China approved a 5.2 billion yuan ($730 million) green hydrogen facility in Inner Mongolia capable of producing 90,000 tonnes annually, while Hebei Province advances a 13.5 billion yuan pipeline to transport 1.5 million tonnes per year from Zhangjiakou to Tangshan’s steel manufacturing corridor. These developments follow Beijing’s latest five-year plan, signaling renewed commitment to hydrogen infrastructure despite sector struggles with economic viability and demand uncertainty.
The China Coal Energy subsidiary project in Inner Mongolia represents significant scale expansion in a region already positioned as China’s renewable energy production hub. At 90,000 tonnes annual capacity, the facility would rank among China’s largest dedicated green hydrogen installations, requiring approximately 4-5 TWh of renewable electricity input at typical electrolysis efficiency rates of 50-60 kWh per kilogram. This implies dedicated wind and solar capacity exceeding 600-750 MW at Inner Mongolia’s capacity factors, assuming direct renewable electricity sourcing rather than grid power.
Pipeline Infrastructure Signals Demand Confidence
Hebei’s 1,000-kilometer hydrogen pipeline from Zhangjiakou to Tangshan addresses a fundamental constraint limiting green hydrogen adoption: transportation economics. Compressed hydrogen truck transport costs $3-5 per kilogram over 500-kilometer distances, while pipeline transport reduces costs to $0.50-1.50 per kilogram depending on throughput volumes. The 1.5 million tonne annual design capacity—equivalent to 4,100 tonnes daily—positions the pipeline to serve multiple industrial consumers across Hebei’s manufacturing belt.
Tangshan’s steel industry represents logical anchor demand. The city produces approximately 130 million tonnes of crude steel annually, accounting for roughly 12% of China’s total output. Replacing coal-based hydrogen used in direct reduction ironmaking with green hydrogen could reduce steelmaking emissions by 1.5-2.0 tonnes of CO2 per tonne of steel produced. If the pipeline’s full 1.5 million tonne hydrogen capacity serves steel production, it would support decarbonizing roughly 15-20 million tonnes of steel output—approximately 15% of Tangshan’s production.
However, this assumes steel mills convert blast furnace processes to direct reduction iron (DRI) pathways compatible with hydrogen use. China’s steel sector has invested heavily in existing blast furnace infrastructure with remaining service lives of 15-25 years, creating capital lock-in that slows hydrogen adoption. The pipeline infrastructure positions supply ahead of confirmed demand, betting that carbon pricing mechanisms or regulatory mandates will drive steel sector conversion rates sufficient to absorb capacity.
Five-Year Plan Provides Policy Backstop
Beijing’s inclusion of hydrogen support in the latest five-year plan contradicts market signals suggesting overcapacity and weak economics. China’s existing hydrogen production—predominantly grey hydrogen from coal and natural gas—exceeds 35 million tonnes annually, primarily serving petroleum refining and chemical synthesis. Green hydrogen production remains below 500,000 tonnes, constrained by costs 2-3 times higher than conventional hydrogen at $4-6 per kilogram versus $1.50-2.50 for grey hydrogen.
The policy commitment implies continued subsidies bridging the green premium gap. Provincial governments in Inner Mongolia, Hebei, Gansu, and other renewable-rich regions offer capital subsidies covering 20-40% of electrolyzer costs plus preferential electricity pricing for industrial hydrogen production. These incentives reduce delivered green hydrogen costs to $3-4 per kilogram in optimal locations, narrowing but not eliminating the price differential against fossil-based alternatives.
China’s approach diverges from European and North American strategies, emphasizing carbon pricing to create market pull for green hydrogen. Instead, Beijing combines supply-side industrial policy—subsidizing production capacity and infrastructure—with nascent demand-side interventions through pilot programs requiring green hydrogen use in specific applications. This model risks creating stranded assets if anticipated demand fails to materialize at subsidized capacity scales.
The Inner Mongolia project’s approval by regional regulators rather than central authorities reflects the decentralized implementation of the national hydrogen strategy. Provincial competition for renewable energy industrial development creates the risk of uncoordinated capacity expansion exceeding realistic demand trajectories. Inner Mongolia’s wind and solar resources—among China’s most abundant—attract multiple hydrogen projects, but the province’s distance from major industrial demand centers and limited pipeline connectivity constrain market access.
Steel Sector Decarbonization Economics
Tangshan’s steel industry represents China’s most emissions-intensive manufacturing cluster, making it a priority target for decarbonization efforts. However, hydrogen-based steelmaking faces economic hurdles beyond fuel costs. DRI-electric arc furnace (EAF) production routes using green hydrogen require capital investments of $500-800 per tonne of capacity—significantly higher than blast furnace rehabilitation costs of $100-200 per tonne. For Tangshan’s 130 million tonne capacity base, full conversion would require $65-100 billion in capital expenditure.
This investment magnitude exceeds individual steel company balance sheets, necessitating state-directed capital allocation or policy mechanisms forcing conversion. China’s national carbon trading system, launched in 2021, currently covers only the power sector. Extending carbon pricing to steel would create economic drivers for hydrogen adoption, but price levels below $50 per tonne CO2—typical of current Chinese carbon permits—provide insufficient incentive given green hydrogen’s premium costs.
