Abstract
China has implemented a capacity payment mechanism for coal-fired power plants since January 2024, but it remains unclear whether current levels of capacity payments are sufficiently high or low. As the country operates the world’s largest coal fleet, the design and implementation of this mechanism will have far-reaching implications for power sector decarbonization and low-carbon energy integration. We evaluate the profitability of coal-fired power plants across provinces and find that pre-tax profit margins range from -33% to 26% with capacity payments in 2024, with regional disparities expected to widen by 2035. The results suggest that capacity payments should be tailored to each grid region’s capacity needs and operational patterns. In the longer term, China’s capacity payment mechanism should evolve from its current administrative approach to a market-based framework to enhance efficiency and align with broader power market reforms.
Main Text
China has begun implementing capacity payment mechanisms in recent years for coal-fired power plants to improve cost recovery and maintain grid reliability. In 2022, the Nation Development and Reform Commission (NDRC) and the National Energy Administration (NEA) issued the “Guiding Opinions on Accelerating the Establishment of a National Unified Electricity Market System”, referred to as Document No. 118, which mandates that all regions with electricity spot markets should “establish a market-based mechanism for recovering power generation capacity costs” (NDRC, 2022). Subsequently, in November 2023, the NDRC and NEA jointly issued the “Notice on Establishing a Coal Power Capacity Pricing Mechanism”, which took effect in January 2024 (NDRC, 2023a). Under this framework, the fixed costs of coal units are standardized nationwide at 330 RMB/kW-yr, with roughly 30% of these costs recoverable through capacity payments in most regions during 2024-2025. In areas undergoing faster coal transitions, the recovery ratio can reach 50% (NDRC, 2023b). Beginning in 2026, the proportion of fixed costs recovered through capacity payments will increase to at least 50% across all regions. Given that China operates the largest coal fleet in the world, the design and implementation of such a capacity payment mechanism will play a critical role in shaping the country’s transition towards a low-carbon energy system.
The rationale for introducing capacity payment mechanisms is two-fold. First, China’s electric power system is expected to have more coal power online, and a growing challenge lies in ensuring cost recovery for these units. While renewable capacity has been growing at an unprecedented rate of over 300 GW/yr since 2023, new coal-fired projects continue to advance, with a total estimated capacity of 94.5 GW, representing 93% of the global new coal capacity in 2024 (CarbonBrief, 2025). However, rising fuel costs, limited cost pass-through, and decreasing capacity factors when renewable energy is abundant have contributed to significant losses for coal-fired power plants. In 2021 alone, over 80% of coal units failed to cover their operating costs, leading to nationwide financial losses exceeding 300 million RMB (Chen, 2022). In provinces like Gansu, coal-fired power plants represent a large share of outstanding loans and face higher fuel costs than other provinces (Wang et al., 2022). As renewable energy continues to displace coal generation, the reduced utilization of coal units may increase the risk of loan defaults, potentially destabilizing local banking systems.
Second, China’s efforts to reduce the carbon intensity of its coal fleet remain financially challenging. Under its 2030 Nationally Determined Contributions (NDCs), China targets a 65% reduction in carbon intensity from 2005 levels by 2030, while the latest 2035 NDCs call for economy-wide greenhouse gas emissions to decline by 7-10% below peak levels by 2035 (United Nations Climate Summit, 2025). To reduce emissions from coal power, China unveiled the Coal Action Plan in 2024, promoting the adoption of technologies such as biomass or green ammonia co-firing and carbon capture and storage (CCS) (ARE, 2024). However, it remains uncertain whether these financially constrained units have sufficient financial incentives to undergo capital-intensive retrofits. Moreover, recent studies show that retrofitted coal power may operate at even lower capacity factors, as their value propositions shift toward providing flexibility services and supporting renewable integration (PKU, 2025).
This policy context gives rise to two central research questions: (1) Which regions experience the most cost recovery pressure (i.e., least profitable) under the current capacity payment mechanism, and (2) How should capacity payment mechanisms evolve to align with ongoing decarbonization and power market reforms? Overcompensating coal units exclusively could incentivize additional coal investment and create fossil fuel infrastructure lock-in. The answers to these questions become crucial when China’s new coal capacity reaches its highest level in a decade. To the best of our knowledge, no existing study has examined how capacity payment mechanisms affect the financial viability and transitional risks of China’s coal-fired power plants.
