In September 2020, the People’s Republic of China announced targets of peaking economy-wide carbon emissions before 2030 and achieving carbon neutrality before 2060.

With national emissions equivalent to approximately one-third of the global total, these commitments are some of the most significant ever made in the global response to climate change. China’s power generation is approximately 60% reliant on thermal power, the majority of which is coal-fired.

To achieve its climate targets, China must therefore transition away from a reliance on coal towards low-carbon alternatives. China has led the world in the deployment of wind and solar, bolstered by the strong financial case for renewables over coal. However, recent data indicates that c.200 GW of new coal capacity is currently under construction or in various stages of permitting, with 50GW beginning construction in 2022 alone[i].

If all planned units are completed, they will join a fleet already suffering financial stress and are unlikely to recover investment costs over their operating lives. The poor financials indicate that the motivation for these investments is to ensure security of supply, driven by a series of supply crises during 2021-2022, but the scale of planned capacity additions is at odds with China’s stated emissions targets, particularly if these plants operate as baseload generation.

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Key Findings

  • China’s planned investments in over 200GW of new coal capacity could lead to between US$26-US$40bn of value destruction via asset stranding. Allowing all planned units to be completed entails significant financial risks and could increase the costs of timely power sector decarbonisation. To reduce stranding risk, all planned coal units not absolutely critical for grid balancing or district heating should be cancelled or mothballed. Stated commitments to prevent the construction of additional baseload coal capacity should be more stringently enforced.
  • Existing grid management and power trading arrangements entrench incentives for provincial governments to invest in local thermal capacity to meet growth and volatility in power demand. The prevalence of inflexible, long-term power trading arrangements inhibits more dynamic regional transfers, pushing local energy planners towards investments in local coal to ensure security of supply. Facilitating more price discovery and flexible inter-provincial trading should be a key near-term priority of ongoing power market reforms. Expanding channels for shorter-term power trading and flexibility, such as via interprovincial spot markets, could unlock latent potential in China’s grid and reduce incentives for new coal investments.
  • Technological retrofitting of coal units for greater flexibility could have significant positive implications for emissions reductions, renewables integration and system stability. However, it is unclear that sufficient economic incentives always exist for coal plants to invest in technologies that enable a transition from baseload to flexible generation. The potential emissions reductions and improved system value achieved through the technological retrofitting program warrants its expansion to all feasible units. Out-of-market revenues from expanded ancillary service markets and the implementation of competitive capacity markets should be prioritised to provide greater financial incentives for operating coal units to transition to more flexible roles, expediting the decline of baseload coal and power sector emissions.