The 1,000-kilometer pipeline’s 13.5 billion yuan ($1.9 billion) investment pencils out at approximately $1.3 million per kilometer—within typical ranges for high-pressure hydrogen pipelines but requiring decades of utilization at near-capacity to recover capital costs. The project’s viability depends critically on securing long-term offtake agreements from steel producers willing to commit to hydrogen-based production routes despite economic uncertainties.
Zhangjiakou’s selection as a hydrogen supply hub leverages the city’s renewable energy infrastructure developed for the 2022 Winter Olympics. The region hosts approximately 20 GW of wind and solar capacity with curtailment rates historically reaching 15-20% during low-demand periods. Converting curtailed renewable electricity into hydrogen creates value from otherwise-wasted generation, but economics depend on electrolyzer utilization rates. Operating electrolyzers only during curtailment periods limits annual production hours to 1,500-2,500 versus optimal 6,000-7,000 hours, dramatically increasing per-kilogram production costs.
Technology Deployment and Manufacturing Scale
China’s electrolyzer manufacturing capacity has expanded rapidly, with domestic producers including Longi Green Energy, Sungrow, and China Energy Engineering Group scaling alkaline and proton exchange membrane (PEM) systems. Announced manufacturing capacity exceeds 15 GW annually—sufficient to supply global demand at current deployment rates—creating deflationary pressure on electrolyzer costs that fell from $900-1,100 per kW in 2020 to $400-600 per kW in 2025 for Chinese alkaline systems.
This cost reduction trajectory improves green hydrogen production economics but hasn’t yet achieved price parity with grey hydrogen. Further cost declines require manufacturing scale expansion and technology improvements, increasing electrolyzer efficiency and reducing balance-of-plant costs. China’s industrial policy model—capacity subsidies driving scale production ahead of demand—mirrors strategies previously deployed in solar panels and batteries, where oversupply created global price deflation, enabling accelerated adoption.
However, hydrogen differs from solar and batteries in requiring both production and consumption infrastructure investments. Solar panels and batteries provide value individually; hydrogen requires integrated supply chains linking production, transport, storage, and end-use equipment. This coordination challenge has constrained hydrogen deployment globally, and China’s state-directed investment model represents an attempt to overcome market coordination failures through centralized planning.
The Inner Mongolia and Hebei projects’ November 2025 approvals suggest accelerated timelines for construction starts, potentially targeting 2027-2028 operational dates. This aligns with China’s 2030 carbon peak goal and 2060 carbon neutrality commitment, requiring rapid scaling of low-carbon industrial processes throughout the current decade. Steel sector decarbonization timelines prove particularly challenging given long asset lifespans and high capital intensity.
Demand Uncertainty and Market Development
China’s green hydrogen demand projections vary widely across industry analyses. Conservative estimates project 5-8 million tonnes of annual demand by 2030, primarily in petroleum refining and chemical synthesis, where hydrogen use is established. Aggressive scenarios incorporating steel, transportation, and power sector applications reach 15-20 million tonnes by 2030 and 50-100 million tonnes by 2050. Current announced production capacity—including the Inner Mongolia project—totals approximately 2-3 million tonnes annually when all projects reach operation.
This suggests either substantial additional capacity announcements are forthcoming or actual demand will track below optimistic projections. Steel industry conversion rates represent the critical variable. If major steel producers commit to hydrogen-based DRI-EAF routes at scale, demand could absorb growing green hydrogen supply. If steel companies prioritize carbon capture and storage on existing blast furnaces or shift to scrap-based EAF production, green hydrogen demand remains constrained to niche applications.
Transportation sector hydrogen demand—particularly heavy-duty trucks and buses—has underperformed Chinese government targets. Battery electric vehicles proved more economical for most applications, and hydrogen refueling infrastructure development lags behind electric charging networks. Some provinces have reduced hydrogen vehicle subsidies, acknowledging limited commercial viability outside specific use cases like long-haul trucking or port logistics equipment.
The policy support signaled in China’s five-year plan provides investment certainty for project developers and equipment manufacturers, but doesn’t guarantee end-user adoption at projected scales. Previous Chinese industrial policies have created overcapacity, requiring export markets or domestic demand stimulation through administrative measures. Green hydrogen may follow similar patterns if domestic industrial consumption remains below subsidized production capacity.
International hydrogen trade opportunities could absorb excess Chinese production if export markets develop, but hydrogen’s low energy density and transport costs favor regional production and consumption. Liquid organic hydrogen carriers or ammonia conversion enable long-distance shipping but add costs and conversion losses. China’s coastal provinces might develop export-oriented green ammonia facilities targeting markets in Japan, South Korea, and Europe, though competing production in the Middle East, North Africa, and Australia regions complicates export market access.
The Inner Mongolia and Hebei projects represent test cases for China’s hydrogen industrial policy model. Their commercial performance over the next 3-5 years will inform subsequent capacity expansion decisions and subsidy policy adjustments. If Tangshan steel mills successfully integrate pipeline hydrogen into production processes at economically viable costs, replication across other industrial clusters becomes feasible. If hydrogen costs remain prohibitive despite subsidies and infrastructure investments, policy approaches may shift toward carbon capture or alternative decarbonization pathways.
