According to BP's Energy Outlook 2035, China will become the world's largest energy importer by 2035, overtaking Europe in terms of its energy imports. China's projected growth in demand for energy supplies, its plans to embrace cleaner and more efficient energy sources, and developments in the liquefied natural gas (LNG) and gas global markets provide a strong basis for the view that there is considerable scope for increase in its natural gas consumption. It is also likely that such increase in consumption will be met by a growing volume of natural gas imports. As a general overview, this article discusses the current state of China's consumption and importation of natural gas, the supply and pricing factors affecting such imports, and the potential for growth in imports as well as the extent to which such imports will be supplied by LNG and pipeline gas quantities respectively.
Natural Gas Consumption and Importation
Presently, coal supplies the vast majority of China's energy consumption, with such fuel source supplying over 65% of its energy demand in recent years. As for natural gas, this currently supplies a significantly smaller fraction of China's total energy needs, being approximately 5% of China's energy primary sources in 2013. However, it is worth noting that the size of the Chinese gas market means that even with such a small fraction of energy demand being met by natural gas, China is already the world's third largest gas consumer and its natural gas consumption in 2013 was approximately 160 billion cubic metres (BCM). Furthermore, China's natural gas consumption has been continually increasing in recent years. In 2013, consumption increased by approximately 12% and it is projected to increase over 10% by the end of this year. As shown by the chart below, there has been a widening gap between domestic production and growing gas demand, resulting in total imports increasing to around 52 BCM and import dependence rising to around 30% in 2013.
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Source: BP Statistical Review of World Energy
Imports – Pipeline Gas and LNG
Unlike other major LNG consuming markets in North Asia (i.e., Japan, Korea and Taiwan), China is also able to import substantial quantities of natural gas through pipelines, namely, pipeline connections originating from Central Asia and Myanmar and in future, following the signing of the China National Petroleum Corporation (CNPC) Gazprom contract, Russia's Siberian gas fields. Since China became an importer of LNG in 2006 and pipeline gas in 2010, both types of imports have grown steadily. In 2013, China's imports of pipeline gas and LNG were roughly even being equal to 27.4 BCM and 24.5 BCM respectively or 53% and 47% respectively of aggregate imports.
(1) LNG Import Quantities
At present, China has 10 major LNG receiving terminals in operation, namely, the Guangdong Dapeng, Fujian, Shanghai, Zhejiang, Zhuhai, Tianjin FSRU, Jiangsu Rudong, Dalian, Tangshan and Hainan receiving terminals. Together these terminals have a regasification capacity of about 35 MTPA. In 2013, China's largest LNG suppliers were Qatar, Australia, Malaysia and Indonesia. Set out below is the breakdown of LNG imports supplied from various countries in 2013.
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Source: China's maritime customs data
Based on recent upstream interests acquisitions and LNG sale and purchase agreements (SPAs), there is significant potential for increased LNG imports to China. Since 2010, Chinese companies have reportedly spent up to US$ 8.5 billion on unconventional oil and gas projects in the United States. In particular, there have been recently a number of high profile LNG-related investments and LNG SPA signings by Chinese corporations, for instance, as set out below:
Sinopec's acquisition in 2014 of a 15% stake in the Pacific Northwest LNG project in British Columbia, Canada, together with its signing of a 20 year contract to take 1.8 million tonnes annually of LNG from the project.
CNOOC's US$ 18 billion acquisition in 2013 of Nexen, a Calgary based company that has large oil sand and shale gas reserves in western Canada, part of which is earmarked for overseas exports through the Aurora LNG export project.
CNOOC's US$ 1.93 billion acquisition in 2013 of additional interests from the BG Group of the Queensland Curtis LNG project in Australia and under a separate agreement CNOOC's purchase of an additional 5 MTPA of LNG for 20 years from BG Group.
CNPC's US$ 4.2 billion acquisition in 2013 of a 20% working interest in Mozambique Area 4 (which may form part of the supply source for East Africa's first LNG export project) from Eni.
CNPC's acquisition in 2013 of a 20% stake in OAO Gazprom - Novatek's $20 billion Yamal LNG project from which CNPC will receive long-term supplies.