To address these gaps, we adopt the following methodology. First, we analytically solve for the pre-tax profit margin for coal-fired power plants in each province, incorporating key factors such as electricity benchmark tariffs, contract prices for coal on-grid power, annual run hours, fuel costs, and capacity payment revenues. In this process, we estimate capital recovery factors (CRF) for each coal unit using the 5-year loan prime rates from the People’s Bank of China and calculate capacity-weighted CRF in each province. This approach allows us to capture the spatial heterogeneity in investment timing and financing conditions. Second, we use a forward-looking approach, where we obtain capacity and generation mix at the provincial level for 2035 based on the least-cost decarbonization pathways for China’s power sector (Z. Zhang et al., 2025). We update the profit margin calculations accordingly to estimate the distribution of future coal power profitability in 2035, considering future electricity demand, renewable cost, and policy uncertainties. Finally, we provide policy recommendations to inform China’s ongoing capacity market design, drawing on our analytical findings and international experiences with capacity payment mechanisms.
Figure 1 shows the pre-tax profit margins for coal-fired power plants across Chinese provinces in 2024, using operation and cost data from the same year. Three scenarios are analyzed: (1) no capacity payments, (2) capacity payments with an unadjusted electricity tariff ceiling, and (3) capacity payments with an adjusted electricity tariff ceiling. The ceiling price for coal on-grid power is set at 120% of the benchmark tariff in each province (NDRC, 2021). The adjusted ceiling reflects current market practice, in which capacity payments are converted to an energy-equivalent value using annual run hours and then deducted from the tariff ceiling.
Regions with low electricity benchmark tariffs, low run hours, and high fuel costs generally see low coal power profitability. The Northwest grid region has both the least profitable (e.g., Ningxia, Gansu, and Qinghai) and most profitable coal units (e.g., Inner Mongolia), primarily driven by differences in fuel costs and annual run hours. The dominant factors driving low coal profitability vary by region. For example, Central China has the highest fuel costs nationwide, whereas Northeast China has the lowest level of annual run hours, albeit above-average electricity benchmark tariffs.
Introducing capacity payments significantly improves profitability, raising pre-tax profit margins by an absolute amount of 4%-20% before tariff ceiling adjustments. The largest gains occur in provinces with the lowest baseline profitability (e.g., Qinghai, Gansu, and Yunnan). Higher capacity prices increase profit margins by an additional 3%-5% in provinces such as Sichuan and Guangxi, assuming comparable levels of coal run hours and electricity benchmark tariffs. However, once tariff ceiling adjustments are implemented, capacity payments have minimal impacts on profitability in provinces where mid-to-long-term (MLT) electricity contract prices are already close to the tariff ceiling (e.g., Ningxia, Guizhou, and Hainan). Detailed results showing different capacity payment levels are provided in Supplementary Information.
Figure 2 shows the distribution of pre-tax profit margins with capacity payments (unadjusted tariff ceiling) and installed coal capacity in 2035 in each province, alongside the outstanding loans for coal-fired power plants as of 2022 (Wang et al., 2022). The results are derived from least-cost decarbonization pathways of China’s power sector consistent with a 2ºC global temperature rise target, which provide a set of plausible future coal capacity and annual run hours. According to these pathways, total installed coal capacity will drop from around 1,400 GW in 2024 to 880-1,050 GW in 2035 nationwide, and electricity generation from coal-fired power plants will decrease from 6,940 TWh in 2024 to 3,070-3,450 TWh in 2035. Correspondingly, average coal run hours will decrease from around 5,000 hours in 2024 to 3,100-3,900 in 2035 nationwide.
As coal utilization declines, pre-tax profit margins will change by an absolute amount of -25% to 5% from 2024 to 2035 nationwide, where the profit increases are attributable to higher capacity payment levels. Regions that have lower-quality renewable resources may experience moderate gains in coal profitability of up to 8% (e.g., Jiangxi). In comparison, the largest reductions are observed in Inner Mongolia and Jilin, driven by sharp declines in coal generation and large-scale renewable deployment.
Two distinct patterns of financial risks may emerge by 2035. First, regions with persistently low coal profitability and moderate levels of outstanding coal loans, such as Gansu and Ningxia, face elevated risks of cost recovery shortfalls and stranded assets. Second, regions with highly uncertain coal profitability and large outstanding coal loans, such as Inner Mongolia and Shandong, experience systemic financial vulnerability as the energy transition accelerates.
