0/m3 in 2025E. Based on existing coal prices, we estimate coal will only be 45% cheaper than natural gas in 2025E, down from 60% in 2016.

China: breakdown of average non-residential China: breakdown of average non-residential gas retail tariff in 2016 gas retail tariff in 2020 (CNY/m3) (CNY/m3) 3.5 3.0 3.0 2.5 0.7 2.5 0.9 2.0 2.0 0.2 0.3 1.5 1.5 0.6 3.0 0.5 2.5 1.0 1.8 1.0 1.8 1.8 2.1 1.6 1.6 1.1 1.1 0.5 1.2 1.2 0.5 0.0 - - 0.0 - - Well-head Long-distance City-gate tariff Intra-province Distribution Retail tariff Well-head Long-distance City-gate tariff Intra-province Distribution Retail tariff price transmission transmission tariff price transmission transmission tariff tariff tariff tariff tariff

Source: Wind, Daiwa estimates Source: Wind, Daiwa estimates Note: For non-direct supply, non-CTG customers Note: For non-direct supply, non-CTG customers

China Gas: 12 January 2018

China: breakdown of average non-residential China: breakdown of average non-residential gas retail tariff in 2023 gas retail tariff in 2025 (CNY/m3) (CNY/m3) 2.5 2.5

2.0 0.6 2.0 0.5 1.5 0.2 1.5 0.2 0.4 2.2 1.0 1.0 0.4 2.0 1.6 1.4 1.4 1.5 0.5 1.0 1.0 1.3 1.3 0.5 0.9 0.9 0.0 - - 0.0 - - Well-head Long-distance City-gate tariff Intra-province Distribution Retail tariff Well-head Long-distance City-gate tariff Intra-province Distribution Retail tariff price transmission transmission tariff price transmission transmission tariff tariff tariff tariff tariff

Source: Wind, Daiwa estimates Source: Wind, Daiwa estimates Note: For non-direct supply, non-CTG customers Note: For non-direct supply, non-CTG customers

In light of the fact that more than 90% of the coal consumption comes from the commercial and industrial (C&I) segments in China, the majority of coal buyers are price-sensitive and hence the improving economics of natural gas over coal should be able to stimulate demand. Together with the policy headwinds on the use of coal, the process of coal-to-gas conversion should speed up. Coupled with abundant international supply (especially LNG) to satisfy the strong demand, we expect China natural gas consumption to grow at 11% CAGR from 2016 onward to 525bcm in 2025, representing 14% of China’s total primary energy consumption.

China: natural gas consumption (bcm)

600 525 16% 14% 500 12% 400 350 315 10% 280 300 245 8% 206 171 187 193 6% 200 134 150 108 4% 100 2% 0 0% 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E 2025E Natural gas consumption (LHS) % of primary energy consumption (RHS)

Source: CEIC, Daiwa estimates

China: natural gas demand breakdown China: natural gas supply breakdown 2016 demand 2016-2025E incremental demand 2016 supply 2017-2025E incremental supply Gas-fired power Domestic conventional gas Industrial CTG Transportation Rural gas City-gas: residential Domestic unconventional gas Imported piped gas City-gas: commercial Industrial (non CTG) Imported LNG 11 bcm (4%) 42 bcm (13%) 31 bcm (10%) 128 bcm (40%) 43 bcm (13%) 319 bcm 51 bcm (16%) 319 bcm 53 bcm (17%) 44 bcm (14%) 66 bcm (21%) 64 bcm (20%) 72 bcm (22%) 206 bcm 33 bcm (10%) 209 bcm

Source: Wind, Daiwa estimates Source: Wind, Daiwa estimates

China Gas: 12 January 2018

Chapter 2

What are the core demand drivers behind solid consumption growth of natural gas?

China Gas: 12 January 2018

Dissecting upcoming natural gas demand

While the increasing adoption of natural gas seems inevitable under the favourable price reform and government support discussed in Chapter 1, the key questions now are: 1) how large is the untapped market, and 2) what will be the primary drivers. To answer these questions, we employ a bottom-up approach in this chapter to examine each major use of natural gas to attempt to quantify upcoming natural gas demand.

Strong 11% demand CAGR until 2025E, led by industrial fuel and rural gas Based on our findings, we believe there is still ample scope for growth in natural gas demand and estimate demand will expand at a 14% CAGR over 2016-20E and an 8% CAGR over 2020-25E. By 2025E, we expect natural gas demand to reach 525bcm, which is 150% higher than the national consumption in 2016, representing 14% of primary energy consumption. In particular, we see industrial fuel/ rural gas as the most important growth drivers, accounting for 33%/16% of incremental demand. Below we summarise the individual growth prospects for each major use of natural gas.

China: natural gas demand projection China: 320bcm incremental demand breakdown by major use over 2016-25E

(bcm) Others Gas-fired power 600 Industrial (non- 5% 10% 525 CTG) 500 13% Industrial coal- 400 350 City-gas to-gas (CTG) 315 commercial 280 20% 300 245 9% 206 200 City-gas Rural gas 100 residential 16% Transportation 13% 14% 0 2016 2017E 2018E 2019E 2020E 2025E Source: Wind, Daiwa estimates Source: Daiwa estimates

Industrial fuel (CTG/ non-CTG: 20%/13% of incremental demand): We expect demand from industrial fuel to register an 11% CAGR between 2016 and 2025E and remain the largest user of natural gas, thanks to strong demand from new industrial coal-to-gas (CTG) conversion (60% of total additional industrial demand). Despite the strong volume growth, the distribution tariff for new industrial CTG demand is relatively weak at c.CNY0.5/m3 (non- industrial CTG: c.CNY0.8/m3) as distributors generally need to offer discounts to acquire users given industrial CTG clients are less motivated to adopt natural gas as their energy cost would double, compared with non-CTG users, which would see more favourable economics (oil-to-gas clients will likely see 50% energy cost saving).

Rural gas (16% of incremental demand): Although a relatively new demand driver, rural gas demand should be the second-largest contributor of incremental natural gas consumption until 2025E, on the back of 43m potential new rural connections from northern and northeast China. Compared with urban residential clients, the margin on gas sales to rural households will be thinner (CNY0.4/m3 vs CNY0.55/m3), given their lower affordability.

Transportation/ power and heat cogeneration (14%/10% of incremental demand): We see demand from transportation rising at an 11% CAGR over 2016-25E. However, this will be largely driven by LNG-vehicle growth as opposed to CNG vehicles, given the continuing competition from EV. As for power and heat co-generation, we are less optimistic than the government and see demand increasing only at a 7% CAGR over 2016-25E, the slowest among the major drivers due to inferior investment returns and a lack of solid policy support.

City gas (residential/commercial: 13%/10% of incremental demand): Regarding traditional city gas projects, we estimate residential demand will expand at an 11% CAGR over 2016-25E, on the back of increasing penetration (2015: 42.8%) and urbanisation. For the commercial segment, we expect growth to be slightly higher (12% CAGR) over the same period, primarily driven by coal-to-gas conversion from large heating users like hotels, hospitals, and central heating companies.

In the remainder of this chapter, we analyse each major use of natural gas and explain how we come up with each growth forecast.

China Gas: 12 January 2018

China: demand and margin comparison for major natural gas volume drivers over 2016-25E

Dollar margin (CNY/m3) 1.2

1.0 Transportation City-gas commercial 0.8 Industrial (non-CTG) 0.6 0.4 Rural gas City-gas residential Industrial CTG 0.2 Power and heat co-generation 0.0 0 10 20 30 40 50 60 70 Coal to gas oil to gas Incremental demand over 2016-25E (bcm)

Source: Daiwa estimates

China: natural gas demand forecast (in bcm) 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E … 2025E

Total demand 108 134 150 171 187 193 206 245 280 315 350 525 Residential, commercial, industrial and chemical 79 99 112 129 139 135 139 171 197 223 249 381 Transportation 11 14 15 18 21 24 27 30 34 40 45 71 Power generation, heating and others 18 22 23 24 26 34 40 45 49 53 56 73

Demand proportion Residential, commercial, industrial and chemical 73% 74% 75% 75% 75% 70% 68% 70% 70% 71% 71% 73% Transportation 10% 10% 10% 10% 11% 12% 13% 12% 12% 12% 13% 13% Power generation, heating and others 17% 16% 15% 14% 14% 18% 19% 18% 18% 17% 16% 14%

Demand growth rate 21% 24% 12% 14% 10% 3% 7% 19% 14% 13% 11% 8% Residential, commercial, industrial and chemical 24% 13% 15% 8% -3% 3% 23% 15% 13% 12% 9% Transportation 30% 12% 14% 22% 11% 12% 12% 15% 15% 14% 9% Power generation, heating and others 19% 4% 9% 7% 31% 16% 12% 10% 8% 6% 5%

Natural gas as % of primary energy consumption 4% 5% 5% 5% 6% 6% 6% 7% 8% 9% 10% 14%

Source: CEIC, Wind, Daiwa estimates

China Gas: 12 January 2018

Industrial fuel: 33% of 2016-25E new natural gas volume

Accounting for c.20% of total coal consumption in China, industrial fuel is the second-largest user of coal and hence is highlighted by the government as one of the key areas for coal-to-gas conversion. For now, coal represents 73% of the total industrial fuel, compared with just 10% for natural gas, implying a large penetration opportunity for natural gas. In terms of users, the building materials/chemicals/textiles industries are the major owners of industrial boilers in China, controlling 12%/11%/19% of industrial boilers by capacity, respectively.

China: industrial fuel breakdown by primary China: ownership of industrial boiler breakdown energy by industry

Others Metallurgy 9% 8% Building materials 12% Natural gas 10% Others 43% Oil Chemical 8% 11%

Coal Defense 73% 7% Textile 19%

Source: China Securities Journal, Wusuobuneng, Daiwa estimates Source: ifeng.com, Daiwa estimates

Unequivocal support from the government

In our view, China’s government has demonstrated a strong willingness to push for industrial coal-to-gas conversion, particularly in the ceramic, construction materials, electrical and mechanical, glass, and textile industries, as shown by its: 1) explicit targets for shutting down coal-fired boiler facilities, 2) rolling out more subsidies, and 3) strict local enforcement for closing down coal-fired boilers. . Explicit targets for shutting down coal-fired boiler facilities: In its 13th FYP, the government clearly stated its aim to close down all 10t/h or smaller coal-fired boilers in built-up areas in all cities and 20t/h or smaller coal/oil- fired industrial boilers in all the highly-polluting fuel-free zones. Given that c.75%/c.85% of total coal-fired boilers in terms of units/capacity are for industrial use, this implies massive coal-to-gas conversion for the industrial sector, particularly in the BTH area, Yantgze River delta region, Pearl River delta region, and northeast China. In total, the five-year plan aims to replace 189kt/h equivalent of coal-fired boilers (c.9% of total coal-fired boiler capacity) with gas-fired boilers, leading to 45bcm of additional natural gas consumption.

China: existing targets for coal-fired boilers demolition and replacement in selected provinces Provinces/ municipalities Target Beijing Close all 10t/h or smaller coal-fired boilers and all 35t/h or smaller coal-fired boilers in built-up areas Close all industrial coal-fired boilers in the downtown area, all 35t/h or smaller industrial coal-fired boilers in the Binhai area, Dongli Tianjin area, Jinnan area, Xiqing area, Beichen area, and all the 10t/h or smaller industrial coal-fired boilers in the remaining areas Close all 10t/h or smaller coal-fired boilers or above in cities and ban the construction of 20t/h or smaller coal-fired boilers in the built- Guizhou up areas in all prefecture-level cities Close all boilers powered by highly polluting fuels (except for heating purposes) in all built-up areas across all county-level cities and Zhejiang all 10t/h or smaller coal-fired boilers in other areas Close all 10t/h or smaller coal-fired boilers in key control areas and ban the construction of 10t/h or smaller boilers powered by highly Guangdong polluting fuels in the province Close all 35t/h or smaller coal-fired boilers in built-up areas in all prefecture-level cities and all 10t/h or smaller coal-fired boilers in all Hebei urban-rural fringe areas and county-level cities Close all 10t/h or smaller coal-fired boilers in built-up areas in all prefecture-level cities and in central heating areas in all county-level Henan cities Close all 35t/h or smaller coal-fired boilers in built-up areas in all prefecture-level cities and county-level cities and all 10t/h or smaller Shandong coal-fired boilers in all urban-rural fringe areas and rural areas Close all 20t/h or smaller coal-fired boilers in built-up areas in all prefecture-level cities and all 10t/h or smaller coal-fired boilers in Shanxi built-up areas in all county-level cities

Source: Provincial Department of Environmental Protection

China Gas: 12 January 2018

Rolling out more subsidies: Other than unambiguous targets to shut down small and inefficient coal-fired boilers, local governments also have rolled out their own subsidy programmes to incentivise boiler users to speed up the whole demolition and replacement process. For some key air pollution prevention areas, we note that the local governments have stepped up their effort on subsidisation. For example, the Hebei provincial government has published a compensation plan in July 2017 which unifies the subsidy policy and amounts for the whole province as opposed to the individual subsidy schemes set by different city/county governments, to ensure the effectiveness of the overall financial aid programme.

China: subsidies for coal-fired boilers demolition and modification in selected provinces Provinces/ municipalities Cities Action Subsidy Beijing N/A Modification of coal-fired boilers into boilers powered by cleaner fuels CNY130k per t/h Demolition of coal-fired boilers CNY30k per t/h Hebei All cities Modification of coal-fired boilers into boilers powered by cleaner fuels CNY80k per t/h Henan Luoyang Modification of coal-fired boilers into boilers powered by cleaner fuels CNY20k per t/h Shandong Jinan Early demolition/modification of coal-fired boilers into boilers powered by cleaner fuels CNY100k per t/h Shandong Jinan Demolition/modification of coal-fired boilers into boilers powered by cleaner fuels CNY50k per t/h

Source: Department of Environmental Protection in various provinces

Strict local enforcement for shutting down coal-fired boiler facilities: On the execution side, we note that enforcement agencies have taken strong action against unqualified boiler users and often adopt extreme means such as cutting off water and electricity supplies in order to make them comply with regulations. As a result, local coal-fired boiler reduction policies can usually be strictly implemented, as highlighted by the accomplishments in the BTH area. For example, there are a total of 8488t/h of coal-fired boilers being modified to be powered by cleaner fuel in 2016, almost triple the annual target. Other than Beijing, we also observed a similar promising situation in Tianjin and Hebei where the reduction targets have been exceeded. Given that industrial coal-to-gas conversion will become one of the metrics of performance evaluation for local officials in accordance with the Opinion on Facilitating the Use of Natural Gas published in July 2017, we believe the level of enforcement will be further enhanced going forward.

China: scoreboard on demolition and modification of coal-fired boilers in the BTH area in 2016 Provinces/ Completed # of Completed % of completion of annual municipalities Description units capacity(t/h) target Beijing Replacement of coal-fired boilers 1,858 8,488 283% Tianjin Replacement of industrial coal-fired boilers 434 N/A 106% Hebei Demolition of coal-fired boilers 12,919 21,863 130% Hebei Replacement of industrial coal-fired boilers 7,281 21,463 121% Average 160%

Source: Department of Environmental Protection and DRC in various provinces

11% demand CAGR from industrial fuel over 2016-25E

In light of the abovementioned factors, we are confident in the government’s ability to meet, if not surpass, its targets for clearing coal industrial boilers. Currently, the Chinese government mainly focuses on demolishing small coal-fired boilers with capacity of 10t/h or less. However, as a large proportion of 10t/h or smaller coal-fired boilers will be demolished soon, we believe the government’s focus will gradually switch towards bigger coal-fired boilers with a capacity of between 10t/h and 35t/h after 2017, following the lead of the BTH area. On our estimates, there are a total of 120k units or 504k t/h of industrial coal-fired boilers with a capacity of 10t/h to 35t/h in China, (28%/26% of total industrial coal-fired boiler capacity/units). Assuming 40% of these are converted into gas-fired boilers, this would mean 200k t/h of new gas-fired boilers. Given an average of 3,000 annual utilisation hours, we estimate that the total incremental gas consumption from conversion of 10-35t/h industrial coal-fired boilers would be 50bcm.

China Gas: 12 January 2018

China: potential gas demand from conversion of 10-35t/h industrial coal-fired boilers Unit Total capacity of coal-fired boilers in China m t/h a 1.80 Capacity % of boilers between 10t/h - 35t/h % b 28% Total capacity to be eliminated m t/h c = a * b 0.50 % converted to gas boilers % d 40% Total coal-to-gas capacity m t/h e = c * d 0.20 Hourly gas consumption per t/h cm f 83 Utilisation hour per year hour g 3000 Annual gas consumption per t/h mcm h = f * g 0.25 Annual gas consumption from upon conversion bcm i = e * h 50

Source: Daiwa estimates Note: The total 2016-25E incremental gas demand from industrial CTG conversion will be 64bcm with 50bcm coming from conversion of 10-35t/h industrial coal-fired boilers and 14bcm coming from the conversion of remaining 10t/h or smaller industrial coal-fired boilers

Referencing the pace of the demolition and replacement of 10t/h or smaller coal-fired boilers, we believe the 50bcm additional gas consumption will be fully realised by 2025E at the latest, translating into a c.6bcm increment per year on average. Upon the completion of 10t/h to 35t/h boilers conversion, we expect the government to target 35t/h or larger boilers after 2025. Accounting for the 50bcm incremental demand from industrial CTG, together with organic growth from existing industrial natural gas users, we estimate natural gas demand from industrial fuel to expand at an 11% CAGR to 177bcm over 2016-25E, representing 33% of total natural gas demand in 2025E.

Industrial coal-fired boilers conversion roadmap

<=10 t/h 10 to 35 t/h >= 35 t/h

2013 to 2017 2018 to 2025 After 2025

Source: Daiwa estimates

China: industrial coal-fired boiler breakdown China: industrial coal-fired boiler breakdown by capacity by unit > 35 t/h 8% < 10 t/h 20-35 t/h 20% 9%

> 35 t/h 52% 10-20 t/h 10-20 t/h 14% 17% < 10 t/h 67%

20-35 t/h 14%

Source: MEP, Daiwa estimates Source: MEP, Daiwa estimates Notes: The breakdown is based on original capacity in2012 before the government’s demolition Notes: The breakdown is based on original capacity in 2012 before the government’s plan demolition plan

China Gas: 12 January 2018

China: breakdown of incremental industrial natural gas demand over 2016-25E bcm 200

150 42 bcm (40%)

50 bcm (47%) 100 14 bcm (13%) 50 71 bcm 0 2016 demand Incremental demand over 2016-25E

CTG demand (10 t/h or smaller boiler conversion) CTG demand (10 -35 t/h boiler conversion) non-CTG demand

Source: Daiwa estimates

China Gas: 12 January 2018

Rural gas: 16% of 2016-25E new natural gas volume

Scattered coal burning is a major hidden polluter

Scattered coal burning is defined as the use of cheaper bulk and other low-grade coal by individuals and small businesses, mostly in rural areas. Unlike power plants and other large coal users, users of scattered coal generally do not treat or filter (eg, desulphurisation) the resulting air pollutants from coal burning. Together with the fact that cheaper low-grade coal is more polluting, the amount of air pollutants emitted from each tonne of scattered coal burning is more than c.15 times that of coal burning by power plants. As a result, even though scattered coal accounts for only c.10% of total coal consumption in the BTH area, it is responsible for c.50% of the total pollutants arising from coal burning.

Government targeting rural households to decrease the use of scattered coal

In 2015, China consumed 750m tonnes of scattered coal (c.20% of annual total coal consumption), of which c.30% was used by rural households, which primarily burned coal for heating in winter and cooking. Given the highly polluting nature of scattered coal burning, the central government has clamped down on scattered coal use by rural households since 2016. For example, in the 2017 Air Pollution Prevention Plan for BTH and surrounding areas, the MEP aims to fully control use of scattered coal in urban villages, rural-urban fringe zones and village areas in the 2 + 26 cities. As a result, affected households will be forced to switch to alternative fuels such as natural gas. For 2017, the government has targeted to complete coal to cleaner fuel conversion for 3.6m rural households in northern China.

China: provincial target on rural coal to cleaner fuel conversion for 2017E Household (000) 2,000 1800 1,800 1,600 1,400 1,200 1,000 800 600 420 390 350 400 300 290 200 0 Beijing Tianjin Hebei Shanxi Shandong Henan Source: MEP

To facilitate rural coal-to-gas conversion, the government is offering subsidies to incentivise rural households, in light of the higher gas usage cost compared with that of coal. Based on our findings, most local governments in northern China that have confirmed the subsidy policy are offering a c.CNY10k/household subsidy for gas appliances, connection and gas usage over the first three years of conversion. With the subsidies, we see the natural gas cost is at a 22% discount to that of coal, hence rural households should be financially motivated to adopt the conversion. While some argue that villages may switch back to coal burning upon the end of subsidies, we believe the chances are slim given the: 1) government’s strict control on scattered coal consumption, 2) decreasing supply of cheap low-grade coal, and 3) the diminishing financial impact of the cost difference between the use of coal and natural gas on the back of increasing income of rural households (the cost difference accounts for just 1.4% of rural household income, on our estimates).

China: typical rural residential natural gas subsidy Item Cost (CNY) Subsidy (CNY) Provincial subsidy portion City & county subsidy portion Gas appliances 4,000 2,700 50% 50% Gas connection 4,000 4,000 25% 75% Gas sales (for first three 9,540 3,600 33% 67% years) Total 17,540 10,300 34% 66%

Source: Various government policies, Daiwa estimates; note: as at end-2017

China Gas: 12 January 2018

China: fuel economics for rural coal-to-gas conversion Item ASP (CNY) Amount consumed Heat content Total cost (CNY) Gas cost premium over coal Coal 1/kg 2,550 kg 4,000 kcal/kg 2,550 n.a. Gas - without 2.65/m3 1,200 m3 8,500 kcal/ m3 3,180 25% subsidy Gas - with subsidy 1.65/m3 1,200 m3 8,500 kcal/ m3 1,980 -22%

Source: Various government policies, Daiwa estimates; note: as at end-2017

Three stages of rural coal-to-gas conversion, with a potential market of 43m households

For rural coal-to-gas conversion, we expect the government to launch its campaign gradually, in three main stages. For 2017-18 (stage 1), the BTH areas and some heavily polluted cities in northern China (eg, the 2 + 26 cities) will be the focus. After the conversion of the BTH area is largely completed, from 2019-21 (stage 2), we believe the focus will shift to other parts of northern China, namely Henan, Shandong, and Shanxi, given their proximity to strategically important BTH areas and their severe air pollution (Henan/Shanxi/Shandong rank first/fourth/ninth out of the total 31 Chinese provinces and municipalities in terms of PM2.5 in 1H17). After 2021 (stage 3), when the conversion in northern China is nearly complete, we believe the last target in terms of geographic region for rural gas projects will be northeast China, thanks to the new Russian gas supply, and selected provinces in northwest China that have severe air pollution (eg, Shaanxi). In total, we estimate total penetrable rural households in all three stages amount to 71m. Considering that 60% of these will potentially go for coal-to-gas conversion (may not be geographically feasible for some, eg, mountainous areas or adopt other means such as coal-to-electricity conversion), the rural coal-to-gas market amounts to 43m households, on our estimates.

China: potential market size of rural coal-to-gas projects Est number of rural Stage Province Total Population (m) Rural population (%) Average household size household (m) Beijing 21.7 13.5 2.5 1.2 1 Tianjin 15.6 17.1 2.8 1.0 (2017-2018) Hebei 74.7 46.7 3.2 10.8 Sub-total 12.9

Shandong 99.5 41.0 2.9 14.2 2 Shanxi 36.8 43.8 3.1 5.2 (2019-2021) Henan 95.3 51.5 3.4 14.5 Sub-total 33.9

Heilongjiang 38.0 40.8 2.8 5.6 3 Jilin 27.3 44.0 2.9 4.1 (2022-2025) Liaoning 43.8 32.6 2.8 5.2 Shaanxi 38.1 45 3.1 5.4 Xinjiang 24.0 52 3.3 3.8 Sub-total 24.1 Total 71 Conversion ratio 60% Potential market size 43

Source: Wind, Daiwa estimates

China: PM2.5 level of selected provinces in northern, northeast, and northwest China as of 1H17 (µg/m3) 100

0 Henan Shanxi Xinjiang Shaanxi Shandong Liaoning Jilin PM2.5 National average PM2.5

Source: Wind, Daiwa estimates

China Gas: 12 January 2018

51bcm new gas demand from rural gas by 2025E

Unlike other major uses of natural gas, demand from rural gas projects has only increased recently, given there were limited residential natural gas users in rural areas before 2016. Currently, we expect rural gas households to gradually increase to 19m in 2020E, on the back of the implementation of more coal-free zones and a more comprehensive financial aid programme. Assuming annual gas consumption of 1,200m3 for each rural household, we expect the total additional gas demand from rural coal-to-gas conversions to amount to 23bcm in 2020E, from close to zero in 2016. If all the feasible rural users (43m households) finish conversion by 2025E as we assume, total gas demand from rural gas can could reach 51bcm, representing a 17% CAGR over 2020-25E.

China: natural gas demand from rural coal-to-gas conversion 2017E 2018E 2019E 2020E … 2025E Rural gas household (m) 3 6 12 19 43 Growth (%) - 152% 87% 64% 17% Annual gas consumption per household (m3) 1200 1200 1200 1200 1200 Annual incremental gas demand (bcm) 3 5 7 9 6 Total gas demand (bcm) 3 8 14 23 51

Source: Wind, Daiwa estimates

China Gas: 12 January 2018

Transportation: 14% of 2016-25E new natural gas volume

Given that transportation is the second-largest source of PM2.5 after coal burning, the Chinese government is also determined to reduce the emission of pollutants from vehicles and vessels. One way to do so is through the promotion of CNG-powered passenger vehicles and LNG-powered trucks/vessels. Currently, petroleum is not surprisingly the major fuel, as it powered 97% of vehicles in China in 2016. For marine transportation, petroleum dominates the market as all inland vessels in China are fuelled by diesel.

China: vehicle ownership breakdown by fuel type China: inland vessel ownership breakdown by fuel type Hybrid/pure LNG CNG/LNG electricity 0% 3% 0%

Petroleum Diesel 97% 100%

Source: Wusuobuneng, Daiwa estimates; note: for 2016 Source: China5e, Daiwa estimates; note: for 2016

Natural gas enjoys strong economics vs. oil for land transportation

For land transportation, natural gas now has a cost advantage in China as its primary competing fuel is oil rather than coal, which is much cheaper. For example, using LNG and diesel retail price as a proxy, natural gas only costs c.50% of oil in terms of CNY/MJ. As a result, natural gas has a cost advantage over petroleum for both short- distance passenger vehicles (PV) and long-haul commercial vehicles (CV) from a fuel cost perspective. For example, on our estimates, the fuel cost of CNG PV is 43%/35% less than that of regular PV in inland/coastal regions while the fuel cost of a heavy-duty LNG truck is 44%/38% cheaper than that of a diesel truck in inland and coastal regions. Given the prevailing natural gas vehicle (NGV) retrofitting costs in China, we find that the payback period is as short as 0.2 years/0.8 years for taxis/heavy-duty trucks.

China: cost per energy content comparison in China: cost per energy content comparison in inland regions (end-2017) coastal regions (end-2017) CNY/MJ CNY/MJ 0.18 0.18 0.16 0.16 0.16 0.16 0.14 0.14 0.12 0.12 0.10 0.10 0.09 0.09 0.08 0.08 0.08 0.08 0.06 0.06 0.04 0.02 0.04 0.03 0.02 0.02 0.00 0.00 Coal Piped gas LNG Diesel Coal Piped gas LNG Diesel Source: Wind, Daiwa estimates Source: Wind, Daiwa estimates Note: we use Henan as a proxy for inland regions Note: we use Jiangsu as a proxy for coastal regions Note: we use annual average price for the calculation of LNG cost due to its seasonal Note: we use annual average price for the calculation of LNG cost due to its seasonal fluctuation fluctuation

China Gas: 12 January 2018

China: economics of a NGV vs. regular vehicle Passenger vehicle Heavy-duty truck Petroleum (L) CNG (m3) Diesel (L) LNG (kg) Fuel usage per 100km 8 8 31 28 CNY per unit of fuel - inland 6.6 3.7 6.2 3.8 CNY per 100km - inland 53 30 191 106 Natural gas vs oil -43% -44%

CNY per unit of fuel - coastal 6.6 4.2 6.1 4.2 CNY per 100km - coastal 52 34 190 118 Natural gas vs oil -35% -38%

Source: Wind, China NGV Business Intelligence, Daiwa estimates Note: we use annual average LNG and CNG prices due to their seasonal fluctuation

China: payback period for NGV conversion Units Taxi - inland Taxi - coastal Heavy-duty truck - inland Heavy-duty truck - coastal NG type CNG CNG LNG LNG Travel distance 000 km/year 110 110 150 150 Fuel cost saving for every 100km CNY 23 19 85 72 Total fuel cost saved 000 CNY/year 26 21 128 108 NGV retrofitting cost 000 CNY/vehicle 5 5 100 100 Payback period Year 0.2 0.2 0.8 0.9

Source: Daiwa estimates

Sufficient station network to facilitate growth of NGV ownership

Other than strong economics, a growing refuelling station network is also favourable for rising NGV use. Indeed, the government plans to have more than 1.2m natural gas refuelling stations in place in 4 years, translating to an 11% 2016-20E CAGR. Even though we understand the government’s intention to speed up the adoption of NGV vehicles through better station network coverage, we are more cautious on the growth of NGV refuelling stations in light of their currently low utilisation rate, deterring station owners from rapid expansion. As a result, we project a CAGR of only 5.1% for NGV refuelling stations until 2020E to 9.5k stations, from 7.8k in 2016, made up of equally driven growth of CNG stations and LNG stations. That said, despite our milder forecast, the projected scale of station network is sufficient to support the growth of NGV ownership, in our view, given the implied vehicle/station ratio in 2020E will be still low at 780 on our estimates, compared with the average of 1,100 in the 10 countries with the largest rates of NGV ownership.

China: NGV refuelling station forecasts 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E Total number of NGV refuelling station 3,016 4,196 5,576 6,409 6,983 7,800 8,349 8,796 9,186 9,526 YoY% 36% 39% 33% 15% 9% 12% 7% 5% 4% 4% Number of CNG stations 2,114 2,832 3,732 4,447 4,723 5,340 5,601 5,823 6,027 6,210 YoY% 33% 34% 32% 19% 6% 13% 5% 4% 4% 3% Number of LNG stations 902 1,364 1,844 1,962 2,260 2,460 2,748 2,973 3,160 3,316 YoY% 43% 51% 35% 6% 15% 9% 12% 8% 6% 5% Total NGV ownership ('000) 1,524 2,160 3,365 4,595 5,190 5,576 6,048 6,512 6,978 7,430 YoY% 37% 42% 56% 37% 13% 7% 8% 8% 7% 6% Number of NGV per station 505 515 603 717 743 715 724 740 760 780

Source: SAE-China, Daiwa estimates

LNG vehicle ownership is seeing solid growth thanks to strong demand for LNG heavy–duty trucks…

In 10M17, the production volume of heavy-duty LNG trucks expanded by 540% YoY to 75k units, representing 7.8% of the total heavy-duty trucks sold in China, exceeding the historical high of 6.7% recorded in 2014. Other than the pick-up in overall demand for heavy-duty trucks (71% YoY growth for 10M17), the robust growth is driven by: 1) the improving economics of LNG heavy-duty trucks, and 2) the strict ban on the use of old diesel trucks in some urban areas in northern China, while some ports like Tianjin prohibit the use of diesel trucks for coal transportation. On our estimates, the economics of LNG heavy-duty trucks will be obvious when the LNG/diesel price ratio drops below 0.75, as evidenced by new truck sales. Given the: 1) ongoing unfavourable policies on diesel trucks, and 2) the low penetration rate of LNG heavy-duty trucks (c.5% in 2016), we forecast the growth of LNG vehicle ownership to remain strong, at a 30% CAGR over 2016-20E to 713k units.

China Gas: 12 January 2018

China: LNG heavy-duty truck sales against LNG to diesel retail price ratio 14,000 1.3 12,000 1.2 1.1 10,000 1 8,000 0.9 6,000 0.8 0.7 4,000 0.6 2,000 0.5

0 0.4

Jul-14 Jul-15 Jul-16 Jul-17

Jan-14 Jan-15 Jan-16 Jan-17

Mar-14 Mar-15 Mar-16 Mar-17

Nov-14 Nov-17 Sep-14 Sep-15 Nov-15 Sep-16 Nov-16 Sep-17

May-14 May-15 May-16 May-17

LNG heavy-duty truck sales volume (LHS) LNG (kg)/diesel (L) retail price ratio (RHS)

Source: Cnworld, Wind, Daiwa estimates

…yet the growth of CNG-vehicles looks set to slow due to greater competition from EVs

In contrast to the solid growth in LNG vehicle ownership, the development of the CNG vehicle market has slowed recently with the rise of EVs. In 2015/16, the growth YoY of CNG vehicle ownership contracted sharply to 12%/7%, respectively (2014: 36% YoY), since the Chinese government has been actively supporting the adoption of EVs from 2014 through a range of measures such as subsidies, tax rebates, and special access to transit lanes. Indeed, in 2017, despite the improving economics of natural gas, the growth of CNG vehicle ownership remained sluggish as indicated by the weak sales of CNG fuel cylinders. Given the continued policy tailwinds for EVs (eg, subsidies up until 2020E), we assume growth in CNG vehicle ownership will remain lacklustre in the medium term and only see a 6% 2016-20E CAGR to 6.7m units from 5.3m units in 2016.