Furthermore, there has been a clear trend of an increasing number of LNG import terminals in China. Currently, there are a number of LNG terminal projects in China under construction (e.g., the Qingdao, Shenzhen and Guangxi terminals) or proposed to be constructed, and these projects once completed are expected to substantially increase China's aggregate LNG receiving and regasification capacity. According to the U.S. Energy Information Administration, China's import regasification capacity is set to increase by another 20 BCM by 2016, increasing its present regasification capacity by nearly 50%.
(2) Pipeline Import Quantities
At present, China receives pipeline gas supplies from Central Asia and Myanmar. Originating from Turkmenistan, the Central Asia Gas pipeline (CAGP) has presently a total of 3 lines – these are, namely, Lines A and B that have a total capacity of 30 BCM, and Line C that was commissioned this year and which is expected to have a total capacity of 25 BCM by 2015. As for the Sino-Myanmar pipeline, this has a total capacity of 12 BCM per annum. Without taking into account Line C of the CAPG which has not yet reached full capacity, China's international pipeline capacity is currently at least 42 BCM. In terms of pipeline gas supply, Turkmenistan was in 2013 by far the largest supplier to China, with gas supplies coming from the Bagtyyarlyk field. Set out below is the breakdown of pipeline imports supplied from various countries in 2013.
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Source: China's maritime customs data
Given the potentially rich gas resources of China's current and future pipeline gas suppliers (e.g., Turkmenistan and Russia), there is significant potential for additional pipeline gas supplies. Most notably, Gazprom has recently signed in May this year a US$ 400 billion agreement with CNPC to supply 38 BCM of natural gas a year with supplies commencing in 2018 and for a 30 year term. Apart from the CNPC Gazprom agreement, there are also a number of other indications which signal that China will significantly expand its pipeline imports:
The new investment by CNPC in Galkynysh gas field, and the gas supply agreement signed between CNPC and TurkmenGas for 25 BCM of gas per year. By 2020, this would raise planned imports from the Central Asian country to 65 BCM per year, with such additional gas imports being supplied from the Galkynysh field.
China's plans to expand both the CAGP and also the China's West-East pipelines which transport gas from Central Asia and Xinjiang to the demand centres in China's North-east. By 2015, the expansions of the CAGP will raise pipeline capacity to at least 55 BCM per year. As for China's West-East pipelines (currently two), these will be expanded to a third pipeline set to be operational by 2015 and there are already proposals to construct the fourth and fifth pipelines.
While gas imports from Myanmar last year only amounted to approximately 2 BCM, Chinese gas imports from Myanmar are expected to reach at least 10 BCM per annum, which is still well within the 12 BCM per annum throughput capacity of the Sino-Myanmar pipeline.
Uzbekistan gas exports to China are also expected to increase over time, and under a framework agreement signed between CNPC and Uzbekneftegaz, Uzbekistan is reportedly expected to increase gas exports to China to at least 10 BCM per annum over the coming years.
Pricing – Pipeline Gas and LNG
(1) LNG Pricing
In 2013, the average price of LNG imports into China was reportedly US$ 13.8 per MMBtu. The cheapest LNG cargoes were Australian and Indonesian LNG cargoes with an average price of US$ 3 to 4 per MMBtu. In contrast, the average price of cargoes from Qatar (which was China's biggest LNG supplier in 2013) was US$ 17.32 per MMBtu. In this respect, one reason for the pricing divergence is that Australian and Indonesian LNG are likely supplied under earlier and more advantageously priced long-term SPAs (i.e., supplies from the Australian North West Shelf project and the Indonesian Tangguh projects).
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Source: China's maritime customs data
(2) Pipeline Gas Pricing
In 2013, China received pipeline gas imports at an average price of US$ 9.78 per MMBtu. Leaving aside Kazakhstan (which constituted less than one percent of overall pipeline supply to China), the average pricing for pipeline imports into China, as compared to LNG imports, fell within a much narrower range (i.e., US$ 8.63 per MMBtu for Uzbekistan gas, US$ 9.94 per MMBtu for Turkmenistan gas, and US$ 11.68 per MMBtu for Myanmar gas). The graph below sets out the breakdown of prices for China's pipeline gas imports in 2013:
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Source: China's maritime customs data
As can be seen from the charts above, based on the average 2013 pricing, pipeline imports enjoy an approximate US$ 4 per MMBtu price advantage over LNG imports. In this respect, the pricing agreed under the recent CNPC Gazprom deal is reportedly around US$ 10 per MMBtu, which is still cheaper than the 2013 average price of LNG imports to China. Apart from the significant capital investment for developing LNG projects, one reason for the relatively higher price of LNG is the "Asian Premium" paid by North Asian LNG buyers. Due to the lack of alternative energy sources, the Japan-Korea-Taiwan markets have traditionally been seen as more willing to pay a higher price for LNG cargoes. As Chinese importers are competing for LNG supplies in the same market, they consequently pay for LNG at largely similar prices.
