China goes rogue on new coal

Summary

China waved through a new generation of coal-fired power plants in response to power shortages, despite chronic underutilisation of existing capacity

Extra capacity is seen as an insurance policy, but this is an expensive and ineffective way of propping up an inefficient system

65% (240 GW) of China’s new coal pipeline are in power-exporting provinces, with already low utilisation rates indicating a misallocation of capital

TransitionZero estimates that half of China’s operating coal fleet was lossmaking in 2022, even with conservative assumptions

China needs more transmission lines and better regulation to incentivise efficient use of existing resources and infrastructure – not more redundant coal capacity

China is embarking on a headlong expansion of its coal fleet. The country is accelerating deployment of coal-fired generators in the hope of preventing more summer power shortages, despite a growing body of evidence showing the financial costs of operating the existing fleet. To avoid wasted capital on plants which will be highly underutilised, there is an urgent need for meaningful market reforms.

New data from the Centre for Research on Energy and Clean Air (CREA) and Global Energy Monitor (GEM) reveal that China’s coal expansion is single-handedly reversing progress being made across the rest of the world on coal plant retirements.

Excluding China, the world pivoted decisively away from coal in 2015, since then operational plant capacity has fallen by 124 GW. But China erased that progress, adding 277 GW over the same period. This is like retiring every coal plant in Southeast Asia and Australasia, but simultaneously doubling the number of operational plants across all of Western Europe and the Americas.

The result is a global net increase in coal capacity of 153 GW since 2015, equivalent to tripling the installed coal capacity across Africa (50 GW) in eight years.

Judging by China’s bulging coal project pipeline, the amount of capacity being commissioned will surge even higher over the next few years. Plant permitting, construction starts and new project announcements all raced ahead in 2022. New permit issuance hit an eight-year high of around 100 GW, and the amount of capacity that broke ground in China was six times larger than the rest of the world combined.

Why is China doing this?

Chinese energy planners are on high alert after two consecutive years of power shortages, load shedding and blackouts. An initial wave of outages in 2021 shuttered factories and left hospitals and homes in the dark across 20 provinces, prompting officials in Beijing to order provincial authorities to shore up grid stability.

Their efforts did not prevent a repeat occurrence in summer 2022, when an extreme heatwave spiked air conditioning power demand and reduced hydropower availability. Provinces that import electrons from hydro-rich regions such as Sichuan experienced severe shortages, and in response fired up thermal power plants to keep the lights on. As previously highlighted by TransitionZero, relying on water-cooled thermal plants during a drought exacerbates water stresses at the worst possible time.

Coal remains the bedrock of Chinese industry. Manufacturing prowess underpins China’s place in the world, so the forced closure of factories due to power shortages was seen in Beijing as a national security issue that required an immediate and complete solution.

For provinces that were burned by reliance on their neighbours, a natural response was to turn their back on inter-provincial power exchanges and seek shelter in self-sufficiency and energy security. On the face of it, coal offers that in abundance; China is sitting on 13% of the world’s total coal reserves according to BP’s Statistical Review. The result was record numbers of new coal plants being permitted and breaking ground.

Surplus to requirements

However, opting for new generation capacity and dialling down inter-provincial power trading is the precise opposite of what China needs. The country is already lumbered with significant overcapacity and the existing fleet suffers from very low utilisation rates, so these new coal plants are unlikely to generate much electricity.

Across China, average coal plant utilisation remains low at 55%, well below the 70% that a typical baseload fleet should be operating at¹. TransitionZero analysis finds that based on the current rate of utilisation and provincial power demand growth forecast, it will take between 2-19 years for current operating coal capacity to reach that 70% utilisation benchmark across all provinces. When the new-build pipeline is taken into account the picture looks even more stark — it will take up to 25 years in certain provinces for the utilisation rate to reach standard baseload levels.

And yet instead of ramping up coal burn in its existing fleet, China continues to build more new capacity. There are still 365 GW of coal-fired power plants at various stages of development in China’s pipeline.