In total, we expect total NGV ownership to amount to only 7.4m vehicles in 2020E, falling short of the government’s target of 10m, mainly due to the sluggish growth of CNG vehicles.

China: NGV ownership forecasts 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E Number of CNG vehicle ('000) 1,485 2,085 3,235 4,411 4,960 5,316 5,688 6,029 6,361 6,680 YoY% 35% 40% 55% 36% 12% 7% 7% 6% 6% 5% Number of LNG vehicle ('000) 39 75 130 184 230 260 360 482 617 750 YoY% 285% 95% 73% 42% 25% 13% 38% 34% 28% 21% Total NGV vehicles ('000) 1,524 2,160 3,365 4,595 5,190 5,576 6,048 6,512 6,978 7,430 YoY% 37% 42% 56% 37% 13% 7% 8% 8% 7% 6% Total civil vehicles ('000) 106,000 121,000 137,000 154,000 172,000 194,000 209,000 224,000 239,000 253,000 YoY% 16% 14% 13% 12% 12% 13% 8% 7% 7% 6% NGV penetration (%) 1.4% 1.8% 2.5% 3.0% 3.0% 2.9% 2.9% 2.9% 2.9% 2.9%

Source: SAE-China, Chyxx, CVworld, Xinhuanet, Daiwa estimates

Improving policy support for LNG vessels

As at end-2016, there were 130 LNG vessels in China, with more than 70% of them being idle. In terms of economics, given the expensive retrofitting cost (CNY1.2m for a 2,000-tonne vessel), the payback period is much longer for vessels than vehicles (17 years for a 2,000-tonne vessel) for natural gas conversion, which deters vessel owners. As for the refuelling network, there are fewer than 20 LNG refuelling stations as limited LNG vessel ownership creates a chicken-and-egg situation. Also, there is still a lack of standards for marine LNG refuelling, which hinders the overall pace of conversion. However, the government has been addressing the aforementioned issues through expanding the scope of its subsidy policies and speeding up the construction of new refuelling stations. For example, existing vessels are now eligible for conversion subsidies, which only applied to new vessels before, effectively shortening the payback period (17 years to 8 years for a 2,000-tonne vessel). Also, the government plans to set up more fuelling terminals, especially along the Yangtze River, Beijing-Hangzhou Grand Canal, and Xi River. In total, the government aims to add at least 180 more fuelling stations to reach 200 by 2020. As a result, we expect the growth of LNG vessel ownership to accelerate during the 13th FYP, with total ownership of 10k vessels by end-2020E.

China Gas: 12 January 2018

China: payback period for 2,000 tonne LNG vessel conversion Items Units LNG cost * CNY/tonne 3,822 Diesel cost* CNY/tonne 5,680 LNG usage per annum tonne/annum 120 Diesel usage per annum tonne/annum 100 Annual saving per year CNY k / year 71 LNG Retrofitting cost CNY k / year 1,200 Payback period (without subsidy) year 17 Subsidy CNY k 700 Payback period (with subsidy) year 7

Source: Wind, Sebweekly, Daiwa estimates Notes*:We use the annual average fuel prices in Shanghai Notes**:Assuming 65% conversion rate (Fuel mix: 65% LNG and 35% diesel)

11% natural gas demand CAGR from transportation over 2016 to 2025

Given the robust sales of new LNG heavy-duty trucks and their higher gas consumption per vehicle, we expect LNG vehicles to be the primary driver of demand growth from the transportation sector, accounting for 61% of the 18bcm incremental volume growth from 2016 to 2020. As for CNG, due to the slower pace of petrol-CNG conversion for PVs on the back of competition from EV, we forecast demand to expand at a mere 6% CAGR between 2016-20E and account for 30% of incremental demand. For LNG vessels, though we forecast demand to increase at a 193% CAGR for 2016-20E on improving government support, they will still be the smallest contributor and only account for 9% of the additional demand for the overall transportation sector, on our estimates, given a low base. After 2020, we still expect LNG vehicles to be the main contributors to additional natural gas demand. Nevertheless, LNG vessels should overtake CNG vehicles to be the second-largest driver of new natural gas demand on continued policy tailwinds and more developed infrastructure. In total, we expect transportation gas demand to reach 71bcm by 2025E, translating into an 11% CAGR for 2016-25E.

China: natural gas demand from transportation China: breakdown on natural gas demand from transportation bcm 100% 80 70 80% 60 50 60% 40 40% 30 20 20% 10 0 0% 2016 2017E 2018E 2019E 2020E … 2025E 2016 2017E 2018E 2019E 2020E … 2025E CNG vehicle gas consumption LNG vehicle gas consumption CNG vehicle gas consumption LNG vehicle gas consumption LNG vessel gas consumption LNG vessel gas consumption

Source: NEA, Daiwa estimates Source: NEA, Daiwa estimates

China: natural gas demand forecasts from transportation 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E … 2025E Total number of NG vehicles ('000) 1,524 2,160 3,365 4,595 5,190 5,576 6,048 6,512 6,978 7,430 9,060 Total NG vehicle gas consumption (bcm) 14 15 18 21 24 27 30 34 39 43 62 Total number of LNG vessels ('000) 0 0 0 0 0 0 1 2 5 10 50 Total LNG vessel gas consumption (bcm) 0 0 0 0 0 0 0 0 1 2 9 Transportation demand (bcm) 14 15 18 21 24 27 30 34 40 45 71 YoY% 30% 12% 14% 22% 11% 12% 12% 15% 15% 14% 9% Demand proportion 10% 10% 10% 11% 12% 13% 12% 12% 13% 13% 14%

Source: SAE-China, CVworld , NEA, Daiwa estimates

China Gas: 12 January 2018

China: breakdown of incremental transportation natural gas demand over 2016-25E bcm 80 70 9 bcm (20%) 60 50 25 bcm (58%) 40 30 10 bcm (22%) 20 10 27 bcm 0 2016 demand Incremental demand over 2016-25E

CNG vehicle demand LNG vehicle demand LNG vessel demand

Source: Daiwa estimates

China Gas: 12 January 2018

Power and heat co-generation : 10% of 2016-25E new natural gas volume

Gas-fired power is still underdeveloped in China relative to the international community

Currently, coal is the primary source used to generate electricity in China, with coal-fired capacity/generation representing 57%/63% of the total power generating capacity/power generation in China. In comparison, gas-fired IPPs only account for 5% of the total power generating capacity. In terms of generation, given the weak utilisation hours, the market share of gas-fired IPP is even smaller, at 3%, well below the equivalent figures of 23%/27% in the US/Japan. As a result, gas-fired power is not the largest user of natural gas in China, accounting for only 18% of total gas consumption.

China: power capacity mix China: power generation mix

Nuclear Others Solar Nuclear Others Solar 5% 0% 4% 1% 0% 9% Wind Wind 2% 4%

Hydro 20% Hydro 20% Coal 57%

Other thermal Other thermal 6% Coal 3% 63% Gas Gas 5% 3%

Source: CEC, BJX.com, Daiwa estimates, note: as of 2016 Source: CEC, BJX.com, Daiwa estimates, note: as of 2016

China: gas-fired power generation share of total China: gas-fired power share of total natural gas power generation consumption 50% 44% 70% 60% 60% 40% 50% 30% 27% 40% 35% 23% 28% 20% 30% 17% 20% 10% 3% 10%

0% 0% China US Japan UK China US Japan UK Source: CEC, BJX.com, Daiwa estimates, note: as of 2016 Source: CEC, BJX.com, Daiwa estimates, note: as of 2016

Challenges faced by gas-fired IPPs

Like other users of natural gas, gas-fired IPPs have been operating at a disadvantage given the weaker price competitiveness of natural gas compared with coal as fuel. On top of this, gas-fired IPPs also suffered from insufficient government support and local deficiencies in core technology on gas-fired power generation. Below we summarise the three major challenges faced by gas-fired IPPs.

1. Limited gas supply in heating season. Similar to other industrial natural gas buyers, gas-fired IPPs are facing limited gas supply during the peak heating season. Hence, their utilisation hours are negatively impacted. Also, the higher gas procurement cost will generally squeeze their margin as there is not a pricing mechanism for IPPs to pass through the seasonal increase in fuel costs, which account for c.90% of their total non-cash operating costs, in most provinces.

2. Low utilisation with insufficient subsidies. Given the more expensive tariffs of gas-fired power resulting from its higher operating cost, gas-fired power plants are mainly used only in the peak season in some places to satisfy extra demand by grid companies, leading to sub-optimal utilisation hours (gas average: c.2,800 hours vs. thermal average: c.4,200 hours). However, local governments do not provide sufficient subsidies to compensate for this peak shaving.

China Gas: 12 January 2018

3. High operating costs. In terms of unit fuel cost, gas-fired power is two times more expensive than coal- fired power. On top of that, gas-fired IPPs also bear huge upfront investment as they need to import the core components, such as turbine blades, as domestic manufacturers are still not equipped with the core technology. As a result, for ongoing servicing and maintenance, IPPs have to rely on original suppliers, thus pushing up their O&M costs. Together with the low utilisation of gas-fired power, the levelised cost of energy (LCOE) of a combined-cycle power plant in northern China is on average CNY0.63/kWh, which is 125% higher than that of an ultra-supercritical (USC) coal-fired power plant, on our estimates.

Due to the aforementioned factors, the return on a gas-fired power plant remains unattractive for now. On our estimates, the project IRR of a combined-cycle co-generation power plant is only 7.0%, which is low relative to the 8.1% project IRR of a USC coal-fired power plant and hence deters new investment in the field and hinders the development of gas-fired power in China.

Positive signs from the government …

In the 13th FYP for Natural Gas Development, the government aims to have gas-fired installed capacity of 110GW, accounting for over 5% of total installed capacity by the end of 2020, as opposed to no specific target mentioned in the 12th FYP. The 110GW capacity implies 54.5GW of new installations over 2015-20E, accelerating from the 40GW of new installations over 2010-15. On top of this, in the Opinion on Facilitating the Use of Natural Gas, the government aims to fine-tune the gas-power price linkage mechanism and distribute more subsidies in financially feasible areas to relieve the burden of gas-fired IPPs, especially for co-generation and distributed energy projects. In terms of tight supply in the winter season, the increasing supply from Central Asia and Russia and the commissioning of more LNG terminals should gradually ease supply constraints.

… yet the problem remains largely unsolved, in our view

While we acknowledge the ambitious capacity target set by the government and agree that the gas shortfall issue will fade over time when new supply ramps up given the current solid project pipelines, the core issue of poor returns is largely unsolved as the government has yet to propose any concrete measures to boost utilisation hours. In addition, the subsidy proposals are vague, with no specific objectives and timelines for local governments to implement. Moreover, under the current power reform in China, gas-fired IPPs are required to gradually participate in market-based sales, which have already begun in Guangdong. As the China power market is currently in oversupply, IPPs generally need to sell at a discount to the benchmark tariff in a market-based transaction. For example, 0.6bn kWh of gas-fired power from a leading IPP group was sold through a market-based transaction in 1H17, representing 2% of its total gas-fired sales, with an average discount of CNY0.245/kWh, translating into a 33% discount to the benchmark gas-fired tariff in Guangdong.

As we forecast for power oversupply to persist in the medium term (we estimate the total redundant coal-fired capacity to increase from 196GW in 2016 to 270GW in 2020E), the realised tariffs by gas-fired IPPs should keep trending down with increasing proportion of market-based sales, offsetting the potential cost saving from lower gas prices brought by the natural gas price reform. As such, by 2020E, we believe the LCOE of a combined-cycle power plant will still be 110% higher than the prevailing LCOE of a USC coal-fired plant and the project IRR is unexciting at 5.7% even for a large-scale gas-fired co-generation plant in northern China, which should have above-average utilisation hours.

China: LCOE comparison of power plants China: IRR comparison of power plants

(CNY/kWh) 14% 6,000 0.7 11.7% 0.63 12% 0.57 10.1% 5,500 0.6 10% 8.1% 8.3% 5,000 0.5 8% 7.0% 5.7% 4,500 0.4 6% 0.28 4,000 0.3 4% 0.2 2% 3,500 0.1 0% 3,000 USC coal-fired (2017)* Combined-cycle co-gen in Combined-cycle co-gen in 0.0 Northern China (2017) Northern China (2020E) USC coal-fired (2017) Combined-cycle co-gen in Combined-cycle co-gen in Project IRR (LHS) Equity IRR (LHS) Utilization hours (RHS) Northern China (2017) Northern China (2020E) Source: Daiwa estimates Source: Daiwa estimates Notes*: assuming a standard coal price of CNY535/tonne

China Gas: 12 January 2018

Natural gas consumption from power and heat cogeneration to expand at a 7% CAGR over 2016 to 2025E As a result, despite the seemingly proactive government stance on the development of gas-fired power generation, we are not that optimistic in light of the inferior investment return and lack of solid subsidy policy support. Therefore, compared with the 12% implied by government’s 2020 target, we only forecast a 7% capacity CAGR for 2016-2020E and 5% for 2020-2025E. In terms of new gas-fired units, we believe they will still primarily be co-generation plants located in big cities with large power loads and high levels of air pollution in northern China. Also, we project only a mild improvement in utilisation hours from 2,764 in 2016 to 3,000 in 2020 and 3,200 in 2025E, given the continued uncompetitive gas-fired tariff. As a result, we forecast natural gas demand from power and heat co-generation to see a 7% CAGR to 69bcm over 2016 to 2025E — the slowest among all the major uses of natural gas.

China: natural gas demand forecasts from power and heat cogeneration 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E … 2025E Total installed gas-fired power capacity (GW) 26 34 38 43 57 66 70 76 81 86 91 117 Growth rate 29% 10% 14% 33% 16% 6% 8% 7% 7% 6% 5% - % of total thermal power capacity 4% 4% 5% 5% 6% 7% 8% 7% 7% 7% 8% 9% - % of total capacity 3% 3% 3% 3% 4% 4% 4% 4% 4% 4% 4% 5% Total gas-fired power generation (bn kWh) 78 109 110 116 133 167 188 208 227 247 267 364 Growth rate 40% 1% 6% 15% 25% 13% 10% 9% 9% 8% 6% Annual utilisation hours 2938 3210 2938 2653 2753 2714 2764 2850 2900 2950 3000 3200 Gas consumption rate for power generation (m3/kWh) 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 Gas-fired power demand (bcm) 15 21 21 22 25 32 37 39 43 47 51 69 Growth rate 40% 1% 6% 15% 25% 15% 8% 9% 9% 8% 6% Demand proportion 14% 15% 14% 13% 14% 16% 18% 16% 15% 15% 14% 13%

Source: CEC, Daiwa estimates

China Gas: 12 January 2018

City gas: 23% of 2016-25E new natural gas volume

Residential: continue to ride on increasing gas-penetration and urbanisation

During the 12th FYP, urban residential gas usage grew rapidly, with the penetration rate rising from 28.2% in 2010 to 42.8% in 2015. Despite this growth, urban residential natural gas penetration is still far below that of developed countries such as the UK and Japan. Hence, we believe there is still ample room for growth in residential gas demand in urban areas. Indeed, according to the 13th FYP for natural gas development, the government plans to boost the penetration rate by 14.2pp to 57% by the end of 2020. Together with the rising urbanisation rate (2016: 57.4% vs. 2020E target: 60%), we expect urban residential gas demand to be solid and register a 13% CAGR over 2016 to 2020E, despite the fact it will not benefit as much as the other uses of natural gas from price reform since there will be limited room for reduction in the residential gas tariff, as it is already much lower than for other uses. For 2020 to 2025E, we expect residential gas consumption to continue to expand at 9% CAGR to 70bcm, accounting for 13% of total demand.

Urban residential natural gas penetration China: urban residential gas demand projection comparison as of 2015

100% bcm 90% 70 80% 70% 60 60% 50 50% 40% 40 30% 20% 30 10%

0% 20 China Japan UK US 2016 2017E 2018E 2019E 2020E 2025E Source: Sinoergy.com, Daiwa estimates Source: Frost & Sullivan, NBS , Daiwa estimates

Commercial: a large market to explore

The commercial segment is usually located close to city centres. Coupled with the fact that the boiler size is generally smaller given the relatively limited amount of heating required compared with the industrial segment, the commercial sector is directly affected by the government’s goal to eliminate all small coal-fired boilers in built-up areas of cities. Hence, the commercial segment is also undergoing massive coal-to-gas conversion. Relative to the industrial sector, the commercial segment has more incentive to switch to gas-fired boilers, because it can: 1) save costs, as the treatment costs of pollutants emitted by small coal-fired boilers are high due to the lack of scale economies, 2) make use of the additional land after the conversion as gas-fired boilers occupy less space, which can be valuable given the commercial segment is located in prime areas, and 3) as the conversion can reduce noise pollution and hence have a positive impact on the surrounding neighbourhood.

As a result, we are confident of natural gas demand growth from the commercial sector, especially for users with significant heating demand, such as hotels, hospitals, and central heating companies. Indeed, as of 2016, we estimate that the commercial sector (ex. central heating companies) only consumed c.6bcm of natural gas in total, representing only c.30% of the potential total demand of c.20bcm if we assume 50% of existing coal users in the sector switch to natural gas. Hence, we expect commercial gas demand to register a 14% CAGR over 2016-20E and a 10% CAGR over 2020-25E to 49bcm in 2025E from 18bcm in 2016, representing 9% of total natural gas consumption.

China Gas: 12 January 2018

China: commercial sector(ex. central heating) China: commercial gas demand projection total coal consumption Items bcm 1cm natural gas to 1kg coal energy content 1.2 60 Natural gas to coal heating efficiency 1.3 1cm natural gas to kg coal conversion ratio 1.6 Coal consumption (mn tonne) 41 50 Conversion rate 50% Equivalent NG consumption (bcm) 14 40

10 2016 2017E 2018E 2019E 2020E 2025E Source: Wind, Daiwa estimates Source: Frost & Sullivan, NBS , Daiwa estimates

China: breakdown of incremental city gas natural gas demand over 2016-25E bcm 140 120 14 bcm (19%) 100 17 bcm (23%) 80 43 bcm (58%) 60 40 20 45 bcm 0 2016 demand Incremental demand over 2016-25E

residential Commercial (central heating) Commercial (non-central heating)

Source: Daiwa estimates

China Gas: 12 January 2018

Chapter 3

Can supply catch up with robust demand?

China Gas: 12 January 2018

Ample international supply to meet growing demand in the long run

As highlighted in Chapter 2, we expect natural gas demand in China to show an 11% CAGR between 2016 and 2025E. However, some may wonder if there is enough supply to meet this robust demand. We believe so, thanks to the: 1) room for further growth in domestic production, especially for unconventional gases, 2) ramping up of existing and new imported gas pipelines, and 3) abundant global LNG supply. In particular, we see offshore LNG as the primary contributor of supply (40% of 2016-25E incremental supply) given that: 1) China needs to depend more on imports as growth of domestic supply is not as fast as demand, 2) the all-in price of offshore LNG spot imports is c.15% cheaper than imported piped gases in the natural gas consumption centre (areas with large consumption of natural gas) in China and the discount may further widen on continued oversupply in the global LNG market, and 3) LNG can help China to diversify its sources of imported supply to ensure its energy security.

That said, we believe China is likely to face some seasonal supply tightness during the heating season in the near term as: 1) historically winter demand is 2x that of summer (4x in northern China, and may widen to 6-8x after completion of coal to gas conversion), and 2) there is insufficient peak shaving capacity. Nevertheless, with China’s peak-shaving capacity ramping up to a more optimal level in 3 years, we believe the seasonal imbalance will gradually fade. In the rest of this chapter, we detail why we think there is sufficient supply to satisfy demand in the long run, despite seasonal gas shortages which could potentially slow the ambitious CTG plan over 2018-19E.

China: natural gas balance China: 2016-25E incremental supply breakdown bcm Domestic 600 528 conventional gas 500 Imported LNG 22% 40% 400 352 317 283 300 245 209 200 Domestic unconventional 100 gas 21% 0 Imported piped 2016 2017E 2018E 2019E 2020E 2025E gas Natural gas demand Excess supply 17%

Source: NEA, Daiwa estimates Source: Daiwa estimates

China: natural gas monthly consumption in 2016 bcm 35

15 2x

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Source: NDRC

China Gas: 12 January 2018

Overview of natural gas supply in 2016

In 2016, domestic natural gas production amounted to only 137bcm, 33% less than the national demand of 206bcm. As a result, China needs to rely on imports, with the import ratio rising from 22% in 2011 to 34% in 2016. In terms of imported gas, piped gas represented 53% of total imports and primarily came from Myanmar and Central Asian countries such as Turkmenistan and Uzbekistan. As for imported LNG, the supply is more diversified, with major suppliers ranging from Qatar and Yemen, to Malaysia, Indonesia and Australia. For domestically produced gas, conventional gas accounts for 89% of total production while non-conventional gases, including shale gas/coal-bed- methane gas (CBM)/ synthetic coal-to-gas, accounts for 6%/3%/2%, respectively.

China: natural gas supply breakdown China: imported natural gas breakdown by origin

Imported LNG Papua New Uzbekistan US 15% Guinea 2% 2% 3% Indonesia 4% Turkmenistan Imported piped 38% gas Myanmar 18% Domestic 5% conventional Malaysia Domestic coal- gas 8% to-gas 60% 1% Qatar Domestic shale 12% gas 4% Domestic CBM Australia 26% 2% Source: NEA, note: as of 2016 Source: SCI99.com, note: as of 2016

China: natural gas supply historical trend bcm 250 34% 40% 31% 31% 31% 200 30% 23% 22% 150 20% 100 10% 50

0 0% 2011 2012 2013 2014 2015 2016 Domestic production (LHS) Imports (LHS) Import % (RHS)

Source: NDRC

Sufficient supply

1. Further tapping into domestic reserves especially for non-conventional gases. According to the Ministry of Land and Resources, China should have total conventional natural gas resources of 68tcm, with 40tcm of recoverable reserves (ie, economically viable for production as cost is lower than the selling price). However, as of the end of 2015, China has only discovered proven gas resources of 12.7tcm (11.7tcm of conventional gas + 1tcm of non-conventional gas). In other words, there is 55tcm of undiscovered resources for China to explore and potentially use. Indeed, in the 13th FYP, the government has targeted to discover 23%/200%/72% or 3tcm/1tcm/0.4tcm of new conventional gas/shale gas/CBM resources during 2015 to 2020, increasing total proven gas resources by 35%. Also, for synthetic coal-to-gas, we see significant room for growth given the massive idle capacity. Although there is still plenty of conventional gas for China to explore, we are not so bullish on the growth potential on the increasing level of difficulty for exploration going forward. On the other hand, we are more upbeat on the prospect of non-conventional gas due to: 1) increasing participation in non-conventional natural gas exploration from the private sector, which has a higher level of motivation and efficiency, and 2) massive idle synthetic coal-to-gas capacity to be utilised (2017: 3bcm of annual production vs 90bcm of total capacity).

China Gas: 12 January 2018

China: domestic natural gas production forecasts bcm 300 40.0% 250 30.0% 200 150 20.0% 100 10.0% 50 0 0.0% 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E … 2025E

Conventional gas (LHS) CBM (LHS) Shale gas (LHS) Synthetic coal-to-gas (LHS) Unconventional gas proportion (RHS)

Source: NDRC, Daiwa estimates

2. Ramping up of existing imported pipelines and construction of new pipelines. As discussed above, China’s existing piped gas imports are sourced from Central Asia (90%) and Myanmar (10%). For the China-Central Asia gas transmission project, there are three pipelines up and running with a total annual capacity of 55bcm, yet the utilisation rate was sub-optimal at c.63% in 2016. As for the China-Myanmar gas pipeline (annual capacity: 12bcm), the utilisation is only even lower, at c.30% on our estimates. As a result, there is ample room for China to increase its imported piped gas volume by ramping up the utilisation of the existing pipelines. Indeed, CNPC expects the China-Central Asia project to supply c.39 bcm of natural gas to China this year, a c.10% jump compared with 2016.

On top of ramping up its existing pipelines, China is scaling up its piped gas importing capacity by launching new pipelines. Currently, CNPC is conducting a preliminary study on a new pipeline (Route D) from Turkmenistan to Xinjiang, which is scheduled to be completed in 2020. The new pipeline will have a designed annual capacity of 30bcm, boosting total annual capacity of the China-Central Asia project by 55% to 85bcm.

In addition, there is a new major pipeline under construction from Russia to China. The pipeline will originate from the Chayanda and Kovykta gas fields in Eastern Siberia with a designed annual capacity of 38bcm. According to CNPC and Gazprom, the pipeline will commence operation as soon as 2019, with a full ramp up in five years. CNPC and Gazprom are also in the final stages of negotiation on the construction of another natural gas pipeline from Western Siberia to Xinjiang with an estimated annual capacity of 30bcm. Hence, in total, China could import as much as 68bcm of natural gas from Russia each year.

China: imported natural gas pipeline (in-use) Projects Year of commencement Annual designed capacity (bcm) Utilization rate China-Central Asia Natural Gas Pipeline A, B, C 2009 55 63% China-Myanmar Natural Gas Pipeline 2013 12 30% Total 67 58%

Source: Wind, Daiwa estimates

China: imported natural gas pipeline (under construction/planning) Projects Year of commencement Annual designed capacity (bcm) China-Central Asia Natural Gas Pipeline D Earliest 2020 30 China-Russia Eastern Natural Gas Pipeline Earliest 2019 38 China-Russia Western Natural Gas Pipeline TBC 30 Total 98 Increment to existing capacity (%) 146%

Source: Wind, Daiwa estimates

3. Abundant global LNG supply. Global LNG trading volume grew by 13.1m tonnes (5% YoY), the largest increment since 2011, to 258m tonnes in 2016, thanks to the increasing supply driven by higher liquefaction capacity. However, based on the current project pipelines, global supply will continue its robust growth, with 120m tonnes of new liquefaction capacity in 2017E to 2020E, primary from Australia (31m tonnes) and the US (58m tonnes). Together with the potential continued demand weakness from Japan and Korea, the two largest LNG importers accounting for c.45% of global LNG imports in total, on competition from alternative fuels (eg, nuclear power), the IEA expects the oversupply in global LNG markets to extend into the 2020s, despite the solid demand growth from countries like China and India.

China Gas: 12 January 2018

Indeed, according to the Oxford Institute for Energy Studies, even under a bullish case of strong Asian demand on the back of a slower pace of nuclear restarts in Japan and the scaling-back of nuclear plants in Taiwan, there will still be 21/10bcm of excess global LNG supply in 2019/20E. As a result, we believe there is ample supply of LNG in the market to meet China’s strong consumption growth.

Global LNG import breakdown in 2016 Incremental global liquefaction capacity breakdown by countries over 2016-20E

Others Others 6% 31% Japan Russia 32% 14%

US 48% Malaysia 6%

Taiwan 6% India South Korea 7% China 13% Australia 10% 26%

Source: International Gas Union Source: International Gas Union Notes: Only accounting for those under construction

Global liquefaction capacity forecast Global LNG balance under a bullish Asian demand scenario (m ton/annum) bcm 500 600 500 400 300 400 200 100 0 2016 2017E 2018E 2019E 2020E

300 Asian Demand European Demand Middle East Demand 2016 2017E 2018E 2019E 2020E South American Demand Other Demand Excess Supply Source: International Gas Union Source: Oxford Institute for Energy Studies

Currently, the majority of the China’s LNG purchases are imported through long-term take-or-pay contracts, and many of them are expensive given that the crude oil import price into Japan, against which Asian LNG spot prices are generally referenced, were high at the time the contracts were signed (2011-12). On our estimates, the Asian LNG spot price is c.25-30% lower than China’s average long-term LNG import contract price. However, because of the prolonged oversupply, buyers are now gaining more bargaining power and hence are able to renegotiate the unfavourable terms of the long-term contracts with sellers. Coupled with the fact that the price on new purchases is likely to stay low on the back of oversupply, we see a possibility of lower overall import LNG prices for China over time. For the trailing 12 months, we estimate that the spot price is c.15% lower than China’s average LNG import price.

China Gas: 12 January 2018

Asian LNG spot price vs. China average LNG import price USD/MmBTU 14 12 10 8 6 4 2 0 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Asian LNG spot price (SLING) China average LNG import price

Source: Bloomberg, Wind, Daiwa estimates

Solid infrastructure plan to complement growing supply Other than having ample supply of natural gas, China is enhancing its capability to handle and deliver the new supply to demand centres in the east. In the Mid-to-Long Term Development Plan on Oil and Gas Pipeline Network Development, published in July 2017, the government targets to increase its total gas pipeline network length by a 9.8% CAGR to 163k km in 2025E, from 64k km in 2015. China also aims to make its segmented pipeline more inter-connected in order to improve the flexibility of its supply. The government has also stated it aims to increase its storage capacity by a 17% CAGR to 40bcm by 2025 (see Appendix II), so that it is able to import and store up more during the low season in summer and use the storage for peak shaving in the heating season.

Seasonal supply-demand imbalance in winter is likely to persist in 2018-19E but gradually fade Even though China technically has enough supply to meet its natural gas demand on a full-year basis, China tends to experience regional supply shortages in places with strong heating demand during the winter (November to March), due to the fact that: 1) winter demand is twice as much as summer demand (4x in northern China), and 2) there was insufficient peak shaving capacity, as evidenced by the fact that China only had storage capacity of 7.4bcm in 2016, equivalent to only 3.6% of annual consumption, much lower than the international standard of 11%. For 2017, with massive incremental demand driven by the coal-to-gas initiatives, oil majors together expect China to experience c.11bcm of supply shortage during the heating season, representing c.10% of total gas demand during the 2017-18 heating season. As a result, the government is currently ramping up natural gas storage capacity and connecting separate pipelines with the goal of eliminating the bottleneck on transmission and storage and hence addressing the supply constraints. With China’s peak shaving capacity likely to ramp up to a more optimal level in 3 years (equivalent to c.6.7% of consumption from c.4.3% in 2016), we believe the seasonal imbalance will gradually fade.

Sufficient supply to meet robust demand with offshore LNG taking the lead Given that we expect natural gas demand (11% CAGR) to outpace the growth of domestic production (8% CAGR) over 2016-25E, we believe China will need to increase its dependence on imports. We expect imported LNG to expand at an 19% CAGR over 2016-25E, faster than the growth of piped gas, given that: 1) the all-in price of offshore LNG spot imports is at a c.15% discount compared with that of imported piped gases in eastern China, the natural gas consumption centre accounting for 43% of total consumption, due to the lack of cross-province transmission fees, 2) there is increasing supply in the global LNG market, which should create more favourable terms for buyers going forward, and 3) China can diversify its sources of imported supply to reduce over-reliance on any particular country.

Nevertheless, we still forecast a 10% CAGR for imported piped gas, primarily driven by the ramp-up of the China- Central Asia pipeline and new supply from Russia starting from 2020. In total, we forecast the proportion of imported gas to go up from 34% in 2016 to 48% in 2025E. In terms of domestic supply, we expect unconventional gas supply to expand at a 21% CAGR over 2016-25E, much faster than the 5% CAGR for conventional gas, on the back of: 1) a rising level of difficulty for exploration of conventional gas, and 2) increasing participation in non- conventional natural gas exploration from the more efficient private sector going forward.

China Gas: 12 January 2018

China: natural gas supply forecast (in bcm) 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E … 2025E Domestic conventional gas 89 97 110 115 122 124 122 134 146 155 165 194 Domestic unconventional gas 4 4 5 3 6 11 15 20 26 34 41 81 CBM 4 4 5 3 4 4 5 6 7 9 10 18 Shale gas - - - - 1 5 8 11 14 17 20 33 Synthetic Coal-to-gas - - - - 1 2 2 3 5 8 11 30 Total domestic gas supply 93 101 115 118 128 135 137 154 172 189 206 275 yoy growth 12% 9% 14% 3% 8% 6% 1% 11% 12% 10% 9% 6% Imported piped gas 4 16 20 28 31 36 38 43 47 50 62 91 Central Asia 4 16 20 28 31 33 35 39 43 45 47 58 Myanmar - - - - - 3 3 4 4 5 6 8 Russia ------9 25 Imported LNG 11 12 15 25 27 26 34 48 64 78 84 162 Total imported gas supply 15 28 35 53 58 61 72 91 111 128 146 253 yoy growth 150% 87% 23% 54% 9% 5% 17% 27% 23% 17% 16% 12% Total supply 108 129 150 172 186 196 209 245 283 317 352 528 yoy growth 21% 19% 16% 15% 8% 6% 6% 17% 16% 12% 12% 8% Import proportion (%) 14% 22% 23% 31% 31% 31% 34% 37% 39% 40% 41% 48%

Source: Wind, Daiwa estimates

China: natural gas infrastructure map (as at 30 June 2017)

Eastern Siberia Western Siberia

Xinjiang Qinhua

Heilongjiang Datang Fuxin

Central Asia – China Pipeline (from Kazakhstan) Datang Keqi

Xinjiang- Jilin Shandong coal gas pipeline Inner Mongolia (Sinoprec, Huineng approved by Liaoning NDRC)

Xinjiang Beijing PetroChina Hebei Caofeidian LNG PetroChina Dalian LNG Xinjiang- Inner Mongolia Guangdong- Gansu CNOOC Tianjin LNG Zhejiang coal Tianjin gas pipeline (Sinopec, approved by Shandong Sinopec Qingdao LNG NDRC) Ningxia Shanxi Hebei

Qinghai Jiangsu Coal-to-gas projects (to be Shaanxi Henan PetroChina Rudong LNG commissioned by 2016) Shanghai Guanghui Qidong LNG Coal-to-gas projects (after 2016) CNOOC Shanghai Yangshan LNG Tibet LNG terminals (operating) Anhui CNOOC Zhongximentang LNG Hubei CNOOC Ningbo Zhejiang LNG Sichuan Natural gas reserve Chongqing Existing pipeline Jiangxi Zhejiang Planned pipeline Hunan Shaanxi-Beijing Pipeline I Guizhou CNOOC Putian LNG (PetroChina) West-East Pipeline III Fujian Shaanxi-Beijing Pipeline II (PetroChina) (PetroChina) Burma-China Pipeline Guangdong CNOOC Yuedong LNG (PetroChina) Yunan CNOOC Dapeng LNG Shaanxi-Beijing Pipeline III Guangxi (PetroChina) Yulin-Jinan Pipeline JOVO Dongguan LNG CNOOC Zhuhai LNG Shaanxi-Beijing Pipeline IV (Sinopec) Sinopec Beihai LNG (PetroChina) Sichuan-East Pipeline West-East Pipeline I (Sinopec) CNOOC Hainan LNG (PetroChina) Zhong-Wu Pipeline Hainan West-East Pipeline II (PetroChina) (PetroChina) Source: NDRC, Daiwa Note: Existing LNG receiving capacity: 60m ton; LNG receiving capacity under construction/planning: 38m ton

China Gas: 12 January 2018

Chapter 4

Does strong volume growth lead to strong profits?

