China's National Development and Reform Commission and National Energy Administration on 27 January issued a nationwide notice refining how generation capacity is paid and how reliability is compensated as the country builds a spot electricity market. The move formalises differentiated rules for coal, gas, pumped storage and new grid‑side batteries, and signals a more systematic shift from ad‑hoc government pricing to market‑based revenue mechanisms meant to stabilise supply while advancing the low‑carbon transition.
Under the new guidance, provincial authorities must raise the share of a coal unit's fixed costs recovered through capacity payments to at least 50%, with room to set a higher share based on local market maturity and utilisation hours. Provincial regulators may also establish analogous capacity payments for gas plants, determined as a share of their fixed costs. The intent is to provide a steadier revenue stream to dispatchable thermal units whose energy market earnings have been eroded by growing renewable output and falling utilisation rates.
Pumped storage will continue to be treated differently depending on project vintage. Stations that began construction before China’s 2021 pumped‑storage pricing reform will remain under government pricing during operation, with re‑pricing at the end of their commercial life. Stations started after the 2021 reform will see provincial authorities set a uniform capacity price every three to five years based on average cost recovery rules, while operators participate in energy and ancillary markets and share a portion of market revenues with the system.
For grid‑side independent new‑type storage, provinces may now offer capacity payments tied to a plant’s peak contribution. Payments are benchmarked to local coal capacity rates and scaled by the storage unit’s continuous discharge duration relative to the annual peak duration, capped at parity. Such projects will be subject to a provincial “white‑list” and additional management rules from the national agency, reflecting concerns about grid planning and reserve adequacy.
The notice also sets a process for introducing a reliable capacity compensation mechanism once spot markets run continuously. That mechanism will compensate reliable capacity — defined as the portion of a unit that can supply during yearly system peaks — in a way that covers the fixed costs residual markets cannot. Eligible resources will include market‑participating coal and gas plants and qualifying grid storage; government‑priced units are excluded from this separate compensation.
Complementary reforms address market transactions and settlement. Provinces may lift lower bounds on coal long‑term trading prices and relax requirements on how much coal capacity must be contracted in advance, allowing greater scope for flexible pricing that tracks supply‑demand or fuel‑cost shifts. Capacity fees and reliability payments will be included in local system operation costs; settlements for pumped storage and grid storage will follow spot or market rules where those markets run, with charging and discharging treated asymmetrically in regions without continuous spot markets.
The policy package ties implementation to provincial assessments of consumer affordability and local system needs. Regulators must factor user economic bearing capacity into compensation levels and into approvals for new flexible resources, and failure to meet operational benchmarks can lead to deductions from capacity payments. The central agencies emphasise coordination among price and energy departments, grid operators and generators to ensure data, contracts and settlements align with the new regime.
This is a pragmatic step to reconcile three competing priorities: preserve system reliability as variable renewables grow, reduce investment uncertainty for dispatchable plants and nudge more storage and flexible assets into markets. The reforms will materially reshape revenues for thermal generators and storage providers, but they also carry risks: capacity payments can blunt incentives to retire high‑emission plants if set too generously, and provincial discretion may produce an uneven patchwork of compensation that complicates national decarbonisation targets. Markets and regulators will need to calibrate payments carefully as China’s spot markets mature.