Given the current coal buildout is driven by energy security concerns, we would expect to see the distribution of the new pipeline capacity skewed towards the power-importing provinces. But this isn’t borne out in the data. Only 41% of pipeline plants and 52% of under-construction plants are located in these provinces. Looking at the whole pipeline, nearly 65% (240 GW) of upcoming plants are located in power-exporting provinces. Given they are already exporting power, we can assume these provinces are not at risk of shortages. Based on TransitionZero’s analysis, these investments are unnecessary, owing to the already low utilisation of existing plants, the underutilisation of interprovincial transmission lines, and the large capacity being constructed in the power-importing provinces. Taken together, this trifecta clearly indicates a misallocation of capital.

Some China-based experts see the coal expansion as an insurance policy. New coal plants will run only when demand surges and renewable output dips. Framed this way, low utilisation could be spun as a positive outcome. But this fails to grasp a key challenge undermining the efficient operation of Chinese coal generators: misalignment of incentives.

It is not unusual for coal plants to shut down when they are most needed. The root of the problem is China’s awkward mix of variable fuel input costs and fixed or inflexible revenues from generation tariffs.

During periods of market tightness and high demand, the cost of coal rises as more thermal generators are called upon to balance rising grid loads. But electricity tariffs do not always allow generators to pass these costs on to power offtakers or end-consumers. This incentivises plant operators to shut down or schedule maintenance, rather than firing up and incurring financial losses.

In short, China could double its coal generation capacity and still endure blackouts unless perverse incentives embedded in the current regulatory framework are weeded out.

Deep in the red

Low utilisation rates and loss-making tariff structures are a recipe for financial losses, and Chinese coal companies are all too familiar with this unholy trinity. Previous analysis by TransitionZero found that an increasing number of units in China’s coal fleet may be struggling to cover their operating costs and the vast majority could be shut and replaced at a saving to consumers. TransitionZero estimates that roughly one-quarter of China’s coal fleet was in the red in 2020. The outlook has since grown even more bleak, with an increasing number of the coal fleet operating in the red in both 2021 and 2022.

Coal prices have more than doubled from January 2020 to December 2022. However, the benchmark electricity tariff for coal plants has remained unchanged since 2019, with the exception of an expansion of the floating range to 20% in either direction announced in October 2021. Even with the conservative assumption that all provinces benefited from the 20% increase in tariff price, TransitionZero analysis estimates that half of China’s coal fleet continued to operate in the red in 2022.²

Even while coal plants are facing losses, electricity demand has not decreased. As a result, the government is forced to spend billions of yuan bailing out coal power companies in order to ensure continued electricity supply to its citizens. The tariff adjustments are a step in the right direction towards reducing government subsidies for coal fired power plants, but more changes are required in order to reduce the amount of government funds propping up this costly and polluting industry. In the face of these losses and continued underutilisation of coal plants, we estimate the cost of planned expansion of coal capacity will reach between $200-300 billion dollars³.

The quest for system adequacy

China will need to retain some coal capacity as backup for renewable intermittency and seasonal variations in power demand while it transitions to a cleaner and more flexible power system. The key question is, how quickly can coal be tapered down without jeopardising system reliability?

With wind and solar deployment growing exponentially in China, and coal plant economics already extremely challenged, there is a risk that dispatchable capacity is retired in a disorderly fashion. Zero-marginal cost renewables depress in-province clearing prices and erode coal plant running hours, which exacerbate financial losses and accelerate closures.

Without policy intervention and adequate resource planning, system reliability could be further eroded. For this reason, Beijing is expected to broaden its capacity compensation mechanism that pays coal plants for their availability, regardless of how much electricity they actually generate. This is similar to capacity mechanisms in force in the UK and other parts of Europe.

One modelling study concluded that the faster China decarbonises its grid, the more coal it would need to keep in reserve propped up by capacity payments. By 2050, China could need between 125 GW and 240 GW of coal capacity in operation and in reserve, with the higher figure attributed to more aggressive renewables deployment. These volumes of reserve capacity could cost between 1.84 and 2.17 trillion yuan ($267 and $391 billion) in cumulative capacity payments.

This capacity range equates to roughly 9% to 16% of China’s total portfolio of operational and planned coal plants. China currently has 1,093 GW in operation, 115 GW under construction, and a further 250 GW in the pre-construction/permitted phase. If China builds out this pipeline and maintains its very low retirement rate, then the operational fleet could swell to almost 1,500 GW in the coming years.

