Measuring the Impact - China’s coal fleet is becoming more flexible, but much of its potential remains untapped

Available evidence suggests that current implementation of coal power retrofitting is broadly aligned with the government’s objectives. The 2025 national target for coal power flexibility retrofit was achieved three years in advance, and the country is on track to meet its remaining 2027 goals.

Early signals at both national and provincial levels indicate that coal utilisation is beginning to decline. However, these trends remain uneven and require careful interpretation, given wide variations in local system conditions, policy implementation and retrofit progress across regions.

Crucially, while the technical flexibility of China’s coal fleet has expanded rapidly, its full potential is not yet reflected in system operations. Market design, dispatch practices and institutional arrangements continue to shape how and to what extent coal flexibility is activated in practice.

China has made steady progress in upgrading its coal fleet during the 14th Five-Year Plan period (FYP, 2021-2025). According to the China Electricity Council (CEC), 360 GW of existing coal power capacity was retrofitted for flexibility by the third quarter of 2024. Combined with newly built plants over the last decade, China’s total flexible coal power capacity exceeded 600 GW by the end of 2024.

The progress has not only exceeded the original 2025 target, but also positions the country to meet its 2027 goal of maximising fleet flexibility. The China Electric Power Planning and Engineering Institute (EPPEI) estimates this will require retrofitting 500-700 GW of coal power units by 2027. Given the acceleration observed during the 14th FYP period, reaching this range appears technically achievable.

While flexibility retrofits were introduced during the  13th FYP (2016-2020), progress before 2020 was modest compared with the rapid expansion during the 14th FYP period (2021-2025). This shift reflects the growing need for system flexibility over the past five years, as renewables penetration accelerated after 2020.

During the 13th FYP, wind and solar curtailment was largely addressed through a combination of grid expansion, enhanced cross-provincial power trading, and the introduction of the Renewable Portfolio Standard (RPS).

Since 2021, however, the scale of renewable expansion significantly accelerated, increasing the urgency of having more flexibility in the system.

Progress has varied across provinces. Guangxi has retrofitted 84% of its coal power units as of September 2025, placing the southern province among the fastest in China. Among major coal-producing regions, Inner Mongolia had retrofitted 51.43 GW of its coal capacity by 2025, almost 70% of the units that require upgrading. Shanxi reports that it has retrofitted more than half of its fleet for flexibility. Xinjiang had completed 36.83 GW by the end of 2024.

Together, these developments indicate strong implementation momentum, while also highlighting remaining retrofit potential through 2027.

Over the past two decades, China’s utilisation of its coal fleet has generally declined, reflecting structural shifts in its economic and energy systems.

National coal capacity factor (CF) peaked at around 75% in 2005, when coal power units operated as the backbone of the electricity system and underpinned rapid economic growth.

Utilisation then declined steadily, reaching a low point in 2016, largely due to coal over capacity. Policy reforms introduced in the same year to address this overbuild led to a partial recovery, with coal CF rising to 56.3% by 2018.

Coal utilisation increased again in 2021 as electricity demand rebounded during the post-pandemic economic recovery, and remained elevated in 2022 with the government’s emphasis on energy security following power shortages and extreme weather events.

More recently, coal utilisation has resumed its decline. Rapid growth in wind and solar has pushed their combined installed capacity beyond that of coal, while policy encourages coal power to operate more as a flexibility support.

Looking ahead, coal utilisation is expected to continue declining through the 15th FYP period (2026-2030) and beyond, as renewables deployment continues to accelerate.

Compared with the previous low coal utilisation point (2016-2018), the current period (2023-2025) shows greater month-to-month variation in coal utilisation rate. This suggests that coal is now used less consistently across the year than during the last low-utilisation period, which was largely driven by overcapacity in the fleet.

Decomposition of the drivers of this change shows that increased variability is primarily linked to stronger seasonality in electricity demand, with significantly higher summer peaks in recent years. Wind and solar generation further contribute to short-term fluctuations, although their seasonal complementarity mitigates the effect. The main offsetting factor is hydropower’s summer peaking pattern, which matches demand well.

It is important to note that the decline in coal utilisation remains relatively modest and recent, indicating that there is still significant scope to further activate flexibility within the existing coal fleet. This potential is explored in more detail in Chapter 3.

At the provincial level, thermal power utilisation trends vary, reflecting differences in retrofit progress and local conditions, including energy resources, policy frameworks and socio-economic structures. These variations provide useful insights into the effectiveness of policy approaches in changing coal utilisation.

Provinces that have advanced more rapidly on retrofitting have seen faster declines in coal utilisation. Guangxi, for example, where more than 80% of the coal fleet has been retrofitted for flexibility, has seen a marked reduction in utilisation, with coal CF falling by 19.6% between 2023 and 2025.

2.4.1 Cost structure of flexibility retrofits

The cost of retrofitting coal units for flexibility depends on factors such as unit age, capacity, automation levels, technical design and operational expertise. According to the China Electricity Council (CEC), retrofit typically costs between 500 CNY ($71.8 USD) and 1500 CNY ($215.2 USD) per kW.

Beyond upfront capital expenditure, flexible operation introduces additional costs. These include higher operation and maintenance expenses, accelerated depreciation resulting from more frequent low-load operation, increased wear and tear, and more frequent component replacement. Reduced operating hours further lower revenues by lowering electricity sales.

Operating at lower load levels also reduces fuel efficiency. Coal consumption per unit of electricity generated increases as load falls – by around 10% at a 40% load, 20% at a 30% load, and by nearly 60% at a 20% load. When coal power plants operate primarily as flexible load-regulation resources, operators must absorb these efficiency losses in their cost.

Low-load operation also introduces higher safety risks and greater uncertainty over plant lifetimes, further shaping operational decisions.

2.4.2 Revenue models and policy support

To strengthen the business case for the use of coal as flexibility support, the government has introduced supporting policies, including the coal capacity pricing mechanism, alongside dedicated funding programmes to mobilise capital for retrofit projects.

Under China’s current framework, coal power revenues from electricity sales derive from three main components:

• Electricity payments: payment based on electricity generated and sold.
• Capacity payments: compensation for maintaining available capacity to ensure system adequacy, regardless of utilisation.
• Ancillary services payments: additional income for services such as load regulation, frequency regulation and reserve provision.

As China advances towards its long-term carbon neutrality goal, companies are encouraged to explore new revenue models. In practice, many companies, particularly large state-owned enterprises (SOEs), have begun diversifying into renewable energy and other energy storage projects.

The government has further promoted joint ventures between coal power and renewable energy companies. This approach has been particularly encouraged in regions such as Inner Mongolia, where both coal resources and renewable potential are abundant, aiming to sustain the long-term business model of local coal power companies.