Our analysis has several limitations. First, we calculate coal run hours by dividing monthly electricity generation by the installed coal capacity at the provincial level, due to the limited availability of provincial-level statistics on actual coal run hours. We use the annual statistics from NEA to verify that our run hour estimates are reasonable at the national level (i.e., the average nationwide run hours are around 4,417 hours from 2013 to 2023). Second, actual electricity prices for on-grid coal power in each province can fluctuate by up to 20% relative to the benchmark tariffs. We obtain average annual contract prices from industry reports and trading websites, but detailed data at the firm level are limited. Lastly, for our analysis of coal profitability in 2035, we assume capacity payment prices rise to 50% of the standardized fixed cost. We do not consider coal transition pathways such as CCS retrofits, early retirement, and flexibility retrofits. While other studies have done detailed assessments on coal transition pathways using power system models with unit-level engineering details, integrating such analyses into future capacity market modeling will be an important next step.
This work has important implications for enhancing the capacity payment mechanism in China. We show that coal power profitability ranges from -33% to 26% across provinces in 2024 with capacity payments, and this disparity is expected to widen further by 2035. Such heterogeneity suggests capacity payment should vary by province at the very least, if the policy objective is to partially recover the fixed costs of coal-fired units. China’s NDRC currently excludes certain coal-fired power plants from receiving capacity payments, specifically those that do not meet requirements for energy consumption, environmental protection, and flexible adjustment capabilities. However, among the eligible plants, the existing framework does not differentiate payment levels according to other key drivers of profitability, such as unit age, fuel efficiency, and fuel costs (Hui, 2023). Incorporating these factors into the payment structure could make the mechanism more targeted and cost-effective, ensuring support is directed toward units that are both financially vulnerable and essential for grid reliability.
Second, China should explore a broader suite of capacity payment design options to improve efficiency and adaptability. Our analysis shows that coal profitability can decrease by up to 15% in 2035 in provinces with great potential for high-quality renewable resources, but increase by up to 8% in provinces with relatively lower-quality resources. Although nationwide coal run hours are expected to decline each year, the resource adequacy needs and operational patterns will continue to differ across grid regions and over time. This suggests that capacity payment mechanisms should be sufficiently dynamic to adapt to those grid changes, yet not overly volatile to undermine investment confidence. For example, annual fixed capacity payments may affect spot market bidding behaviors more than quarterly or monthly payments, and can be less effective without non-performance penalties. Key design dimensions, including update frequency, interannual variability, and the look-back period for assessing historical performance, should be carefully determined next. Moreover, assessing the capacity value of coal capacity could adopt a reliability-based approach, such as the Effective Load Carrying Capability (ELCC), given reliability standards, to ensure resources are compensated according to their actual contribution to resource adequacy.
In the longer timeframe, China’s capacity payment mechanism should evolve from its current administrative approach to a more market-based framework. A market-based approach can be more effective in revealing efficient price signals to ensure resource adequacy (Joskow, 2008). As resources other than coal power can also help meet the system’s capacity needs, the mechanism should be inclusive to all resource types, while reflecting their distinct technical-economic characteristics (Kahrl et al., 2021), such as asymmetric risk exposure (Mays et al., 2019). While there is no consensus on the optimal mechanism design, it is essential to systematically evaluate the available options, such as resource eligibility, reliability-based or performance-based, class-based or unit-specific, and average or marginal capacity value (Byers et al., 2018; Prete et al., 2024). Future capacity market design should adhere to key principles: competitive, non-discriminatory, enforcing non-performance penalty, and minimizing spot market distortions (Ming et al., 2023; RAP, 2023).
Finally, as China aims to reach carbon neutrality by 2060, it remains nebulous whether and how the expanding coal fleet will be efficiently utilized to support this transition. Coal-fired power plants, especially the retrofitted units that are less carbon-intensive, will play a critical role in contributing to resource adequacy and grid resilience, as renewable penetration rises. However, the policy framework for incentivizing coal retrofit decisions is still unclear. Going forward, the design of capacity payment mechanisms should consider the interaction with decarbonization policies, spot market reforms, and the national emission trading scheme, to ensure coal’s evolving role aligns with the long-term climate targets.
Suggested citation:
Zhang, Z., Zhang, Y., & Davidson, M. “Capacity Payments for Coal-fired Power Plants in China” Electricity Market Tracker, January 27, 2026, https://https://emtracker.org/research/capacity-payments-for-coal-fired-power-plants-in-china/