Assuming that capacity payments will be the principal financial mechanism for supporting this expansion, the cost could be an order of magnitude greater than the figures cited in the modelling study. This presents a real risk that, without robust regulatory oversight, the capacity mechanism will balloon into an unsustainable subsidy for coal plants that deliver zero or negative system value and are ripe for closure.

Is there a cheaper way?

The study cited above did not consider inter-provincial generation structure, power transfers or transmission topology on long-term expansion of the power sector. It was also limited by data availability and granularity.

This is a major shortcoming because China is still curtailing off significant volumes of wind power generated in resource-rich, sparsely populated western and northern interior regions. At the same time, transmission lines connecting these regions with load centres on China’s industrialised southern and eastern seaboards are often underutilised due to a lack of incentives to trade power between provinces.

There have been signs of improvement in recent years but the curtailment problem persists, which suggests that policy intervention is required. A positive first step would be a central edict mandating provincial power trading, followed by reforms to allow market-based inter-province transfers, price discovery and settlement.

Power sector liberalisation is happening in a few provinces such as Shandong, which recently allowed wholesale power prices to turn negative in response to soaring rooftop solar PV deployment. But liberalising inter-provincial power trade has not kept pace. This means renewables can be constrained by negative prices within-province, and denied access to higher prices in neighbouring provinces that are contending with a demand surge or supply deficit.

Economic dispatch versus political economy

China is also yet to overcome a more basic regulatory obstacle to efficient use of existing resources: the switch from administrative to economic plant dispatch decisions. The country is still transitioning away from an “equal share” approach to one based on economic principles.

Under equal share, thermal generators of the same class are allocated an equal amount of annual producing hours, regardless of efficiency. Reforms are underway to roll out economic dispatch, whereby plants with the lowest costs are called on to generate first. This is akin to the merit order approach widely used in market-based power systems.

Economic dispatch would dramatically improve curtailment rates. The International Energy Agency estimates that nationwide combined wind and solar curtailment would drop to 5% in 2035, compared to 33% under the status quo. This would deliver operational cost savings of approximately 11% or $45 billion per year and cut power sector CO2 emissions by 15% (650 million tonnes per year). Other studies show that economic dispatch would deliver substantial health benefits.

Unfortunately, the rollout of economic dispatch is running into challenges of political economy. Income from power generation within one province is directly related to its fiscal income, which is an important indicator for measuring the top leaders’ political performance. Acquiescing to economic dispatch could jeopardise the career prospects of governors in provinces with the most costly, inefficient coal plants.

Big challenges, big rewards

Building out more coal is quick and easy, but ultimately an exercise in futility because it exacerbates systemic inefficiencies. Liberalisation of China’s internal power market is a more challenging undertaking because it confronts existing power structures and threatens the market power of incumbent vertically integrated monopoly utilities.

The path of greatest resistance promises the greatest rewards. China is a continent-sized country, which gives it a huge advantage over other countries when it comes to integrating wind and solar. Liberalisation and regulatory reform can enable market-based solutions to structural inefficiencies, opening a route to market for clean resources that are today assigned zero value by market failings.

Ultimately, Beijing will need to force through difficult reforms at the provincial level if it is to align its power system with China’s net zero by 2060 target. Doing so will deliver huge economic benefits along the way and avoid a wholesale misallocation of capital that would be better spent on improving power sector efficiency and flexibility.

Notes:

1. Utilisation rates are derived from NBS reported province level thermal generation, and disaggregated based on installed capacity of coal and gas at the province level as reported by GEM.

2. 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). 2021 data is based on coal tariff data as of September 2021. 2022 revenue data assumes that a 20% increase in tariffs is applied across the board in all provinces, a conservative assumption given the NDRC’s statement in October 2021. The LRMC includes: fuel, variable (VOM) and fixed (FOM) operating costs. Fuel costs are obtained from WIND and SXCoal. 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.

3. TransitionZero estimate based on 365 GW and a conservative $0.5M/MW to $0.8/MW electricity price.