Sichuan, the most densely populated and industrialised province in south-west China, relies heavily on hydropower. This summer it was hit by extreme heatwaves and drought, causing reservoirs to dry up and the power system to suffer.
To keep power flowing to homes, the local government pulled the plug on factories for two weeks. But as the drought dragged on, household supplies were affected too.
Experts say the crisis highlights thorny and longstanding problems for China’s electricity reforms: inflexible markets, insufficient demand-side response, and a failure to tune and balance the power system. Together, these mean a drought can quickly cause electricity shortages. And the growing threat of climate change impacts may be more than the ageing system can handle.
China must decide: should it shore up the existing system with more coal and gas power or speed up its reforms?
Crisis
Sichuan is known as the province of a thousand rivers, counting 1,419 of them, large and small, within its borders. It also boasts diverse terrain, stretching from the heights of the Qinghai-Tibetan Plateau and the Hengduan Mountains down to the Sichuan Basin, with a fall of almost 7,000 metres between its highest and lowest points. That makes Sichuan ideally suited for hydropower, which now accounts for the lion’s share of its energy mix.
Hydropower accounted for 77.39% of the province’s total generating capacity of 114 gigawatts (GW) in late 2021.
In normal years, summer is the rainy season. Rivers rush east off the plateau and are channelled through turbines as they go, generating huge quantities of electricity. This isn’t just for Sichuan’s own needs. There is a surplus for export to Shanghai, Zhejiang and the other industrialised provinces in eastern China.
But climate change transformed this year’s rainy season into a drought, with rivers in the Yangtze Basin running dry when least expected.
In July and August, rainfall in the Sichuan Basin was half or more below usual levels. Meanwhile, temperatures were 2.3C higher than average between June and the end of August, the highest since full records started in 1961, according to the Sichuan Climate Centre.
Those historic highs meant new lows for hydropower generation. According to the Sichuan Daily, by 16 August, water in a number of important reservoirs had reached the “dead level”, meaning there was no longer enough to run the turbines. Hydropower generation was 50% lower than in the same period the previous year. Meanwhile, the hot weather had locals reaching for their air conditioning: the demand for electricity province-wide shot up 25% year-on-year.
The electricity system was overdrawn and at risk of collapse. If the load stays too high for too long, the grid can fail and cause widespread blackouts. Sichuan had no choice but to pull the plug on its factories. That continued until the end of August, when cooler air blew in from the north, pushing out the subtropical high pressure. Rain fell at last and the crisis drew to an end.
Coal power raises its head again
Some said the crisis could be blamed on an over-reliance on hydropower and that more thermal power plants were needed to ensure stable supplies.
Sure enough, after the shortages, the provincial government put policy incentives in place for new gas-fired power plants. In October, it issued a document saying it would make capacity payments to gas-fired plants that can regulate power at peak times, the first such statement in China. That would mean payments could be collected by a power plant even when it is on standby.
Since mid-July, Caixin reports that provinces including Guangdong, Anhui, Xinjiang and Guizhou have put building new coal power plants on their agenda. Total generating capacity when built, according to Caixin, would come to almost 17 GW. It looks like China may see a wave of coal power construction in the coming three years.
That trend can be traced back to September last year when several provinces were hit by electricity shortages. In the final quarter, approvals for coal power plants suddenly increased compared to the same period in 2020. Almost 20 GW of coal power plant construction was approved in the six months from October 2021 to March 2022, according to a Greenpeace briefing, which judged that the need to ensure supplies and energy security was now driving the electricity sector.
Yuan Jiahai, a professor at North China Electric Power University’s School of Economics and Management, told China Dialogue: “We have seen a lot of electricity supply issues these two years. What to do? If we build more coal power then it’ll be there when we need it, but utilisation rates will usually be very low. It’d be an ongoing waste in order to ensure we don’t see shortages in a crisis. For policymakers, security and stability come first.”
New coal power should always be the last choiceHuang Hui, NRDC, and Yang Fuqiang, Peking University
Yet, more coal power won’t necessarily make the system more secure. An unexpected jump in coal prices could also trigger a crisis.
That was what caused last year’s shortages: a disconnect between coal prices and power prices meant many coal power plants were losing money with every single kilowatt-hour of power they produced, so they shut down.
Moreover, coal power is no less vulnerable to extreme weather than hydropower. In July 2021, a downpour in Zhengzhou left the local electricity system reeling. A Yuneng Power plant to the west of the city flooded and was at risk of being unable to continue generating. The same downpour damaged the electricity infrastructure in Zhengzhou, Luoyang, Jiaozuo and elsewhere.
Any single piece of infrastructure can fall foul of unpredictable risks: a dry summer, a sudden downpour, or high coal prices. The question is, how do we ensure the system as a whole can stay safe and stable?
An inflexible system
Electricity systems have three connected stages: generation, transmission and distribution. This year’s problems in Sichuan were mainly caused by a large and sudden drop in generation. A simple solution would be to add more generating capacity to cover any fall. But the underlying problem is more complex.
