Discussion - Unleashing coal’s flexible potential while easing the transition to cleaner solutions

China’s determination to reposition coal as a flexibility provider has accelerated retrofit activities across its fleet, putting the country on track to meet its 2027 goals. As China enters the 15th Five-Year Plan (FYP, 2026-2030), two structural challenges are coming into focus.

First, the scope for further retrofitting is inherently limited. By 2027, retrofit potential is expected to be largely exhausted. Sustaining flexibility gains without expanding coal capacity will therefore depend on the rapid uptake of clean flexibility solutions, particularly battery energy storage.

Second, despite the expansion of flexibility capacity, much of its potential remains underutilised. These constraints are less linked with physical capacity than with power market design, dispatch practices and system operations.

China aims to establish a unified national power market by 2030, with core structures and key mechanisms in place by 2025. Market-based trading has expanded rapidly, 64.0% of electricity consumption was traded on the market in 2025, up from just 16.9% in 2016. The 15th FYP represents a critical window to align market rules and regulations with the evolving power system.

Looking ahead, the International Energy Agency (IEA) estimates that nearly 60% of China’s flexibility needs in 2030 could be met by non-fossil resources. Managing this shift to clean flexibility will be essential to deliver meaningful emission reductions while maintaining a secure, renewables-led power system.

To date, China’s existing coal fleet has served as a reserve to meet rising flexibility needs. However, the remaining retrofit margin is narrowing under current timelines. As a result, clean flexibility, newly coal capacity and pumped hydro combined are set to make up a growing share of China’s flexibility. Meanwhile, the demand for flexibility will continue to rise. Wind and solar capacity is set to expand rapidly well beyond 2027. China targets 3600 GW of wind and solar by 2035, actual deployment is likely to exceed this goal.

If battery energy storage deployment, along with pumped hydro expansion and other flexibility options, such as demand response and interconnection, fails to keep pace, the system risks falling back on additional coal capacity that may be underutilised. This would increase the risk of locking in emissions beyond 2030 and prolonging the fossil fuel use plateau.

Coal also faces inherent technical limitations. Compared with battery energy storage, coal power cannot reach similarly low minimum load levels or match ramping performance, while carrying higher operational and safety risks.

Policy direction is increasingly aligned with cleaner alternatives. China has already installed almost half of global battery energy storage capacity.

In September 2025, the government released an action plan setting a target of 180 GW of “new energy storage” by 2027, a category that is defined dominantly by battery energy storage.

As of the end of 2025, after the strong growth in December, China had already installed 144.7 GW of new energy storage capacity, putting the country on track to soon surpass its 2027 target ahead of schedule. China Energy Storage Alliance (CNESA) now projects new energy storage capacity (dominated by batteries) to reach 371.2-450.7 GW by 2030.

The beginning of 2026 also sees positive policy momentum for battery energy storage, as the January policy from NDRC and NEA opens up the capacity pricing mechanism to the technology, recognising the value of its capacity for the first time, and providing additional incentives for energy storage operators.

The challenges of expanding coal flexibility and sustaining clean flexibility growth reflect the wider system pressure.

These dynamics are closely linked to structural issues that the government has sought to address through rounds of power market reform since 2015. Electricity pricing still does not consistently reflect underlying supply and demand conditions, and dispatch decisions remain partly administrative. China’s reform agenda signals a shift towards a more market-oriented power system.

The year 2025 marks a milestone in this transition, as China aims to establish the foundation for a unified national power market. Reform momentum has accelerated, including the transition of wind and solar projects towards market-based pricing, and a faster timeline for spot market development.

3.2.1 Ancillary service market

China’s ancillary service market is evolving from an administratively managed add-on into a core component of the power market structure. Unlike most mature electricity spot markets with stronger price signals, load regulation is remunerated in China as an ancillary service.

Over time, policy has shifted from non-remunerated ancillary service provision to pilot market mechanisms, and more recently, towards formal integration with spot and mid- to long-term (MLT) markets. Reform directions also point to a growing role for emerging actors and clean flexibility technologies in providing ancillary services.

