Breaking the hard-to-abate bottleneck in China's path to carbon neutrality with clean hydrogen

The study addresses how China—whose emissions profile is dominated by heavy industry and heavy-duty transport—can achieve carbon neutrality by 2060, given the difficulty of electrifying HTA sectors and their reliance on fossil feedstocks. It poses three questions: (1) What are the distinctive challenges for decarbonizing HTA sectors in developing countries like China, and are current technologies (efficiency, fuel switching, CCUS/NETs) sufficient? (2) What roles can clean hydrogen play as energy carrier and feedstock across HTA sectors? (3) Is widespread hydrogen deployment cost-effective in an optimized whole-energy-system pathway to net zero? The study’s importance lies in reassessing hydrogen demand across sectors and national contexts, moving beyond supply-side cost views, and informing China’s 2030 peak and 2060 neutrality pledges.

Prior national decarbonization studies for China provided limited treatment of HTA sectors. International attention to HTA has focused on CCUS and negative emission technologies, with concerns about path dependency in heavy industries. The IPCC recognizes low-emission hydrogen as a key mitigation option. Existing hydrogen literature emphasizes production technologies and costs, and transport applications in developed countries, with less focus on heavy industry demand and developing-economy contexts. Studies show green hydrogen is technologically mature with declining costs, but analyses often omit comprehensive cross-sector demand and the potential scale in HTA sectors, motivating this work.

The authors develop an integrated, technology-rich, dynamic linear programming energy system optimization model for China (China-MAPLE), based on the IEA-ETSAP TIMES-VEDA framework, covering 2015–2060 in five-year steps. The model optimizes least-cost pathways across supply and demand sectors, with enhanced representation of HTA sectors (iron and steel, cement, chemicals, non-ferrous metals, glass/paper/brick, transport including buses, trucks by class, domestic shipping, rail, and residential heating). Four scenarios are analyzed: BAU (no constraints), NDC (peak ~2030, 60–65% carbon intensity reduction vs 2005, ≥20% non-fossil supply, HTA efficiency/fuel switching/CCUS), ZERO-NH (net zero before 2060 without hydrogen; best-available efficiency, fuel switching, CCUS, BECCS), and ZERO-H (same as ZERO-NH plus clean hydrogen as energy and feedstock in heavy industry, transport, and heat). Hydrogen production technologies include fossil-based with and without CCUS (coal/methane gasification or reforming) and electrolysis (AEC, SOEC, PEM), with cost/efficiency learning assumptions (e.g., SOEC and PEM improve over time). Delivery is modeled via gaseous/liquid road transport with specified costs and efficiencies; storage via tanks. Equations specify hydrogen demand in steel (as heat and reducing agent including hydrogen-DRI and supplemental BF-BOF), cement (heat), chemicals (feedstock and heat for ammonia, methanol, etc.), and transport (HFC shares by mode, distances, loads). Primary energy trajectories and sectoral penetrations are endogenously optimized. Sensitivity analyses vary hydrogen production costs (±30–50% and more) and GDP growth to test robustness of hydrogen penetration and system investment costs.

