China's energy transition enters a carbon-driven phase: three-year policy window reshapes assets and opportunities

From subsidies to carbon price and compliance

China's energy transition is entering a new phase, moving away from a model built on subsidies toward one shaped by carbon price and compliance obligations. Nuclear power green certificates, carbon footprint standards and CCUS standards are all being stood up as new pricing and compliance frameworks, using market signals than grants to push end users toward decarbonisation. China is no longer just building out the world's largest renewable energy base, it is now directing how that energy gets consumed, with carbon cost becoming a real input into the calculation. Going forward, energy asset valuations will need to reflect carbon asset value alongside physical capacity, not just one or the other.

Nuclear power's entry into the green certificate system

One of the more consequential supply-side shifts is the planned inclusion of nuclear power in China's green electricity certificate system, with implementation rules expected in 2027-2028. If all 64 operating reactors were issued certificates, annual supply could rise by roughly 480 million certificates, equal to about a quarter of 2025's wind and solar issuance, which would likely dilute the scarcity premium that has driven green certificate prices up sevenfold over the past two years. The economics still favour nuclear as a baseload source: a single 1 GW-class unit generates around 7.5 billion kWh a year with a carbon footprint of just 6.5 grams of CO2 per kWh, well below wind or solar PV. For a coastal refining complex with annual electricity demand of 3 billion kWh, procuring nuclear power directly instead of buying certificates could save around RMB 17 million a year, though international recognition of nuclear green certificates under frameworks like RE100 and CBAM remains an open question worth watching.

Green hydrogen approaches its cost inflection point, but isn't there yet

Green hydrogen becomes cost-competitive with grey hydrogen once electricity prices fall to around RMB 0.15 per kWh and carbon prices climb above roughly RMB 100 per tonne. The Current conditions, renewable electricity at RMB 0.2-0.4 per kWh and carbon prices around RMB 80 per tonne, keep the economics just out of reach for now. Over the 15th Five-Year Plan period, we expect green hydrogen adoption to concentrate on industrial feedstocks, particularly ammonia synthesis and refining, rather than transport, where electric heavy-duty trucks remain the more competitive pathway, hydrogen fuel-cell trucks look likely to stay confined to demonstration routes and extreme cold applications. The 'nuclear power direct supply plus electrolyser' model stands out as a promising template for coastal petrochemical parks that sit near nuclear resources and carry heavy carbon-footprint pressure, though the approach is still at an early commercial stage. For overseas suppliers, this points to real demand for imported electrolysers and green hydrogen equipment as China builds out this capacity.

CCUS moves from demonstration to scale

CCUS is shifting from standalone pilot projects toward replicable, investable engineering builds, a change reinforced by the national CCUS-EOR standard that took effect in July 2026 and now gives the technology a unified framework for project engineering and carbon accounting. Activity is concentrating around the Ordos, Bohai Bay, Junggar and Pearl River Mouth basins, with CNPC, Sinopec and CNOOC each anchoring projects in different basins and increasingly combining renewable power generation, oilfield electrification and CCUS into integrated 'zero-carbon oil field' developments. Industry estimates put the breakeven oil price for a CCUS-EOR project at roughly US$70 per barrel, assuming a CO2 price no higher than RMB 300 per tonne. For foreign technology providers, entering these state-owned enterprise supply chains looks like the more realistic path in, particularly for those with strengths in measurement, monitoring and verification, leakage detection, and EOR optimisation modelling.

Carbon footprint standards raise the stakes for CBAM compliance

Document No. 45 also kicks off work on two measurement frameworks that matter a great deal for exporters: carbon footprint standards for primary energy products, and official national emission factors, with fuels, fertilisers, hydrogen, ethylene, ammonia and methanol as the initial priorities. Standard development is expected to run through 2026-2027, with the first official standards and emission factors landing sometime in 2028-2030, while 2026-2028 should be the peak procurement window for corporate carbon management platforms, a spend that can run from several million to tens of millions of RMB for a mid-sized refinery. The real significance here is less about the standards themselves and more about compliance leverage. Once China's own emission factors exist, exporters can use actual emissions data in place of the EU's default values under CBAM, avoiding the much higher costs that come with punitive default calculations.

The risk is a timing mismatch: if CBAM's scope expands before China finalises its standards in 2028, exporters could be caught facing the EU's punitive assumptions during the gap.

Where the opportunities and risks sit

On the opportunity side, we'd flag three areas in particular. First, access to state-owned enterprise supply chains for electrical equipment, green hydrogen equipment, CCUS engineering and carbon management platforms. Given that SOEs such as the three oil majors, pipeline operators and major power groups will be the primary implementers. Second, a dual-track power procurement strategy that combines green certificates for renewable compliance, with nuclear power purchase agreements to lower product carbon intensity. Third, cross-border arbitrage in green ammonia and green methanol, where China already turned net exporter in 2025, shipping around 120,000 tonnes to South Korea and 80,000 tonnes to Japan.

The risks are worth naming too. Joint-venture refineries face a tightening squeeze from equipment thresholds under the parallel Document No. 698, the Three-Year Action Plan for Energy-Saving and Carbon-Reduction Retrofit in Key Industries and the capacity replacement requirements in. Also, in Document No. 45, both of which raise the bar for new-build and expansion approvals. International recognition of China's nuclear green certificates and emission factor databases is still unresolved, and CBAM's expansion timeline remains uncertain enough that we'd caution against pricing in those impacts too early.

Key Takeaway

Document No. 45 marks a deliberate pivot in how China manages its energy transition, from subsidy-driven build-out toward a carbon price and compliance-led system. For companies operating in China, that means energy asset valuations increasingly need to price in carbon exposure and carbon asset access alongside physical capacity. For investors and traders, the highest-conviction opportunities over the next three years look concentrated in nuclear power's integration into the green certificate system, green hydrogen and CCUS infrastructure build-out, and the arbitrage potential opening up in green ammonia and green methanol as carbon footprint standards start to reshape export pricing.

The above content is the major conclusions and highlights extracted from the "China's Energy Transition Enters a Carbon-Driven Phase: Three-Year Policy Window Reshapes Assets and Opportunities" chapter of the latest China Policy Perspective (produced by GL Consulting).

The full chapter includes detailed sector-by-sector demand and cost modelling, provincial risk mapping, and strategic recommendations for investment, trading and capital allocation.

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