China Gas: 12 January 2018

Significant margin pressure

Large volume accompanied by margin squeeze Given that natural gas costs twice as much as coal, China’s government has outlined its goal to keep lowering natural gas prices to reduce the end-user financial burden amid its push for increasing adoption of natural gas. As a result, it has launched industry-wide price reform (see Chapter 1). Since distribution tariffs represent a huge chunk of non-residential end-retail gas prices (30%), we believe they will continue to come under the spotlight during the reform process and that the government will continue to cut distribution tariffs.

China: non-residential T&D dollar margin China: non-residential piped natural gas retail comparison tariff breakdown CNY/m3 City-distribution 1.0 0.9 tariff Well-head price 30% 40% 0.8 0.6 0.6

0.4 0.3 Intra-province 0.2 transmission Cross-province tariff transmission 0.0 10% tariff Cross-province transmission Intra-province transmission City-distribution 20% Source: Sinoergy.com, Daiwa estimates; note: as of end-2017 Source: Frost & Sullivan, NBS, Daiwa estimates; note: as of end-2017

As a result, while we now believe that natural gas consumption is likely to be strong in the coming years when growing demand is met with sufficient supply, we argue that the volume growth will not directly lead to corresponding bottom-line growth for the gas distribution sector given the looming margin risk from the ongoing reform. Coupled with the inferior affordability of industrial coal-to-gas clients, we now see three major long-term sources of margin squeeze for city-gas distributors: 1) price discount for industrial coal-to-gas conversion, 2) regulation of distribution return, and 3) liberalisation of the downstream retail market (especially for large users) and one major short-term source of margin squeeze: increasingly market-based gas procurement cost. Hence, we see the 1H17 dollar margin squeeze of CNY0.04/m3 or c.5% YoY (excluding the impact of low-margin sales to gas-fired power plants) for national city-gas distributors as just the beginning, and believe the squeeze will continue as the reform progresses and industrial coal to gas sales account for a higher proportion of the total sales mix. In total, we expect the average non-residential dollar margin (non-residential gas sales represents c.85% of total gas sales) to contract by 45% from CNY0.9/m3 in 2016 to CNY0.5/m3 in 2025. Below, we elaborate on the major sources for margin squeezes.

ENN historical distribution dollar margin CRG historical distribution dollar margin (VAT-inclusive) (VAT-inclusive) CNY/m3 CNY/m3 0.87 0.85 0.9 0.86 0.9 0.9 0.8 0.83 0.8 0.82 0.8 0.80 0.80 0.80 0.8 0.8 0.8 0.78 0.8 0.76 0.8 0.8 0.75 0.8 0.7 0.72 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 2015 2016 1H15 1H16 1H17 1H17 (ex 2015 2016 1H15 1H16 1H17 1H17 (ex power plant power plant impact) impact)

Source: Company, Daiwa estimates Source: Company, Daiwa estimates

China Gas: 12 January 2018

China: sources of margin squeeze for city gas distributors

Price discount for industrial coal-to-gas conversion

Regulation of distribution Margin Liberalisation of return squeeze downstream retail market

Increasingly market- based gas procurement cost amid seasonal gas Permanent source supply tightness in winter with unlikely pass- Temporary source thorough

Source: Daiwa

China: three major long-term sources of margin squeeze for city-gas distributors Sources Description Impact on dollar margin Price discount for The affordability for coal-to-gas clients is lower than existing industrial clients and hence city gas The distribution dollar margin for these new customers is industrial coal-to-gas distributors need to offer discounted tariffs to acquire these new clients c.CNY0.3/m3 (c.30% to 40%) lower than the existing industrial conversion distribution dollar margin, while 50% of new coal-to gas industrial users use the discount Regulation of distribution The Chinese government has set the ROA cap on gas distribution at 7% effective from July 2018, but return local governments have the discretion to set their own return cap and review the distribution tariff Overall non-residential dollar margin is squeezed by the new tariff every three years review every three years c.CNY0.1/m3 (c.10% to 15%) Liberalisation of The Chinese government intends to change the monopoly status of city gas distributors by introducing One-off squeeze of c.CNY0.3-0.4/m3 (c.40 to 50%) of dollar downstream retail market more downstream competition through direct piped gas supply from upstream suppliers and LNG margin for big industrial clients once the local market opens up in for large users point-to-point supply three years

Source: Daiwa estimates

China: timeline on distribution dollar margin squeeze

Apr16 2017-2025 2018-20 Jul 24 Zhejiang capped non- Sales to 50% of new coal-to-gas clients c.40-50% cut in dollar margin for big c.10-15% cut in overall non-residential residential retail gas price at will see a c.CNY0.3/m3 (c30% to 40%) industrial clients once local government distribution dollar margin upon review of CNY3.4/m3 , leading to a dollar margin squeeze compared with opens up retail market distribution tariff c12% distribution dollar regular industrial dollar margin margin squeeze

Jul 17 Jul 18 Jul 21 Shandong capped non- Tariff reduction in some provinces/cities, leading to c.10-15% cut in overall non-residential residential distribution c.10-15% cut in overall non-residential distribution distribution dollar margin upon review of dollar margin at dollar margin upon implementation of 7% ROA cap distribution tariff CNY0.9/m3 on gas distribution

Source: Daiwa estimates

Major sources of margin squeeze

1. Price discount for industrial coal-to-gas conversion. According to our bottom-up demand forecast projection, 20% of incremental demand will be driven by coal-to-gas industrial customers. Given that their affordability is generally lower than existing industrial clients (which usually switch from oil to gas and oil is more expensive than coal), gas distributors often have to offer a discount to those customers. Based on our market research, the discounts average c.10% of the regular C&I retail tariff and 50% of new clients will need the discount. Given that the ASP of industrial gas sales is c.CNY3.0/m3 with a dollar margin of c.CNY0.8/m3, a 10% tariff discount implies a c.35% cut in dollar margin to c.CNY0.5/m3, which was essentially what ENN experienced in 1H17 when acquiring coal-to-gas industrial clients.

China Gas: 12 January 2018

2. Regulation of distribution return. As described in Chapter 1, China’s government has set the ROA cap on gas distribution at 7%, effective from July 2018, to prevent overcharging of distribution tariffs. At first glance, it may seem that the immediate earnings impact on gas distributors will be limited given that most gas distribution projects in China are making sub-7% ROAs (in the range of 3% to 5%, except for mature projects with high penetration and a commercial and industrial focus). However, we concur that there is possibility that local governments may still implement a tariff cut upon the completion of the tariff review because: 1) the 7% ROA is the maximum allowable return guided by the NDRC, yet the provincial price bureaux have the right to set their tariffs from a lower return target based on their own circumstances, and 2) the provincial price bureaus also have the discretion to determine the acceptable level of utilisation rate and if the utilisation rate of the city-gas project is lower than the pre-determined threshold, gas distributors will only be entitled to a fraction of the allowable return.

Under the backdrop of promoting the use of natural gas by reducing the gas usage cost of end-users, we believe local governments have reason to set a tougher return and utilisation target, particularly in places where the local government has no stake in city gas distributors. Indeed, in Shaanxi, the distribution ROA cap is set at only 6%. In the long run, as the return and cost structure of city gas distributors will be under review every three years, gas distributors can no longer conceal their high margins and hence the dollar margin will be on a downward trend on the back of increasing utilisation once the return cap is achieved. We expect the non-residential distribution margin to be squeezed by c.CNY0.1m3 (c.10-15%) every three years upon tariff review.

3. Liberalisation of the downstream retail market. The end-goal of natural gas reform is to lower gas usage cost, and one of the ways to achieve this goal is to liberalise the downstream retail market. Hence, it is the government’s intention to introduce more competition to the monopolised gas distribution business. Indeed, in the Opinion on Facilitating the Use of Natural Gas, the NDRC has indicated that end-users should have the right to determine their own suppliers and sources of gas supply. As a result, we note that some local governments, such as the Anhui and Liaoning provincial governments, are rolling out new policies that encourage users to secure gas supply from alternative parties. In our view, direct piped gas supply and point-to-point LNG supply are the two main sources of competition for gas distributors.

China: local policies to open up the downstream retail market Provinces /cities Policy Description Chengdu Implementation details on upgrading the Encouraging large users to bypass the city-gas distributors and secure natural Energy Policy for Key National Cities gas directly from CNPC and Sinopec Anhui Notice on the Oil and Gas Infrastructure Separating the natural gas transmission business from retail business, offering Construction Plan for Anhui during 2017-2021 the users a choice to select their own suppliers, especially for large users, and opening up competition in the retail market Liaoning Work Plan on Facilitating “Gasification” of Reducing the gas usage cost for end users through lowering T&D charges while Liaoning encouraging large users to directly negotiate with upstream suppliers to determine the prices

Source: Daiwa

Direct piped-gas supply (mainly targeting large users): Under this approach, end-users directly procure natural gas from upstream suppliers (eg, CNPC and Sinopec), without the involvement of gas distributors. Given that upstream suppliers need to build additional pipelines to transmit gas to clients, this is only feasible for users: 1) with substantial demand (large industrial clients), and 2) which are located close to the existing pipeline network of upstream suppliers. In other words, the number of affected industrial users will be limited, but the volume they procure will be significant. Direct supply of gas has been around for many years, serving many large users such as gas-fired power plants, which are outside of the concession rights areas of city-gas projects. But with the government’s intention to open up direct supply to competition, we believe direct supply will gradually extend coverage into city areas, especially in places where local governments have given the green light. That said, we think the central government would prefer to promote competition in a way that does not breach the concession agreement (the existing gas distributor has sole gas distribution rights in the area in which it was awarded the concession, which usually last for 30 years) or undermine the financial interest of the local government. Hence, we argue that a likely scenario will be a compromise between upstream suppliers and city-gas distributors. One possible scenario will be for upstream suppliers to use the existing pipelines of city-gas distributors to deliver gas to end-clients and compensate distributors with transmission fees. For example, Sinopec now uses Suntien’s (956 HK, HKD2.04, Buy [1]), city-gas distribution networks to supply gas to its industrial clients in Hebei. However, Suntien’s dollar margin of CNY0.05/m3 is much lower under this scenario than its average retail dollar margin of CNY0.65/m3.

China Gas: 12 January 2018

Point-to-point LNG supply: Under this approach, natural gas is sold in the form of LNG which is transported directly from production sites (LNG factories or LNG receiving terminal operators) to buyers via trucks. The LNG then undergoes regasification at the purchaser’s end for consumption. Previously, point- to-point LNG supply was mainly used to supplement piped gas supply in areas that gas pipelines could not reach. However, under the recent coal-to-gas initiatives, point-to-point LNG supply now competes with piped gas supply for newly converted industrial users, which have lower affordability and look for cheaper gas supply. Compared with piped gas, point-to-point LNG supply is generally less costly as it adopts more market-based pricing and has access to cheap offshore LNG (only in coastal regions). Similar to direct piped gas supply, point-to-point LNG supply is technically unauthorised in areas where city gas distributors have service concession rights. However, unlike direct piped gas supply, point-to-point LNG supply should receive less government support during the retail market liberalisation process given: 1) safety concerns, and 2) instability of supply arising from road transportation. Having said that, point-to-point LNG supply still poses an escalating threat to gas distributors going forward, especially in provinces with strong government support for point-to-point LNG supply, like Shandong.

China: economics of piped natural gas vs. point-to-point LNG Piped natural gas Piped natural gas Point-to-Point LNG Price per unit (CNY/m3) 3.02 2.43 Heating efficiency (%) 90 90 Hourly gas consumption per t/h (m3) 83 83 Utilisation hours per year 3000 3000 Annual gas consumption per t/h (mcm) 0.25 0.25 Annual fuel cost saving on using point-to-point LNG per t/h (CNYm) 0.15 Annual fuel cost saving on using point-to-point LNG for 10 t/h boiler (CNYm) 1.47 Equipment cost for setting up LNG regasification station (CNYm) 0.75 Payback period for switching to point-to-point LNG for 10t/h boiler (year) 0.5

Source: Wind, Daiwa estimates; note: for 2017

Even though direct supply and point-to-point LNG supply will most likely only affect industrial clients, the adverse impact on gas distributors is still consequential given: 1) the large procurement volume (industrial segment accounts for over 40% of total sales volume for major national city gas distributors, the largest among the sub-segments), and 2) upstream suppliers (mostly the oil majors) will be motivated to develop the direct supply business to secure buyers for their gas purchased under long-term take-or-pay contracts, since downstream distributors will be able to bypass the oil majors and import natural gas from other parties amid upstream liberalisation (opening up pipelines and LNG terminals for third-party access).

CRG gas sales volume breakdown CGHL gas sales volume breakdown CNG/LNG CNG/LNG station station Residential 11% 14% Residential 23% 26%

Commercial 22% Commercial 20%

Industrial Industrial 43% 41%

Source: Company, note: as of 2016 Source: Company, note: as of 2016

4. Increasingly market-based gas procurement cost amid seasonal gas supply tightness in winter without full pass-thorough. In the past, gas procurement costs, essentially the city-gate tariffs plus intra- province transmission fees, were largely determined by government and remained stable with infrequent changes which gas distributors could mostly pass to end users by asking the local price bureau to adjust the retail tariffs accordingly. However, with China now aiming to liberalise pricing for the whole industry chain, we see gas procurement costs becoming more market-based, which poses a short-term risk to gas distributors arising from incomplete cost pass-through during the liberalisation process.

China Gas: 12 January 2018

In 2017, CNPC raised its city-gate tariffs by 10% to 15% during the heating season from November 2017 to March 2018 on supply tightness. However, CNPC only guarantees the base volume (the gas amount distributors purchased in the previous heating seasons). For any additional volume, city-gas distributors need to procure the additional gas through: 1) bidding at natural gas exchanges (SHPGX or CQPGX), where the cap can be 63% higher than the city-gate tariffs on average as CNPC needs to pass through its higher purchase costs, or 2) in the spot LNG market. Given there is a temporary supply shortage in the current heating season, the cost of incremental volume is likely to be higher than the city-gate tariffs, implying that the average procurement cost of city-gas distributors will increase by more than 10% to 15%. However, most local governments only approve a seasonal hike of 10% to 15% (or even freeze tariffs for community service providers like schools or hospitals). Hence, city-gas distributors would need to absorb the difference and earn a thinner margin or even supply gas at a loss, similar to what happened in Tianjin in 2016. As a result, additional gas sales in winter are likely to be unprofitable.

Indeed, most gas companies have now guided for a CNY0.03-0.05/m3 dollar margin squeeze in 2H17, which implies a 4Q dollar margin slump due to the incomplete pass-through of the gas cost hike in the 2017-18 heating season. For now, we expect city-gas distributors to suffer an 18% dollar margin squeeze in winter, relative to the non-heating season. Assuming 50% of gas sales take place in the heating season, the seasonal gas cost hike is likely to lead to a 9% overall dollar margin squeeze for city-gas distributors, and we expect this to occur for the next three years until the end of supply tightness. On the other hand, we believe the gas procurement cost is not likely to rise much even under a market-based mechanism given the more balanced demand-supply landscape.

China: margin impact of incomplete pass-through of a gas cost hike during winter Cost (CNY/m3) Dollar margin (CNY/m3) Volume proportion Base volume 2.35 0.68 85% Incremental volume 3.60 (0.57) 15% Incremental volume subsidy n.a 0.45 Blended volume 2.54 0.56 Unit dollar margin squeeze 0.12 Dollar margin squeeze (%) 18%

Source: Wind, Daiwa estimates; note: for 2017

China: national gas distributors dollar margin projection CNY/m3 0.8

0.7

0.6

0.5 1Q17* 2Q17* 3Q17* 4Q17E 1Q18E 2Q18E CGHL CRG ENN

Source: Daiwa estimates Note: * Historical data estimated by Daiwa

Gradual margin squeeze with a total of 45% contraction in non-residential distribution margin by 2025 Based on the abovementioned factors, the distribution dollar margin is under pressure from both the tariff and input cost sides. While we believe soaring gas procurement costs will only squeeze margins temporarily until the resolution of seasonal supply tightness in three years, the dollar margin squeeze resulting from: 1) price discount for industrial coal-to-gas conversion, 2) stricter regulation on distribution return, and 3) liberalisation of the downstream retail market will be permanent. In total, we expect the average non-residential dollar margin to contract by 45% from CNY0.9/m3 in 2016 to CNY0.5/m3 in 2025.

China Gas: 12 January 2018

China: non-residential average distribution margin forecast

CNY/m3 1.0

0.8

0.6

0.4

0.2

0.0 2016 2017E 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E non-residential distribution margin Squeeze from competition for big users Squeeze from review on distribution tariff Squeeze from industrial CTG Squeeze from seasonal cost hike Source: Daiwa estimates

China Gas: 12 January 2018

Chapter 5

Who stands ready to manage margin risks and emerge as a winner?

China Gas: 12 January 2018

Hedging and diversification to be the silver lining

In Chapter 4, we explained that the gas distribution industry will inevitably incur margin risk going forward. However, there are ways to mitigate the risks. With the right strategies, we think city gas distributors can still fare well and reap the benefits from robust natural gas demand growth. We classify these strategies into two groups: hedging (maintaining the profitability of existing city-gas businesses through an integrated business model) and diversification (entering into other “blue ocean” markets with unregulated returns). In terms of hedging, we note that city-gas distributors can go upstream (obtaining a cheaper source of gas) or downstream (providing distributed energy [DE] services instead of just natural gas) to make up for the loss distribution margin. For now, ENN is most active on hedging among the national city-gas distributors, given: 1) access to its parent’s LNG terminal to be commissioned in 2H18, and 2) it has the largest number of DE projects on hand. In terms of diversification, we believe city-gas distributors can leverage their existing resources and customer bases to develop unregulated rural connections and value-added service (VAS) businesses, and earn additional income to compensate for the lower profitability of the city-gas distribution segment. As of now, we see CGHL as the pioneer in the space of diversification compared with its national peers, as evidenced by its higher proportion of profit from derived from diversification strategies.

China city-gas distributors: solutions to distribution margin squeeze Solutions to margin squeeze

Hedging Diversification

Importing of Rural DE projects VAS services Offshore LNG connection

Source: Daiwa

China city-gas distributors: hedging strategies China city-gas distributors: 2017E gross profit breakdown 100% Before margin squeeze 80%

After margin squeeze 60%

40% Cheap LNG 20% DE services 0% CGHL CRG ENN Gas input cost Distribution margin Incremental income from DE services Gas sales City-gas connection Rural gas connection VAS Others

Source: Daiwa Source: Company, Daiwa estimates Notes: We use 1H17 before-tax dollar margin except for CGHL which we use 1H18

Hedging:

1. Embracing upstream opportunities: self-importing of low-cost offshore LNG. For city-gas distributors, the impact of market liberalisation from the current oil and gas reform is two-fold. On one hand, the opening-up of the downstream retail market leads to more competition for city-gas distributors. On the other hand, the liberalisation of the upstream market introduces new cost-saving opportunities. As mentioned, access to pipelines and LNG terminals will gradually be opened up to more parties as the reform continues. In other words, city-gas distributors can bypass the oil majors and import offshore spot LNG, which can be used to supply their projects in coastal regions. Given that the all-in offshore spot LNG (including handling and regasification cost) is cheaper than the city-gate prices in coastal regions (c.5% or c.CNY0.1/m3 cheaper in non-heating season based on our estimates), gas distributors can take advantage 52

China Gas: 12 January 2018

of cheaper LNG costs and shore up their dollar margin even if they are facing price competition from direct supply and point-to-point LNG supply. Indeed, we consider the scale of c.CNY0.1/m3 gas procurement cost saving to be meaningful, representing c.13% of the average blended dollar margin of national leading city-gas distributors. On top of that, during the heating season, city-gas distributors can also make use of their self-imported LNG to avoid the seasonal gas-cost hikes in the event of supply tightness.

China coastal region: LNG spot cost vs. China: LNG spot cost saving vs. dollar margin city-gate tariffs of national gas distributors CNY/m3 CNY/m3 0.75 2.0 0.8 0.73 0.72

0.4 0.6 1.5 0.2 2.0 0.4

1.0 1.3 0.2 0.1

0.5 0.0 Off-shore spot LNG import cost Average coastal city-gate tariff Cost saving from ENN CGHL CRG offshore spot LNG FOB Transportation fee Operator handling fee Average coastal city-gate tariff

Source: NDRC, Daiwa estimates; note: for 2017 Source: Company, Daiwa estimates Notes: We use 1H17 before-tax dollar margin, except for CGHL where we use 1H FY18

That said, we do not rule out the possibility that it may take longer than expected for the LNG terminals to open up given the potential strong opposition from oil majors, as it will become more difficult for them to sell their LNG procured through the expensive long-term take-or-pay contracts signed 5 to 10 years ago (long- term contracts usually last for 15 to 20 years). Hence, we believe only city-gas distributors which have secured access to LNG terminals owned by private parties or which construct their own terminals will be able to import meaningful amounts of low-cost offshore spot LNG and reduce their procurement costs in the short to medium term.

Currently, only ENN has access to an LNG receiving terminal, and it has confirmed that it will import offshore spot LNG starting from 2H18E. Also, with the largest gas sales exposure to coastal provinces among the distributors, ENN appears to be the best positioned to benefit from offshore LNG imports. CGHL has preliminary plans to import LNG from the US, yet the key part of the plan — access to an LNG receiving terminal — remains unresolved. Meanwhile, CR Gas has clearly stated that it is not interested in setting up an LNG terminal to import LNG.

China city-gas distributors: plans to self-import offshore LNG Distributor Action Progress ENN ENN's parent will open its LNG terminal in 2H18 in Zhoushan, Zhejiang and ENN plans to import 2bcm (or 1.43mt) of  natural gas through the terminal, representing 7-9% of its annual retail gas sales volume in 2018-19E based on our estimates. Based on the existing procurement contracts, the all-in cost is CNY 0.2/m3 cheaper than the city-gate price in Zhejiang China Gas CGHL is partnering with DELFIN LNG, a Louisiana-based company to import LNG. Currently, CGHL plans to procure  a total of 3m tonnes of LNG annually from as early as 2021-22. However, the agreement is only an MOU and CGHL currently does not have any LNG receiving terminals in China to import the LNG CR Gas CRG has stated that the company has no plans to invest in any LNG receiving terminals to import offshore LNG

Source: Company

China Gas: 12 January 2018

China city-gas distributors: gas sale exposure in coastal provinces

60%

50%

40%

30%

20%

10%

0% CGHL CRG ENN Source: Company, Daiwa estimates Notes: We use the percentage of Industrial customers as the gas sales exposure proxy for CGHL We use the percentage of projects as the gas sales exposure proxy for CRG We use the percentage of installed designed daily capacity for C&I customers as the gas sales exposure proxy for ENN Note: as of 2016

2. Mitigating downstream retail risk: provision of DE services. As we mentioned, one of the major sources of margin squeeze for city-gas distributors will be the opening-up of downstream competition. However, there are ways for city-gas distributors to pre-empt the competition and maintain their industrial client bases. One such way is by increasing customer stickiness through the provision of customised DE services. By being DE service providers, city-gas distributors can provide customers with secondary energy, including heat, cooling and electricity (known as tri-generation), by setting up a skid-mounted natural gas DE facility close to its customers. Normally, this type of DE project can achieve an energy efficiency rate as high as 85% (vs. pure power generator: 40-60%) and hence can offer energy at competitive prices. Also, by purchasing energy from a third party, end-users can avoid the hassle of purchasing and maintaining equipment. Indeed, the recent coal-to-gas initiatives have driven increasing demand for DE services as some industrial and commercial users are not willing to put up new capital and resources to buy and manage new gas-fired equipment (eg, boilers).

Example of natural gas tri-generation

Source: GE Power

China Gas: 12 January 2018

Efficiency of natural gas tri-generation

Source: Tri-generation

A DE contract usually has an average duration of 15 to 20 years. Therefore, users are not able to switch to a different service provider or purchase natural gas from other sellers and generate secondary energy themselves, implying that the gas distributors can secure gas sales for the next 15 to 20 years and are effectively protected from competition. Hence, city-gas distributors can mitigate their margin risk by: 1) offering smaller discounts, and 2) making up the lost margin with extra income from the provision of DE services. A typical DE project can generally offer an equity IRR of 12%.

Indeed, the Chinese government has been supportive of the development of natural gas DE projects, offering subsidies and simplifying the overall approval process. Under the 13th FYP, the government plans to increase the national installed capacity of natural gas DE projects by 5 times to 50GW. Although we are not as optimistic, as the projects are largely only viable in the better-developed coastal regions with higher utilities prices, we believe there will still be solid growth in the adoption of natural gas DE projects in such a benign environment. Therefore, city-gas distributors should be able to acquire a meaningful number of natural gas DE projects to secure their gas sales. In the long run, city-gas distributors can even expand from running individual DE projects to building regional integrated energy (IE) networks, covering entire industrial parks/districts. With the IE network, city-gas distributors can supply energy to multiple clients with different sources (eg, solar, geothermal) and thus optimise the total energy efficiency, helping them cut costs and further boosting customer stickiness.

Relative to other national city-gas distributors, ENN is the first-mover in the field of integrated energy services and already has over 22 DE projects up and running, with 26 more in the pipeline. In addition, to improve the return of its DE projects, ENN has taken steps to develop its in-house DE processors, which can be deployed to smaller-scale projects such as hotels and offices. As a result, the company is able to achieve a c.50% saving on DE processor procurement. Although not as ambitious as ENN in terms of IE services, both CGHL and CRG are ramping up, with 20 to 30 DE projects under construction or at the planning stage.

China city-gas distributors: number of DE ENN: in-house DE processor projects in operation/pipeline

0 CGHL CRG ENN in operation under construction/planning

Source: Company, Daiwa estimates Source: ENN

China Gas: 12 January 2018

IE project overview

Source: ENN

Diversification:

1. Embracing the potential for significant rural connection income. On our estimates (see Chapter 2), there are 43m potential rural coal-to-gas households. Assuming an average connection fee of CNY3,000 and net profit margin of 35%, the total potential net profit from rural connection amounts to CNY45bn. As we expect the conversion process to last for 9 years until 2025E, the annual net profit increment from rural connection should be CNY5bn, representing 10.2% of the total net profit of the city gas distribution industry in China in 2016. Moreover, as the government has specified that connection profit will not be part of the regulated return subject to the 7% ROA cap, we believe the risk of connection fee cuts and complete elimination of connection fees is limited. Hence, if city-gas distributors participate actively in rural connection going forward, they should be able to generate sizable profits to compensate for their income loss from the margin squeeze.

Among the city-gas distributors, we see that CGHL is most aggressive in expanding its rural presence. For FY17E (April 2017 to March 2018 for CGHL), the company plans to connect 1.1m new rural households, representing 29% of its total residential connections. CRG and ENN are more conservative and only target rural households in villages close to their existing pipeline networks. Hence, each of them plans to acquire 200k rural customers in 2017E, accounting for 7-11% of their total residential connections.

China city-gas distributors: rural connection China: profitability of city connection vs. rural guidance for 2017E connection (000) CNY 1,200 35% 80% 4,000 1,000 30% 70% 25% 60% 3,500 800 20% 50% 600 15% 40% 3,000 400 10% 30% 200 5% 20% 2,500 0 0% 10% CGHL CRG ENN 0% 2,000 City connection Rural connection 2017E rural connection guidance (LHS) GPM (LHS) NPM (LHS) ASP (RHS) Rural connection as % of total connection for 2017E (RHS) Source: Company, Daiwa estimates Source: Company, Daiwa estimates, note: as of 2017

2. Cross-selling of value-added services (VAS). With an enormous customer base (over 22m households for the national leaders on average), city-gas distributors can cross-sell gas-related products and services in addition to gas provision. Some notable examples are gas appliances (such as heaters and stoves), gas insurance for the home, and energy saving equipment. Indeed, some city-gas distributors have even rolled

China Gas: 12 January 2018

out their own branded gas appliances to command a higher margin (gross profit margin: c.50%). On top of this, some city-gas distributors have transformed their e-payment mobile apps into comprehensive e- commerce platforms to cross-sell non-energy-related products and services ranging from electronics and food to air tickets. Currently, most VAS income comes from sales of gas appliances. Hence, VAS revenue is dependent on the number of new connections in the short run.

In terms of profitability, the VAS business can generate a superior operating margin (c.40%), which we partly attribute to the saving on SG&A thanks to limited customer acquisition and maintenance costs. Also, the VAS business is asset-light and does not require much investment in PP&E. As a result, the return on the VAS business is much higher than the existing return of city-gas distributors.

Compared with its peers, CGHL has most financial exposure to the VAS business, which accounted for 2.5%/4.8% of the company’s revenue/operating profit in 2016 (FY17), compared with 0.8%/0.6% for CRG and 0.7%/1.4% for ENN. Also, CGHL’s VAS revenue per new connection is much higher than its peers’, implying that the difference is due to CGHL’s more active promotion of its VAS products and services. Given that: 1) the gas penetration rates in cities are similar for the national gas distributors, and 2) it is more likely for city-gas distributors to sell their domestically-made gas appliances to rural households than to urban customers which can afford international brands, the determining factor for the growth of VAS business will be the number of new rural connections. Hence, CGHL looks poised to experience stronger growth in the VAS business relative to CRG and ENN. For FY18, CGHL expects to register 48% new residential connection growth, primarily driven by rural connections, much higher than 0%/4% for CRG and ENN in 2017E.

China city-gas distributors: VAS business China city-gas distributors: residential contribution in 2016 connection growth guidance for 2017E and city-gas penetration CNY 60% 70% 6% 400 50% 60% 5% 50% 300 40% 4% 40% 3% 200 30% 30% 2% 20% 100 20% 1% 10% 10% 0% 0 0% 0% CGHL CRG ENN CGHL CRG ENN VAS as % of revenue (LHS) VAS as % of op profits (LHS) 2017E residential YoY connection growth guidance (LHS) VAS revenue per new connection (RHS) City-gas residential penetration rate (RHS) Source: Company, Daiwa estimates Source: Company, Daiwa estimates Notes: For CGHL, we use FY18E numbers

Key stock pecking order:

Among the national city-gas distributors, ENN and CGHL are more active in pursuing hedging and diversification strategies and hence are better prepared to shore up their profitability amid the upcoming unavoidable industry- wide distribution dollar margin squeeze, and to reap the benefits from strong natural gas consumption growth. On the other hand, we expect CRG to experience difficulties given its pure city-gas model and its passive approach on hedging and diversification. Hence, we prefer ENN and CGHL over CRG. However, given that CGHL delivered a 105% share price return in 2017, the stock is currently trading at 14.7x 12-month forward PER, much more demanding than the 10.8x 12-month forward PER of ENN. As a result, after taking into account the risk-reward profile, we select ENN as our top pick, followed by CGHL, and CRG.

1. ENN (2688 HK, HKD51.5, Buy [1])

Slated to enjoy cheap LNG upon commissioning of parent’s Zhoushan LNG terminal in 2H18 ENN has secured a total of 1.43mtpa of LNG import contracts for the next five years (2H18-2H23) and the 1.43mtpa (c.2bcm pa; 1 tonne of LNG equals 1400m3 of natural gas) represents 7-9% of ENN’s annualised gas sales in 2018-19E. Based on current oil prices, the all-in cost of the imported LNG is CNY2.0/m3, translating into a CNY0.1/m3 discount to the benchmark city-gate price in Zhejiang, where the terminal is located. More importantly, the import of LNG through its parent company’s terminals can enhance ENN’s gas supply reliability during the winter heating season; hence, ENN can avoid a large CNY0.1-0.2/m3 margin squeeze arising from purchasing of

China Gas: 12 January 2018

expensive third-party spot LNG. As the Zhoushan terminal will gradually expand, we expect ENN to substitute an increasing proportion of its piped gas supply in Zhejiang and surrounding provinces such as Jiangsu and Fujian with cheap offshore LNG, and use the savings to hedge the upcoming dollar margin squeeze.