In assessing the overall price difference between pipeline gas and LNG imports, one important factor to consider relates to costs involved in transporting pipeline gas from the border regions (e.g., north-western China) to the major gas consuming cities in the north-eastern regions. Taking gas imports from Turkmenistan as an example, if we assume that the pipeline transportation tariff for such gas is approximately US$ 3-4 per MMBtu and that the regasification costs for LNG delivered at China's LNG terminals (which mostly are located relatively proximate to the major gas consuming regions (e.g., Guangdong, Pearl Delta and Yangtze Delta)) are approximately US$ 1 per MMBtu, then the final price difference between the delivered cost of Turkmen pipeline gas and LNG imports (after regasification) could potentially narrow to US$ 1-2 per MMBtu. In this connection, the overall transportation tariffs which will be paid for gas delivered under the Gazprom CNPC agreement is likely to be less (compared to gas delivered from Turkmenistan) as the gas will be delivered at China's northern border and hence closer to cities in China's north east, but such tariffs will nonetheless impact on the final delivered cost. In any case, although the delivered cost of pipeline gas is still cheaper than LNG at current day prices, the effect of transportation tariffs is still one factor to be taken into account in assessing the actual cost difference between LNG and pipeline gas imports.
Demand for Natural Gas Imports
In the near term, natural gas imports into China are likely to continue to rise, particularly in view of growing natural gas demand. According to China's National Development and Reform Committee (NDRC), the natural gas market will by 2020 reach 400 BCM, which is more than double the present consumption of natural gas. For various reasons discussed below, there are considerable difficulties for China's domestic gas production to be able to fully satisfy the future quantities required by the country. More generally, the demand for gas imports will be affected by a number of different factors which are further discussed below.
(1) Governmental Policy and Environmental Concerns
Given that key aspects of China's economy are influenced by central planning directions and that state owned enterprises continue to play a significant role in the energy sector, the importance of the government's energy policy with respect to future gas imports cannot be understated. In China's Twelfth Five Year Plan (2011-2015), one of the key socio-economic objectives is to significantly reduce environmental pollution, in particular, with a target for an 8 percent reduction in sulphur dioxide emissions and 10 percent reduction in nitrogen oxide emissions by 2015. This goal is largely driven by the serious air pollution issues, which have been worsening over recent years. To meet such emissions reduction targets, the Chinese government plans to significantly increase the consumption of natural gas (being the cleanest burning fossil fuel) as well as renewable energy. China's Natural Gas Development Plan expects that natural gas consumption will increase by an average of 20 BCM per year up to 2015.
Consistent with the stated policy of the government to reduce pollution emissions, there is a move towards increasing the electricity volumes generated by natural gas and reducing reliance on coal for electricity generation. Based on a recent announcement by the National Energy Agency (NEA), the government will prohibit the construction of new captive coal power plants in the Beijing-Tianjin-Hebei area, the Yangzi River Delta and the Pearl River Delta, and except for cogeneration plants, cease approvals for new-build coal fired power stations in such areas. There are also plans to increase electricity generated from natural gas to 56,000 MW by 2015, representing a 53% increase from electricity generated from natural gas in 2010. Given that the current capacity for gas-fired power generation in China is about 43,090 MW, such targeted output is not far off from being met next year. Even though coal will likely remain the predominant fuel source of electrical generation in the foreseeable future, this trend of increasing the usage of natural gas quantities for electrical generation will provide an important boost to raising the levels of natural gas import and consumption over the coming years.
The pricing issues relating to natural gas form another set of important factors affecting the level of end user consumption in China and hence its demand for natural gas imports:
Particularly from a longer term perspective, the pricing of imported natural gas (which in 2013 stood at an average of US$ 13.8 per MMBtu for LNG and US$ 9.78 per MMBtu for piped natural gas) is likely to have an important impact on the extent of its demand, especially when considering the significantly lower prices of coal. In this respect, it has reported that the Guangdong prices of base and incremental gas volumes (in terms of electricity generation) are RMB 0.97 per KwH and RMB 1.17 per KwH respectively, whereas the corresponding cost of coal is only RMB 0.3 per KwH. Even taking into account the higher environmental costs of coal generation, gas-fired electrical generation is still more expensive by RMB 0.2 per KwH to RMB 0.3 per KwH. Given the cost differential between natural gas and coal, the higher pricing of imported natural gas may serve to constrain the scale of future pipeline and LNG imports into China, especially in the longer term.
