On 8 November 2023, China’s National Development and Reform Commission (NDRC) and the National Energy Administration (NEA) issued a policy on establishing a coal power capacity pricing mechanism. The policy proposes adjusting the current single pricing of coal-fired power to a two-part pricing system, comprising capacity pricing and electricity pricing. Electricity pricing is market-based, reflecting electricity supply-demand dynamics and changes in coal prices. The new capacity pricing is set at a fixed rate that will be gradually adjusted. Coal plants in most provinces will first receive CYN 100/kW (approx. EUR 12/kW), while those in seven provinces with a greater renewable energy share will get CYN 165/kW (approx. EUR 20/kW). These provinces include Henan, Hunan, Chongqing, Sichuan, Qinghai, Yunnan, and Guangxi. Starting from 2026, all coal plants will receive at least CYN 165/kW.
The introduction of capacity pricing aims to drive renewable expansion and expedite the shift toward low-carbon energy. However, there are concerns about whether the policy could indirectly reduce renewable energy profitability and slow down the energy transition. This concern arises from the fact that renewable energy electricity prices are linked to coal power electricity prices in China, with the new mechanism expected to drive down the latter. This exemplifies that China is still in the early stage of developing its green electricity and carbon markets, meaning that the true value of renewable energy is not yet adequately reflected.
The potential for capacity payments to provide incentives for further increasing coal capacity is also worth considering and monitoring. The fixed pricing structure does not capture the quality of and specific costs associated with backup capacity, such as response speed, duration, cold start, or standby start. Whether the bidding reserve market mechanism adopted by Germany and other countries is more reasonable remains to be validated over time.