Large ambitions for natural gas DE projects As of the end of 1H17, ENN had 22 DE projects which contributed CNY98m sales in 1H17. According to management, ENN aims to transform into an integrated energy (IE) provider from a pure gas supplier, with DE/IE sales contributing 50% of the company’s net profit in 3 to 5 years’ time. The ambitious target implies ENN is well aware of the upcoming fierce downstream competition and trying to secure its future profitability through DE projects before the opening-up of the downstream retail market. As DE projects generally last for 15 to 20 years, the earnings outlook for ENN should be highly visible upon its transformation to an IE provider, despite the intensifying downstream competition.

2. CGHL (384 HK, HKD20.8, Outperform [2])

Aiming for 20% share of the 40m rural household connection market Given that: 1) the central government is committed to reducing the uncontrolled use of scattered coal in rural areas, and 2) local governments are likely to push for the coal-to-gas conversion to be done as soon as possible to meet their environmental targets while subsidies from the central government are still in place, the senior management of CGHL is optimistic on the near- to mid-term growth of its rural connection business. CGHL aims to connect a total of 8m rural households in northern China by the end of FY2022E (March 2022), representing 25-30% of the potential rural market size on our estimates. CGHL expects to connect 1.1m/2.0m/2.5m rural households in FY18E/19E/20E. Nevertheless, given the unexpected seasonal gas shortage in 2018 arising partly from faster- than-expected rural coal-to-gas conversion in northern China, we believe there is downside risk to CGHL’s rural connection target in the near term as: 1) the central government may decide to slow the pace of rural coal-to-gas conversion until the issue of seasonal supply tightness is resolved with enhanced peak-shaving capabilities, or 2) CGHL may decide to slow the connection speed if there is insufficient cheap gas supply for incremental rural residential gas sales.

VAS business to account for 20% to 30% of net profit in 3-5 years In 1H FY18 thanks to strong gas heater sales, CGHL’s VAS business posted 160% YoY operating profit growth to HKD289m, representing 6% of the total operating profit of the company. For 2H FY18E, the company expects its VAS business to maintain strong growth on the back of its large backlog of wall-mounted gas heater orders (520k units with ASP of CNY4,000-6,000 and operating profit margin of c.20%). To further improve its margin, CGHL plans to improve the proportion of its self-produced gas heaters, which could boost its margin by several percentage points. Other than generating VAS sales from new customers, CGHL is also looking at its large existing user base (c.23m) for recurring sales, primarily from: 1) cross-selling of different products and services through its proprietary mobile platform Zhongran Smart Living (中燃慧生活) , and 2) replacement demand for gas heaters, which usually have a replacement cycle of 8 to 10 years. In 3-5 years, CGHL expects the VAS business to account for 20% to 30% of the company’s net profit.

CGHL: residential connection guidance CGHL: Gasbo showroom m 6 60% 5 50% 4 40% 3 30% 2 20% 1 10% 0 0% FY18E FY19E FY20E Rural connection City connection (LHS) Rural connection proportion (RHS)

Source: Company, Daiwa estimates Source: Daiwa

China Gas: 12 January 2018

Examples of services provided by Zhongran’s Smart Living mobile app

Piped gas Staples & Overseas Securities LPG order Electricity Power retail sales services seafood shopping accounts

Smart-living Red Pocket Finance services

Home Gas Digital Air tickets Food products appliances products

Promotions Group-Buy

Source: Company, Daiwa research

3. CRG (1193 HK, HKD24.7, Hold [3])

Existing high exposure to city-gas sales and lack of hedging and diversification are a double whammy Relatively speaking, CRG has the highest earnings exposure to city-gas sales, which represents 54% of its total 2017E gross profit, higher than 29% for CGHL and 49% for ENN. The gas sales-centric profit mix, together with CRG’s passive stance on hedging and diversification, has put CRG in an unfavourable position, in our view, amid the forthcoming dollar margin squeeze. Moreover, as most of the city-gas projects with a high level of profitability were developed or acquired in 2000-15, there are likely limited M&A opportunities ahead for CRG. Hence, we do not believe CRG will be able to offset the negative impact from dollar margin squeeze through inorganic growth, which in the past has been the key growth driver for CRG.

China Gas: 12 January 2018

Appendices

China Gas: 12 January 2018

Appendix I: seasonal gas shortage during heating season in China

As highlighted in Chapter 3, although there is technically enough natural gas supply to satisfy robust demand on a full-year basis, there are still frequent seasonal gas shortages during the heating season from time to time due to the huge pick-up in demand during winter (historically demand is 2x vs. summer and the difference is even larger at 4x for northern China). For 2017-18 in particular, we have seen a serious gas shortage starting from November, with a daily gas shortage of c.100mcm, representing c.10% of daily natural gas demand during the winter. As a result, the national ex-factory price, which is market based, once had risen as much as c.85% since the beginning of heating season. Below, we discuss each of the major causes of the current gas shortage and assess the chance of re-occurrence in the upcoming years.

China: seasonal natural gas demand and supply China: national LNG ex-factory prices in China

Demand CNY/ton 8,000 7,000 85% increase Supply 6,000 5,000 4,000 3,000 2,000 1,000

Jul-17

Apr-17 Oct-17

Jan-17 Jun-17 Jan-18

Feb-17 Mar-17

Sep-17 Dec-16 Aug-17 Nov-17 Dec-17 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Nov-16 May-17 Source: Daiwa Source: SHPGX, Daiwa

Overview of gas shortage supply in 2017-18 heating season

Starting from 1 November when the heating season began in some regions in northern China, a number of cities such as Baoding in Hebei province reported supply tightness. When more regions entered the heating season in mid-November, we saw a more severe demand-supply imbalance in northern China, particularly in the 4 core provinces (Hebei, Henan, Shandong and Shanxi) where basic heating and cooking demand from residents and public service providers (eg, schools and hospitals) were not satisfied. As a result, the government had to limit the supply to industrial users in order to secure residential gas usage. But as the temperature began to fall towards the end of November, the imbalance continued to increase in northern China. For example, Hebei issued an “orange” alert, indicating that the provincial gas shortage reached 10-20% of total gas required. Hence, the government had to limit piped gas supply to central China and southern China and divert LNG imports to meet the basic heating demand in northern china. We estimate the daily shortage amounted to c.100mcm across the nation, representing c.10% of the total gas needed.

China: Hebei natural gas demand supply imbalance alert levels Alert Level Degree of shortage Course of action Red Over 20% of total demand needed Limiting gas supply to non-residential users in the order of: 1) industrial, 2) commercial, 3) public services, 4) vehicles Orange 10% to 20% of total demand needed Limiting gas supply to industrial and commercial users Yellow 5% to 10% of total demand needed Limiting gas supply to industrial and commercial users Blue 3% to 5% of total demand needed Requiring city gas distributors to procure additional gas through market sources

Source: Hebei DRC

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Four major causes of the 2017-18 gas shortage during the heating season

China: major causes of 2017-18 gas shortage during the heating season

Faster than Recovery of expected coal industrial to gas demand conversion

Supply disruption from Lack of gas central Asia storage for piped gas and c.10% gas peak shaving Tianjin LNG deficit in 2017-18 heating season

Source: Daiwa

1. Supply disruption from central Asia piped gas and Tianjin LNG To ensure sufficient local gas supply, Turkmenistan has reduced its gas supply to China. As a result, the daily imported piped gas volume from central Asia is 40-50mcm less than the contracted volume. Together with delay in commissioning of the Sinopec Tianjin LNG receiving terminal which has a daily capacity of 20- 30mcm, this has resulted in 70mcm of daily unfulfilled demand, representing c.75% of the total gas deficit during 2017-18 heating season, based on our estimates.

2. Faster-than-expected coal to gas conversion before the end of the 2013-17 five-year environmental plan Given 2017 was the final year of the Air Pollution Prevention and Control Plan, local governments were rushing to accomplish their unfinished targets on coal-to-gas conversion before the deadline. Some officials even over-achieved their assigned targets without taking into account the supply of natural gas. For example, YTD, the Hebei government has completed the demolition of 11.7k t/h of coal-fired boilers and rural connections for 2.6m households in total, 160%/40% higher than the annual target of 4.5k t/h and 1.8m households. As a result, actual demand from coal-to-gas conversion was larger than expected, leading to excess demand.

3. Recovery in industrial demand Accounting for c.50% of natural gas consumption, industrial demand (fuel + chemical companies) will directly affect overall demand growth. In 2017, given: 1) the acceleration of industrial activity, and 2) the improving economics of natural gas vs. oil for industrial use on rebounding oil price (discount widening from 20% to 35%), industrial demand has picked up substantially(c.22% YoY growth in 10M17), exacerbating the scale of excessive demand.

4. Lack of gas storage for peak shaving In 2016, China had underground gas storage capacity of 7.4 bcm, representing merely 3.6% of 2016 national consumption. In other words, gas storage, if fully utilised, is only enough for 13 days of consumption (or 9 days during heating season), much lower than the western world (60 days for US and 110 days for Europe). As a result, if demand unexpectedly ramps up, as it did during the 2017-18 heating season, China did not have a sufficient buffer for peak shaving, leading to a nation-wide gas shortage.

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China: daily supply deficit breakdown during the 2017-18 heating season mcm 100

80 24

60 25 94 40 70

20 45 45

0 - Central Asia piped gas supply Tianjin LNG supply disruption Unexpected demand Total supply deficit disruption

Source: Inengyuan, Daiwa estimates

Seasonal gas shortage likely to recur in the near term, though to a lesser extent

From the above, it is clear that this year’s serious gas shortage is largely a result of a combination of temporary and one-off events which can be progressively resolved. For example, the Sinopec Tianjin LNG receiving terminal is ready to be opened, pending the resolution of minor issues between local governments and SOEs. In light of the lower-than expected supply from central Asia, China can take advantage of the abundance of international LNG supply to make up for the shortfall. Also, with regard to coal to gas conversion, we believe the central government will learn its lesson and have a better plan and guidance going forward. Hence, the conversion should progress in a controlled manner and is not likely to result in substantial excess demand once again.

As a result, we believe China is not likely to experience another gas shortage of this scale. That said, we argue seasonal supply tightness will still occur from time to time in the near term due to: 1) the significant difference during winter and the off-peak season, and 2) China’s underdeveloped peak shaving capability (including underground gas storage, LNG storage, and offshore LNG receiving capacity), which takes at least three years to ramp up. Nevertheless, over the longer term, we see the seasonal gas shortage gradually fading out as the Chinese government is determined to enhance its peak shaving capability. By the end of 2020, we expect China’s national natural gas storage capacity (including both underground and LNG storage) to markedly strengthen to c.23bcm, representing c.6.7% of national consumption (2016: c.4.3%), thanks to: 1) the continued expansion of existing underground storage and commissioning of large-scale new storage, and 2) increasing LNG storage capacity in northern China (See Appendix II and IV). We expect LNG equipment makers, such as CIMC Enric (3899 HK, HKD7.33, Outperform [2]) and owners of LNG liquefaction factory, like Kunlun Energy (135 HK, Not rated) to be primary beneficiaries of increasing demand for LNG storage. Additionally, we believe oil majors are likely to expedite their exploration of gas fields in order to produce more to meet the excess demand in case of supply tightness. Hence, oil and gas field services companies are also likely to benefit.

China Gas: 12 January 2018

Appendix II: The outlook for gas storage in China

In Appendix I, we highlighted that one of the key reasons for the seasonal gas shortage in China is the lack of gas storage for peak-shaving. Understanding the bottleneck, China’s government has vowed to enhance its gas storage capacity. Indeed, the government plans to expand overall natural gas storage capacity (including LNG) at 17% CAGR to 40bcm by 2025, representing 8% of national consumption based on our estimates, up from 5% in 2016. Below, we discuss the current situation and outlook for the natural gas storage in China.

Basics of natural gas storage

Natural gas is usually stored underground under pressure in gaseous form. There are three primary types of underground gas storage facilities: aquifers, depleted oil and natural gas fields, and salt caverns. Depleted oil and natural gas fields are most commonly used and accounted for 80% of the world’s natural gas storage by capacity in 2016. To qualify as a good storage site, the facility has to be close to the load centre/major pipelines and have a large storage capacity and fast rate of deliverability (the rate at which the stored gas can be extracted for use). Other than underground facilities, there are also above-ground storage facilities, such as LNG-tanks. However, relatively speaking, above-ground facilities are less economical for large-scale storage due to their smaller size and hence natural gas storage is dominated by underground facilities, except for countries that rely heavily on LNG imports, such as Japan. For example, underground storage facilities account for 98% of natural gas storage in the US.

Underground storage facilities comparison Types of storage Aquifers Depleted oil and natural gas reservoirs Salt caverns Effective storage capacity Large Medium to large Small Deliverability Moderate Moderate High Low as the geologic characteristics are unknown and a High as it uses existing infrastructure and the geologic Low as a complete new underground structure Economics high cushion gas requirement characteristics are well-known needs to be created Development cycle 10 - 12 years 5 - 8 years 5 - 10 years

Source: EIA, GWPC, Gas in Focus, Daiwa estimates

Snapshot of underground storage facilities

Source: Energy Infrastructure

Global underground gas storage capacity Global underground gas storage deliverability breakdown by type of facility breakdown by type of facility Salt caverns 8% Salt caverns Aquifers 24% 12%

Aquifers Depleted gas 11% fields Depleted gas 65% fields 80%

Source: CEDIGAZ, note: as of 2016 Source: CEDIGAZ, note: as of 2016

China Gas: 12 January 2018

China is lagging the world on storage capacity

In China, underground facilities are the primary means for natural gas storage and account for c.70% of total storage capacity. As of the end of 2016, China only had 7.4bcm of actual underground gas storage capacity in terms of working gas (the actual amount of gas that can be extracted from storage and used), representing only 3.6% of its national consumption in 2016, 7pp below the International Gas Union’s acceptable standard. As a result, China does not have sufficient peak-shaving capacity and needs to handle excess demand via demand-side management. Indeed, according to CNPC, underground storage can only satisfy c.60% of the excess demand during peak usage times. Currently, the majority of underground storage in China is controlled by CNPC and Sinopec, with the rest primarily owned by city-gas distributors.

China: natural gas storage capacity breakdown Level of underground gas storage capacity development: China vs. western peers

35% Others 34% 30% 25% 20% 15% 10% CNPC underground 5% storage Sinopec 0% 65% underground US Germany China storage 1% Underground storage capacity as % of annual consumption World average/acceptable standard for countries with >30% import reliance Source: CEDIGAZ, NDRD, Daiwa estimates, note: as of 2016 Source: BP, IGU

China: major underground natural gas storage in China (as of November 2016) Underground gas storage Working gas design Cushion gas capacity* Maximum withdrawal rate facility (actual) capacity* (bcm) (bcm) Total Capacity* (bcm) (mcm/d) Dagang Cluster (Banqiao) 3.03 3.93 6.96 34 Jing 58 Group 0.75 0.79 1.54 6 Bannan 0.43 0.58 1.01 4 Wen 96 0.29 0.3 0.59 5 Liuzhuang 0.25 0.21 0.46 2 Jintan 1.71 0.93 2.64 15 Shuang 6 1.6 2.53 4.13 15 Suqiao 2.33 4.41 6.74 21 Hutubi 4.5 6.2 10.7 28 Xiangguosi 2.28 1.98 4.26 14 Shaan 224 0.5 0.54 1.04 4 Total 17.7 (7.4) 22.4 40.1 148

Source: CEDIGAZ *Note: Actual capacity may be smaller than designed capacity as some are still under construction

China Gas: 12 January 2018

China: map of major underground natural gas storage in China (as of 2016)

Source: D-maps, Daiwa

Three major causes for the lack of development in underground gas storage

Heavy upfront investment with long payback period According to Sinoergy, the unit capex (investment per m3 of working gas capacity) for underground gas storage is CNY3-6. Assuming a storage size of 700mcm (the average storage size of underground storage in China, it would costs c.CNY3bn to build an underground storage facility. To put this into perspective, PetroChina (857 HK, not rated) and Sinopec (386 HK, not rated), the major listed platforms of CNPC and Sinopec Group, only made CNY38bn/CNY31bn of net profit on average in 2015/16, implying that a single underground storage facility costs c.9% of net profit of the oil majors. Hence, the upfront investment required for underground gas storage is deterrent.

Lack of proper pricing mechanism for storage services Previously, underground storage fees were embedded in the long-distance transmission fees charged by oil majors. In other words, oil majors were not able to charge additional income on their capital they put up for the construction of the underground storage except for some limited financial subsidies from the government. Hence, oil majors were not motivated to construct underground storage and private capital was not interested in entering this market. But this is currently under review, given that gas pricing will be market-based going forward, hence storage owners can eventually increase the gas price during peak season to make up for the storage investment.

Insufficient policy support The government has failed to offer sufficient compensation to encourage the enterprises to invest, given the unattractive returns on natural gas storage investment. Also, until recently, there was no policy requiring gas transmission operators and gas distributors to maintain a minimum amount of gas storage. Hence, they had the leeway to not construct the necessary storage facilities

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Total gas storage targeted to expand at 17% CAGR to 40bcm in 2025, representing 8% of annual consumption Going forward, we believe the development of underground natural gas storage will speed up in China thanks to a more benign environment driven by: 1) a more market-based natural gas pricing mechanism (see Chapter 1) through which storage owners can pass the storage cost to users and make a reasonable return on investment, 2) stricter policies requiring industry participants to maintain certain amount of reserves (major gas suppliers are now required to have the storage capacity for 10% of the annual contracted volume).

At present, China targets to expand its underground storage capacity at a 22% CAGR to 15bcm in 2020, which we believe is achievable in light of: 1) the large potential room for growth in existing underground storage (2016 actual working gas capacity: 7.4bcm vs. designed capacity: 17.7bcm), and 2) commissioning of large-scale storage (eg, Sinopec’s Wen 23 gas storage facility with designed capacity of 3.9 bcm). On top of underground storage, the government also plans to expand its total storage capacity through boosting the scale of LNG storage in both city gas projects and LNG receiving terminals. By 2025, it aims to achieve an overall storage capacity (including LNG) of 40bcm (17% CAGR), representing c.7.6% of national consumption based on our estimates, up from c.4.3% in 2016.

China Gas: 12 January 2018

Appendix III: 2017-21 northern China heating plan

In December 2017, the NDRC, NEA and 8 other ministries jointly published the 2017-21 Winter Clean Heating Plan (the plan) for northern China. The plan specifies that clean energy has to account for 50%/70% of heating in northern China in 2019/2021, up from 34% in 2016 and provided concrete targets for each energy source (see below). In the key 2+26 cities, the goal is even more ambitious with clean energy likely to fuel 90%/100% of heating in 2019/2021 in built-up areas.

Overview of winter heating in China: coal is still responsible for heating in 83% of total floor area As of 2016, total heating area in northern China amounted to 20.6bn sqm, with city/rural areas accounting for 68%/32%. Not surprisingly, coal is still the largest source of heating, with 83% of total floor area covered by coal- fired heating. Of the 83%, clean coal accounts for 17pp. In total, c.400m tonnes of coal (50% of which is scattered coal) is burned each year for heating in northern China, representing c.10% of annual coal consumption. On the other hand, natural gas is the second largest source of heating in northern China, accounting for 11% of total heating floor area. Nevertheless, the contribution from other clean energy sources is much smaller. For example, geothermal and biomass fuel each account for 2% of heating floor area only. As for solar power and residual industrial heat, they represent less than 1% of floor area each. In total, clean energy sources (including clean coal) only accounted for 34% of heating area in China in 2016.

Sources of heating in northern China for 2016 2016 Coal 83% Natural gas 11% Electricity 2% Geothermal 2% Biomass fuel 1% Solar power 0% Residual industrial heat 0%

Source: NEA

Clean energy to account for 70% of heating in northern China by 2021, led by clean coal, biomass fuel and natural gas To clean up air in northern China, the government is determined to increase adoption of clean energy sources for heating (replacing scattered coal in particular) and has offered specific targets in the plan. First, it targets an incremental area of 7.5bn sqm (30% 2016-21 CAGR) to be covered by ultra-low emission, clean-coal centralised heating, the largest among various clean-energy sources given that clean coal is readily available. The government has also placed greater emphasis on biomass fuel, targeting for it to cover an incremental area of 1.9bn sqm (60% 2016-21 CAGR). For natural gas, even though the plan does not offer a specific target for the whole of northern China, it targets an incremental area of 1.8bn sqm for the “2+26” cities over 2016-21. On top of that, the plan also aims for incremental area of 1.1/0.5/0.05/0.1bn sqm to be covered by heating fuelled by electricity/ geothermal power/ solar power/ residual industrial heat in northern China over 2016-21, which would provide upside for electricity consumption growth in these areas. In total, China targets for clean energy to account for 50%/70% of heating in northern China by 2019/2021.

2021 clean energy heating target in northern China 2016 2021 Growth (%) CAGR % of area adopting clean heating 34% 70% 36pp N/A Area using electricity for heating (bn sqm) 0.4 1.5 275% 30% Area using clean coal for centralised heating (bn sqm) 3.5 11 214% 26% Area using geothermal heating (bn sqm) 0.5 1 100% 15% Area using biomass fuel for heating (bn sqm) 0.2 2.1 950% 60% Area using solar power for heating (bn sqm) N/A 0.05 N/A N/A Area using residual industrial heat for heating (bn sqm) 0.1 0.2 100% 15% Area using natural gas for heating in 2+ 26 cities (bn sqm) 1.2 3 150% 20%

Source: NEA

China Gas: 12 January 2018

Appendix IV: 2017-21 northern China gas supply security workplan

Given the serious gas shortage in the current heating season (see Appendix I), China’s government has recognised that it needs to further safeguard its gas supply in order to continue to promote coal-to-gas conversion for winter heating. As a result, along with the 2017-21 Northern China Heating Plan, 10 ministries have jointly published the 2017-21 Northern China Gas Supply Security Workplan (the plan), targeting to secure enough gas to satisfy the gas demand for heating arising from ongoing coal-to-gas conversion in northern China, particularly in the 2+4 municipalities/provinces (Beijing, Tianjin, Shandong, Shanxi, Henan, Hebei). Below, we summarise the key measures specified in the plan which are for the 2+4 municipalities/provinces.

China: gas pipeline, LNG infrastructure, and underground storage target for 2+4 municipalities/provinces 2016 2021 Growth CAGR Annual designed capacity of pipeline supply of natural gas to northern China (bcm) 160 235 47% 8% Provincial and distribution network distance (km) 13,000 17,300 33% 6% Annual provincial and distribution network capacity (bcm) 194 252 30% 5% Annual LNG terminal receiving capacity (m tonnes) 14.7 37.1 152% 20% LNG terminal storage capacity (bcm) 1.3 3.7 188% 24% Annual LNG terminal gasification capacity (bcm) 0.1 0.2 201% 25% Underground storage daily withdrawal capacity (mcm) 31.5 70 122% 17%

Source: NEA

Annual piped gas supply capacity to expand at 8% CAGR to 235 bcm in 2021 Currently, the existing pipeline network covering the 2+4 cities/provinces has an annual capacity of 160bcm. By 2021, the government plans to expand capacity by 47% (8% CAGR) to 235bcm, primarily through the commissioning of new pipelines. Additionally, in order to expand the geographical coverage of piped gas, it also plans to extend the provincial transmission and city-distribution networks by 33% (6% CAGR) to 17,300km, which will expand the transmission/distribution capacity by 30% (5% CAGR) to 252bcm in 2021.

China: piped gas supply capacity expansion plan for 2+4 municipalities/provinces Year Description Incremental annual capacity (bcm) 2017 Commissioning of Shaanxi-Beijing IV Pipeline and Tianjin LNG Pipeline 20 2018 Commissioning of Ordos-Anping-Cangzhou (Cangzhou to luquan sub-section) N/A 2019 Commissioning of Ordos-Anping-Cangzhou (Puyang to Baoding sub-section) and expansion of Shaanxi-Beijing IV Pipeline 15 Commissioning of China-Russian Eastern Pipeline (Zhangling to Yongqing sub-section), Tangshan LNG Pipeline II, and Western Inner 2020 35 Mongolia Coal-to-gas Pipeline (Eastern section) 2021 Commissioning of China-Russian Eastern Pipeline (Anping to Taixing sub-section) and Shenmu-Anping CBM pipeline 5 Total 75

Source: NEA

Expanding LNG receiving capacity by 20% CAGR to 37m tonnes in 2021 On top of piped gas, China also plans to shore up its supply through more offshore LNG procurement. As a result, the government targets to increase its LNG receiving capacity through both expansion of existing LNG receiving terminals and construction of new terminals. In the plan, the government targets to increase its annual LNG receiving capacity of existing terminals in the 2+4 cities/provinces by 152% (20% CAGR) to 37m tonnes with a 188% (24% CAGR) /201% (25% CAGR) increase in storage/ annual gasification capacity to 3.7/0.2 bcm in 2021 in the 2+4 municipalities/provinces. Given the above mentioned targets have not factored in incremental supply from new terminals, we believe the real growth in receiving capacity is likely to be stronger than the abovementioned 20% CAGR.

China: upcoming new storage in existing LNG receiving terminal in 2+4 municipalities/ provinces Commissioning Year LNG terminal # of additional LNG storage tank 2020 Tangshan LNG terminal 4 2020 Shandong LNG terminal 2 2020 CNOOC Tianjin LNG terminal 4-6 2020 Huanghua LNG terminal 3 2020 Caofedian LNG terminal 3 2021 Sinopec Tianjin LNG terminal 2 2021 Rizhao LNG terminal 3 2021 Longkou LNG terminal 3 Total 24-26

Source: NEA

China Gas: 12 January 2018

Enhancing underground storage capacity and boosting daily withdrawal capacity by 17% CAGR to 70mcm in 2021 In addition to the increase in LNG receiving capacity, the government also targets to improve its peak-shaving capability in northern China in the 2+4 municipalities/ provinces through 1) an increase in underground storage capacity, which should boost the daily withdrawal capacity by 122% (17% CAGR) to 70mcm in 2021;and, 2) the construction of new LNG storage facilities, which should enhance local LNG emergency reserves in each of the municipalities/ provinces.

China: upcoming new local LNG emergency reserves in 2+4 municipalities/ provinces Municipalities/provinces Incremental LNG emergency reserve (mcm) Equivalent days of gas consumption in 2016 Beijing 190 4 Tianjin 58 3 Shandong 74 3 Shanxi 48 3 Hebei 300 14 Henan 167 7 Total 837 6

Source: NEA; note: as at end-2017

China Gas: 12 January 2018

Company Section

China Utilities 12 January 2018

ENN Energy (2688 HK) ENN Energy

Target price: HKD60.00 (from HKD57.04)

Share price (10 Jan): HKD51.50 | Up/downside: +16.5%

Upgrading: defensive growth, undemanding valuation Dennis Ip, CFA (852) 2848 4068  Self-owned LNG contracts likely to slow dollar margin squeeze [email protected]  Distributed-energy services should help retain large C&I users Don Lau, CFA (852) 2848 4469  Upgrade to Buy (1) with a hedged business model; lifting TP to HKD60 [email protected]

What's new: In 2017, ENN (our 2nd pick in the China city-gas sector) Forecast revisions (%) achieved a 75% share price appreciation vs. CGHL’s 110%. In 2018, we Year to 31 Dec 17E 18E 19E assign ENN Energy as our top pick, given its integrated business model, Revenue change 12.7 19.5 24.0 with self-owned LNG contracts and active participation of distributed- Net profit change (1.7) 2.6 7.9 Core EPS (FD) change (1.7) 2.6 7.9 energy (DE) projects for its large commercial and industrial (C&I) users, Source: Daiwa forecasts could be the answer to a continual dollar margin squeeze in 2018-19E, and to achieving 15% recurring profit growth. We expect ENN’s valuation to Share price performance rerate from the current 10.8x 2018E PER (CGHL and CRG: 14-15x) after (HKD) (%) cash settlement of its USD500m convertible bonds before 23 February 2018, 60 135 and believe that the current level offers a good entry point. 54 124 48 113 What's the impact: Upstream hedge – self-owned LNG contracts. 41 101 35 90 ENN’s 1.43mtpa of 5-year LNG import contracts, to be supplied starting in Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 2H18E via its parent-owned Zhoushan terminal in Zhejiang, have an ENN Energy (LHS) Relative to HSI (RHS) average cost of CNY1.9-2.0/m3 under a USD55-60/barrel oil price scenario, lower than the summer city-gate tariff of CNY2.1/m3 (winter: 10- 12-month range 35.30-59.20 15% premium). Most importantly, this 2bcm of self-contracted LNG supply Market cap (USDbn) 7.13 represents 7-9% of ENN’s annualised gas sales in 2018-19E, enhancing its 3m avg daily turnover (USDm) 15.85 gas supply reliability during the winter heating season, and avoiding a large Shares outstanding (m) 1,082 ENN Group (30.5%) CNY0.1-0.2/m3 margin squeeze on incremental-volume from expensive Major shareholder third-party spot LNG. Hence, we expect ENN’s dollar margin squeeze to be Financial summary (CNY) contained within CNY0.02/m3 vs. peers’ CNY0.03-0.04/m3 in 2018-19E. Year to 31 Dec 17E 18E 19E Revenue (m) 43,812 52,862 62,069 Downstream risks mitigated by DE projects. Through gas liberalisation, Operating profit (m) 5,852 7,164 7,852 city-gas distributors can bypass oil majors to procure LNG in the long run. Net profit (m) 3,697 4,289 4,960 Core EPS (fully-diluted) 3.416 3.962 4.583 As a result, oil majors are likely competing for direct-supply contracts with EPS change (%) 23.6 16.0 15.7 large C&I users. ENN said it is in the process of transforming itself from a Daiwa vs Cons. EPS (%) 8.2 9.4 9.2 pure gas distributor into an energy solution provider using gas-fired power- PER (x) 12.6 10.8 9.4 Dividend yield (%) 2.1 2.5 3.0 heat-cooling tri-generation DE skids, to keep customers and maintain profit. DPS 0.888 1.070 1.283 PBR (x) 2.7 2.3 1.9 What we recommend: We upgrade ENN to Buy (1) from Outperform (2) EV/EBITDA (x) 7.6 6.3 5.4 ROE (%) 22.8 22.6 22.2 on a resilient 15% 2016-19E recurring EPS CAGR and undemanding 10.8x 2018E PER. Despite our 2% 2017E EPS cut on the dollar margin squeeze, Source: FactSet, Daiwa forecasts we raise our 2018-19E EPS by 3-8% after raising our gas sales volume assumptions by 13-27% despite cutting our dollar margin by 6-7%. We raise our WACC from 9.5% to 9.8% on the margin squeeze, despite a hedge with self-owned LNG. Our new assumptions lift our terminal value by 4%, and hence our TP by 5% from HKD57.04 to HKD60. Key downside risk: a higher-than-expected distribution tariff cut for certain provinces from July 2018, the first tariff adjustment of the newly-introduced 7%-ROA policy.

How we differ: Our 2018-19E EPS are 9% higher than consensus, as we believe the market has not incorporated the LNG cost savings starting from 2H18E, to relieve the unit dollar margin downward trend.

See important disclosures, including any required research certifications, beginning on page 111

ENN Energy (2688 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook ENN: total gas sales volume and unit dollar margin

We raise our 2017-18 retail gas sales volume growth Unit: mcm forecasts by 5-10pp from 15-17% YoY to 22-25% YoY, on 35,000 0.80 the addition of gas sales for both industrial- and city- 30,000 0.75 25,000 integrated energy projects. However, we trim our unit dollar 0.70 gas sales margin by CNY0.06-0.04/m3 on industrial CTG, 20,000 0.65 and lower-margin gas sales to Quanzhou industrial 15,000 0.60 customers and Dongguan’s gas-fired power plants. 10,000 5,000 0.55 With more reliable gas supply from its self-owned LNG, 0 0.50 ENN will be able to continue its plan to add 100-200k rural 2012 2013 2014 2015 2016 2017E 2018E 2019E residential customers pa over 2018-19E. Total piped gas sales volume Gas sales dollar margin

Source: Company, Daiwa estimates

Valuation ENN: 1-year forward PER

Trading at a 10.8x 2018E PER currently, ENN is below its PER (x) peer average of 14-15x (except for TCCL) and is also 25 1.3SD below its past-11-year-average 12-month-forward 23.4x Avg+2SD PER of 15.9x. We believe ENN’s valuation is attractive, 20 19.7x Avg+1SD given: 1) the superior locations of its city-gas projects in 15.9x Avg coastal areas, where c.60% of the connected population is 15 located, and which are exposed to multiple gas sources 12.2x Avg-1SD allowing the company low-cost gas purchases which 10 8.5x Avg-2SD should help maintain its gas dollar margin in the long term. We believe ENN is the only gas company in China able to 5

explore more upstream cost-saving opportunities in the

Jul-11

Oct-09 Apr-13 Oct-16

Jan-15 Jan-08 Jun-14

Mar-16 Mar-09

Feb-12

Nov-13 Aug-08 Dec-10 Sep-12 Aug-15 Dec-17 May-17 near term. ENN’s lagging PER is mainly due to the May-10 Source: Company, Daiwa estimates overhang of its USD500m convertible bond, in our view, which will be settled before 23 February 2018.

Earnings revisions ENN: Bloomberg consensus earnings-forecast revisions

The Bloomberg-consensus 2017-19 EPS forecasts for (CNY) ENN have risen by 4-15% since April 2017, likely as the 4.5 street has factored in higher gas sales volume growth after ENN guided for strong high-teen retail gas sales volume 4.0 growth for 1H17E. However, we see another c.9% EPS 3.5 adjustment in 2018-19E, given ENN’s self-owned LNG contracts to restore its gas sales dollar margin once its 3.0 parent commissions the LNG terminal in 2H18E.