Another key factor to consider is the domestic pricing of natural gas within the Chinese market. The wholesale pricing of natural gas has been traditionally regulated by the government, and such regulation has caused losses for Chinese gas importing companies arising from selling imported natural gas at lower domestic rates (particularly for residential users). When releasing its 2013 financial results, the state-owned Petro-China revealed that it lost RMB 49 billion (US$ 7.9 billion) last year from importing natural gas and selling it at lower domestic prices. In this respect, it should be noted that there is considerable disparity between the prices paid by different classes of gas users with the lowest prices being paid by residential users – for instance, based on 2011 data of end-user gas prices, residential users in Beijing paid nearly US$ 3.50 per MMBtu less compared to users in the industrial and public services sectors, and over US$ 11 per MMBtu less compared to users in the transportation sector. Such disparity suggests a considerable element of cross-subsidisation among the various users in order to maintain lower residential gas prices. Recently, however, China's government has taken important steps to raise gas pricing. In July 2013, the NDRC announced a price reform to the country's wholesale gas markets, which divided consumption into 2 tiers – one tier being the existing consumption as of 2012 (i.e., the base volumes), and another tier being the incremental volumes above the base consumption (i.e., the incremental volumes). Under the reform, the incremental volumes were pegged to 85% of the price of a basket of alternative fuels (consisting of 60% and 40% weightage to fuel oil and liquefied petroleum gas respectively), while the price for base volumes was to be adjusted by not more than RMB 400 per thousand cubic metres. Reportedly, the price reform resulted in an average price adjustment of 15% for all consumers (apart from the residential users who were not affected by the price reforms). Recently this year, the NDRC has further raised prices paid by non-residential users for base volumes by RMB 400 per thousand cubic metres. While there is still greater reform to be undertaken before the gas pricing can said to be fully liberalised (particularly in relation to residential users), the price reforms are nonetheless important steps towards a more market-based pricing for domestic sales of natural gas.
Apart from the wholesale pricing of natural gas in the domestic market, the pricing for electricity generated from natural gas is another important factor that would influence the demand for gas imports. In China, electricity pricing is regulated by the government. Taking into account the relatively higher costs of gas-fired power generation compared to coal-fired power generation (as mentioned above), such regulation does not allow Chinese companies to generate commercial profits through generation of electricity from natural gas without substantial government subsidies. For instance, it has said that the average power generation cost of gas in Guangdong is approximately RMB 0.81 per KwH, higher than the mandated on-grid tariff of RMB 0.74 per KwH. In recognition of the need for pricing adjustment to reflect more accurately the actual generation costs, the NDRC announced in October last year that it would raise the on-grid prices of gas generated electricity in Shanghai, Jiangsu, Zhejiang, Guangdong, Hainan, Henan, Hubei and Ningxia. Together with pricing reforms relating to domestic gas sales, there is however still a need for more widespread and fundamental electricity price reform to allow electricity prices to more fully reflect the actual cost using natural gas for electricity generation.
Notwithstanding the prices issues discussed above, it is important to note that natural gas demand is largely driven by the government's desire to utilise cleaner and more environmentally-friendly sources of energy. Taking this into account together with the fact that the China is unlikely to achieve gas self-sufficiency in the near term (for reasons discussed below), the demand for natural gas, at least in the short term, is not entirely price-sensitive nor is natural gas in this respect easily substitutable with coal – coal, although being a cheaper energy source, is one of the main contributors of air pollution in China (e.g., as a result of its usage for power generation). Additionally, while natural gas prices are unlikely to fall below domestic coal prices, one cannot rule out the possibility of natural gas pricing softening in future - for instance, due to increased LNG supplies (e.g., from the United States, Australia and East Africa) coming onto the market in the latter part of this decade, diversification of gas sources (e.g., Russian pipeline gas from eastern Siberia) and the possible development of a hub-based pricing mechanism in Asia for natural gas. Also, the imposition of a carbon tax (which has reportedly been considered by the Chinese government) would serve to narrow the pricing difference between natural gas and coal. Overall, while the resolution of pricing-related issues will have an important impact on the long term growth of China's gas market, such issues should not significantly reduce China's demand for natural gas imports in the near future. Indeed, projections for China's future gas imports generally anticipate an increase in their overall volume.