- Hydrogen in heavy industry: - Steel: Under ZERO-H, by 2060 the BF-BOF share falls to 34%, EAF rises to 45%, and hydrogen-DRI reaches 21%; clean hydrogen supplies 29% of the sector’s final energy. Falling renewable power prices (US$38–40/MWh by 2050) make green hydrogen and hydrogen-DRI increasingly competitive. - Cement: Of 47 mitigation technologies, energy efficiency reduces only 8–10% of emissions; waste-heat cogeneration/oxy-fuel provide 4–8%. Clinker ratio reduction can yield 50–70% abatement but has performance concerns. Hydrogen technologies (20 options used) exhibit lower average abatement costs than typical CCUS/fuel switching. Green hydrogen can reduce 89–95% of CO₂ from industrial heat; process emissions still require CCUS. - Chemicals: In 2060 under ZERO-H, gas-based ammonia with hydrogen heat reaches 20% of production; CGTM/NTM with hydrogen heat reaches 21% for methanol. Hydrogen supplies 17% of final energy for chemical industry heat by 2060, alongside electricity (32%) and bioenergy (18%). - Transport decarbonization: - LDVs: HFC LDVs reach about 5% by 2060; EVs remain more cost-competitive. - Buses: HFC buses become more competitive than electric by ~2045; 61% of fleet by 2060. - Trucks: In ZERO-H, HFC light-duty trucks reach 53% by 2060; HFC heavy-duty trucks reach 66% by 2060. Diesel/biodiesel/CNG HDVs exit after 2050 in both net-zero scenarios. HFC vehicles have cold-weather performance advantages. - Shipping: By 2060, 65% ammonia-fueled and 12% hydrogen-fueled domestic shipping in ZERO-H. Hydrogen provides ~56% of the transport sector’s final energy in 2060. - System-wide energy and investments: - By 2060 in ZERO-H, non-fossil fuels provide 93% of primary energy (88% in 2050); wind and solar supply about half. Clean hydrogen supplies ~13% of TFEC in 2060; hydrogen consumption is ~56.7 Mt, with production scaling to ~65.7 Mt. - Cumulative investment to 2060: ZERO-NH US$20.63T vs ZERO-H US$18.91T; savings US$1.72T and ~0.13% of aggregate 2020–2060 GDP. Annual HTA-sector investment falls from ~US$392B (ZERO-NH) to ~US$359B (ZERO-H) by relying less on costly CCUS/NETs. - Regional hydrogen shares exceed national average in 10 provinces (e.g., Inner Mongolia, Fujian, Shandong, Guangdong) due to renewable resources and industrial demand. - Hydrogen supply evolution: - By-product hydrogen grows from 0.78 Mt (2030) to 14.50 Mt (2060). - Blue hydrogen (coal/methane with CCUS) dominates to ~2040; green hydrogen scales rapidly thereafter. By 2060, centralized SOEC and PEM reach ~19.36 Mt and ~18.10 Mt, respectively (over half of production); large centralized AEC grows to ~1,197 PJ. - Cost competitiveness of green hydrogen: - Green hydrogen average cost in China falls to ~US$2/kg by 2037 and ~US$1.2/kg by 2050, undercutting blue hydrogen (~US$1.9/kg). External sources project US$0.7–1.6/kg ranges by 2050. - A blue-only hydrogen case raises aggregate investment to ~US$19.54T, US$0.63T higher than mixed clean hydrogen. Sensitivity shows hydrogen TFEC share remains >10% even with +50% cost; at –50% cost, TFEC share rises to ~17.6%. The ZERO-H and ZERO-NH investments equalize only if hydrogen costs are ~+87% above central assumptions, indicating strong robustness.

The integrated least-cost analysis shows that reliance solely on efficiency, CCUS, and NETs is unlikely to deliver cost-effective deep decarbonization of China’s HTA sectors. Incorporating clean hydrogen across heavy industry and heavy-duty transport produces a lower-cost net-zero pathway, materially reducing dependence on expensive CCUS/NETs and enabling technological shifts such as hydrogen-DRI in steel and hydrogen-based high-temperature heat in cement and chemicals. Transport results indicate hydrogen’s comparative advantage in buses and medium/heavy trucks, and for shipping via ammonia, while EVs retain an edge for LDVs. System-level outcomes include higher renewable penetration and a substantial role for hydrogen in TFEC by 2060. Green hydrogen emerges as the preferred long-term option in China due to rich wind/solar resources, learning-driven cost declines, potential use of curtailed renewables, and infrastructure co-location benefits; blue hydrogen plays a transitional role to ~2040. Policy implications include integrating hydrogen into target-driven planning and leveraging market instruments like an expanded ETS to prioritize least-cost abatement in unregulated commodity industries (steel, cement). Utilizing curtailed renewable power for electrolysis can enhance returns on renewable investments and accelerate capacity growth.

This study provides the first comprehensive whole-system assessment of clean hydrogen’s role in decarbonizing China’s HTA sectors on a least-cost path to net zero by 2060. It demonstrates that hydrogen, used as both energy carrier and feedstock, enables significant emissions reductions in steel, cement, chemicals, and heavy-duty transport while reducing total investment needs by about US$1.72 trillion relative to a no-hydrogen net-zero pathway. Green hydrogen is projected to become more cost-effective than blue before 2040 and to dominate production by 2060, supported by China’s abundant renewables and potential to exploit curtailed power. Future research should refine hydrogen transport and storage infrastructure modeling (including pipelines), quantify atmospheric implications of hydrogen leakage, incorporate short-term grid-balancing dynamics affecting electrolysis costs, and evaluate social, employment, and acceptance impacts of hydrogen transitions. Continued technology innovation in hydrogen production, storage, and industrial applications could further improve costs and accelerate adoption.

The analysis simplifies hydrogen transport and storage (assumes road trailers and tanks; no hydrogen pipelines or network effects), does not assess indirect atmospheric impacts of potential hydrogen leakage, and omits short-term power system dynamics that affect electricity and green hydrogen costs. Broader societal impacts (employment, welfare, public acceptance) are not evaluated. Long-distance transoceanic hydrogen/ammonia transport is excluded.