2.5

Jul-17 Jul-17

Apr-17 Apr-17 Oct-17 Oct-17 Oct-17

Jun-17 Jun-17

Mar-17

Dec-17 Nov-17 Nov-17 Dec-17

Aug-17 Aug-17 Sep-17 Sep-17

May-17 May-17 May-17 2017E EPS 2018E EPS 2019E EPS

Source: Company, Daiwa estimates

ENN Energy (2688 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Natural gas sales volume (m3) 6,225 8,037 10,120 11,286 13,265 18,070 22,966 28,064 Gas sales dollar margin (CNY/m3) 0.70 0.69 0.76 0.78 0.72 0.63 0.61 0.60 Residential gas connection ('000 1,122 1,220 1,323 1,707 1,821 1,850 1,900 1,950 houesholds) Gross profit contribution - connection 47 44 46 50 49 46 40 37 fee

Profit and loss (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Gas connection 3,633 3,843 4,403 5,508 5,611 5,734 6,063 6,394 Sales of gas 10,516 14,102 17,485 18,680 17,900 22,449 27,789 34,173 Other Revenue 3,878 5,021 7,199 7,875 10,592 15,630 19,011 21,502 Total Revenue 18,027 22,966 29,087 32,063 34,103 43,812 52,862 62,069 Other income 171 238 271 391 650 706 714 790 COGS (12,688) (16,935) (22,365) (24,337) (25,873) (34,813) (42,258) (50,363) SG&A (1,971) (2,133) (2,417) (2,683) (2,757) (2,565) (3,049) (3,449) Other op.expenses (482) (1,252) (28) (1,560) (1,890) (1,287) (1,105) (1,195) Operating profit 3,057 2,884 4,548 3,874 4,233 5,852 7,164 7,852 Net-interest inc./(exp.) (621) (567) (430) (542) (609) (609) (637) (684) Assoc/forex/extraord./others 416 443 629 695 571 628 635 703 Pre-tax profit 2,852 2,760 4,747 4,027 4,195 5,871 7,163 7,871 Tax (859) (960) (1,127) (1,306) (1,307) (1,712) (2,017) (2,059) Min. int./pref. div./others (511) (548) (652) (685) (737) (735) (857) (852) Net profit (reported) 1,482 1,252 2,968 2,036 2,151 3,425 4,289 4,960 Net profit (adjusted) 1,616 1,937 2,343 2,736 3,212 3,697 4,289 4,960 EPS (reported)(CNY) 1.388 1.156 2.741 1.880 1.987 3.164 3.962 4.583 EPS (adjusted)(CNY) 1.514 1.789 2.164 2.527 2.968 3.416 3.962 4.583 EPS (adjusted fully-diluted)(CNY) 1.504 1.788 2.014 2.526 2.763 3.416 3.962 4.583 DPS (CNY) 0.345 0.382 0.610 0.640 0.687 0.888 1.070 1.283 EBIT 3,057 2,884 4,548 3,874 4,233 5,852 7,164 7,852 EBITDA 3,552 3,451 5,201 4,734 5,113 6,867 8,269 9,047

Cash flow (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 2,852 2,760 4,747 4,027 4,195 5,871 7,163 7,871 Depreciation and amortisation 618 708 817 939 959 1,015 1,105 1,195 Tax paid (859) (960) (1,127) (1,306) (1,307) (1,712) (2,017) (2,059) Change in working capital 941 966 1,272 (301) (498) 265 551 1 Other operational CF items 316 552 (626) 663 2,089 2,032 2,025 1,957 Cash flow from operations 3,868 4,026 5,083 4,022 5,438 7,472 8,827 8,966 Capex (2,878) (3,034) (2,578) (2,540) (2,657) (3,000) (3,000) (3,000) Net (acquisitions)/disposals (3) (118) (658) (4,000) (513) (600) (600) (600) Other investing CF items 2,014 58 504 346 (660) (633) (629) (597) Cash flow from investing (867) (3,094) (2,732) (6,194) (3,830) (4,233) (4,229) (4,197) Change in debt (600) (2,559) 171 (299) 76 603 (3,000) (3,000) Net share issues/(repurchases) 0 0 3 0 0 0 0 0 Dividends paid (315) (414) (709) (693) (799) (961) (1,158) (1,389) Other financing CF items 715 2,750 1,872 0 (1,016) (272) (3,420) 0 Cash flow from financing (200) (223) 1,337 (992) (1,739) (631) (7,578) (4,389) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash 2,801 709 3,688 (3,164) (131) 2,609 (2,980) 381 Free cash flow 990 992 2,505 1,482 2,781 1,826 3,203 3,395 Source: FactSet, Daiwa forecasts

ENN Energy (2688 HK): 12 January 2018

Financial summary continued … Balance sheet (CNYm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 6,472 7,082 10,574 7,454 7,515 9,918 6,938 7,319 Inventory 311 419 510 404 515 523 537 552 Accounts receivable 2,062 2,829 2,883 3,051 4,423 5,041 6,372 7,822 Other current assets 842 767 1,035 948 1,387 3,007 3,201 3,448 Total current assets 9,687 11,097 15,002 11,857 13,840 18,489 17,049 19,140 Fixed assets 15,099 17,531 19,441 21,121 22,297 24,360 26,334 28,218 Goodwill & intangibles 1,434 1,500 1,993 2,206 1,675 1,207 1,128 1,049 Other non-current assets 4,673 5,777 6,599 11,835 13,569 13,544 14,179 14,882 Total assets 30,893 35,905 43,035 47,019 51,381 57,601 58,691 63,290 Short-term debt 3,945 921 1,530 6,654 4,644 4,719 4,719 4,719 Accounts payable 4,894 6,166 7,262 7,133 8,323 8,696 10,570 12,149 Other current liabilities 2,775 3,782 4,748 5,621 5,374 5,858 5,331 5,464 Total current liabilities 11,614 10,869 13,540 19,408 18,341 19,273 20,620 22,332 Long-term debt 7,297 11,522 12,970 9,026 12,147 12,750 9,750 6,750 Other non-current liabilities 1,312 1,622 1,984 2,490 3,039 4,526 3,281 4,744 Total liabilities 20,223 24,013 28,494 30,924 33,527 36,549 33,651 33,826 Share capital 113 113 113 113 112 112 112 112 Reserves/R.E./others 8,540 9,430 11,985 13,355 14,854 17,318 20,448 24,020 Shareholders' equity 8,653 9,543 12,098 13,468 14,966 17,430 20,560 24,132 Minority interests 2,017 2,349 2,443 2,627 2,888 3,623 4,480 5,332 Total equity & liabilities 30,893 35,905 43,035 47,019 51,381 57,601 58,691 63,290 EV 50,162 50,352 48,495 52,463 53,554 51,935 52,138 48,906 Net debt/(cash) 4,770 5,361 3,926 8,226 9,276 7,551 7,531 4,150 BVPS (CNY) 8.104 8.813 11.171 12.439 13.827 16.103 18.995 22.295

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) 19.6 27.4 26.7 10.2 6.4 28.5 20.7 17.4 EBITDA (YoY) 26.5 (2.8) 50.7 (9.0) 8.0 34.3 20.4 9.4 Operating profit (YoY) 26.3 (5.7) 57.7 (14.8) 9.3 38.3 22.4 9.6 Net profit (YoY) 25.8 19.9 21.0 16.8 17.4 15.1 16.0 15.7 Core EPS (fully-diluted) (YoY) 24.3 18.9 12.7 25.4 9.4 23.6 16.0 15.7 Gross-profit margin 29.6 26.3 23.1 24.1 24.1 20.5 20.1 18.9 EBITDA margin 19.7 15.0 17.9 14.8 15.0 15.7 15.6 14.6 Operating-profit margin 17.0 12.6 15.6 12.1 12.4 13.4 13.6 12.7 Net profit margin 9.0 8.4 8.1 8.5 9.4 8.4 8.1 8.0 ROAE 20.6 21.3 21.7 21.4 22.6 22.8 22.6 22.2 ROAA 5.6 5.8 5.9 6.1 6.5 6.8 7.4 8.1 ROCE 14.8 12.5 17.0 12.7 12.7 16.0 18.4 19.5 ROIC 14.8 11.5 19.4 12.2 11.3 14.9 16.8 17.5 Net debt to equity 55.1 56.2 32.5 61.1 62.0 43.3 36.6 17.2 Effective tax rate 30.1 34.8 23.7 32.4 31.2 29.2 28.2 26.2 Accounts receivable (days) 39.5 38.9 35.8 33.8 40.0 39.4 39.4 41.7 Current ratio (x) 0.8 1.0 1.1 0.6 0.8 1.0 0.8 0.9 Net interest cover (x) 4.9 5.1 10.6 7.1 7.0 9.6 11.2 11.5 Net dividend payout 24.8 33.1 22.2 34.0 34.6 28.1 27.0 28.0 Free cash flow yield 2.1 2.1 5.4 3.2 6.0 3.9 6.9 7.3 Source: FactSet, Daiwa forecasts

Company profile

ENN Energy is one of the leading city-gas distributors in China, owning 165 projects (as of June 2017) with a geographical focus on mainly on coastal Guangdong, Shandong, Jiangsu, Zhejiang and Hunan provinces.

ENN Energy (2688 HK): 12 January 2018

Valuation

We raise our WACC from 9.5% to 9.8% on margin squeeze, despite a hedge with self- owned LNG contracts. Our new assumptions lift our terminal value by 4%, and hence our TP by 5% from HKD57.04 to HKD60. ENN: DCF Valuation Forecast 12 months to 31 Dec, All figures in CNYm 2018E 2019E 2020E 2021E 2022E 2023E 2024E Terminal Valuation Date 6-Jan-18 Next Balance Date 31-Dec-18 First Year Cash Flow Adjustment 0.98 Free Cash Flow EBITDA 8,269 9,047 9,962 11,130 12,216 13,153 10,595 Less: Other Non Cash ------Less: Cash Tax Payable on EBIT (2,017) (2,054) (2,183) (2,454) (2,704) (2,918) (2,251) Plus: Decrease in Working Capital 551 1 1,221 1,067 898 777 1,045 Less: Capital Expenditure (3,600) (3,600) (3,800) (3,800) (3,800) (3,800) (3,800) Free Cash Flow 3,203 3,395 5,200 5,944 6,609 7,213 5,588 5,700 Free Cash Flow for Valuation Purposes 3,203 3,395 5,200 5,944 6,609 7,213 5,588 5,700 WACC 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% 9.8% NPV of Free Cash Flow 2,922 2,821 3,935 4,096 4,148 4,124 2,909 38,099

Source: Daiwa forecasts, Company

ENN: DCF calculation ENN: DCF sensitivity analysis Terminal Value Equity Terminal Growth Rate 2.0% Enterprise Equity Value Terminal WACC 9.8% Discount NPV of Term Val. PV of Value Value Per Share Estimated Terminal Free Cash Flow 5,700 Rate FCF at 2020 Term Val. (CNYm) (CNYm) (HK$) NPV of Terminal Value (as at 31 Dec 2024) 73,178 7.3% 27,451 107,767 65,908 93,359 85,808 92.75 NPV of Terminal Value (as at 06 Jan 2018) 38,099 7.8% 26,924 98,459 58,290 85,214 77,663 83.95 DCF Valuation 8.3% 26,411 90,631 51,948 78,359 70,808 76.54 NPV of Forecasts 24,955 8.8% 25,913 83,956 46,597 72,510 64,959 70.22 NPV of Terminal Value 38,099 9.3% 25,427 78,197 42,032 67,459 59,908 64.76 Add: Market value of stakes in Associates #1 - 9.8% 24,955 73,178 38,099 63,054 55,503 60.00 Associate #2 - 10.3% 24,496 68,763 34,682 59,177 51,627 55.81 Associate #3 - 10.8% 24,049 64,851 31,691 55,739 48,188 52.09 Enterprise Value 63,054 11.3% 23,613 61,361 29,056 52,669 45,118 48.77 Less: Net Debt (as at 06 Jan 2018) (7,551) 11.8% 23,189 58,227 26,721 49,911 42,360 45.79 Equity Value 55,503 12.3% 22,777 55,397 24,642 47,419 39,868 43.09 No. Shares (millions) 1,082 Per Share Equity Value (CNY) 51.3 FX (HKD/CNY) 1.17 Per Share Equity Value (HKD) 60.00

Source: Daiwa forecasts and estimates Source: Daiwa forecasts and estimates

ENN Energy (2688 HK): 12 January 2018

China Utilities 12 January 2018

China Gas (384 HK) China Gas

Target price: HKD23.80 (from HKD28.10) Share price (10 Jan): HKD20.80 | Up/downside: +14.4%

Downgrading: diversification partly offsets EPS risk Dennis Ip, CFA (852) 2848 4068  Gas shortage to introduce near-term concerns on dollar margin risk [email protected]  Rural-gas earnings contribution maintained for FY18-20E Don Lau, CFA (852) 2848 4469  Downgrading to Outperform (2) on dollar margin trend [email protected]

What's new: In 2017, CGHL — formerly our top pick among the China city- Forecast revisions (%) gas distributors — saw a 105% share-price rise. But aggressive coal-to-gas Year to 31 Mar 18E 19E 20E (CTG) conversion has led to a 15-25% gas volume shortage in northern Revenue change (1.9) (2.1) (5.8) China, where gas companies will need to adopt expensive spot LNG to Net profit change 3.4 2.2 (3.8) Core EPS (FD) change 3.4 2.2 (3.8) supply residential and key commercial customers (hospitals, schools). On Source: Daiwa forecasts these concerns, we cut our FY18-20E dollar margin assumptions by 5-11%. Share price performance What's the impact: Dollar margin squeeze offset by aggressive rural (HKD) (%) diversification. Based on updates given at our recent PURE conference, 25 185 all city-gas distributors are seeing an extra CNY0.01-0.03/m3 HoH squeeze 21 159 in the dollar margin of gas sales in 2H17, which suggests the dollar margin 18 133 in 4Q17/December 2017 was CNY0.55/m3 / CNY0.45/m3, caused by 14 106 10 80 expensive incremental-volume gas during the winter-heating period. Jan-17 Apr-17 Jul-17 Oct-17 Jan-18

China Gas (LHS) Relative to HSI (RHS) Management and shareholder interests aligned. Facing a continuous dollar-margin squeeze for city gas, CGHL plans to increase its rural 12-month range 11.04-25.00 connections, from 1.1m in FY17E to 2.5m by 2020E to double its residential Market cap (USDbn) 13.21 connections from 2.5m in FY17E to 5.0m in FY20E, while also selling gas 3m avg daily turnover (USDm) 20.09 appliances to rural households. We expect CGHL to achieve HKD6bn net Shares outstanding (m) 4,969 Major shareholder Beijing Enterprises Holdings (24.7%) profit for FY18E as part of the conditions for 225m employee share options

(exercise price: HKD12.4, by 15 April 2019). CGHL has another 100m Financial summary (HKD) share options for Founder Liu Minghui and Executive President Huang Year to 31 Mar 18E 19E 20E Rong (exercise price: HKD13.84) once it achieves HKD7.5bn in net profit or Revenue (m) 42,195 53,408 64,102 HKD150bn market cap (or c.HKD30.35 share price) by 23 June 2022. Operating profit (m) 8,394 10,099 11,141 Net profit (m) 6,006 7,331 8,142 Core EPS (fully-diluted) 1.210 1.477 1.640 Gas supply reliability to maintain dollar margin is the key. We expect EPS change (%) 35.1 22.1 11.1 CGHL to achieve its targeted HKD7.5bn net profit in FY19E or FY20E, as Daiwa vs Cons. EPS (%) (0.5) 1.0 (5.6) PER (x) 17.2 14.1 12.7 we expect the gas shortage to subside in the winter of 2019-20E at the Dividend yield (%) 1.7 2.1 2.4 latest, while the CNY1/m3 gas subsidy for rural households will last for 3 DPS 0.344 0.435 0.499 years, and hence near-term significant dollar margin risks are unlikely, in PBR (x) 4.2 3.4 2.9 EV/EBITDA (x) 12.2 10.0 8.9 our view. ROE (%) 26.5 26.7 24.8 Source: FactSet, Daiwa forecasts What we recommend: We downgrade CGHL from Buy (1) to Outperform (2) and cut our 12-month DCF-derived TP to HKD23.8 from HKD28.1, after lifting FY18-19E EPS by 2-3% but cutting FY20E EPS by 4%. This is mainly due to a lower SG&A cost for FY18-19E, despite our cuts to the unit dollar margin by CNY0.03-0.06/m3 over FY18-20E. We change our WACC from 9.0% to 9.3% on lower margin trends. Key risks: considerable margin squeeze on its northern gas projects on severe winter gas shortage and slower-than-expected rural connections on reliable gas supply concerns.

How we differ: Our FY20E EPS is 6% below the consensus, likely as we factor in CGHL’s dollar margin squeeze on its gas sales.

See important disclosures, including any required research certifications, beginning on page 111

China Gas (384 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook CGHL: total gas sales volume and unit dollar margin

Despite the dollar margin squeeze, we see CGHL (mcm) (CNY/m3) achieving a 14% CAGR in its gas sales gross profit in 20,000 0.80 FY17-20E, given a doubling of gas sales growth over the 0.75 16,000 same period. Due to strong rural gas connections and even 0.70 stronger value-added services earnings, we see the gross 12,000 0.65 profit proportion from gas sales falling from 30% in FY17 to 0.60 8,000 25% in FY19E, demonstrating CGHL’s earnings 0.55 0.50 diversification from gas sales, amid a continuous dollar 4,000 0.45 margin squeeze. 0 0.40 FY13 FY14 FY15 FY16 FY17 FY18E FY19E FY20E Total gas sales volume (LHS) Gas sales dollar margin (RHS)

Source: Company, Daiwa estimates

Valuation CGHL: 1-year forward PER

On our revised EPS forecasts, CGHL is trading at a 14.7x PER (x ) 12-month rolling forward PER, in line with its long-term 40 average 12-month forward PER. We view the valuation as 35 undemanding given our forecast for a 23% FY17-20E EPS 30 28.0x Avg+2SD CAGR (previous: 24%), representing only a 0.7x PEG over 25 21.7x Avg+1SD the same period. 20 15 15.4x Avg

10 9.1x Avg-1SD 5 2.8x Avg-2SD 0 Jan-09 Jan-11 Jan-13 Jan-15 Jan-17 Source: Company, Daiwa estimates

Earnings revisions CGHL: Bloomberg consensus earnings-forecast revisions

In 2017, the consensus FY18-19E EPS estimates were (HKD) FY18-19E consensus revised revised up by 30-40% after the NDRC confirmed that the 1.8 up by 30-40% in 2017 ROA cap for downstream gas distributors would be 7% 1.7 1.6 instead of 6% and connection income would not be 1.5 included in the ROA calculation, and on the back of the 1.4 1.3 company’s aggressive rural connection plan to double gas 1.2 sales and connections over FY18-20E. 1.1 1.0 0.9 We believe management is committed to achieve a 0.8

HKD6bn net profit in FY18E, and HKD7.5bn net profit in

Jul-17

Apr-17 Oct-17

Jan-17 Jun-17 Jan-18

Mar-17

Feb-17

Aug-17 Sep-17 Nov-17 Dec-17 FY19E or FY20E, due to management share option May-17 2018E EPS 2019E EPS 2020E EPS targets. Source: Company, Daiwa estimates

China Gas (384 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Mar 2013 2014 2015 2016 2017 2018E 2019E 2020E Natural gas sales volume (mn m3) 6,825 8,045 8,975 9,860 12,224 17,441 22,101 26,846 Gas sales dollar margin (CNY/m3) 0.70 0.72 0.75 0.72 0.68 0.63 0.59 0.55 Residential gas connection ('000 1,226 1,662 1,921 2,100 2,565 3,650 4,500 5,000 houesholds) Gross profit contribution - connection 49 46 48 46 50 53 52 50 fee (%)

Profit and loss (HKDm) Year to 31 Mar 2013 2014 2015 2016 2017 2018E 2019E 2020E Sales of piped gas 7,352 10,169 12,929 12,996 13,779 17,299 22,368 27,767 Gas connection income 2,709 3,658 4,659 4,794 5,748 8,421 10,389 11,635 Other Revenue 7,895 12,182 14,078 11,708 12,466 16,475 20,650 24,699 Total Revenue 17,956 26,008 31,666 29,497 31,993 42,195 53,408 64,102 Other income 588 485 727 (472) 231 572 704 832 COGS (13,605) (20,011) (24,327) (21,370) (22,657) (30,460) (39,091) (47,853) SG&A (1,788) (2,071) (2,586) (2,649) (2,905) (2,954) (3,845) (4,744) Other op.expenses (575) (711) (883) (914) (960) (960) (1,077) (1,196) Operating profit 2,576 3,699 4,597 4,092 5,703 8,394 10,099 11,141 Net-interest inc./(exp.) (691) (615) (554) (758) (705) (705) (698) (689) Assoc/forex/extraord./others 552 636 767 383 904 916 1,102 1,216 Pre-tax profit 2,437 3,721 4,810 3,718 5,902 8,605 10,504 11,668 Tax (400) (741) (940) (984) (1,208) (1,760) (2,159) (2,411) Min. int./pref. div./others (272) (404) (499) (460) (547) (838) (1,014) (1,116) Net profit (reported) 1,764 2,576 3,371 2,273 4,148 6,006 7,331 8,142 Net profit (adjusted) 1,671 2,569 3,320 3,231 4,397 6,006 7,331 8,142 EPS (reported)(HKD) 0.394 0.536 0.673 0.458 0.845 1.210 1.477 1.640 EPS (adjusted)(HKD) 0.373 0.534 0.663 0.651 0.896 1.210 1.477 1.640 EPS (adjusted fully-diluted)(HKD) 0.349 0.515 0.645 0.651 0.896 1.210 1.477 1.640 DPS (HKD) 0.079 0.121 0.162 0.195 0.250 0.344 0.435 0.499 EBIT 2,482 3,692 4,546 5,050 5,952 8,394 10,099 11,141 EBITDA 3,057 4,404 5,430 5,964 6,912 9,354 11,176 12,337

Cash flow (HKDm) Year to 31 Mar 2013 2014 2015 2016 2017 2018E 2019E 2020E Profit before tax 2,437 3,721 4,810 3,718 5,902 8,605 10,504 11,668 Depreciation and amortisation 575 711 883 914 960 960 1,077 1,196 Tax paid (400) (741) (940) (984) (1,208) (1,760) (2,159) (2,411) Change in working capital 269 287 262 1,845 (339) 752 726 888 Other operational CF items 16 (594) (363) 370 (199) (211) (405) (527) Cash flow from operations 2,896 3,383 4,653 5,862 5,117 8,345 9,742 10,814 Capex (2,511) (3,182) (4,003) (3,288) (4,195) (4,400) (4,600) (4,800) Net (acquisitions)/disposals (187) (1,215) (33) (358) 0 0 0 0 Other investing CF items 122 (744) (1,135) (355) (23) 0 0 0 Cash flow from investing (2,576) (5,141) (5,170) (4,001) (4,218) (4,400) (4,600) (4,800) Change in debt (33) 4,730 768 1,693 0 (1,000) (1,000) (1,000) Net share issues/(repurchases) 193 0 (233) (947) 0 0 0 0 Dividends paid (278) (411) (606) (942) (966) (1,227) (1,707) (2,157) Other financing CF items (858) (93) (638) (1,131) (705) (705) (698) (689) Cash flow from financing (976) 4,226 (708) (1,327) (1,671) (2,932) (3,405) (3,845) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash (655) 2,468 (1,226) 533 (772) 1,013 1,738 2,169 Free cash flow 386 201 650 2,574 0 4,066 5,314 6,224 Source: FactSet, Daiwa forecasts

China Gas (384 HK): 12 January 2018

Financial summary continued … Balance sheet (HKDm) As at 31 Mar 2013 2014 2015 2016 2017 2018E 2019E 2020E Cash & short-term investment 4,499 6,705 5,292 5,772 5,242 6,255 7,993 10,162 Inventory 952 1,207 1,199 1,213 1,679 1,975 2,340 2,746 Accounts receivable 3,347 4,737 5,328 5,094 6,067 7,476 9,755 11,883 Other current assets 555 1,284 1,149 1,567 2,375 2,375 2,375 2,375 Total current assets 9,354 13,932 12,968 13,647 15,363 18,081 22,463 27,166 Fixed assets 13,896 17,835 21,116 22,850 25,783 29,310 32,918 36,604 Goodwill & intangibles 1,752 4,322 5,570 5,540 6,358 6,271 6,186 6,104 Other non-current assets 7,493 9,176 10,971 11,497 12,483 12,780 13,178 13,573 Total assets 32,495 45,265 50,624 53,533 59,987 66,442 74,745 83,447 Short-term debt 3,640 2,783 2,581 10,324 10,873 10,373 9,873 9,373 Accounts payable 4,148 6,079 6,924 8,549 9,650 12,106 15,477 18,899 Other current liabilities 5,229 3,422 2,132 929 2,056 1,711 1,711 813 Total current liabilities 13,017 12,284 11,637 19,803 22,579 24,191 27,061 29,085 Long-term debt 6,356 14,192 16,817 12,010 12,745 12,245 11,745 11,245 Other non-current liabilities 379 631 735 756 735 940 686 1,082 Total liabilities 19,752 27,108 29,189 32,569 36,059 37,377 39,492 41,413 Share capital 46 50 50 49 50 50 50 50 Reserves/R.E./others 11,439 15,734 18,346 17,803 20,501 24,800 29,973 35,639 Shareholders' equity 11,485 15,783 18,396 17,853 20,550 24,849 30,023 35,688 Minority interests 1,258 2,374 3,039 3,112 3,377 4,216 5,230 6,345 Total equity & liabilities 32,495 45,265 50,624 53,533 59,987 66,442 74,745 83,447 EV 104,257 109,186 111,933 114,115 115,521 114,049 111,968 109,521 Net debt/(cash) 5,496 10,271 14,106 16,562 18,376 16,363 13,626 10,457 BVPS (HKD) 2.563 3.284 3.672 3.596 4.187 5.006 6.049 7.190

Key ratios (%) Year to 31 Mar 2013 2014 2015 2016 2017 2018E 2019E 2020E Sales (YoY) (5.2) 44.8 21.8 (6.9) 8.5 31.9 26.6 20.0 EBITDA (YoY) 4.7 44.0 23.3 9.8 15.9 35.3 19.5 10.4 Operating profit (YoY) 7.1 48.7 23.1 11.1 17.9 41.0 20.3 10.3 Net profit (YoY) 103.4 53.7 29.3 (2.7) 36.1 36.6 22.1 11.1 Core EPS (fully-diluted) (YoY) 97.2 47.5 25.3 0.9 37.7 35.1 22.1 11.1 Gross-profit margin 24.2 23.1 23.2 27.6 29.2 27.8 26.8 25.3 EBITDA margin 17.0 16.9 17.1 20.2 21.6 22.2 20.9 19.2 Operating-profit margin 13.8 14.2 14.4 17.1 18.6 19.9 18.9 17.4 Net profit margin 9.3 9.9 10.5 11.0 13.7 14.2 13.7 12.7 ROAE 15.7 18.8 19.4 17.8 22.9 26.5 26.7 24.8 ROAA 5.4 6.6 6.9 6.2 7.7 9.5 10.4 10.3 ROCE 11.6 12.8 12.0 12.0 13.1 16.9 18.6 18.6 ROIC 13.0 12.7 11.6 8.2 11.4 15.2 17.0 17.4 Net debt to equity 47.9 65.1 76.7 92.8 89.4 65.8 45.4 29.3 Effective tax rate 16.4 19.9 19.5 26.5 20.5 20.5 20.6 20.7 Accounts receivable (days) 61.7 56.7 58.0 64.5 63.7 58.6 58.9 61.6 Current ratio (x) 0.7 1.1 1.1 0.7 0.7 0.7 0.8 0.9 Net interest cover (x) 3.6 6.0 8.2 6.7 8.4 11.9 14.5 16.2 Net dividend payout 20.1 22.5 24.0 42.5 29.6 28.4 29.4 30.4 Free cash flow yield 0.4 0.2 0.6 2.5 0.0 3.9 5.1 6.0 Source: FactSet, Daiwa forecasts

Company profile

China Gas is one of the leading city-gas distributors in China, owning 330 projects (as of March 2017) with a geographical focus on northern provinces. It also owns LPG wholesale and distribution businesses.

China Gas (384 HK): 12 January 2018

Valuation

We cut our 12-month DCF-derived TP to HKD23.8 from HKD28.1, after lifting our FY18- 19E EPS by 2-3% but cutting our FY20E EPS by 4%. Also, we raise our WACC from 9.0% to 9.3% on lower margin trends.

Our new assumptions trim the NPV of terminal value by 20%, leading to the 15% cut in our TP to HKD23.8.

CGHL: DCF valuation Forecast 12 mths to 31 Mar, All figures in HKD millions FY18E FY19E FY20E FY21E FY22E FY23E FY24E Terminal Valuation Date 6-Jan-18 31-Mar-18 31-Mar-19 31-Mar-20 31-Mar-21 31-Mar-22 31-Mar-23 31-Mar-24 31-Mar-24 Next Balance Date 31-Mar-18 First Year Cash Flow Adjustment 0.23

Free Cash Flow EBITDA 9,354 11,176 12,337 13,256 14,525 16,317 11,089 Less: Other Non Cash 78 89 101 399 434 489 852 Less: Cash Tax Payable on EBIT (1,717) (2,076) (2,302) (2,388) (2,668) (3,060) (2,013) Plus: Decrease in Working Capital 752 726 888 1,141 1,249 1,413 2,392 Less: Capital Expenditure (4,400) (4,600) (4,800) (1,300) (1,300) (1,300) (1,270) Free Cash Flow 4,066 5,314 6,224 11,109 12,240 13,859 11,049 11,270

Free Cash Flow for Valuation Purposes 4,066 5,314 6,224 11,109 12,240 13,859 11,049 11,270

WACC 9.3% 9.3% 9.3% 9.3% 9.3% 9.3% 9.3% 9.3% 9.3%

NPV of Free Cash Flow 3,984 4,764 5,104 8,336 8,404 8,707 6,350 88,846

Source: Daiwa forecasts and estimates

CGHL: DCF calculation CGHL: DCF sensitivity analysis Target gearing (debt/capital) (%) 35% Discount NPV of Enterprise Equity Equity Value

Market risk premium (%) 10.0% Rate FCF Value Value Per Share (HKD)

Beta 0.95 6.8% 49,696 205,901 189,538 38.19

Risk-free rate (%) 3.5% 7.3% 48,844 186,225 169,861 34.22

Cost of debt (%) 3.2% 7.8% 48,014 169,944 153,581 30.94 8.3% 47,205 156,250 139,887 28.18 Cost of equity (%) 13.0% 8.8% 46,416 144,571 128,208 25.83 WACC (%) 9.3% 9.3% 45,648 134,494 118,130 23.80

9.8% 44,899 125,709 109,345 22.03 Terminal Value 10.3% 44,168 117,983 101,620 20.47 Terminal Growth Rate 2.00% 10.8% 43,456 111,136 94,772 19.09

Terminal WACC 9.29% 11.3% 42,761 105,025 88,662 17.86 11.8% 42,083 99,539 83,175 16.76 Estimated Terminal Free Cash Flow 11,270

NPV of Terminal Value (as at 31 Mar 2024) 154,600

NPV of Terminal Value (as at 06 Jan 2018) 88,846

DCF Valuation

NPV of Forecasts (HKDm) 45,648

NPV of Terminal Value (HKDm) 88,846

Enterprise Value (HKDm) 134,494

Less: Net Debt (as at 22 Sep 2016) -16,363

Equity Value (HKDm) 118,130

No. Shares (m) 4,963

Per Share Equity Value HK$23.80

Source: Daiwa forecasts Source: Daiwa estimates and forecasts

China Gas (384 HK): 12 January 2018

Hong Kong Utilities 12 January 2018

Towngas China (1083 HK) Towngas China

Target price: HKD6.70 (from HKD6.90) Share price (10 Jan): HKD6.13 | Up/downside: +9.3%

Riding on improving gas sales exposure Dennis Ip, CFA (852) 2848 4068  Poised to enjoy recovering gas sales at its 64 acquired projects [email protected]  Improving sales mix should partly offset the dollar margin squeeze Don Lau, CFA (852) 2848 4469  Parent’s buyback provides share-price support; reiterate Outperform (2) [email protected]

What's new: In 2017, TCCL delivered a 54% share-price return (vs. the Forecast revisions (%) HSI’s 36%). For 2018, we expect TCCL to come under less dollar margin Year to 31 Dec 17E 18E 19E pressure than its peers, given its improving sales mix toward more profitable Revenue change 2.8 5.9 9.4 projects, which should give it a more resilient share price than peers. Net profit change (4.6) (5.2) (6.2) Core EPS (FD) change (4.6) (5.2) (6.2)

Source: Daiwa forecasts What's the impact: Sustained strong gas sales volume growth for 11M17. Thanks to coal-to-gas initiatives, TCCL’s total gas sales volume Share price performance growth was strong at 17.8% for 11M17, on track to achieve its 18% volume (HKD) (%) growth guidance for 2017E. Going forward, given: 1) the recovery in 7.0 125 industrial activity, and 2) rebound in oil prices, we believe gas sales at 6.3 116 TCCL’s 63 projects (signed from 2007-15), which were affected by slow 5.5 108 4.8 99 industrial sales in 2014-1H16, will gradually pick up to meet TCCL’s long- 4.0 90 term sales volume target (78% behind currently). Hence, we see TCCL as Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 well-positioned to sustain mid-double-digit gas sales volume for 2016-19E. Towngas Ch (LHS) Relative to HSI (RHS)

Likely less dollar margin pressure on improving sales mix. Unlike its 12-month range 4.19-6.59 peers, which guided for a 7-9% HoH dollar margin squeeze in 2H17E on the Market cap (USDbn) 2.12 gas procurement cost hike arising from the winter supply shortage, TCCL 3m avg daily turnover (USDm) 1.73 estimates its dollar margin expanded from CNY0.67/m3 in 1H17 to Shares outstanding (m) 2,711 Major shareholder The Hong Kong and China Gas (67.1%) CNY0.68/m3 in 2H17E thanks to its higher gas sales exposure to provinces with a higher dollar margin (eg, Shandong); we see TCCL’s sales mix Financial summary (HKD) continuing to improve. That said, with multiple causes for a dollar margin Year to 31 Dec 17E 18E 19E squeeze ahead, we expect TCCL’s dollar margin to contract, despite its Revenue (m) 8,412 9,871 11,558 milder dollar margin squeeze (CNY0.01/m3 pa, at the segment level) relative Operating profit (m) 1,513 1,629 1,767 Net profit (m) 1,268 1,386 1,528 to its peers’ CNY0.02-0.04/m3 pa. Core EPS (fully-diluted) 0.468 0.511 0.564 EPS change (%) 1.9 9.3 10.2 Parent’s active buyback offers downside cushion. In 2017, HKCG (3 HK, Daiwa vs Cons. EPS (%) 5.5 4.5 4.2 PER (x) 13.1 12.0 10.9 HKD15.42, Outperform [2]) increased its stake in TCCL by 2.8pp to 67.1%, Dividend yield (%) 2.1 2.4 2.7 up from 0.1pp/1.3pp in 2015/16. Given: 1) TCCL is trading currently at a 50% DPS 0.128 0.145 0.166 12-month forward PER discount to HKCG, and 2) the solid recovery outlook PBR (x) 1.2 1.1 1.0 EV/EBITDA (x) 9.2 8.0 7.0 for the abovementioned acquired projects, we believe the buybacks will ROE (%) 9.1 9.3 9.6 continue if TCCL’s share price retreats to a more attractive level (last Source: FactSet, Daiwa forecasts repurchase price: HKD5.7), offering support to the share price.