(3) Economic growth, Urbanisation and Transportation
While the Chinese economy has shown signs that the pace of economic growth is slowing down, natural gas only occupies a small portion of China's primary energy mix, which is at a level far below the world's average natural gas consumption at 23.8%. Accordingly, there is significant headroom for growth in the Chinese gas market and natural gas importation as the country progresses into a more developed economy. Such economic development has a number of positive implications for the growth in natural gas consumption and importation in China: First, developed economies have greater financial capability to bear the additional costs arising from natural gas consumption. Second, these economies usually use a greater portion of their electricity for residential and commercial purposes (as opposed to industrial uses), and such usages require a greater need for electricity peaking facilities that can be ramped up and down to accommodate fluctuations in energy demand. In turn, this is likely to translate into greater demand for natural gas as such peaking facilities often utilise natural gas as the fuel source. Third, along with the development of the economy, the scale of urbanization is only expected to increase over the coming years. Generally speaking, such urban population are expected to have better access to gas pipeline distribution networks and also the financial ability to afford the higher tariffs charged for gas-generated electricity. Apart from economic growth and urbanization factors, China is expected to soon have the world's largest fleet of natural gas vehicles as the country pushes forward its development of natural gas and LNG fuelling stations and distribution networks, and this in turn is likely to boost the demand for natural gas.
(4) Alternative Energy Sources
China has access to a wide basket of alternative energy sources including nuclear power and renewable energy sources such as wind power and hydropower. For instance, China has been assessed by the International Energy Agency (IEA) to have the largest potential amongst all countries for hydropower generation. To a certain extent, the presence of renewable energy sources may compete with the consumption of natural gas. However, it is important to bear in the mind the limitations of renewable energy and its potentially complementary relationship with natural gas. Renewable energy sources typically offer less stability than fossil fuel for power generation (e.g., hydropower generation in China is known to decline in winter until the summer rains), and gas–fired power plants are often used as peaking power facilities to avoid disruption that would otherwise occur from relying solely on renewable energy. Hence, an increased reliance on renewables for power generation may promote rather than reduce natural gas consumption.
As for nuclear power, the Chinese government (as seen from the Twelfth Five Year Plan) still foresees a significant role for it in the country's future energy mix. Nonetheless, given that most of China's nuclear power plants are already located or planned to be located near high density population centres along the eastern coast and also taking into account the concerns arising from the Fukushima incident, the government will have to balance advantages from nuclear power and corresponding safety considerations in developing its nuclear power generation facilities. In any case, the scale of China's energy demands makes it highly unlikely that any one energy source or combination thereof, whether nuclear power or renewable energy, will entirely substitute the demand for natural gas, especially when taking into account the fact the government's plans (e.g., the Twelfth Five Year Plan) to diversify China's energy supply sources.
(5) Domestic Production
China holds significant gas reserves, particularly unconventional gas reserves in the form of shale gas. There have been hopes that China would soon be able to emulate the shale gas revolution in the United States and thus reduce its import dependence for natural gas. With technically recoverable reserves estimated at 1,115 trillion cubic feet, China holds the largest shale gas reserves in the world, which is more than double that held by the United States. Given such potentially vast domestic gas supply sources, China's Natural Gas Development Plan calls for an increase in unconventional gas production, with a target of 6.5 BCM of shale gas production by 2015. By 2020, the Shale Gas Development Plan (2011-2015) targets shale gas production to increase even more substantially to 60 to 100 BCM.