Evidence from more advanced regional markets highlights the impact of this approach. In China’s northeast grid region, including Heilongjiang, Jilin, Liaoning and eastern Inner Mongolia, the coal capacity factor has remained below the national average for the past decade, with a sharper decline in recent years.

This trend is notable given the region’s high heating demand and large share of combined heat and power (CHP) units, which typically face greater operational constraints. Lower utilisation is closely linked to the region’s early introduction of an ancillary service market in 2014, which provides financial incentives for power plants to operate at reduced output.

To maximise the role of ancillary service markets in unlocking system flexibility and integrating clean flexibility sources, reform momentum must be sustained through the 15th FYP (2026-2030). Priorities include expanding market-based mechanisms, covering the full range of ancillary services, strengthening links with spot and MLT markets, and improving cost allocation arrangements.

3.2.2 Inter-provincial market integration

China has been investing heavily in its high-voltage direct current (HVDC) network to transfer power from resource-rich western and northern provinces to eastern coastal demand centres.

While current HVDC technology can operate at utilisation rates as low as 10%, institutional and market arrangements continue to constrain the efficient use of this infrastructure and its supporting flexibility.

Transmission planning and market design remain partly misaligned, many corridor decisions reflect earlier development models that prioritised local generation and long-term contracts. Since inter-provincial trade is still dominated by these inflexible contracts, imported electricity remains largely inflexible, limiting the scope for dynamic adjustment as local supply and demand shift.

Progress towards a unified national power market offers the opportunity to unlock system-wide flexibility. In 2025, notable steps were taken towards this vision – in July, the NDRC and NEA introduced a policy to enhance trading between the State Grid and China Southern Grid regions; in December 2025, the two ministries issued a new policy on evaluation and regulation to support a fully integrated market.

3.2.3 Power system operation

Dispatch practices continue to constrain flexibility. Economic dispatch – allocating generation based on marginal cost – is not yet fully implemented to ensure the system operates cost-effectively, and coordination with the spot market remains limited.

In addition, the current dispatch mechanism requires excessive reserve and lacks a dynamic mechanism to manage load and renewable forecast. As a result, the system tends to carry reserve surpluses, keeping many coal power units online and limiting renewable integration.

Transmission constraints further restrict efficiency, as certain lines receive dispatch priority. This causes power flows to follow fixed routes rather than responding to market signals, diminishing the ability of the system to optimise across regions.

China is taking decisive steps in this direction. In February 2024, the NDRC and NEA issued a policy highlighting smart dispatch capacity building, and in December 2024, China released an action plan for 2025 to 2027 to enhance flexibility and optimise power system dispatch. Deeper alignment between market design and dispatch practice will be essential to fully unlock flexibility.

From the 13th (2016-2020) to the 14th FYP period (2021-2025), China’s policy has steadily repositioned coal power from a baseload to a provider of system flexibility. Government strategy and mandates have reinforced this role shift, prompting rapid retrofitting across the existing coal fleet and overcoming significant technical challenges in the past decade.

Yet the progress has revealed its limits. Coal’s flexible potential remains only partially realised. Market and operational constraints continue to limit the extent to which retrofitted coal can respond dynamically to system needs.

At the same time, the scope for further flexibility gains from existing coal units is narrowing. By 2027, the existing fleet will be mostly retrofitted and coal is technically less capable than emerging clean flexibility options, particularly battery energy storage.

This tension has sharpened policy urgency. The past 13th and 14th FYP periods also represent the decade of the latest round of power market reform in China. In 2025, a series of new policies and regulatory measures accelerated power market reform. Continued reforms in these directions are able to not only unlock the flexible operation of coal units but also integrate a broader range of clean flexibility technologies.

As China approaches the 15th FYP and the critical milestone of 2030, coal use is nearing a structural plateau. Transition in the upcoming five years will require a coordinated effort to reduce reliance on coal as a baseload and accelerate clean flexibility deployment. Without addressing persistent market and regulatory constraints, the system risks reverting to the easier option of building new coal, jeopardising energy transition targets and delaying emissions reductions.

A power system dominated by renewables will require two parallel efforts: fully utilising the transitional flexibility embedded in the coal fleet and rapid scaling of clean, market-driven flexibility solutions.