What we recommend: We reiterate our Outperform (2) rating but trim our 12-month DCF-based TP to HKD6.7 (from HKD6.9) after the 5-6% cuts to our 2017-19E EPS to reflect the upcoming dollar margin squeeze. Key risk: a higher-than-expected distribution tariff cut for certain provinces in the tariff review, which is scheduled to be completed by the end of June 2018.

How we differ: Our 2017-19E EPS forecasts are 4-5% above the consensus, likely as we assume higher gas sales volume growth and dollar margin.

See important disclosures, including any required research certifications, beginning on page 111

Towngas China (1083 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook TCCL: subsidiary gas sales volume and segment dollar margin

We are revising up our 2017-19E subsidiary gas sales (mcm) (CNY/m3) volume growth forecasts by 3-5pp from 16-18% YoY to 20- 4,000 0.32 22% YoY on the prospect of a stronger-than-expected 0.31 3,000 recovery in TCCL’s industrial gas sales, especially from its 0.30 0.29 64 newly-signed projects since 2010. Nevertheless, we are 2,000 less optimistic about the margin outlook and now expect its 0.28 segmental dollar margin to decline by CNY0.01/m3 from 1,000 0.27 2018E onward (vs. flat to CNY0.01/m3 pa expansion 0.26 0 0.25 before). 2013 2014 2015 2016 2017E 2018E 2019E

Subsidary gas sales (LHS) For gas connections, we forecast 4-6% pa new connection Subsidary gas segment dollar margin (RHS) growth for 2017-19E. Source: Company, Daiwa forecasts

Valuation TCCL:1-year forward PER

TCCL is trading at a 12.0x 1-year forward PER, or 0.7SD PER (x) below its past-10-year average 1-year forward PER. Like 30 26.4x Avg+2SD its peers, TCCL has experienced a rerating since mid-June 25 2017, from a 10.5x to 13.3x 1-year forward PER in 21.2x Avg+1SD 20 November 2017, on the removal of the overhang, suggesting that connection income would not be included 15 16.0x Avg in the calculation of a 7% RoA. That said, TCCL is still 10 10.7x Avg-1SD trading at a discount to some of its peers, which command 5 5.5x Avg-2SD 1-year forward PERs of 14-15x. With HKCG’s buyback, we see strong support for TCCL’s share price at the HKD5.7 0

level, representing an 11.3x 1-year forward PER.

Jul-09 Jul-17 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16

Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-09 Source: Company, Daiwa estimates

Earnings revisions TCCL: Bloomberg consensus earnings-forecast revisions

The Bloomberg-consensus 2017-19 EPS forecasts for (HKD) TCCL have been raised by 2-4% since the release of the 0.55 interim results in August, which we believe was due to the street factoring in sustained gas sales volume growth. 0.50 Nevertheless, we believe the EPS consensus forecasts still do not fully reflect the 11M17 volume growth and the 0.45 upcoming gas sales recovery from TCCL’s 64 acquired projects; hence we expect a further 4-5% upward revision

to 2017-18 consensus EPS forecasts in the future. 0.40

Jul-17

Apr-17 Oct-17

Jan-17 Jun-17 Jan-18

Feb-17 Mar-17

Nov-17 Dec-17

Aug-17 Sep-17 May-17 2017E EPS 2018E EPS 2019 EPS

Source: Bloomberg

Towngas China (1083 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Total gas sales volume (mn m3) 5,320 5,945 6,511 6,562 7,120 8,371 9,774 11,332 Subsidary gas sales volume (mn m3) 1,310 1,570 1,726 1,719 1,890 2,306 2,790 3,348 Gas sales segment dollar margin 0.23 0.27 0.27 0.26 0.29 0.31 0.29 0.28 (HKD/m3)

Profit and loss (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales of gas 3,972 5,265 6,205 6,011 5,518 6,733 8,123 9,739 Gas connection 1,211 1,451 1,677 1,708 1,663 1,679 1,748 1,820 Other Revenue 0 0 0 0 0 0 0 0 Total Revenue 5,183 6,716 7,882 7,719 7,181 8,412 9,871 11,558 Other income 160 246 14 (162) 65 160 160 160 COGS (4,048) (5,320) (6,263) (6,100) (5,529) (6,402) (7,693) (9,189) SG&A 0 0 0 0 0 0 0 0 Other op.expenses (392) (471) (553) (601) (629) (657) (709) (762) Operating profit 904 1,171 1,080 856 1,088 1,513 1,629 1,767 Net-interest inc./(exp.) (148) (164) (174) (181) (251) (321) (323) (321) Assoc/forex/extraord./others 480 601 625 593 618 694 747 811 Pre-tax profit 1,236 1,609 1,531 1,269 1,455 1,886 2,053 2,256 Tax (299) (383) (350) (344) (362) (469) (511) (564) Min. int./pref. div./others (95) (120) (127) (117) (119) (149) (156) (164) Net profit (reported) 841 1,106 1,054 808 974 1,268 1,386 1,528 Net profit (adjusted) 796 946 1,195 1,203 1,233 1,268 1,386 1,528 EPS (reported)(HKD) 0.342 0.424 0.402 0.305 0.363 0.468 0.511 0.564 EPS (adjusted)(HKD) 0.323 0.363 0.456 0.454 0.459 0.468 0.511 0.564 EPS (adjusted fully-diluted)(HKD) 0.323 0.362 0.454 0.454 0.459 0.468 0.511 0.564 DPS (HKD) 0.064 0.080 0.100 0.100 0.121 0.128 0.145 0.166 EBIT 904 1,171 1,080 856 1,088 1,513 1,629 1,767 EBITDA 1,179 1,502 1,482 1,305 1,568 2,029 2,183 2,359

Cash flow (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 1,236 1,609 1,531 1,269 1,455 1,886 2,053 2,256 Depreciation and amortisation 276 331 402 449 480 516 554 592 Tax paid (299) (383) (350) (344) (294) (469) (511) (564) Change in working capital 524 436 (201) 312 555 136 643 511 Other operational CF items (661) (942) (124) (270) (530) (694) (747) (811) Cash flow from operations 1,075 1,051 1,258 1,417 1,667 1,375 1,992 1,985 Capex (1,610) (1,685) (2,005) (1,955) (1,900) (1,200) (1,200) (1,200) Net (acquisitions)/disposals (136) (317) (318) (5) (99) 0 0 0 Other investing CF items 96 (981) (272) 190 403 0 0 0 Cash flow from investing (1,651) (2,983) (2,595) (1,770) (1,596) (1,200) (1,200) (1,200) Change in debt 670 788 681 1,261 (608) 49 (50) (50) Net share issues/(repurchases) 0 940 10 41 3 0 0 0 Dividends paid (147) (191) (121) (187) (155) (325) (347) (394) Other financing CF items 567 70 73 46 0 0 0 0 Cash flow from financing 1,089 1,607 643 1,161 (759) (276) (397) (444) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash 513 (326) (694) 808 (689) (101) 395 341 Free cash flow (536) (634) (746) (539) 0 1,813 1,875 2,112 Source: FactSet, Daiwa forecasts

Towngas China (1083 HK): 12 January 2018

Financial summary continued … Balance sheet (HKDm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 2,699 2,605 1,797 2,376 1,579 1,478 1,872 2,214 Inventory 395 588 566 558 493 523 545 567 Accounts receivable 1,057 1,580 1,788 1,507 1,190 1,580 1,854 2,297 Other current assets 196 274 225 217 280 150 315 229 Total current assets 4,346 5,047 4,376 4,658 3,542 3,730 4,586 5,307 Fixed assets 7,652 9,355 11,026 12,055 12,692 13,396 14,062 14,690 Goodwill & intangibles 4,462 5,972 6,499 6,293 5,855 5,880 5,860 5,840 Other non-current assets 4,795 5,254 5,449 5,866 5,938 6,612 7,340 8,130 Total assets 21,255 25,629 27,350 28,871 28,027 29,618 31,847 33,967 Short-term debt 1,946 2,419 2,483 3,183 2,653 2,653 2,653 2,653 Accounts payable 2,998 4,152 4,136 4,160 4,333 4,889 5,828 6,805 Other current liabilities 629 812 770 806 785 785 785 785 Total current liabilities 5,574 7,383 7,389 8,149 7,770 8,326 9,265 10,242 Long-term debt 3,145 3,488 4,075 4,591 5,184 5,234 5,184 5,134 Other non-current liabilities 1,249 1,280 1,441 1,431 409 325 517 466 Total liabilities 9,968 12,150 12,906 14,171 13,363 13,885 14,965 15,842 Share capital 246 261 263 267 271 271 271 271 Reserves/R.E./others 10,236 12,270 12,991 13,212 13,228 14,149 15,141 16,220 Shareholders' equity 10,482 12,531 13,254 13,478 13,499 14,420 15,412 16,491 Minority interests 805 947 1,191 1,222 1,165 1,314 1,470 1,634 Total equity & liabilities 21,255 25,629 27,350 28,871 28,027 29,618 31,847 33,967 EV 15,747 16,273 17,800 18,229 18,988 18,594 17,557 16,520 Net debt/(cash) 2,393 3,302 4,761 5,398 6,258 6,409 5,964 5,573 BVPS (HKD) 4.261 4.796 5.035 5.058 4.979 5.318 5.684 6.082

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) 20.0 29.6 17.4 (2.1) (7.0) 17.1 17.3 17.1 EBITDA (YoY) 15.8 27.3 (1.3) (11.9) 20.1 29.4 7.6 8.1 Operating profit (YoY) 15.6 29.6 (7.8) (20.7) 27.0 39.0 7.7 8.5 Net profit (YoY) 34.5 18.9 26.3 0.6 2.5 2.8 9.3 10.2 Core EPS (fully-diluted) (YoY) 34.0 12.2 25.5 (0.2) 1.2 1.9 9.3 10.2 Gross-profit margin 21.9 20.8 20.5 21.0 23.0 23.9 22.1 20.5 EBITDA margin 22.8 22.4 18.8 16.9 21.8 24.1 22.1 20.4 Operating-profit margin 17.4 17.4 13.7 11.1 15.2 18.0 16.5 15.3 Net profit margin 15.4 14.1 15.2 15.6 17.2 15.1 14.0 13.2 ROAE 7.9 8.2 9.3 9.0 9.1 9.1 9.3 9.6 ROAA 4.0 4.0 4.5 4.3 4.3 4.4 4.5 4.6 ROCE 5.8 6.5 5.3 3.9 4.8 6.6 6.7 7.0 ROIC 5.2 5.9 4.6 3.2 4.0 5.3 5.4 5.7 Net debt to equity 22.8 26.4 35.9 40.1 46.4 44.4 38.7 33.8 Effective tax rate 24.2 23.8 22.9 27.1 24.9 24.9 24.9 25.0 Accounts receivable (days) 67.2 71.7 78.0 77.9 68.5 60.1 63.5 65.5 Current ratio (x) 0.8 0.7 0.6 0.6 0.5 0.4 0.5 0.5 Net interest cover (x) 6.1 7.2 6.2 4.7 4.3 4.7 5.0 5.5 Net dividend payout 19.6 22.0 22.0 22.1 26.4 27.4 28.4 29.4 Free cash flow yield n.a. n.a. n.a. n.a. 0.0 10.9 11.3 12.7 Source: FactSet, Daiwa forecasts

Company profile

Towngas China is one of the leading city-gas distributors in China, owning 105 projects (as of Jun 2017) with a geographical focus on Sichuan, Shandong and Liaoning provinces. In 2016, the company sold 1.9bcm of natural gas (at the subsidiary level).

China Utilities 12 January 2018

(1193 HK) China Resources Gas China Resources Gas

Target price: HKD23.60 (from HKD27.50) Share price (10 Jan): HKD24.70 | Up/downside: -4.5%

Margin squeeze on lack of hedging and diversification Dennis Ip, CFA (852) 2848 4068  Pure city-gas business leading to inferior-than-peers’ EPS growth… [email protected]  …due to continued and irreversible gas-sales dollar margin squeeze Don Lau, CFA (852) 2848 4469  Maintaining Hold (3) rating; cutting TP to HKD23.60; a rich 1.8x PEG [email protected]

The latest downward revision of HoH dollar margin guidance, from Forecast revisions (%) CNY0.02/m3 to CNY0.05/m3, in 2H17 verifies our thesis that hedging and Year to 31 Dec 17E 18E 19E diversification (H&D) is vital for city-gas distributors to achieve at least mid- Revenue change 0.8 6.4 11.7 Net profit change (8.9) (8.5) (11.1) teen EPS growth, which explains our preference for CRG’s competitors Core EPS (FD) change (9.0) (8.6) (11.2) ENN and CGHL. We believe the winter gas shortage has worsened the Source: Daiwa forecasts dollar margin outlook for CRG over 2017-19E, such that CRG’s 9% 2017- 19E EPS CAGR lags behind ENN’s 15% and CGHL’s 23% (our estimates), Share price performance while its rich 14x 2018E PER, vs. peers’ 11-15x, is unjustified. (HKD) (%) 31 115 What's the impact: Continued dollar-margin squeeze seems to be the 29 104 new norm; hedging and diversification (H&D) is the key. Based on our 27 93 24 81 recent updates, all city-gas companies recorded a CNY0.01-0.03/m3 HoH 22 70 gas sales dollar margin squeeze for 2H17. This implies that the 4Q17/ Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 December 2017 dollar margins came in at CNY0.55/CNY0.45/m3 due to Ch Res Gas (LHS) Relative to HSI (RHS) expensive incremental-volume gas over the heating season. Even though the spot LNG price has dropped to CNY5k/tonne in January 2018, we 12-month range 22.15-30.80 expect a 10-11% YoY dollar margin squeeze in 1H18E given one extra Market cap (USDbn) 7.02 month of heating season in 1H vs 2H (1.5 months in 1H, 2.5 months in 2H). 3m avg daily turnover (USDm) 10.82 Shares outstanding (m) 2,224

Major shareholder China Resources Group (64.0%) Over 2018-25E, we see 3 major sources of margin squeeze: 1. A potential CNY0.3/m3 squeeze for industrial coal-to-gas users Financial summary (HKD) 2. A c.CNY0.1/m3 squeeze every 3 years, starting from July 2018, for Year to 31 Dec 17E 18E 19E most C&I users in some provinces Revenue (m) 38,056 44,793 52,197 3. A potential CNY0.4-0.5/m3 squeeze for big users due to direct Operating profit (m) 5,531 5,974 6,235 Net profit (m) 3,441 3,853 4,255 competition from oil majors Core EPS (fully-diluted) 1.580 1.769 1.953 EPS change (%) 4.5 12.0 10.4 Facing a continuous dollar-margin squeeze for city gas, CRG’s peers Daiwa vs Cons. EPS (%) (10.0) (10.4) (12.3) PER (x) 15.6 14.0 12.6 CGHL and ENN have been aggressively exploring rural and industrial coal- Dividend yield (%) 2.2 2.6 2.9 to-gas projects, or importing cheap LNG while exploring distributed-energy DPS 0.550 0.633 0.719 services to big C&I users. CRG has a relatively high city-gas sales PBR (x) 2.7 2.4 2.2 contribution to gross profit (50% vs peers’ 27-56%) without much H&D. EV/EBITDA (x) 9.0 8.2 7.6 ROE (%) 18.2 18.1 17.9

Source: FactSet, Daiwa forecasts What we recommend: We maintain our Hold (3) rating and trim our 12- month DCF-based TP from HKD27.50 to HKD23.60, after cutting our 2017-19E EPS by 9-11% as we reduce CRG’s gas-sales dollar margin by CNY0.05-0.03/m3 for 2017-19E. Although we expect CRG to see only 5% YoY EPS growth in 2017E due to the dollar margin squeeze, the company will likely raise its DPS payout to 35% for 2017 (2016: 30%) to maintain 20% YoY DPS growth, in line with its peers. Key upside/downside risks: less/more-than-expected dollar margin squeeze.

How we differ: Our 2017-19E EPS are 10-12% below the consensus, which we attribute to our lower gas-sales dollar-margin assumptions.

See important disclosures, including any required research certifications, beginning on page 111

China Resources Gas (1193 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook CRG: total gas sales volume and unit dollar margin

We revise up our 2017-19E natural gas sales volume (Unit: bcm) (Unit: CNY/3) growth forecasts for CRG from 17-13% YoY previously to 30,000 0.75 22-19% YoY, after factoring in the 1H17 results due to the 25,000 marked recovery in industrial gas sales volume growth. 0.70 However, we cut our unit dollar margin assumptions for 20,000 0.65 2017-19 by 7-10%, and reduce our earnings estimates 15,000 from Tianjin by HKD50-75m, factoring in the dollar-margin 0.60 loss from expensive spot LNG purchase due to winter gas 10,000 shortage. 5,000 0.55

0 0.50 2013 2014 2015 2016 2017E 2018E 2019E Total gas sales volume (LHS) Gas sales unit dollar margin (RHS)

Source: Company, Daiwa forecasts

Valuation CRG: 1-year-forward PER

Based on our revised recurring EPS forecasts, CRG is PER (x) trading at a 14.0x 2018E PER, 0.2SD below its past-10- 25 year 12-month-forward PER. We consider this multiple as 22.5x Avg+2SD 20 rich because we expect the upcoming dollar margin 19.2x Avg+1SD squeeze to drag down CRG’s 2017-19E EPS CAGR from 15 15.8x Avg 13% (our previous forecast) to 9%. CRG’s lack of hedging 12.5x Avg-1SD 10 and diversification of its pure city-gas business model is 9.2x Avg-2SD unlikely to offset its earnings loss from the gas sales dollar- 5 margin squeeze, compared with peers ENN and CGHL.

May-… May-…

Jul-11

Oct-09 Apr-13 Oct-16

Jan-08 Jun-14 Jan-15

Mar-09 Feb-12 Mar-16

Dec-10 Nov-13 Dec-17

Sep-12 Aug-15 Aug-08 Source: Bloomberg, company, Daiwa forecasts

Earnings revisions CRG: consensus EPS forecast revisions

The Bloomberg consensus has slightly raised its 2017-19E (HKD) EPS forecasts for CRG by 0-3% YTD. However, we see a 2.3 10-12% downside risk, on the basis that the street has not 2.2 factored in a sufficient unit dollar margin squeeze for the 2.1 company’s gas sales, in our view. 2.0 1.9 1.8

1.7

Jul-17 Jul-17

Apr-17 Apr-17 Oct-17 Oct-17

Jan-18 Jun-17 Jun-17

Mar-17 Mar-17 Mar-17

Nov-17 Nov-17 Dec-17 Dec-17

Aug-17 Aug-17 Aug-17 Sep-17 Sep-17

May-17 May-17 2017E EPS 2018E EPS 2019E EPS

Source: Bloomberg

China Resources Gas (1193 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Natural gas sales volume (mn m3) 9,268 12,091 13,660 14,913 16,272 19,825 23,754 28,182 Gas unit dollar margin (CNY/m3) 0.56 0.71 0.67 0.71 0.71 0.61 0.57 0.54 Increase in residential gas connection 1,129 1,403 2,329 2,872 2,690 2,805 3,045 3,211 ('000 houesholds) Gross profit contribution - connection 42 42 43 41 40 43 42 42 fee (%)

Profit and loss (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales of gas 10,725 17,164 22,481 20,249 20,765 25,767 31,636 38,284 Gas connection 2,896 5,124 6,236 6,869 7,439 7,665 8,567 9,297 Other Revenue 0 0 0 5,717 4,712 4,624 4,590 4,616 Total Revenue 13,622 22,288 28,717 32,834 32,916 38,056 44,793 52,197 Other income 280 518 877 682 648 735 778 816 COGS (8,869) (14,106) (19,047) (21,794) (20,447) (25,247) (30,340) (36,228) SG&A (2,626) (4,604) (5,083) (5,790) (5,877) (6,681) (7,729) (8,850) Other op.expenses (500) (560) (1,024) (1,041) (1,285) (1,331) (1,529) (1,700) Operating profit 1,907 3,536 4,440 4,892 5,955 5,531 5,974 6,235 Net-interest inc./(exp.) (315) (524) (537) (541) (538) (551) (493) (433) Assoc/forex/extraord./others 977 798 861 961 772 983 1,194 1,497 Pre-tax profit 2,569 3,811 4,764 5,311 6,189 5,964 6,675 7,299 Tax (540) (987) (1,408) (1,508) (1,751) (1,462) (1,682) (1,860) Min. int./pref. div./others (384) (663) (869) (965) (1,148) (1,061) (1,140) (1,184) Net profit (reported) 1,646 2,161 2,486 2,838 3,289 3,441 3,853 4,255 Net profit (adjusted) 1,646 2,161 2,486 2,838 3,289 3,441 3,853 4,255 EPS (reported)(HKD) 0.816 0.996 1.144 1.305 1.512 1.581 1.770 1.955 EPS (adjusted)(HKD) 0.816 0.996 1.144 1.305 1.512 1.581 1.770 1.955 EPS (adjusted fully-diluted)(HKD) 0.816 0.996 1.144 1.305 1.512 1.580 1.769 1.953 DPS (HKD) 0.119 0.160 0.250 0.330 0.450 0.550 0.633 0.719 EBIT 1,907 3,536 4,440 4,892 5,955 5,531 5,974 6,235 EBITDA 2,407 4,096 5,390 5,932 7,240 6,863 7,502 7,934

Cash flow (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 2,569 3,811 4,764 5,311 6,189 5,964 6,675 7,299 Depreciation and amortisation 500 560 950 1,041 1,285 1,331 1,529 1,700 Tax paid (540) (987) (1,408) (1,508) (1,751) (1,462) (1,682) (1,860) Change in working capital 1,868 4,613 2,443 365 2,121 2,232 2,072 2,200 Other operational CF items (2,097) (2,326) (1,272) 482 (479) (983) (1,194) (1,497) Cash flow from operations 2,300 5,671 5,476 5,690 7,365 7,082 7,399 7,841 Capex (2,589) (3,764) (3,287) (3,708) (4,487) (4,305) (4,180) (4,055) Net (acquisitions)/disposals (1,600) 659 (652) 103 (1,000) (1,000) 0 0 Other investing CF items (567) (4,259) (57) 2,822 (1,461) (263) (263) (263) Cash flow from investing (4,756) (7,365) (3,996) (784) (6,948) (5,568) (4,443) (4,318) Change in debt 5,205 686 760 (24) (3,498) (1,500) (1,500) (1,500) Net share issues/(repurchases) 2,699 0 0 0 0 0 0 0 Dividends paid (425) (744) (1,088) (1,233) (1,408) (980) (1,197) (1,379) Other financing CF items 346 (329) (304) (123) (326) 0 0 0 Cash flow from financing 7,824 (386) (633) (1,380) (5,232) (2,480) (2,697) (2,879) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash 5,367 (2,079) 847 3,527 (4,815) (965) 259 645 Free cash flow (289) 1,907 2,189 1,982 2,878 3,576 4,350 4,728 Source: FactSet, Daiwa forecasts

China Resources Gas (1193 HK): 12 January 2018

Financial summary continued … Balance sheet (HKDm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 10,608 9,803 9,773 10,802 9,572 8,649 8,908 9,553 Inventory 535 792 640 571 413 557 605 638 Accounts receivable 3,174 6,666 6,992 7,369 8,021 5,776 7,265 9,002 Other current assets 395 958 3,053 1,609 1,965 3,112 3,494 3,952 Total current assets 14,712 18,219 20,458 20,351 19,971 18,095 20,272 23,144 Fixed assets 13,010 18,528 21,492 22,717 24,059 28,007 30,636 32,970 Goodwill & intangibles 691 1,168 2,079 1,975 1,880 1,925 1,948 1,969 Other non-current assets 9,270 12,567 13,722 14,854 13,765 14,393 15,805 17,518 Total assets 37,683 50,482 57,752 59,896 59,675 62,420 68,661 75,601 Short-term debt 175 859 3,297 4,220 3,139 3,139 3,139 3,139 Accounts payable 5,092 11,470 12,840 12,441 10,574 14,421 16,943 19,748 Other current liabilities 5,499 5,627 7,642 8,763 11,703 9,042 10,511 12,132 Total current liabilities 10,766 17,956 23,779 25,423 25,416 26,602 30,593 35,020 Long-term debt 11,518 13,016 11,633 10,679 9,028 7,528 6,028 4,528 Other non-current liabilities 713 895 1,213 1,306 1,526 1,279 1,416 1,556 Total liabilities 22,997 31,866 36,624 37,409 35,970 35,410 38,037 41,105 Share capital 222 222 222 222 222 222 222 222 Reserves/R.E./others 11,476 13,961 15,841 16,787 17,546 19,790 22,264 24,953 Shareholders' equity 11,699 14,183 16,063 17,009 17,768 20,012 22,486 25,175 Minority interests 2,987 4,433 5,065 5,478 5,937 6,998 8,138 9,321 Total equity & liabilities 37,683 50,482 57,752 59,896 59,675 62,420 68,661 75,601 EV 57,248 61,481 63,163 62,556 61,602 61,941 61,148 59,980 Net debt/(cash) 1,085 4,071 5,156 4,098 2,596 2,019 260 (1,885) BVPS (HKD) 5.260 6.377 7.223 7.648 7.989 8.998 10.111 11.320

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) (4.1) 63.6 28.8 14.3 0.3 15.6 17.7 16.5 EBITDA (YoY) (9.7) 70.2 31.6 10.1 22.0 (5.2) 9.3 5.8 Operating profit (YoY) (9.3) 85.4 25.6 10.2 21.7 (7.1) 8.0 4.4 Net profit (YoY) 40.0 31.3 15.1 14.1 15.9 4.6 12.0 10.4 Core EPS (fully-diluted) (YoY) 33.4 22.0 14.9 14.0 15.9 4.5 12.0 10.4 Gross-profit margin 34.9 36.7 33.7 33.6 37.9 33.7 32.3 30.6 EBITDA margin 17.7 18.4 18.8 18.1 22.0 18.0 16.7 15.2 Operating-profit margin 14.0 15.9 15.5 14.9 18.1 14.5 13.3 11.9 Net profit margin 12.1 9.7 8.7 8.6 10.0 9.0 8.6 8.2 ROAE 15.7 16.7 16.4 17.2 18.9 18.2 18.1 17.9 ROAA 5.3 4.9 4.6 4.8 5.5 5.6 5.9 5.9 ROCE 8.6 12.0 13.0 13.3 16.3 15.0 15.4 15.2 ROIC 10.5 13.6 12.8 13.3 16.1 15.1 14.9 14.6 Net debt to equity 9.3 28.7 32.1 24.1 14.6 10.1 1.2 n.a. Effective tax rate 21.0 25.9 29.6 28.4 28.3 24.5 25.2 25.5 Accounts receivable (days) 75.8 80.6 86.8 79.8 85.3 66.2 53.1 56.9 Current ratio (x) 1.4 1.0 0.9 0.8 0.8 0.7 0.7 0.7 Net interest cover (x) 6.1 6.8 8.3 9.0 11.1 10.0 12.1 14.4 Net dividend payout 14.6 16.1 21.8 25.3 29.8 34.8 35.8 36.8 Free cash flow yield n.a. 3.5 4.0 3.6 5.2 6.5 7.9 8.6 Source: FactSet, Daiwa forecasts

Company profile

China Resources Gas is one of the leading city-gas distributors in China, owning 230 projects (as of June 2017) with a geographical focus on economically developed and densely populated cities, serving industrial, commercial and residential customers, as well as operating vehicle gas refueling stations.

China Resources Gas (1193 HK): 12 January 2018

Valuation

We cut our TP for CRG by 14% to HKD23.60 from HKD27.50, as we lower our 2018-19E EPS by 9-11%. Also, we raise our WACC from 9.2% to 9.6% on a less-certain profit outlook, given that CRG does not have the H&D strategies in place to hedge the upcoming margin risk.

Our new assumptions trim the NPV of terminal value by 15%, leading to the cut in our TP to HKD23.6.