Taking into account the recent announcement that China Petrochemical Corp. is planning to produce 5 BCM of shale gas a year from its Fuling site (Chongqing) by 2015, there is some anticipation that China may meet its 2015 shale gas production target. However, it seems increasingly unlikely that China will be able to meet its original 2020 shale gas production target, and the head of China's NEA has reportedly commented that China's objective now is to only produce 30 billion cubic meters of shale gas by 2020. In this connection, there are several challenges confronting the effort to substantially raise shale gas production in China. First, shale gas plays in China are typically found at a deeper depth and more mountainous terrain, and in certain cases, in more heavily populated areas, than those found in the United States. Second, there is limited pipeline infrastructure connecting shale gas fields (which are mainly located nearer to western regions) to demand centres in China's eastern cities. Third, although hydraulic fracking requires substantial amounts of water usage, there is a water shortage in the areas where shale gas reserves are found (e.g., China's Tarim basin in Xinjiang). Fourth, while Chinese companies have been active in acquiring shale gas technology overseas (e.g., North America), Chinese companies still lack appropriate fracking technology and experience, and there is a steep learning curve involved in adapting imported technology to local conditions. Fifth, there is also a need for structural reform relating to mineral rights, market pricing and the monopolistic position of the large national oil companies, for instance, with regards to the transportation pipeline network.
In any case, due to the anticipated growth in domestic natural gas demand and even assuming a substantial increase in shale gas production, neither industry observers nor the Chinese government generally expect that domestic gas production in the near future will be able to fully satisfy demand. For instance, while China's Natural Gas Development Plan targets that domestic production of natural gas will rise up to 176 billion cubic metres by 2015 (including 138.5 BCM of conventional gas production), it anticipates that China will double its gas imports during the same period.
(6) Natural Gas Infrastructure
Another factor that is important to the growth of the natural gas market is the presence of necessary infrastructure to support the receipt, storage and distribution of natural gas. Although infrastructure development is driven by the growth in consumption, the reverse is also true as such development will have a positive impact on the consumption of natural gas by expanding its availability to potential users, for example, through the wider geographical spread of the pipeline network. However, China's main pipeline and distribution pipeline systems do not presently provide sufficient coverage. As of the end of 2012, China's natural gas pipeline network was only one tenth of the pipeline network in the United States, while its natural gas consumption was already one quarter of that for the United States. Additionally, there are also the challenges of developing additional gas-fired power plants as well as storage capacity, which is particularly important given the seasonal nature of China's gas demand. Separately, the relevant regulatory regime and ownership interests governing the pipeline system also require reform, in particular, with regards to the control of the pipeline network by large Chinese oil and gas companies and the need for open and non-discriminatory access to the gas pipeline network.
In response to these infrastructural issues, the Natural Gas Development Plan targets to substantially expand relevant infrastructure and capacity, for instance, by doubling the domestic pipeline grid by 2015 and expanding the country's storage facilities for natural gas. On the regulatory front, the NEA has also recently released a new trial regulationrequiring pipeline operators with spare capacity to offer third parties the right to access their pipeline networks for transportation of natural gas. This is a significant step in a context of an industry where the majority of pipelines are owned by few vertically integrated state owned companies (in particular CNPC owns over 75% of gas pipelines in China). Overall, there is increasing emphasis on expanding the natural gas related infrastructure to cope with the expectation of rising gas demand, and such development in turn should create greater opportunities for growth in the consumption and importation of natural gas.
Projections for Growth in Natural Gas Imports
(1) Growth in Overall Imports
In general, the industry view is that China's future natural gas consumption and importation are set to grow substantially. According to certain NDRC estimates, China's gas consumption is expected to reach 400 BCM in 2020 and import dependence will at such time exceed 40%. This should translate to around 160 BCM of gas imports and 240 BCM of domestic gas production in 2020. The table below shows the potential growth of Chinese gas imports in selected years up to and including 2020:
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Sources: BP Statistical Review of World Energy June 2014 (2013 figure); CNPC Economics and Technology Research Institute (2014 figure); China's Natural Gas Development Plan (2015 figure); and NDRC projections (2020 figure).
Admittedly, projections for future Chinese gas importation vary considerably in degree, depending on projections of future Chinese gas demand (e.g., on the lower end, demand has been predicted to be only 323 BCM in 2020) and domestic production. Based on the IEA's estimates, there could be approximately a 70 BCM difference in net imports as between low and favourable unconventional production scenarios for 2020. In any case, even under the IEA's favourable unconventional production scenario, it is worth noting that estimated overall imports in 2020 would be 50% higher than present day levels. There is therefore good reason to expect that gas imports into China will continue to see significant growth over the coming years, although forecasting the exact extent remains a difficult exercise.
