Coal-to-gas adds a domestic supply buffer
China’s coal-to-gas buildout is becoming a factor for LNG suppliers to include in their view of the country’s future import demand. Rystad Energy estimates that capacity will rise from 9.4 billion cubic meters (Bcm) per year by the end of 2026 to 28 Bcm per year by 2030. That increase would make coal-derived synthetic gas a larger domestic supply buffer, though still a supplement to imports. The distinction matters: added capacity can constrain the growth of import demand at the margin without making overseas gas irrelevant to China’s supply mix.
The strategic case is direct. China can produce and transport this gas without depending on foreign suppliers or exposed shipping routes, giving policymakers another source to draw on when assessing supply security. “At 28 Bcm per year by 2030 it remains a supplemental source, not a replacement for imports,” said Wei Xiong, Rystad Energy’s vice president of gas and LNG markets. He said exporters targeting China should treat the expansion as a potential structural restraint on demand. That’s a meaningful caution for suppliers whose expectations depend on imports continuing to grow.
Xinjiang leads the expansion
Xinjiang’s low-cost coal has put the province at the center of the development pipeline. Rystad says mine-mouth coal there averaged 214 yuan, or $30 per tonne, between April 2025 and May 2026 — less than 40% of the comparable price in Inner Mongolia. A cheaper feedstock can improve project economics before transport and processing costs are counted, though it doesn’t by itself establish that every proposed plant will be profitable. Rystad estimates that delivering Xinjiang-produced synthetic gas to East China costs $9.1–$9.6 per million British thermal units (MMBtu), generally below China’s average LNG import price.
That cost comparison helps explain why the projects are attracting attention, but it needs to be read carefully. A delivered cost estimate and an average import price don’t answer every question about operating performance, capital spending or future prices. Existing plants are operating at more than 90% utilization, according to Rystad, a sign of demand and of the plants’ cost position against imported alternatives. About 20 Bcm per year of CTG capacity is under development, much of it in Xinjiang. If you're working in this space, the gap between capacity being planned and gas actually being produced is where much of the commercial uncertainty sits.
Project approvals also appear to be moving faster in the province. In several recent cases, timelines have shortened from three years or longer to less than 12 months. Faster approvals can shorten the path from proposal to construction, but they don’t remove the engineering, financing or environmental work that projects must complete. The numbers here are significant, though they don't yet tell us how quickly the entire development pipeline will turn into reliable output.
China’s 15th Five-Year Plan, which covers 2026 to 2030, gives CTG a stronger place in the country’s domestic supply architecture. That shift suggests the industry is moving beyond strategic consideration toward project execution, even as environmental conditions shape what can be built. The plan’s role is a signal of direction; its practical effect will depend on which projects proceed and how they perform.
Carbon and water constraints remain
New projects face carbon and environmental requirements that could add cost and complexity. CHN Energy’s Zhundong project, designed for 2 Bcm of annual gas production, is scheduled to start producing in 2027. Its plans include electrolytic hydrogen integration, wastewater recycling and carbon capture capacity of 550,000 tonnes per year. Those features show how a project can be designed to address several environmental pressures, but planned equipment and capacity don’t establish the eventual emissions performance or commercial return.
Rystad CCUS analyst Eryu Wang said China has an established market for carbon capture projects that use captured carbon dioxide, but scaling those applications remains an open question. The commercial case for CTG with lower emissions is also uncertain over the long term. Wang said the availability of water, compliance requirements and carbon emissions pose continuing challenges, while China has yet to set a uniform national decarbonization standard for new projects. That combination leaves developers with costs and requirements that may be difficult to assess consistently across projects.
Integrated CTG facilities can require substantial upfront investment and put added pressure on water resources in northwestern China. Reported water consumption covers the full complex, Rystad says, rather than carbon capture alone. That qualification matters when comparing projects or judging the burden of individual components (and this is the part most people overlook). If captured carbon dioxide is sent to geological storage, the commercial scope for carbon capture may be more limited. A gas plant can therefore look attractive on feedstock costs while still facing difficult questions about its wider resource demands.
What it means for LNG trade
At 28 Bcm per year, CTG would not displace China’s LNG imports, but it could change the margin of demand that overseas suppliers can serve. That matters to LNG producers from Australia, Qatar and the United States, as well as to expectations for global prices and long-term supply contracts. Here's the thing: a domestic source doesn’t need to replace imports to affect how much additional LNG China seeks. If CTG output grows as planned, suppliers may have to account for it when judging the room for future import growth.
The key uncertainty is how quickly planned capacity becomes operating supply and whether projects can manage their cost, water and emissions burdens. The high utilization reported at existing plants offers evidence that current facilities are being used extensively, but it doesn’t settle the outlook for projects still under development. That said, CTG’s projected scale makes it more than a footnote in demand forecasts. For now, China’s program looks like one element of a broader supply hedge: a domestic source that can temper import growth as it expands, while leaving LNG central to the country’s supply mix.
Capacity is a signal, not a settled forecast
For LNG suppliers, the useful question is not simply how much CTG capacity China may build. It’s how much gas those plants will deliver, at what cost, and with what demands on water and emissions controls. Capacity estimates provide a view of possible supply; they don’t guarantee that every project will run as planned. The outlook will become clearer as projects move from approvals and construction into operation.
What this means for you is that China’s import demand should be assessed alongside the pace and performance of its domestic projects. CTG’s expansion could limit some import growth, yet its own constraints leave room for LNG to remain important. A supply buffer with unresolved costs and environmental demands.