China is feeling the burn

China’s energy complex is under considerable pressure, due to economic growth and supply shortages. Domestic thermal coal prices have rallied 30% since January this year¹. These fuel price rises have made the vast majority of China’s operating coal fleet cash negative. Based on TransitionZero estimates, the percentage of profitable units has declined from 67% in 2020 to 29% in Q2 of 2021. These estimates appear to corroborate what local newswires have reported. According to Beijixing news, out of 10 listed coal electricity companies, four reported losses and five others saw first-half profits collapse².

Domestic coal prices are above the unofficial government target zone of ¥500-570 per tonne. To what extent officials can intervene to reduce prices remains to be seen, given their ban on Australian thermal coal. Coal electricity companies have tried to get around the Australian ban by importing coal from Indonesia, Russia and the US, which is causing the price of these contracts to surge. This price volatility dwarfs any economic impact from the recently launched national emissions trading system, which is currently trading around $5t/CO2³. High fuel prices also add to the relative uncompetitiveness of coal power. For instance, based on previous TransitionZero analysis, with comprehensive electricity market reform, the switch from coal to renewables could be negative $20/tCO2.

Notes:

This analysis is based on a series of reasonable assumptions and should not be misconstrued as company data. Net profitability is defined as revenues minus the long run marginal cost (LRMC). Revenue data is based on coal tariff data as of January 2021. The LRMC includes: fuel, variable (VOM) and fixed (FOM) operating costs. Asset and ownership data is from Global Energy Monitor’s global coal plant tracker. Fuel costs are obtained from WIND. FOM costs are averaged $10/kW for all units. Assumes no carbon price. Fuel and revenues are assumed to be unhedged. Company analysis is based on an unweighted average and only includes those units wholly owned by the parent. See Turning the Supertanker for more information on our modelling methodology.

Pricing paradox

While commodity prices will continue to go up and down with investment cycles and geopolitics, China’s coal electricity companies are structurally underperforming both economically and financially. Two-thirds of the fleet may be struggling to cover their operating costs and the vast majority of operating coal could be shut and replaced at a saving to consumers. Moreover, blackouts and brownouts have been prevalent in 2021, despite the coal fleet only operating around half the time⁴ and coal generators scheduling maintenance during a time of supply shortages⁵.

What is causing these investment and operational contradictions? This situation can be explained by policy incentives and underscores the need for further electricity market reform.

China’s rapid economic growth, demographic profile and geographical size has meant it previously made sense for the government to build power infrastructure first and ask questions later. Although these policies supported impressive growth and helped meet the energy needs of the rapidly developing country, they are unsuitable for China’s next phase of economic development. To support its economic growth, China needs to create an efficient, solvent and flexible electricity system. Despite progress on electricity market reforms, there are still substantial inefficiencies, stemming from policies established in previous decades that prioritised rapid growth in coal capacity and rewarded companies with guaranteed operating hours at generous tariff prices.

Blackouts and brownouts have also highlighted a key issue with electricity market reform. According to newswires, the electricity shortages are partly a result of coal plants scheduling maintenance, due to high fuel prices⁶. Since coal generators only get paid an inflexible benchmark tariff, the more they generate, the more money they lose. As such, coal electricity companies have an incentive to shut down which helps reduce financial losses, but exacerbates supply shortages. This is the opposite of what would occur in deregulated markets. Wholesale power prices in the EU, for instance, are at all time highs as coal and fossil gas prices have rallied⁷. In an effort to start rectifying this situation, the NDRC recently introduced flexible electricity pricing⁸.

Moreover, while there is likely significant latency in China’s electricity system - as the coal fleet is only operating half the time - electrons cannot get to where they are needed due to the regional scope of reforms. To integrate large amounts of variable renewable energy, it will be essential to move away from a province-by-province approach to operating the electricity system. China is a world leader in ultra-high voltage transmission, but the utilisation rate of these assets is currently 40%⁹. China is a continent-sized country, meaning that if supply and demand were balanced over a larger geographical area, they would likely increase the utilisation of efficient coal and reduce the uncertainty of wind and solar generation. The Southern Grid region is scheduled to become China’s first regional market, but timing is unknown¹⁰.

Net zero crackdown?

Solving these issues, along with the possible inflexibility associated with contracting and spot markets, will be key to China’s transition to a carbon neutral economy¹¹. Due to the importance of electricity in decarbonisation, these reforms are time sensitive. According to the IEA, no additional new final investment decisions should be taken for new unabated (i.e. CCS-unequipped) coal plants today¹².

While efforts are being made to reform its electricity sector, progress is too slow. One reason for the delay is consensus-based policymaking, which results in reluctance to overturn entrenched industry interests. Latest announcements suggest a move towards a proactive system approach, rather than reactive provincial action¹³. It is for this reason that we believe policy reforms could come in the form of a series of crackdowns. Recent crackdowns in the technology and education sectors are a timely reminder of how the central government can shift policy decisively and comprehensively. How and when these crackdowns will occur is unknown. Indeed, it remains to be seen whether the government will allow markets to dictate investment and retirement decisions once reform is complete. What is clear, is that recent fuel price volatility highlights the urgent need for reform either via consensus or crackdown.

Footnotes:

1. Based on WIND data.
2. BIX (2021), Is the coal-fired power and cogeneration in the northern region in the red?
3. Due to free allocations, the traded price is rarely what regulated entities actually pay. Regarding China’s ETS, those efficient coal generators whose units operate under the carbon intensity benchmark will pay a negative carbon price, meaning they now have an additional revenue stream from burning coal.
4. TransitionZero (2021), Turning the Supertanker.
5. China Power (2021), High coal prices lead to an increase in temporary maintenance at power plants.
6. See footnote 5.
7. Clean Energy Wire (2021), Power market price highest since 2008 due to high gas, coal and ETS prices.
8. NASDAQ (2021), China to allow electricity prices to rise by during peak hours.
9. Jiemian (2020), The utilization rate of UHV lines in the "Three Norths" is only 40%.
10. RAP (2021), Unwinding Finance for Coal Power in China: The Role of Power Sector Reform.
11. We have various concerns ranging from the concentration of participants in spot markets to the process and conditions underpinning the medium- and long-term contracts.
12. IEA (2021), Net Zero by 2050.
13. Carbon Brief (2021), China issues new ‘single-game’ instructions to guide its climate action.