Sichuan is China’s biggest exporter of hydropower, with one-third of its generation sent to places like Jiangsu, Zhejiang and Shanghai in the east, rather than meeting local demand. If it hadn’t been for those existing commitments, Sichuan could have kept the factory lights on.
Of the province’s 114 GW total generating capacity, 88.87 GW is hydropower, 18.25 GW is thermal power, and 7.23 GW is new energy. Even operating at half of the total capacity, Sichuan’s hydropower plants can generate 40 GW.
In China, new energy usually means energy produced from wind, solar, bio and nuclear sources.
Yuan Jiahai and others have calculated that with thermal power running at full capacity, as well as 3 GW of generation from new energy sources and 4 GW in electricity imports from elsewhere, Sichuan had a total of 65 GW of power. That is equal to the province’s peak demand, meaning balance could have been maintained.
However, cross-provincial electricity transfer agreaements (both under government instruction and as deals between grid operators) mean that a significant part of Sichuan’s generated power is sent east. At the worst point of the drought, only 23–25 GW of hydropower was available for local use, leaving a peak-time shortage of around 15 GW.
As well as the cross-provincial agreements, this situation is also due to the physical design of the grid and how the system works.“
“The cross-regional energy market is planned at the national level and designed and operated based on direct current, high volume and unidirectional transmission of power,” said Yuan Jiahai.
He added: “Such a grid design does not allow Sichuan to keep more power for itself. And the system as it stands doesn’t give Sichuan the authority to change planned transfers. When the crisis started, Sichuan declared a ‘Class I power supply emergency’ after approval from national energy supply and security authorities. Only after allocation of supply and demand at the national level was Sichuan able to keep more power for itself.”
Indeed, in China, investment and cross-provincial electricity dispatch is planned at the national level, with provincial authorities mainly in charge of implementing those plans, according to a 2019 report by the China Electric Power Planning and Engineering Institute. When things go off the rails, existing systems do not allow those in immediate control to respond quickly.
“It’s inflexible and lacks market mechanisms,” said Yuan Jiahai. “Long-term cross-provincial deals and trading schemes determined at the national level are set in stone, so there’s very little scope to make use of cross-provincial spot markets to improve the situation at the margin.”
Away from the supply side
In 2015, the State Council published a document on further reforms to the electricity system known as Document No. 9. It referred to a lack of market mechanisms and problems coordinating national- and provincial-level planning.
Yuan Jiahai said electricity trading should “send electricity wherever demand is highest”, similar to the bilateral and bidirectional agreements common in Europe but entirely absent in China. “In other words, our regional markets are lagging far behind.”
“The situation this summer showed how much room there is for more coordination in the existing system,” he said. If there were a regional market, he added, higher prices could have been used to encourage other provinces to fire up reserve capacity and allow Sichuan to retain more of its own electricity. That would have eased problems for the province and been much less damaging than the factory shutdowns. But the costs of doing this would need to be spread fairly. Under market mechanisms, Sichuan would have to be willing to pay more for power originally destined for export, prompting eastern provinces to use reserve generating capacity to meet their own needs.
“I think there’s a lesson here for government and market actors: electricity security and guarantees come at a cost, and low prices can’t necessarily be maintained under all circumstances.” But, he warned, the reforms cannot happen overnight. There will need to be a managed process.
Another problem is that the demand side is failing to respond to supply-side problems. Fixed electricity prices meant household demand remained high throughout that scorching August, with some homes running their air conditioning all day and night. In the end, industrial usage was sacrificed to maintain supplies for households.
“In a situation like that, how much reserve generating capacity would we need to ensure supplies if we don’t think about the demand side?” asked Yuan. Based on his calculations, adding 15 GW of reserve capacity – the amount needed to close the gap this summer – would require a huge investment and would only be used a few days a year. But if electricity users were persuaded to reduce demand, the gap could be shrunk by 7 or 8 GW. Regional markets could supply 4 or 5 GW of the remainder, requiring an investment on the supply side of only 2 or 3 GW.
Document No. 9 also calls for demand-side management to be used to balance supply and demand. The government is to use market reforms on both the demand and the supply side to maintain that balance.
And while the 14th Five Year Plan sets a target for demand-side management – demand-side response mechanisms should be able to shift 3–5% of peak load – market incentives to encourage investment in such mechanisms are lacking. Yuan Jiahai thinks the role of the National Energy Administration (NEA) is a major factor.
He explains that the NEA acts as a “power supply management agency”, rather than improving the overall system. There is no NEA department responsible for managing the demand side, which means that after two power shortages, China is still working to increase supply, rather than balance supply and demand.
So China should focus investment on electricity system reforms, build regional electricity markets, and develop demand-side response.
As Huang Hui, manager of NRDC China’s Climate and Energy Project, and Dr Yang Fuqiang, a research fellow at Peking University’s Institute of Energy, have written: “Whether it is to combat climate change, to achieve the dual carbon targets, or to make a return on investment, new coal power should always be the last choice.”