CRG: DCF valuation Forecast 12 months to 31 Dec, All figures in HKDm 2018E 2019E 2020E 2021E 2022E 2023E 2024E Terminal

Valuation Date 10-Jan-18 Next Balance Date 31-Dec-18 First Year Cash Flow Adjustment 0.98

Free Cash Flow EBITDA 7,502 7,934 8,339 8,792 9,471 10,297 6,439 Less: Other Non Cash 54 313 599 887 1,132 1,335 2,346 Less: Cash Tax Payable on EBIT (1,872) (2,044) (2,179) (2,319) (2,516) (2,958) (1,174) Plus: Decrease in Working Capital 2,072 2,200 1,899 1,688 1,353 817 (13) Less: Capital Expenditure (4,180) (4,055) (3,930) (3,805) (3,680) (3,555) (3,369) Free Cash Flow 3,576 4,350 4,728 5,244 5,760 5,935 4,229 4,314

Free Cash Flow for Valuation Purposes 3,576 4,350 4,728 5,244 5,760 5,935 4,229 4,314

WACC 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6% 9.6%

NPV of Free Cash Flow 3,268 3,627 3,597 3,640 3,649 3,431 2,230 29,973

Source: Daiwa estimates and forecasts

CRG: DCF calculation CRG: DCF sensitivity analysis Target gearing (debt/capital) (%) 35.0% Discount NPV of Enterprise Equity Equity Value Per Share Market risk premium (%) 10.0% Rate FCF Value Value (HKD) Risk-free rate (%) 3.6% 7.1% 25,638 78,157 76,139 35.0 Beta 0.99 7.6% 25,174 71,464 69,445 31.9 Cost of debt (%) 3.2% 8.1% 24,724 65,857 63,839 29.3 8.6% 24,285 61,091 59,072 27.1 Cost of equity (%) 13.5% 9.1% 23,858 56,987 54,968 25.2 WACC (%) 9.6% 9.6% 23,442 53,415 51,396 23.6 10.1% 23,037 50,276 48,258 22.2 Terminal Value 10.6% 22,642 47,496 45,477 20.9 Terminal Growth Rate 2.00% 11.1% 22,257 45,015 42,997 19.7 Terminal WACC 9.6% 11.6% 21,883 42,787 40,769 18.7 12.1% 21,517 40,775 38,756 17.8

Estimated Terminal Free Cash Flow 4,314 NPV of Terminal Value (as at 31 Dec 2024) 56,841 NPV of Terminal Value (as at 06 Jan 2018) 29,973 DCF Valuation NPV of Forecasts (HKDm) 23,442 NPV of Terminal Value (HKDm) 29,973 Add: Market value of stakes in Associates #1 0 Associate #2 0 Associate #3 0 Enterprise Value (HKDm) 53,415 Less: Net Debt (as at 06 Jan 2018) -2,019 Equity Value (HKDm) 51,396 No. Shares (m) 2,178 Per Share Equity Value HKD23.6

Source: Daiwa estimates and forecasts Source: Daiwa estimates and forecasts

China Resources Gas (1193 HK): 12 January 2018

China Industrials 12 January 2018

(392 HK) Beijing Enterprises Beijing Enterprises

Target price: HKD44.20 (from HKD41.00) Share price (10 Jan): HKD44.95 | Up/downside: -1.7%

Moving further away from utility-like BEH Don Lau, CFA (852) 2848 4469  Potential full charging of storage for SJ pipeline implies earnings upside [email protected]  Questions over long-term positioning likely to justify valuation discount Dennis Ip, CFA (852) 2848 4068  Raising TP to HKD44.2 on associate valuations; maintaining Hold (3) [email protected]

What's new: BEH shares are up 8% since 30 August, backed by: 1) the Forecast revisions (%) announcement on 30 August of a milder-than-expected cut in the Shaanxi- Year to 31 Dec 17E 18E 19E Beijing pipeline (SJ pipeline) transmission tariff, and 2) strong 1H FY18 Revenue change (0.5) 1.3 (1.8) Net profit change (0.5) (7.0) (7.2) results (announced 27 November) for associate CGHL (384 HK, HKD20.8, Core EPS (FD) change (0.5) (7.0) (7.2) Outperform [2]), which led the market to revise up 2017-19E EPS by 2-6%. Source: Daiwa forecasts

What's the impact: Transmission volume growth offset by tariff cut. In Share price performance

2017, the SJ pipeline saw solid volume growth of c.14% YoY, thanks to (HKD) (%) robust coal-to-gas conversion in northern China. The effective tariff (ex- 48 110 VAT) was cut by c.30% on 1 September to c.CNY0.20/m3 (assuming an 45 104 average transmission distance of 800 km), offsetting the strong volume 42 98 39 91 growth. However, the pipeline company is reviewing the charging of 36 85 storage fees (CNY0.04/m3) with the CNPC and is confident it will collect Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 fees again following the review. Hence, in our base case, we factor in a B'Jing Ent (LHS) Relative to HSI (RHS)

CNY0.02/m3 storage fee and estimate that the 2017 net profit contribution from the SJ pipeline will be flat YoY at HKD2.8bn, with the 2018 12-month range 36.35-48.00 contribution falling by 16% YoY to CNY2.3bn when the new tariff is applied Market cap (USDbn) 7.25 to the full year. We estimate the full collection of the CNY0.04/m3 storage 3m avg daily turnover (USDm) 9.76 Shares outstanding (m) 1,262 fee would lead to 4% upward revisions to our 2018-19E net profit. Major shareholder Beijing Enterprises Group (56.3%)

BEH’s 11M17 distribution volume was flat, a recovery from the 1% YoY Financial summary (HKD) decline in 1H17. Like its peers. BEH faces a dollar margin squeeze (non- Year to 31 Dec 17E 18E 19E residential: CNY0.024/m3) during the winter as it can only pass through Revenue (m) 57,325 60,863 61,618 part of the cost hike, resulting in a negative earnings impact of c.HKD100m. Operating profit (m) 3,933 3,543 3,649 Net profit (m) 7,096 7,161 7,916 Core EPS (fully-diluted) 5.602 5.654 6.250 Vague positioning likely weighing on valuation. Rather than enjoying EPS change (%) 13.8 0.9 10.5 upside from its recently acquired 29% stake in Jingtang LNG terminal, Daiwa vs Cons. EPS (%) 7.3 (0.1) (0.5) which we believe will benefit from tight gas supply in Northern China, BEH PER (x) 8.0 7.9 7.2 Dividend yield (%) 2.3 2.3 2.5 has opted to sell the stake to non-wholly-owned subsidiary Beijing Gas DPS 1.021 1.031 1.139 Blue Sky (6828 HK, Not rated) at a price implying no more than 5x 2017E PBR (x) 0.9 0.8 0.7 earnings, on our estimates. The decision to dispose of a utility-like asset EV/EBITDA (x) 8.7 8.1 6.9 ROE (%) 11.7 10.7 10.8 with a solid recurring cash-flow profile, together with BEH’s acquisition of Source: FactSet, Daiwa forecasts Verk, which is subject to earnings volatility, will likely do little to assuage investor concerns over the long-term strategic positioning of the company.

What we recommend: Despite the 1-7% cut in our 2017-19E EPS due to lower gas distribution earnings, we lift our SOTP-based 12-month TP to HKD44.2 (from HKD41.0) to reflect our higher valuations of subsidiaries CGHL and BEW (371 HK, HKD6.06, Buy [1]). Upside risk: sharp rise in the dividend payout; downside risk: more non-utility-like M&A moves.

How we differ: Our 2017E EPS for BEH is 7% above consensus, which we attribute to our factoring in the latest earnings of its JVs and associates.

See important disclosures, including any required research certifications, beginning on page 111

Beijing Enterprises (392 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook BEH: DPS and EPS growth YoY

Although we believe BEH’s gas distribution business will 35% remain sluggish on the back of muted volume growth going 30% forward, we forecast an 8% EPS CAGR for 2016-19E as 25% we assume robust earnings growth for associates China 20% Gas and BEW. That said, we expect its DPS to see a slower CAGR of 6% over the same period, as we believe 15% BEH will need to retain more cash to: 1) bring down its 10% gearing (2017E: 71%, vs. 2015: 36%) to a healthier level 5% after the EEW and Verk acquisitions, and 2) prepare for 0% another non-utility-like M&A move. We note that in 2016, 2009 2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E YoY EPS growth YoY DPS growth BEH did not lift its DPS despite seeing 10%-plus YoY growth in EPS. Source: Company, Daiwa forecasts

Valuation BEH: revised SOTP valuation BEH is trading currently at a 2018E PER of 7.9x, 1.3x SD Skate HKD/ % below its long-term average PER and a c.40% discount to Business segment Valuation Ownership share Value Piped gas operation (distribution & 48% the average of its peers’ valuation range (11-15x). transmission), WTE and Russia oilfield DCF at 9.3% 100.0% 51.7 Target price at 22% Although BEH’s valuation looks undemanding, we believe China Gas (384 HK) HKD23.8/share 24.9% 23.2 Target price at 24% the discount is justified and will not narrow until the Beijing Enterprises Water (371 HK) HKD8.35/share 43.8% 25.2 company: 1) re-establishes itself with pure utility positioning Yanjing Brewery (000729 CH) Market Value 45.8% 5.8 5% through new M&As and divestures, thereby restoring Beijing Development (154 HK) Market Value 50.4% 0.7 1% Biosino Bio-Tech (8247 HK) Market Value 18.8% 0.0 0% investor confidence, and 2) rewards its shareholders by Corporate value 106.6 100% raising its payout ratio. Conglomerate discount at 25% discount (35.8) (25%) Net Cash / (Debt) (end of 2017E) (26.7) Target price 44.2 Source: Bloomberg, Daiwa estimates and forecasts

BEH: consensus EPS-forecast revisions Earnings revisions

Since the end of August, the Bloomberg consensus (HKD) earnings forecasts for BEH have risen by 2% for 2017E, 4% for 2018E, and 6% for 2019E (mostly in September). 6.3 We believe the upward revisions primarily resulted from the 6.0 milder-than-expected cut in the SJ pipeline transmission 5.7 tariff. Our revised 2017E EPS are 7% above the 5.4 consensus, likely because we factor in the latest earnings 5.1 of its JVs and associates. 4.8

4.5

Jul-16 Jul-17

Jan-16 Jan-17 Jan-18

Mar-16 Mar-17

Sep-16 Nov-16 Sep-17 Nov-17

May-16 May-17 2017E EPS 2018E EPS 2019E EPS

Source: Bloomberg

Beijing Enterprises (392 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Natural gas distribution sales volume 7.94 8.72 9.96 13.06 14.38 14.61 14.85 15.07 (bcm) Gas sales segment dollar margin 0.27 0.29 0.28 0.27 0.26 0.26 0.23 0.22 (CNY/m3) Natural gas transmission sales volume 23.72 25.21 29.96 32.93 33.63 38.60 42.00 45.60 (bcm) Proportion of net earnings from natural 85 84 92 89 84 83 73 69 gas operations (%)

Profit and loss (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Piped gas operation 20,645 25,159 32,438 43,946 39,379 40,006 43,053 43,551 Brewery operation 14,443 16,837 15,151 14,069 11,590 11,404 11,751 11,633 Other Revenue 482 364 346 2,134 4,990 5,915 6,060 6,434 Total Revenue 35,570 42,361 47,936 60,150 55,959 57,325 60,863 61,618 Other income 1,485 1,515 1,241 1,467 1,628 964 935 954 COGS (28,208) (34,023) (39,360) (51,099) (46,523) (47,607) (51,150) (51,791) SG&A (5,393) (5,957) (6,004) (6,512) (6,644) (6,749) (7,105) (7,132) Other op.expenses n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. Operating profit 3,102 3,698 3,331 3,232 4,039 3,933 3,543 3,649 Net-interest inc./(exp.) (997) (1,134) (1,172) (1,302) (1,492) (1,604) (1,800) (1,800) Assoc/forex/extraord./others 2,049 2,737 3,812 4,708 4,950 6,206 7,047 7,963 Pre-tax profit 4,155 5,301 5,970 6,638 7,497 8,535 8,791 9,811 Tax (557) (545) (565) (682) (858) (1,036) (1,239) (1,437) Min. int./pref. div./others (363) (572) (574) (289) (403) (403) (390) (459) Net profit (reported) 3,235 4,184 4,832 5,667 6,236 7,096 7,161 7,916 Net profit (adjusted) 3,235 4,184 4,832 5,667 6,236 7,096 7,161 7,916 EPS (reported)(HKD) 2.844 3.606 3.776 4.414 4.924 5.622 5.674 6.272 EPS (adjusted)(HKD) 2.844 3.606 3.776 4.414 4.924 5.622 5.674 6.272 EPS (adjusted fully-diluted)(HKD) 2.724 3.523 3.760 4.414 4.924 5.602 5.654 6.250 DPS (HKD) 0.721 0.889 0.900 0.950 0.947 1.021 1.031 1.139 EBIT 3,102 3,698 3,331 3,232 4,039 3,933 3,543 3,649 EBITDA 4,965 5,945 5,682 5,928 7,308 7,257 7,360 7,919

Cash flow (HKDm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 4,155 5,301 5,970 6,638 7,497 8,535 8,791 9,811 Depreciation and amortisation 1,863 2,248 2,351 2,696 3,269 3,324 3,817 4,271 Tax paid (557) (545) (565) (682) (858) (1,036) (1,239) (1,437) Change in working capital 176 2,814 (3,891) 6,436 891 146 617 94 Other operational CF items (255) (3,664) (2,980) (499) 1,164 (5,967) (6,819) (7,763) Cash flow from operations 5,381 6,153 885 14,589 11,963 5,001 5,166 4,977 Capex (8,234) (6,668) (3,661) (4,435) (4,673) (14,086) (6,003) (6,003) Net (acquisitions)/disposals (2,320) (321) (5,968) (253) (13,078) 0 0 0 Other investing CF items 1,185 264 1,466 (1,714) 32 0 0 0 Cash flow from investing (9,370) (6,725) (8,164) (6,401) (17,718) (14,086) (6,003) (6,003) Change in debt 6,560 285 11,319 (1,592) 11,966 9,359 0 0 Net share issues/(repurchases) 0 0 (161) (399) (705) 0 0 0 Dividends paid (1,149) (1,196) (1,436) (1,482) (1,599) (1,706) (1,721) (1,903) Other financing CF items (984) (169) (1,157) (1,272) (1,460) 0 0 0 Cash flow from financing 4,427 (1,080) 8,565 (4,745) 8,202 7,653 (1,721) (1,903) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash 438 (1,652) 1,286 3,443 2,447 (1,431) (2,558) (2,929) Free cash flow (2,853) (515) (2,776) 10,154 7,291 (9,085) (837) (1,026) Source: FactSet, Daiwa forecasts

Beijing Enterprises (392 HK): 12 January 2018

Financial summary continued … Balance sheet (HKDm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 12,298 10,859 11,266 13,767 16,028 14,689 12,131 9,202 Inventory 5,914 5,661 5,393 4,644 4,953 5,068 5,446 5,514 Accounts receivable 3,427 5,124 5,501 3,720 3,771 3,863 4,102 4,153 Other current assets 4,268 4,563 10,862 11,507 9,084 9,201 12,443 13,008 Total current assets 25,907 26,207 33,023 33,638 33,836 32,821 34,121 31,876 Fixed assets 32,805 38,997 39,321 37,736 43,428 45,653 47,237 48,361 Goodwill & intangibles 7,569 7,724 9,137 9,211 19,128 18,596 18,148 17,771 Other non-current assets 23,217 36,694 42,693 44,182 48,316 64,997 72,303 80,286 Total assets 89,499 109,622 124,174 124,766 144,709 162,068 171,809 178,294 Short-term debt 6,277 7,290 17,784 7,048 18,419 11,000 11,000 11,000 Accounts payable 2,616 2,383 2,238 3,641 3,929 4,021 4,320 4,374 Other current liabilities 11,293 16,231 14,487 14,646 16,595 17,809 19,045 19,268 Total current liabilities 20,187 25,904 34,509 25,335 38,942 32,830 34,365 34,642 Long-term debt 20,347 18,488 19,439 27,708 32,211 48,989 48,989 48,989 Other non-current liabilities 1,297 1,162 2,130 3,071 5,517 5,120 7,072 6,254 Total liabilities 41,831 45,554 56,078 56,114 76,670 86,939 90,426 89,885 Share capital 114 127 30,402 30,402 30,402 30,402 30,402 30,402 Reserves/R.E./others 39,524 53,894 n.a. n.a. n.a. 33,606 39,471 46,038 Shareholders' equity 39,637 54,021 57,176 58,187 57,321 64,008 69,872 76,440 Minority interests 8,030 10,047 10,920 10,465 10,718 11,120 11,511 11,969 Total equity & liabilities 89,499 109,622 124,174 124,766 144,709 162,068 171,809 178,294 EV 63,832 52,298 60,103 56,395 68,935 63,462 59,363 54,789 Net debt/(cash) 14,326 14,920 25,956 20,989 34,601 45,300 47,858 50,787 BVPS (HKD) 34.844 46.565 44.688 45.320 45.258 50.714 55.361 60.564

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) 16.7 19.1 13.2 25.5 (7.0) 2.4 6.2 1.2 EBITDA (YoY) (0.6) 19.7 (4.4) 4.3 23.3 (0.7) 1.4 7.6 Operating profit (YoY) (3.7) 19.2 (9.9) (3.0) 25.0 (2.6) (9.9) 3.0 Net profit (YoY) 16.5 29.3 15.5 17.3 10.0 13.8 0.9 10.5 Core EPS (fully-diluted) (YoY) 16.5 29.3 6.7 17.4 11.5 13.8 0.9 10.5 Gross-profit margin 20.7 19.7 17.9 15.0 16.9 17.0 16.0 15.9 EBITDA margin 14.0 14.0 11.9 9.9 13.1 12.7 12.1 12.9 Operating-profit margin 8.7 8.7 6.9 5.4 7.2 6.9 5.8 5.9 Net profit margin 9.1 9.9 10.1 9.4 11.1 12.4 11.8 12.8 ROAE 8.4 8.9 8.7 9.8 10.8 11.7 10.7 10.8 ROAA 3.9 4.2 4.1 4.6 4.6 4.6 4.3 4.5 ROCE 4.4 4.5 3.4 3.1 3.6 3.1 2.6 2.5 ROIC 4.7 4.7 3.5 3.2 3.7 3.1 2.4 2.3 Net debt to equity 36.1 27.6 45.4 36.1 60.4 70.8 68.5 66.4 Effective tax rate 13.4 10.3 9.5 10.3 11.4 12.1 14.1 14.6 Accounts receivable (days) 31.1 36.8 40.5 28.0 24.4 24.3 23.9 24.4 Current ratio (x) 1.3 1.0 1.0 1.3 0.9 1.0 1.0 0.9 Net interest cover (x) 3.1 3.3 2.8 2.5 2.7 2.5 2.0 2.0 Net dividend payout 25.4 24.6 23.8 21.5 19.2 18.2 18.2 18.2 Free cash flow yield n.a. n.a. n.a. 17.9 12.9 n.a. n.a. n.a. Source: FactSet, Daiwa forecasts

Company profile

Founded in 1997, Beijing Enterprises Holdings Limited (BEH) is an environmental control utilities conglomerate. It is involved in city-gas distribution in Beijing, national city-gas projects (through associate China Gas Holdings), gas pipeline transmission through Shaanxi-Beijing pipelines, and construction and operation of water supply and water-treatment plants (through associate Beijing Enterprises Water), waste-to-energy plants (through associate Beijing Development and Germany- based EEW), and an oil field in Russia (through a 20% stake in Verkhnechonsknefttegaz). It also produces and distributes beer in Beijing and other provinces in China.

China Utilities 12 January 2018

China Suntien Green Energy (956 HK) China Suntien Green Energy

Target price: HKD2.70 (from HKD2.70) Share price (10 Jan): HKD2.04 | Up/downside: +32.4%

Multiple catalysts to fuel ongoing rerating journey Dennis Ip, CFA (852) 2848 4068  Sustaining strong gas sales in winter, with limited margin squeeze [email protected]  2017E full-year wind utilisation hours ahead of prior guidance Daniel Yang (852) 2848 4443  Reaffirming Buy (1) and TP of HKD2.7, or 1x 2018E PBR [email protected]

What's new: Despite the fact that Suntien’s gas projects reside in Hebei, Forecast revisions (%) one of the provinces with the most serious gas shortage, we believe Year to 31 Dec 17E 18E 19E Suntien will see only a limited margin squeeze as c.60% of its retail Revenue change - - - business comes from direct supply from Sinopec to industrial customers, Net profit change - - - Core EPS (FD) change - - - where Suntien charges a fixed dollar margin of CNY0.05/m3 (vs. a regular Source: Daiwa forecasts distribution margin of CNY0.65/m3). As a result, we see Suntien’s gas business as essentially a volume play. Share price performance

(HKD) (%) What's the impact: Gas sales volume remained strong in winter 2.5 170 despite gas shortage. Based on the latest update from management, 2.1 150 Suntien’s gas sales volume has sustained its strong growth momentum in 1.7 130 1.4 110 the winter amid the serious gas shortage in northern China, in line with 1.0 90 what we have heard from the national city-gas distributors. Regarding the Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 margin, though the cost went up by c.20% for total gas sales (wholesale + Ch Suntien (LHS) Relative to HSI (RHS) retail), the overall impact should be mild since Suntien is able to pass through 85% of the cost increment. 12-month range 1.15-2.42 Market cap (USDbn) 0.97 3% upward revision to its 2017E wind utilisation target. Suntien has 3m avg daily turnover (USDm) 3.24 revised up its wind utilisation hours target for 2017 to 2,245-2,295 hours, Shares outstanding (m) 3,715 Major shareholder Hebei Const & Inv (50.5%) representing 2-5% YoY growth and a 3% increase from its prior guidance. However, we believe further improvement in utilisation hours will be limited Financial summary (CNY) going forward given an already high base, and hence future power Year to 31 Dec 17E 18E 19E generation growth will be primarily capacity-driven. For now, we forecast an Revenue (m) 6,581 8,326 9,712 18% power generation CAGR on the back of an 18% capacity CAGR Operating profit (m) 1,579 1,855 2,185 Net profit (m) 850 950 1,112 (600MW pa) over 2017-19E. Management believes the company can Core EPS (fully-diluted) 0.229 0.256 0.299 finance the capacity expansion plan with operating cash flow and EPS change (%) 56.7 11.8 17.0 borrowing, and has no plans to finance through equity. Daiwa vs Cons. EPS (%) 0.8 (2.4) (3.8) PER (x) 7.4 6.6 5.7 Dividend yield (%) 5.4 6.0 7.0 What we recommend: We reaffirm our Buy (1) rating on Suntien and DPS 0.091 0.102 0.120 maintain our 12-month DCF-based TP of HKD2.70. Our TP implies a 1x PBR (x) 0.7 0.7 0.6 EV/EBITDA (x) 10.2 9.6 9.0 2018E PBR (vs. the prevailing 0.7x), and we see scope for a further ROE (%) 10.4 10.8 11.7 rerating driven by: 1) a recovery in Suntien’s ROE from 10.4% in 2017E to Source: FactSet, Daiwa forecasts 11.7% in 2019E, 2) a high dividend yield (2018E: 5.7%), 3) planned A- share listing, and 4) potential inclusion in the Hong Kong-Shenzhen Stock Connect. Risk: weaker-than-expected wind speed.

How we differ: Unlike some brokers, we believe Suntien is on course to continue its rerating in 2018E.

See important disclosures, including any required research certifications, beginning on page 111

China Suntien Green Energy (956 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook Suntien: net profit forecast (CNYm) We forecast Suntien’s 2017E net profit to rise by 57% YoY 1,200 250% to CNY850m, riding on: 1) 51% YoY wind-power revenue 1,000 200% growth, and 2) 59% YoY gas-sales volume growth for 150% 2017. 800 100% 600 Going forward, we expect Suntien’s net profit to slow to a 50% 400 14% CAGR during 2017-19E. Still, our growth forecasts 0% are still superior to those for most of its peers in the wind 200 (50%) and gas segments. 0 (100%) 2014 2015 2016 2017E 2018E 2019E Net profit YoY growth (RHS)

Source: Company, Daiwa forecasts

Valuation Suntien: 1-year PBR

Benefiting from a sustained recovery in the wind and gas PBR (x) segments, Suntien’s share price has been rerated from 1.6 0.4x forward PBR in mid-2016 to 0.7x currently, but is still 1.4 1.3x Avg+2SD below the stock’s mean of 0.8x since 2010. Our TP implies 1.2 a 1.0x 2018E PBR, and we see room for further rating as 1.0 1.0x Avg+1SD driven by: 1) a recovery in Suntien’s ROE from 10.4% in 0.8 0.8x Avg 2017E to 11.7% in 2019E, 2) its high dividend yield 0.6 (2018E: 5.7%), 3) its planned A-share listing, and 4) its 0.5x Avg-1SD 0.4 potential inclusion in the Hong Kong-Shenzhen Stock 0.2x Avg-2SD Connect. Risk: weaker-than-expected wind speed. 0.2 0.0 Oct-10 Oct-11 Oct-12 Oct-13 Oct-14 Oct-15 Oct-16 Oct-17 Source: Bloomberg, Daiwa forecasts

Earnings revisions Suntien: Bloomberg consensus EPS (CNY) The Bloomberg 2017-19E EPS consensus has been on an 0.35 uptrend since March 2017, primarily due to a continued 0.30 improvement in the company’s operating performance in 0.25 both the wind and gas segments over the course of the 0.20 year. Since our 2017-19E EPS forecasts are only -4% to 0.15 +1% different from the consensus numbers, we believe 0.10 there is not much scope for further upside revisions in the 0.05

near term. 0.00

3/1/2016 5/1/2016 7/1/2016 1/1/2015 3/1/2015 5/1/2015 7/1/2015 9/1/2015 1/1/2016 9/1/2016 1/1/2017 3/1/2017 5/1/2017 7/1/2017 9/1/2017 1/1/2018

11/1/2015 11/1/2016 11/1/2017 2017E EPS 2018E EPS 2019E EPS

Source: Bloomberg

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China Suntien Green Energy (956 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Natural gas sales volume (mn m3) 1,246 1,484 1,523 1,127 1,111 1,771 2,412 2,857 Wholesales gas proportion (%) 56 51 55 70 71 58 53 54 Gas ASP, excl tax (CNY/m3) 1.97 2.16 2.44 2.32 2.03 1.94 1.91 1.91 Gas cost, excl tax (CNY/m3) 1.50 1.68 2.00 1.89 1.67 1.68 1.68 1.69 Consolidated wind capacity (MW) 1,346 1,445 1,697 2,094 2,796 3,496 4,196 4,896 Wind utilisation (hours) 2,290 2,312 1,996 1,887 2,195 2,247 2,250 2,252

Profit and loss (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Natural gas 2,569 3,327 3,903 2,792 2,392 3,562 4,731 5,556 Wind power 1,133 1,333 1,246 1,427 1,983 3,019 3,595 4,156 Other Revenue 0 0 0 6 9 (0) (0) 0 Total Revenue 3,702 4,661 5,149 4,224 4,384 6,581 8,326 9,712 Other income 78 31 56 77 97 97 105 114 COGS (1,996) (2,651) (3,256) (2,409) (2,166) (3,714) (4,969) (5,845) SG&A (195) (240) (256) (273) (302) (413) (437) (421) Other op.expenses (522) (585) (601) (910) (784) (972) (1,169) (1,374) Operating profit 1,067 1,216 1,093 710 1,228 1,579 1,855 2,185 Net-interest inc./(exp.) (354) (424) (487) (572) (549) (620) (770) (866) Assoc/forex/extraord./others 90 40 69 63 65 166 180 196 Pre-tax profit 803 832 675 200 744 1,125 1,265 1,515 Tax (7) (158) (176) (11) (96) (137) (159) (215) Min. int./pref. div./others (246) (215) (163) (21) (106) (138) (156) (187) Net profit (reported) 550 460 335 168 542 850 950 1,112 Net profit (adjusted) 550 460 363 356 542 850 950 1,112 EPS (reported)(CNY) 0.170 0.142 0.091 0.045 0.146 0.229 0.256 0.299 EPS (adjusted)(CNY) 0.170 0.142 0.099 0.096 0.146 0.229 0.256 0.299 EPS (adjusted fully-diluted)(CNY) 0.170 0.142 0.099 0.096 0.146 0.229 0.256 0.299 DPS (CNY) 0.020 0.053 0.031 0.015 0.063 0.091 0.102 0.120 EBIT 1,067 1,216 1,121 898 1,228 1,579 1,855 2,185 EBITDA 1,535 1,767 1,718 1,591 2,005 2,551 3,025 3,559

Cash flow (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 803 832 675 200 744 1,125 1,265 1,515 Depreciation and amortisation 468 550 598 694 776 972 1,169 1,374 Tax paid (7) (158) (176) (117) (117) (137) (159) (215) Change in working capital (618) 205 (197) 386 73 3 250 100 Other operational CF items 584 167 (13) 176 118 454 590 670 Cash flow from operations 1,230 1,597 885 1,339 1,593 2,417 3,116 3,444 Capex (1,413) (1,536) (2,446) (5,687) (4,221) (5,188) (5,118) (5,048) Net (acquisitions)/disposals (1) (2) (3) 0 0 0 0 0 Other investing CF items 86 268 116 458 612 34 34 34 Cash flow from investing (1,329) (1,270) (2,333) (5,228) (3,609) (5,154) (5,084) (5,014) Change in debt 694 1,398 2,067 4,797 1,217 5,500 2,000 2,000 Net share issues/(repurchases) 0 0 1,256 0 0 0 0 0 Dividends paid (272) (94) (248) (167) (81) (618) (691) (809) Other financing CF items (427) (576) (465) (579) (672) (87) (273) (275) Cash flow from financing (5) 728 2,610 4,051 464 4,795 1,036 916 Forex effect/others 0 0 0 0 0 0 0 0 Change in cash (104) 1,055 1,162 162 (1,551) 2,058 (932) (654) Free cash flow (183) 61 (1,561) (4,348) (2,628) (2,771) (2,002) (1,604) Source: FactSet, Daiwa forecasts

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China Suntien Green Energy (956 HK): 12 January 2018

Financial summary continued … Balance sheet (CNYm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 758 1,670 3,198 3,139 1,491 3,549 2,618 1,963 Inventory 30 43 43 48 45 61 86 106 Accounts receivable 843 846 1,402 1,241 1,597 1,953 2,757 3,459 Other current assets 601 565 689 804 736 823 1,057 1,276 Total current assets 2,231 3,123 5,331 5,232 3,869 6,386 6,518 6,805 Fixed assets 8,602 10,180 11,731 14,971 19,668 24,001 28,059 31,837 Goodwill & intangibles 2,357 2,256 2,198 2,101 2,021 1,915 1,816 1,721 Other non-current assets 2,072 1,855 2,350 4,620 3,816 3,782 3,772 3,762 Total assets 15,263 17,414 21,610 26,924 29,374 36,085 40,165 44,125 Short-term debt 971 1,359 1,730 2,440 5,113 5,113 5,113 5,113 Accounts payable 197 224 437 553 465 679 964 1,189 Other current liabilities 928 1,162 1,364 1,561 2,240 2,482 3,511 4,327 Total current liabilities 2,096 2,744 3,531 4,555 7,818 8,274 9,588 10,629 Long-term debt 6,529 7,545 9,296 13,386 11,933 17,433 19,433 21,433 Other non-current liabilities 15 19 21 82 90 90 90 90 Total liabilities 8,640 10,307 12,848 18,023 19,840 25,797 29,110 32,151 Share capital 3,238 3,238 3,715 3,715 3,715 3,715 3,715 3,715 Reserves/R.E./others 2,329 2,727 3,644 3,698 4,185 4,801 5,411 6,143 Shareholders' equity 5,568 5,966 7,360 7,413 7,900 8,516 9,126 9,858 Minority interests 1,055 1,141 1,403 1,487 1,634 1,772 1,928 2,115 Total equity & liabilities 15,263 17,414 21,610 26,924 29,374 36,085 40,165 44,125 EV 13,700 14,316 14,622 19,415 22,349 25,929 29,017 31,858 Net debt/(cash) 6,742 7,234 7,828 12,687 15,554 18,996 21,928 24,582 BVPS (CNY) 1.719 1.842 2.001 1.995 2.127 2.292 2.457 2.654

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) 16.8 25.9 10.5 (18.0) 3.8 50.1 26.5 16.6 EBITDA (YoY) 23.5 15.1 (2.8) (7.4) 26.0 27.3 18.6 17.7 Operating profit (YoY) 22.2 14.0 (7.9) (19.9) 36.8 28.6 17.5 17.7 Net profit (YoY) 22.5 (16.4) (21.0) (1.8) 52.2 56.7 11.8 17.0 Core EPS (fully-diluted) (YoY) 22.5 (16.4) (30.5) (2.8) 52.2 56.7 11.8 17.0 Gross-profit margin 46.1 43.1 36.8 43.0 50.6 43.6 40.3 39.8 EBITDA margin 41.5 37.9 33.4 37.7 45.7 38.8 36.3 36.6 Operating-profit margin 28.8 26.1 21.8 21.3 28.0 24.0 22.3 22.5 Net profit margin 14.8 9.9 7.1 8.4 12.4 12.9 11.4 11.5 ROAE 10.2 8.0 5.4 4.8 7.1 10.4 10.8 11.7 ROAA 3.7 2.8 1.9 1.5 1.9 2.6 2.5 2.6 ROCE 7.9 8.1 6.3 4.0 4.8 5.3 5.4 5.9 ROIC 8.4 7.1 5.2 3.5 4.6 5.1 5.2 5.4 Net debt to equity 121.1 121.3 106.4 171.1 196.9 223.1 240.3 249.4 Effective tax rate 0.9 18.9 26.1 5.7 12.9 12.2 12.5 14.2 Accounts receivable (days) 61.1 66.1 79.6 114.2 118.1 98.4 103.2 116.8 Current ratio (x) 1.1 1.1 1.5 1.1 0.5 0.8 0.7 0.6 Net interest cover (x) 3.0 2.9 2.3 1.6 2.2 2.5 2.4 2.5 Net dividend payout 11.8 37.2 34.4 33.1 43.2 40.0 40.0 40.0 Free cash flow yield n.a. 1.0 n.a. n.a. n.a. n.a. n.a. n.a. Source: FactSet, Daiwa forecasts

Company profile

China Suntien Green Energy is a clean-energy enterprise controlled by the Hebei Construction & Investment Group. Its main businesses include the investment, construction and operation of wind farms, as well as the transmission and distribution of natural gas and compressed natural gas (CNG).