(2) Future LNG and Pipeline Gas Import Quantities
Assuming Chinese gas demand is 400 BCM in 2020 and total gas imports reach 160 BCM, pipeline gas is likely to form a sizable portion of Chinese natural gas imports. Under a high supply scenario for pipeline gas, assuming the full supply of gas volumes under pipeline supply agreements for supply into China, the aggregate pipeline imports could reach as high as around 120 BCM or about 75% of total gas imports in 2020. Under this scenario, Chinese LNG imports in 2020 would be around 40 BCM (i.e., the total estimated import volume of 160 BCM less 120 BCM of pipeline gas supply) or about 25% of total imports. However, due to the fact that the pipeline supply volumes (e.g., under the CNPC Gazprom contract) may not yet have fully materialised by 2020, LNG cargoes could very well supply a higher percentage of China's gas demand. Even so, when taking into account the additional quantities of pipeline gas from Turkmenistan to be supplied in 2020 and the Russian gas supplies under the CNPC Gazprom contract, it seems likely that pipeline gas supplies will in future exceed LNG cargo imports.
Notwithstanding the discussion above, however, one should not downplay the importance of LNG in China's future natural gas consumption and importation. Assuming that LNG only constitutes 30% of Chinese imports in 2020 (i.e., slightly higher than would be the case under the high pipeline supply scenario) and overall imports reach 160 BCM, this would mean about 50 BCM of LNG imports, which is a doubling of the present level of LNG imports into China. For coastal regions in particular, LNG will continue to form an important part of their energy supplies, given their relative proximity to LNG receiving terminals. Furthermore, the flexibility and potential diversification of supply sources offered by LNG (particularly with the growth in the short term and spot trade of LNG) is likely to mean that China will maintain a sizable proportion of future gas imports in the form of LNG. Although LNG supply is potentially vulnerable to blockades and acts of piracy, trans-national pipelines are not immune from similar transportation and supply disruption risks, and China's energy security is very likely to be optimised through the diversification of supply sources for both pipeline and LNG. Indeed the recent crisis over Ukraine and Europe's dependence on Russian gas imports is likely to be a useful reminder to China (a future Russian gas importer) of the importance of supply diversification in any country's energy policy.
In terms of the relative balance of future LNG and pipeline gas imports into China, one potential game-changer is the possibility of LNG pricing in Asia heading for a downward correction in the longer term. In the latter half of this decade, some view that the start-ups of Australian projects and availability of US LNG (as well as LNG exports from Canada and East Africa) may substantially increase the amount of LNG supply in the global market. On the demand supply, the reactivation of Japanese nuclear plants shut down in the wake of the Fukushima nuclear incident is also expected to reduce demand from the world's largest LNG importer. Furthermore, the rise of China as one of the largest LNG consumers and its ability to switch between pipeline gas and LNG for its fuel needs could add momentum to a softening of North Asian LNG prices. One projection has been made that LNG prices could fall to approximately US$ 10 to 12 per MMBtu in the longer term – if so (and unless pipeline gas prices fall as well), LNG import prices, especially for coastal regions in China, could be fairly competitive vis–à–vis pipeline gas, especially when one takes into account the transportation tariff for delivery of pipeline gas. Furthermore, if Asian LNG prices (which traditionally reflect oil-indexed pricing, e.g., JCC) are eventually priced on a significant scale according to an LNG-specific index (e.g., Japan Korean Marker as published by Platts), LNG purchases could then also provide a valuable opportunity to hedge against oil-indexed pricing under the pipeline gas contracts signed by Chinese companies.
As one of the world's largest gas importers and consumers, there is every reason that the future growth and development of China's gas demand and imports will be of great interest to suppliers, consumers and other participants in the international gas market. On a global scale, the knock-on effects of Chinese gas consumption and importation will be significant not only in terms of providing capital for natural gas projects or offtake of gas quantities, but also the potential effects on gas pricing structures – for instance, it has been suggested that the pricing under Gazprom CNPC deal will set a new floor for LNG prices. However, there remains a number of significant challenges to the long term growth of the natural gas market in China, especially the wide discrepancy between the pricing of gas imports and domestic gas sales to certain user segments (especially residential users). In assessing China's future gas imports, it is also important to bear in mind China's significant potential for increasing domestic gas supply through the development of shale gas and other unconventional gas resources. Nevertheless, taking into account the government's avowed policy to increase natural gas usage, China's projected growth in energy demand and the present challenges facing development of China's unconventional gas resources, both pipeline gas and LNG imports into China have favourable prospects for significant growth in the coming years.