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China Industrials 12 January 2018

(3899 HK) CIMC Enric CIMC Enric

Target price: HKD8.80 (from HKD7.80) Share price (10 Jan): HKD7.33 | Up/downside: +20.1%

Upgrading: sector liberalisation play Dennis Ip, CFA (852) 2848 4068  LNG imports and storage short-term workarounds to gas shortage [email protected]  Explicit government targets to expand LNG receiving/storage capacity Don Lau, CFA (852) 2848 4469  Upgrading to Buy (1) from Outperform (2); raising TP to HKD8.80 [email protected]

What's new: We downgraded Enric on 3 January to Outperform (2) on its: 1) Forecast revisions (%) 2017 results being likely to undershoot market expectations (which we still Year to 31 Dec 17E 18E 19E believe will be the case), and 2) premium valuation. But, based on our Revenue change - 1.2 3.2 Net profit change - 7.3 8.7 research, we now believe a stricter LNG storage policy is likely after the 2017- Core EPS (FD) change - 7.3 8.7 18 supply tightness, which should support stronger LNG equipment sales. Source: Daiwa forecasts

What's the impact: Strong 2018-19E LNG equipment demand on severe Share price performance gas shortage. In 2017, China introduced an aggressive industrial and rural (HKD) (%) coal-to-gas (CTG) conversion programme in northern China, which has led to 8.0 140 a 15-25% gas shortage in the 2017-18 winter. Also, prices of market-based 7.0 125 factory-produced LNG surged by over 150% from CNY3.0k/t to CNY7.5k/t in 6.0 110 4Q17, likely causing a dollar margin squeeze for city-gas distributors over 5.0 95 4.0 80 December 2017-March 2018, given a 100% pass-through of this cost hike to Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 end-users is unlikely. According to local reports (ie, Caixin), LNG trailer CIMC Enric (LHS) Relative to HSI (RHS) transportation costs doubled, given LNG in southern China was used to supply the country’s north to relieve the gas shortages caused by heating demand. As new centralised underground storage could take time to materialise, China 12-month range 4.19-7.67 Market cap (USDbn) 1.81 needs to temporarily enhance its peak shaving capability through increasing 3m avg daily turnover (USDm) 3.65 LNG imports and storage. Shares outstanding (m) 1,936 Major shareholder CIMC Group (70.4%) Solid government target. China’s government is aware of the importance of LNG in solving the seasonal gas shortage and has outlined a solid capacity Financial summary (CNY) growth target. According to the 2017-21 northern China gas supply security Year to 31 Dec 17E 18E 19E work plan, China plans to boost the receiving/storage capacity of LNG Revenue (m) 9,764 12,159 14,161 Operating profit (m) 639 1,013 1,185 terminals in northern China by 152%/188% to 37tonnes/3.7bcm by 2021. It Net profit (m) 424 683 823 also plans to add 837mcm of LNG emergency reserves in 2+4 Core EPS (fully-diluted) 0.219 0.353 0.425 municipalities/provinces in 4 years. Given that city-gas companies need to set EPS change (%) (2.4) 61.2 20.5 up their own LNG storage facilities (at least a 3-day reserve), to enhance winter Daiwa vs Cons. EPS (%) (5.3) (3.1) 1.0 PER (x) 27.9 17.3 14.4 gas supply reliability so as to maintain profitability in 2018-19, we believe Enric, Dividend yield (%) 1.0 2.3 2.8 as one of the leading LNG storage tank manufacturers/receiving terminal EPC DPS 0.064 0.140 0.173 contractors, will see resilient LNG equipment sales. Hence, we lift 2018-19E PBR (x) 2.2 2.1 1.9 net profits by 7-9%. EV/EBITDA (x) 12.9 8.7 7.6 ROE (%) 8.1 12.3 13.7

What we recommend: As we believe Enric’s gross profit will see a 30%-plus Source: FactSet, Daiwa forecasts CAGR for a few years after implementation of a stricter LNG storage policy, Enric’s ROE should reach prior peaks (15-20%) in 2020E, which we would expect to spur a rerating similar to 2009 and 2013. Hence, we lift our rating by one notch to Buy(1), with a new 12-month TP of HKD8.8 (from HKD7.8) set at a PBR of 2.5x (from 2.2x), or 1.0SD above the stock’s past-10-year PBR mean of 1.8x (previous: 0.6SD above), on our 2018E BVPS. Risk: failure to boost energy equipment sales and gross margins.

How we differ: Our 2019E EPS is 1% above consensus, which we attribute to our expectations for more gas equipment sales with improving gross margins amid stronger gas storage targets for city-gas projects.

See important disclosures, including any required research certifications, beginning on page 111

CIMC Enric (3899 HK): 12 January 2018

How do we justify our view? Growth outlook Valuation Earnings revisions

Growth outlook Enric: gross-profit forecasts by business segment

We forecast Enric’s gross profit to rise at a CAGR of 20% 2019E for 2016-19E, after the apparent bottoming of gas equipment sales in 2016. 2018E 2017E We saw a strong recovery in LNG equipment gross-profit 2016 for Enric in 1H17, amid a drop in the gross profit margin 2015 from 15.8% in 1H16 to 13.7% in 1H17 on rising steel costs 2014 and lagging ASP hikes. For 2H17E, we expect the gross profit margin of Enric’s LNG equipment to recover to 15%, 0 200 400 600 800 1,000 1,200 1,400 (CNYm) and further to 16.3% for 2018E, on a rising sales mix from Liquid food equipment Chemical equipment Energy equipment

LNG liquefaction, storage and trailers to better prepare for Source: Company, Daiwa forecasts the next heating season to avoid massive gas shortages, and the purchase of expensive LNG.

Valuation Enric: 1-year forward PBR Enric is trading currently at a 2.1x 2018E PBR, which is PBR (x) 0.4SD above its past-10-year mean. In our view, Enric’s 1- 4.0 year forward PBR chart shows that we are entering the 3.5 3.1x Avg+2SD mid-point of the third upcycle of gas equipment sales in 3.0 China. 2.5 2.4x Avg+1SD 2.0 1.8x Avg 1.5 1.0 1.1x Avg-1SD 0.5 0.5x Avg-2SD

0.0

May-… May-…

Jul-11

Oct-09 Apr-13 Oct-16

Jan-08 Jun-14 Jan-15

Mar-09 Mar-16

Feb-12

Dec-10 Sep-12 Nov-13 Aug-15 Dec-17 Aug-08 Source: Bloomberg, Daiwa forecasts

Earnings revisions Enric: Bloomberg-consensus EPS-forecast revisions

The Bloomberg-consensus 2017 EPS forecasts for Enric (CNY) have been revised down by 25% since August 2017, due to 0.45 the weak gross profit margin on LNG-equipment and rising 0.40 SG&A costs on the Sinopacific acquisitions. We expect 2018E EPS forecasts to be broadly unchanged, with 0.35 expectations for upcoming LNG equipment sales to remain 0.30 robust due to the recent gas supply shortage. 0.25

0.20 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 2017E EPS 2018E EPS 2019 EPS

Source: Bloomberg

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CIMC Enric (3899 HK): 12 January 2018

Financial summary Key assumptions Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Gas equipment GP margin (%) 24.5 23.7 22.7 20.3 15.2 14.4 16.3 16.3 CNG equipment GP margin (%) 31.3 30.0 26.2 22.3 21.0 21.0 21.0 21.0 LNG equipment GP margin (%) 19.5 19.9 20.0 19.6 16.0 19.0 18.7 18.4

Profit and loss (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Energy 4,268 5,372 5,422 3,397 3,241 4,700 6,768 8,460 Chemical 2,846 3,093 3,383 2,710 2,472 2,719 2,964 3,201 Other Revenue 968 1,707 2,462 2,135 2,255 2,346 2,428 2,501 Total Revenue 8,083 10,172 11,267 8,241 7,968 9,764 12,159 14,161 Other income 328 413 447 416 541 533 638 689 COGS (6,505) (8,096) (9,144) (6,709) (6,565) (8,114) (10,033) (11,715) SG&A (824) (1,067) (1,146) (1,020) (1,036) (1,299) (1,447) (1,643) Other op.expenses (136) (190) (200) (210) (243) (246) (304) (307) Operating profit 946 1,231 1,223 718 666 639 1,013 1,185 Net-interest inc./(exp.) (19) (35) (33) (37) (107) (107) (95) (83) Assoc/forex/extraord./others 0 0 0 0 (1,363) (106) 0 0 Pre-tax profit 927 1,195 1,189 681 (804) 426 918 1,102 Tax (162) (208) (148) (145) (132) (106) (233) (279) Min. int./pref. div./others (6) (8) (12) (17) 8 (2) (2) 0 Net profit (reported) 760 980 1,029 520 (929) 318 683 823 Net profit (adjusted) 760 980 1,029 520 434 424 683 823 EPS (reported)(CNY) 0.405 0.509 0.532 0.269 (0.480) 0.164 0.353 0.425 EPS (adjusted)(CNY) 0.405 0.509 0.532 0.269 0.224 0.219 0.353 0.425 EPS (adjusted fully-diluted)(CNY) 0.401 0.498 0.522 0.265 0.224 0.219 0.353 0.425 DPS (CNY) 0.070 0.120 0.195 0.100 0.000 0.064 0.140 0.173 EBIT 946 1,231 1,223 718 666 639 1,013 1,185 EBITDA 1,082 1,421 1,423 928 909 885 1,317 1,492

Cash flow (CNYm) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Profit before tax 927 1,195 1,189 681 (804) 426 918 1,102 Depreciation and amortisation 136 190 200 210 243 246 304 307 Tax paid (162) (208) (148) (145) (132) (106) (233) (279) Change in working capital (185) (202) (148) (635) 898 (910) (656) (526) Other operational CF items 141 161 (19) 554 (487) 41 27 25 Cash flow from operations 857 1,137 1,073 665 (283) (303) 360 628 Capex (556) (342) (391) (212) (234) (250) (250) (250) Net (acquisitions)/disposals (261) 0 0 (235) (50) (610) 0 0 Other investing CF items 90 29 89 (1,105) (362) 0 0 0 Cash flow from investing (726) (313) (302) (1,553) (646) (860) (250) (250) Change in debt (113) (286) (84) 929 455 0 (200) (200) Net share issues/(repurchases) 0 0 337 0 0 0 0 0 Dividends paid (112) (133) (236) (384) (196) 0 (123) (271) Other financing CF items 14 181 (198) 1,789 1,000 0 0 0 Cash flow from financing (211) (237) (180) 2,334 1,258 0 (323) (471) Forex effect/others 0 0 0 0 0 0 0 0 Change in cash (81) 586 591 1,446 329 (1,163) (213) (93) Free cash flow 301 794 683 453 (517) (553) 110 378 Source: FactSet, Daiwa forecasts

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CIMC Enric (3899 HK): 12 January 2018

Financial summary continued … Balance sheet (CNYm) As at 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Cash & short-term investment 1,010 1,676 1,795 2,697 3,181 2,123 1,911 1,818 Inventory 1,974 2,495 1,969 1,912 2,248 2,571 3,179 3,712 Accounts receivable 1,842 2,437 3,139 2,566 2,769 3,269 4,071 4,741 Other current assets 498 881 722 1,641 1,345 1,646 2,050 2,387 Total current assets 5,324 7,489 7,625 8,817 9,543 9,609 11,210 12,658 Fixed assets 1,763 2,115 2,235 2,339 2,271 3,194 3,307 3,410 Goodwill & intangibles 263 253 226 461 546 185 150 122 Other non-current assets 377 523 542 696 529 513 503 494 Total assets 7,727 10,380 10,628 12,312 12,888 13,501 15,170 16,683 Short-term debt 263 134 60 125 177 177 177 177 Accounts payable 1,351 1,857 1,860 1,813 1,966 2,336 2,888 3,373 Other current liabilities 1,501 2,605 2,136 2,480 3,593 3,610 4,215 4,745 Total current liabilities 3,115 4,596 4,056 4,418 5,736 6,123 7,281 8,295 Long-term debt 137 36 25 933 1,422 1,422 1,222 1,022 Other non-current liabilities 397 425 418 495 428 457 755 967 Total liabilities 3,649 5,057 4,499 5,847 7,586 8,002 9,258 10,284 Share capital 17 17 18 18 18 18 18 18 Reserves/R.E./others 4,035 5,272 6,065 6,294 5,141 5,336 5,748 6,236 Shareholders' equity 4,052 5,289 6,083 6,312 5,159 5,353 5,765 6,254 Minority interests 26 34 46 153 143 145 147 146 Total equity & liabilities 7,727 10,380 10,627 12,312 12,888 13,501 15,170 16,683 EV 11,242 10,352 10,159 10,337 10,382 11,447 11,462 11,354 Net debt/(cash) (610) (1,505) (1,709) (1,639) (1,582) (524) (512) (619) BVPS (CNY) 2.162 2.749 3.146 3.264 2.664 2.765 2.977 3.229

Key ratios (%) Year to 31 Dec 2012 2013 2014 2015 2016 2017E 2018E 2019E Sales (YoY) 18.4 25.8 10.8 (26.9) (3.3) 22.5 24.5 16.5 EBITDA (YoY) 26.7 31.3 0.2 (34.8) (2.1) (2.6) 48.9 13.3 Operating profit (YoY) 28.0 30.1 (0.6) (41.3) (7.3) (4.0) 58.5 17.0 Net profit (YoY) 33.0 28.9 5.1 (49.5) (16.4) (2.4) 61.2 20.5 Core EPS (fully-diluted) (YoY) 31.4 24.1 4.9 (49.2) (15.5) (2.4) 61.2 20.5 Gross-profit margin 19.5 20.4 18.8 18.6 17.6 16.9 17.5 17.3 EBITDA margin 13.4 14.0 12.6 11.3 11.4 9.1 10.8 10.5 Operating-profit margin 11.7 12.1 10.9 8.7 8.4 6.5 8.3 8.4 Net profit margin 9.4 9.6 9.1 6.3 5.4 4.3 5.6 5.8 ROAE 20.4 21.0 18.1 8.4 7.6 8.1 12.3 13.7 ROAA 10.5 10.8 9.8 4.5 3.4 3.2 4.8 5.2 ROCE 22.5 24.7 20.9 10.5 9.2 9.1 14.1 15.9 ROIC 24.7 27.9 26.0 12.2 15.6 11.0 14.6 15.8 Net debt to equity n.a. n.a. n.a. n.a. n.a. n.a. n.a. n.a. Effective tax rate 17.4 17.4 12.5 21.3 n.a. 25.0 25.4 25.4 Accounts receivable (days) 72.2 76.8 90.3 126.3 122.2 112.9 110.2 113.6 Current ratio (x) 1.7 1.6 1.9 2.0 1.7 1.6 1.5 1.5 Net interest cover (x) 50.1 35.0 36.5 19.5 6.2 6.0 10.7 14.3 Net dividend payout 17.3 23.6 36.6 37.2 n.a. 38.7 39.7 40.7 Free cash flow yield 2.5 6.7 5.8 3.8 n.a. n.a. 0.9 3.2 Source: FactSet, Daiwa forecasts

Company profile

CIMC Enric has a c.50% share of the CNG/LNG equipment market in China. In our view, it is well positioned for the volume growth of the natural gas vehicles (NGV) market and city-gas storage infrastructure in China. The company also has chemical container tank and liquid food equipment businesses serving the overseas market.

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China Gas: 12 January 2018 CIMC Enric (3899 HK): 12 January 2018

Daiwa’s Asia Pacific Research Directory

HONG KONG SOUTH KOREA Takashi FUJIKURA (852) 2848 4051 [email protected] Sung Yop CHUNG (82) 2 787 9157 [email protected] Regional Research Head Pan-Asia Co-head/Regional Head of Automobiles and Components; Automobiles; Jiro IOKIBE (852) 2773 8702 [email protected] Shipbuilding; Steel Co-head of Asia Pacific Research Mike OH (82) 2 787 9179 [email protected] John HETHERINGTON (852) 2773 8787 [email protected] Banking; Capital Goods (Construction and Machinery) Co-head of Asia Pacific Research Iris PARK (82) 2 787 9165 [email protected] Craig CORK (852) 2848 4463 [email protected] Consumer/Retail Regional Head of Asia Pacific Product Management SK KIM (82) 2 787 9173 [email protected] Paul M. KITNEY (852) 2848 4947 [email protected] IT/Electronics – Semiconductor/Display and Tech Hardware Chief Strategist for Asia Pacific; Strategy (Regional) Thomas Y KWON (82) 2 787 9181 [email protected] Kevin LAI (852) 2848 4926 [email protected] Pan-Asia Head of Internet & Telecommunications; Software – Internet/On-line Games Chief Economist for Asia ex-Japan; Macro Economics (Regional) Olivia XIA (852) 2773 8736 [email protected] TAIWAN Macro Economics (Hong Kong/China) Rick HSU (886) 2 8758 6261 [email protected] Kelvin LAU (852) 2848 4467 [email protected] Head of Regional Technology; Head of Taiwan Research; Semiconductor/IC Design (Regional) Head of Automobiles; Transportation and Industrial (Hong Kong/China) Nora HOU (886) 2 8758 6249 [email protected] Leon QI (852) 2532 4381 [email protected] Banking; Diversified financials; Insurance Regional Head of Financials; Banking; Diversified financials; Insurance (Hong Kong/China) Steven TSENG (886) 2 8758 6252 [email protected] Yan LI (852) 2773 8822 [email protected] IT/Technology Hardware (PC Hardware) Banking (China) Kylie HUANG (886) 2 8758 6248 [email protected] Anson CHAN (852) 2532 4350 [email protected] IT/Technology Hardware (Handsets and Components) Consumer (Hong Kong/China) Helen CHIEN (886) 2 8758 6254 [email protected] Adrian CHAN (852) 2848 4427 [email protected] Small/Mid Cap Consumer (Hong Kong/China) Jamie SOO (852) 2773 8529 [email protected] INDIA Punit SRIVASTAVA (91) 22 6622 1013 [email protected] Gaming and Leisure (Hong Kong/China) John CHOI (852) 2773 8730 [email protected] Head of India Research; Strategy; Banking/Finance Saurabh MEHTA (91) 22 6622 1009 [email protected] Head of Hong Kong and China Internet; Regional Head of Small/Mid Cap Alex LIU (852) 2848 4976 [email protected] Capital Goods; Utilities

Internet (Hong Kong/China) SINGAPORE Carlton LAI (852) 2532 4349 [email protected] Ramakrishna MARUVADA (65) 6228 6742 [email protected] Small/Mid Cap (Hong Kong/China) Head of Singapore Research; Telecommunications (China/ASEAN/India) Dennis IP (852) 2848 4068 [email protected] David LUM (65) 6228 6740 [email protected] Regional Head of Power, Utilities, Renewable and Environment (PURE); PURE (Hong Kong/China) Banking; Property and REITs Daniel YANG (852) 2848 4443 [email protected] Royston TAN (65) 6228 6745 [email protected] Power, Utilities, Renewable and Environment (PURE) – Solar and Nuclear (China) Oil and Gas; Capital Goods Jonas KAN (852) 2848 4439 [email protected] Jame OSMAN (65) 6228 6744 [email protected] Head of Hong Kong and China Property Transportation – Road and Rail; Pharmaceuticals and Healthcare; Consumer (Singapore) Cynthia CHAN (852) 2773 8243 [email protected]

Property (China) JAPAN Michelle WANG (852) 2773 8842 [email protected] Yukino YAMADA (81) 3 5555 7295 [email protected] Transportation – Industrial and Logistics (China) Strategy (Regional) Fiona LIANG (852) 2532 4341 [email protected] Transportation – Railway; Construction and Engineering (China) Thomas HO (852) 2773 8716 [email protected] Custom Products Group

PHILIPPINES Micaela ABAQUITA (63) 2 737 3021 [email protected] Property Gregg Ilag (63) 2 737 3023 [email protected] Utilities; Energy

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China Gas: 12 January 2018 CIMC Enric (3899 HK): 12 January 2018

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DAIWA INSTITUTE OF RESEARCH LTD HEAD OFFICE 15-6, Fuyuki, Koto-ku, Tokyo, 135-8460, Japan (81) 3 5620 5100 (81) 3 5620 5603 MARUNOUCHI OFFICE Gran Tokyo North Tower, 1-9-1, Marunouchi, Chiyoda-ku, Tokyo, 100-6756 (81) 3 5555 7011 (81) 3 5202 2021

New York Research Center 11th Floor, Financial Square, 32 Old Slip, NY, NY 10005-3504, U.S.A. (1) 212 612 6100 (1) 212 612 8417 London Research Centre 3/F, 5 King William Street, London, EC4N 7AX, United Kingdom (44) 207 597 8000 (44) 207 597 8550

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Important Disclosures and Disclaimer

This publication is produced by Daiwa Securities Group Inc. and/or its non-U.S. affiliates, and distributed by Daiwa Securities Group Inc. and/or its non-U.S. affiliates, except to the extent expressly provided herein. This publication and the contents hereof are intended for information purposes only, and may be subject to change without further notice. Any use, disclosure, distribution, dissemination, copying, printing or reliance on this publication for any other purpose without our prior consent or approval is strictly prohibited. Neither Daiwa Securities Group Inc. nor any of its respective parent, holding, subsidiaries or affiliates, nor any of its respective directors, officers, servants and employees, represent nor warrant the accuracy or completeness of the information contained herein or as to the existence of other facts which might be significant, and will not accept any responsibility or liability whatsoever for any use of or reliance upon this publication or any of the contents hereof. Neither this publication, nor any content hereof, constitute, or are to be construed as, an offer or solicitation of an offer to buy or sell any of the securities or investments mentioned herein in any country or jurisdiction nor, unless expressly provided, any recommendation or investment opinion or advice. Any view, recommendation, opinion or advice expressed in this publication may not necessarily reflect those of Daiwa Securities Group Inc., and/or its affiliates nor any of its respective directors, officers, servants and employees except where the publication states otherwise. This research report is not to be relied upon by any person in making any investment decision or otherwise advising with respect to, or dealing in, the securities mentioned, as it does not take into account the specific investment objectives, financial situation and particular needs of any person. Daiwa Securities Group Inc., its subsidiaries or affiliates, or its or their respective directors, officers and employees from time to time have trades as principals, or have positions in, or have other interests in the securities of the company under research including market making activities, derivatives in respect of such securities or may have also performed investment banking and other services for the issuer of such securities. Daiwa Securities Group Inc., its subsidiaries or affiliates do and seek to do business with the company(s) covered in this research report. Therefore, investors should be aware that a conflict of interest may exist. The following are additional disclosures.

Ownership of Securities For “Ownership of Securities” information, please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. Investment Banking Relationship For “Investment Banking Relationship”, please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action.

Japan Daiwa Securities Co. Ltd. and Daiwa Securities Group Inc. Daiwa Securities Co. Ltd. is a subsidiary of Daiwa Securities Group Inc. Investment Banking Relationship Within the preceding 12 months, the subsidiaries and/or affiliates of Daiwa Securities Group Inc. * has lead-managed public offerings and/or secondary offerings (excluding straight bonds) of the securities of the following companies: No Va Land Investment Group Corporation (NVL VN), PT Totalindo Eka Persada Tbk (TOPS IJ), PT Integra Indocabinet Tbk (WOOD IJ), PT Buyung Putera Sembada (HOKI IJ), Cromwell European REIT (CERT_SP). *Subsidiaries of Daiwa Securities Group Inc. for the purposes of this section shall mean any one or more of: Daiwa Capital Markets Hong Kong Limited (大和資本市場香港有限公司), Daiwa Capital Markets Singapore Limited, Daiwa Capital Markets Australia Limited, Daiwa Capital Markets India Private Limited, Daiwa-Cathay Capital Markets Co., Ltd., Daiwa Securities Capital Markets Korea Co., Ltd.

Hong Kong This research is distributed in Hong Kong by Daiwa Capital Markets Hong Kong Limited (大和資本市場香港有限公司) (“DHK”) which is regulated by the Hong Kong Securities and Futures Commission. Recipients of this research in Hong Kong may contact DHK in respect of any matter arising from or in connection with this research.

Relevant Relationship (DHK) DHK may from time to time have an individual employed by or associated with it serves as an officer of any of the companies under its research coverage.

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Australia This research is distributed in Australia by Daiwa Capital Markets Australia Limited and it may only be distributed in Australia to wholesale investors within the meaning of the Corporations Act. Recipients of this research in Australia may contact Daiwa Capital Markets Stockbroking Limited in respect of any matter arising from or in connection with the research.

India This research is distributed in India to Institutional Clients only by Daiwa Capital Markets India Private Limited (Daiwa India) which is an intermediary registered with Securities & Exchange Board of India as a Stock Broker, Merchant Bank and Research Analyst. Daiwa India, its Research Analyst and their family members and its associates do not have any financial interest save as disclosed or other undisclosed material conflict of interest in the securities or derivatives of any companies under coverage. Daiwa India and its associates, may have received compensation for any products other than Investment Banking (as disclosed)or brokerage services from the subject company in this report or from any third party during the past 12 months. Daiwa India and its associates may have debt holdings in the subject company. For information on ownership of equity, please visit BlueMatrix disclosure Link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. There is no material disciplinary action against Daiwa India by any regulatory authority impacting equity research analysis activities as of the date of this report. Associates of Daiwa India, registered with Indian regulators, include Daiwa Capital Markets Singapore Limited and Daiwa Portfolio Advisory (India) Private Limited.

Taiwan This research is solely for reference and not intended to provide tailored investment recommendations. This research is distributed in Taiwan by Daiwa-Cathay Capital Markets Co., Ltd. and it may only be distributed in Taiwan to specific customers who have signed recommendation contracts with Daiwa-Cathay Capital Markets Co., Ltd. and non-customers including (i) professional institutional investors, (ii) TWSE or TPEx listed companies, upstream and downstream vendors, and specialists that offer or seek advice, and (iii) potential customers with an actual need for business development in accordance with the Operational Regulations Governing Securities Firms Recommending Trades in Securities to Customers. Recipients of this research including non-customer recipients of this research shall not provide it to others or engage in any activities in connection with this research which may involve conflicts of interests. Neither Daiwa-Cathay Capital Markets Co., Ltd. nor its personnel who writes or reviews the research report has any conflict of interest in this research. Since Daiwa-Cathay Capital Markets Co., Ltd. does not operate brokerage trading business in foreign markets, this research is prepared on a “without recommendation” to any foreign securities basis and Daiwa-Cathay Capital Markets Co., Ltd. does not accept orders from customers to trade in such foreign securities that are without recommendation. Recipients of this research in Taiwan may contact Daiwa-Cathay Capital Markets Co., Ltd. in respect of any matter arising from or in connection with the research.

Philippines This research is distributed in the Philippines by DBP-Daiwa Capital Markets Philippines, Inc. which is regulated by the Philippines Securities and Exchange Commission and the Philippines Stock Exchange, Inc. Recipients of this research in the Philippines may contact DBP-Daiwa Capital Markets Philippines, Inc. in respect of any matter arising from or in connection with the research. DBP-Daiwa Capital Markets Philippines, Inc. recommends that investors independently assess, with a professional advisor, the specific financial risks as well as the legal, regulatory, tax, accounting, and other consequences of a proposed transaction. DBP-Daiwa Capital Markets Philippines, Inc. may have positions or may be materially interested in the securities in any of the markets mentioned in the publication or may have performed other services for the issuers of such securities. For relevant securities and trading rules please visit SEC and PSE links at http://www.sec.gov.ph and http://www.pse.com.ph/ respectively.

Thailand This research is distributed to only institutional investors in Thailand primarily by Thanachart Securities Public Company Limited (“TNS”). This report is prepared by analysts who are employed by Daiwa Securities Group Inc. and/or its non-U.S. affiliates. This report is provided to you for informational purposes only and it is not, and is not to be construed as, an offer or an invitation to make an offer to sell or buy any securities. Neither TNS, Daiwa Securities Group Inc. nor any of their respective parent, holding, subsidiaries or affiliates, nor any of their respective directors, officers, servants and employees accept any liability whatsoever for any direct or consequential loss arising from any use of this research or its contents. The information and opinions contained herein have been compiled or arrived at from sources believed to be reliable. However, TNS, Daiwa Securities Group Inc. nor any of their respective parent, holding, subsidiaries or affiliates, nor any of their respective directors, officers, servants and employees make no representation or warranty, express or implied, as to their accuracy or completeness. Expressions of opinion herein are subject to change without notice. The use of any information, forecasts and opinions contained in this report shall be at the sole discretion and risk of the user. TNS, Daiwa Securities Group Inc., their respective parent, holding, subsidiaries or affiliates, their respective directors, officers, servants and employees may have positions and financial interest in securities mentioned in this research. Thanachart Securities Public Company Limited, Daiwa Securities Group Inc., their respective parent, holding, subsidiaries or affiliates may from time to time perform investment banking or other services for, or solicit investment banking or other business from, any entity mentioned in this research. Therefore, investors should be aware of conflict of interest that may affect the objectivity of this research.

United Kingdom This research report is produced by Daiwa Securities Co. Ltd. and/or its affiliates and is distributed in the European Union, Iceland, Liechtenstein, Norway and Switzerland. Daiwa Capital

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Markets Europe Limited is authorised and regulated by The Financial Conduct Authority (“FCA”) and is a member of the London Stock Exchange and Eurex. This publication is intended for investors who are not Retail Clients in the United Kingdom within the meaning of the Rules of the FCA and should not therefore be distributed to such Retail Clients in the United Kingdom. Should you enter into investment business with Daiwa Capital Markets Europe’s affiliates outside the United Kingdom, we are obliged to advise that the protection afforded by the United Kingdom regulatory system may not apply; in particular, the benefits of the Financial Services Compensation Scheme may not be available.

Daiwa Capital Markets Europe Limited has in place organisational arrangements for the prevention and avoidance of conflicts of interest. Our conflict management policy is available at http://www.uk.daiwacm.com/about-us/corporate-governance-regulatory.

Germany This document is distributed in Germany by Daiwa Capital Markets Europe Limited, Niederlassung Frankfurt which is regulated by BaFin (Bundesanstalt fuer Finanzdienstleistungsaufsicht) for the conduct of business in Germany.

Bahrain This research material is distributed in Bahrain by Daiwa Capital Markets Europe Limited, Bahrain Branch, regulated by The Central Bank of Bahrain and holds Investment Business Firm – Category 2 license and having its official place of business at the Bahrain World Trade Centre, South Tower, 7th floor, P.O. Box 30069, Manama, Kingdom of Bahrain. Tel No. +973 17534452 Fax No. +973 535113

United States This research is distributed into the United States directly by Daiwa Capital Markets Hong Kong Limited and indirectly by Daiwa Capital Markets America Inc. (DCMA), a U.S. Securities and Exchange Commission registered broker-dealer and FINRA member firm, exclusively to “major U.S. institutional investors”, as defined under Rule 15a-6 promulgated under the U.S. Securities Exchange Act of 1934, as amended, and as interpreted by the staff of the U.S. Securities and Exchange Commission (SEC). This report is not an offer to sell or the solicitation of any offer to buy securities. U.S. customers wishing to effect transactions in any designated investment discussed in this report should do so through a qualified salesperson of DCMA. Non-U.S. customers wishing to effect transactions in any designated investment discussed in this report should contact a Daiwa entity in their local jurisdiction. The securities or other investment products discussed in this report may not be eligible for sale in some jurisdictions. Analysts employed outside the U.S., as specifically indicated elsewhere in this report, are not registered as research analysts with FINRA. These analysts may not be associated persons of DCMA, and therefore may not be subject to FINRA Rule 2241 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account. ADDITIONAL IMPORTANT DISCLOSURES CAN BE FOUND AT: https://daiwa3.bluematrix.com/sellside/Disclosures.action

Ownership of Securities For “Ownership of Securities” information please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. Investment Banking Relationships For “Investment Banking Relationships” please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. DCMA Market Making For “DCMA Market Making” please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action.

Research Analyst Conflicts For updates on “Research Analyst Conflicts” please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. The principal research analysts who prepared this report have no financial interest in securities of the issuers covered in the report, are not (nor are any members of their household) an officer, director or advisory board member of the issuer(s) covered in the report, and are not aware of any material relevant conflict of interest involving the analyst or DCMA, and did not receive any compensation from the issuer during the past 12 months except as noted: no exceptions.

Research Analyst Certification For updates on “Research Analyst Certification” and “Rating System” please visit BlueMatrix disclosure link at https://daiwa3.bluematrix.com/sellside/Disclosures.action. The views about any and all of the subject securities and issuers expressed in this Research Report accurately reflect the personal views of the research analyst(s) primarily responsible for this report (or the views of the firm producing the report if no individual analyst is named on the report); and no part of the compensation of such analyst (or no part of the compensation of the firm if no individual analyst is named on the report) was, is, or will be directly or indirectly related to the specific recommendations or views contained in this Research Report.

The following explains the rating system in the report as compared to relevant local indices, unless otherwise stated, based on the beliefs of the author of the report. "1": the security could outperform the local index by more than 15% over the next 12 months. "2": the security is expected to outperform the local index by 5-15% over the next 12 months. "3": the security is expected to perform within 5% of the local index (better or worse) over the next 12 months. "4": the security is expected to underperform the local index by 5-15% over the next 12 months. "5": the security could underperform the local index by more than 15% over the next 12 months.

Disclosure of investment ratings Rating Percentage of total Buy* 67.3% Hold** 20.9% Sell*** 11.7% Source: Daiwa Notes: data is for single-branded Daiwa research in Asia (ex Japan) and correct as of 31 December 2017. * comprised of Daiwa’s Buy and Outperform ratings. ** comprised of Daiwa’s Hold ratings. *** comprised of Daiwa’s Underperform and Sell ratings.

Additional information may be available upon request.

Japan - additional notification items pursuant to Article 37 of the Financial Instruments and Exchange Law (This Notification is only applicable where report is distributed by Daiwa Securities Co. Ltd.)

If you decide to enter into a business arrangement with us based on the information described in materials presented along with this document, we ask you to pay close attention to the following items.  In addition to the purchase price of a financial instrument, we will collect a trading commission* for each transaction as agreed beforehand with you. Since commissions may be included in the purchase price or may not be charged for certain transactions, we recommend that you confirm the commission for each transaction.  In some cases, we may also charge a maximum of ¥ 2 million (including tax) per year as a standing proxy fee for our deposit of your securities, if you are a non-resident of Japan.  For derivative and margin transactions etc., we may require collateral or margin requirements in accordance with an agreement made beforehand with you. Ordinarily in such cases, the amount of the transaction will be in excess of the required collateral or margin requirements.  There is a risk that you will incur losses on your transactions due to changes in the market price of financial instruments based on fluctuations in interest rates, exchange rates, stock prices, real estate prices, commodity prices, and others. In addition, depending on the content of the transaction, the loss could exceed the amount of the collateral or margin requirements.  There may be a difference between bid price etc. and ask price etc. of OTC derivatives handled by us.  Before engaging in any trading, please thoroughly confirm accounting and tax treatments regarding your trading in financial instruments with such experts as certified public accountants. *The amount of the trading commission cannot be stated here in advance because it will be determined between our company and you based on current market conditions and the content of each transaction etc.

When making an actual transaction, please be sure to carefully read the materials presented to you prior to the execution of agreement, and to take responsibility for your own decisions regarding the signing of the agreement with us.

Corporate Name: Daiwa Securities Co. Ltd. Financial instruments firm: chief of Kanto Local Finance Bureau (Kin-sho) No.108 Memberships: Japan Securities Dealers Association, The Financial Futures Association of Japan Japan Securities Investment Advisers Association Type II Financial Instruments Firms Association

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