CURRENT TENSIONS

As the shortages began to take a toll on industrial production, from October a number of provinces including Zhejiang, Hunan and Guangdong raised trading electricity prices, and allowed prices to rise and fall between peak and low load times for industrial users. 　

A State Council executive meeting on October 8 announced that it will allow more flexibility in the range of fluctuations for the market price of electricity, which previously limited it to a maximum 10 percent rise or a decrease of 15 percent. Now, the price can fluctuate 20 percent up or down, on the precondition of ensuring the stability of electricity prices for households, agricultural and non-profit institutions. And the limit of 20 percent upwards in prices could be removed for high energy-consuming industrial consumers. Four days later, the National Development and Reform Commission (NDRC) said all industrial and commercial users of coal-fired power will orderly enter the market and buy electricity at market-driven prices, signaling the country is taking an essential step toward liberalizing its electricity pricing. 　

“Entering 2021, coal prices soared and stayed high... operating costs for coalfired power plants of the power grid has gone beyond the breakeven point and surpassed benchmark electricity prices severely. The companies have great difficulty keeping the business running and some are already suffering broken cash flows,” said the appeal signed by 11 leading power enterprises and their branches, including Datang International Power Generation and China Huaneng Group, on behalf of 48 coal-fired power enterprises which feed into the Jingjintang grid, part of the State Grid in North China that covers Beijing, Tianjin and northern Hebei Province. 　

The situation is miserable, as described in the letter to the BMCUM, which says all companies are running at a loss due to high costs mainly caused by surging coal prices. The coal stockpile is inadequate and of low quality, which has hindered generation capacity and severely affected electricity transaction and supply. The letter called to raise the transaction price and adjust the prices of long-term power supply contracts in the Beijing area for the winter. 　

Materials provided by Beijing Electric Power Industry Association (BEPIA) to NewsChina confirmed the letter’s content. By the end of July, all five power enterprises under BEPIA were operating at a loss mainly caused by rising fuel costs. Of the five, Zhuozhou and Sanhe thermal power plants lost the least, each losing 20 million yuan (US$3.1m) and 30 million yuan (US$4.6m) in July. Hardest-hit Jinglong Power lost 192 million yuan (US$29.7m) in the seven months. For Jinglong Power, the cost of coal was 334.99 yuan (US$52) per megawatt hour (MWh) while the benchmark electricity price is 326.88 yuan (US$51) per MWh. 　

Yuan Jiahai, a professor at the college of economy and management at North China Electric Power University, told NewsChina that apart from fuel, power plants pay for water, pollution discharge, maintenance and suffer capital depreciation. He calculated that given the current price of coal, around 1,000 yuan (US$154.5) per ton, up from 671 yuan (US$104) per ton, coal-fired plants lose 0.15 yuan (US$0.023) for each kilowatt-hour (kWh) of electricity they generate. Over long-term contracts the plants surrender even more profits, losing at most 0.25 yuan (US$0.038) per kWh. The more electricity they generate, the more they lose, unless the loss is passed on to consumers. 　

Coal accounts for about 60 to 70 percent of overall costs for a power station. In the first seven months of 2021, the price of coal surged. Jinglong Power bought coal at 825 yuan (US$128) a ton in July, double the price of 411 yuan (US$64) a ton in the same period of 2020. The BEPIA said the price of coal purchased by four other plants under the association also rose by 45 percent in July year-on-year. 　

Lin Boqiang, director of China Institute for Studies in Energy Policy at Xiamen University, Fujian Province, said the rise in coal prices is mainly due to post-pandemic economic recovery and seasonal factors. 　

Electricity use has increased as the postCovid Chinese economy continues to recover, which pushes up demand. In February, the China Electricity Council predicted total electricity consumption would increase 6-7 percent this year. But statistics from the National Energy Administration show that between January and July, consumption rose by 15.6 percent year-on-year, far beyond estimates. In addition, raw coal production dropped in March, April, June and July, as China is gradually reducing reliance on coal in favor of renewable energy sources and optimizing its energy mix. In August, surging prices drove coal production to rise again. Decreased imports of coal in the first half of 2021 also tightened supply. 　

Abnormal summer weather exacerbated the power supply shortfall at a time when electricity use peaks. Summer rains fell more in the north, resulting in a reduction in production in the south where hydroelectricity plays a bigger role. More pressure fell on coalfired power to meet demand, Lin said. He also cited the rise in bulk commodities prices and a corruption campaign in coal-rich Inner Mongolia Autonomous Region that targeted business such as mines and other coal-related firms as having contributed to the surge in coal prices. 　

Yet the increased cost of coal cannot be passed on to end users, which is highly regulated as it concerns the national economy and livelihoods. In addition, China’s electricity price is lower than average. China’s average electricity price was 0.611 yuan (US$0.09) per kWh, while that for the 35 OECD members (excluding Israel) in 2019 was 1.029 yuan (US$0.16) per kWh, according to statistics from State Grid. 　

In 2004, the government put forward a coal-electricity price linkage mechanism in an attempt to ease the tension. If coal prices rise more than 5 percent within half a year over the previous period, then electricity prices are adjusted by the NDRC. Since then, China has raised power prices several times. But sometimes the adjustment was not quick enough, leading to huge losses among power enterprises and criticism of the mechanism. 　

In 2019, China abolished the 15-year-old linkage policy and adopted a more flexible pricing system which uses the benchmark price and allowed margins for electricity prices to float. This involves direct trading between power generators and big industrial end-users like high energy-consuming industrial consumers, such as coal and iron and steel, allowing fluctuations of at most 10 percent up and at most 15 percent down based on the benchmark price. 　

When the system came into effect in January 2020, the notice stipulated that the electricity price should not go up in 2020 to ensure the price for industrial consumers would not rise. “But so far, it’s proved much easier to lower the price than raise it,” Lin said. 　

The benchmark price, determined by the on-grid tariff at which the power grid buys from power plants, was fixed in 2019, and is far from reflecting current coal prices. But since the linkage policy was abolished, the government cannot casually raise the benchmark price against the backdrop of a marketoriented reform of the pricing mechanism. “That will probably stir market worries about a return to the era when the government takes full control of the price,” Yuan noted. 　

Besides big end-users that directly buy electricity from power plants, most smalland medium-sized (SMEs) enterprises that are the bedrock of the Chinese economy rely on buying from State grid companies. If the benchmark price is raised, consumer prices go up, translating into a direct increase in cost for SMEs which is then passed on to customers. 　

Knowing the difficulty of allowing the benchmark price to float, the 11 power companies appealed to allow trading prices to float instead, hoping that the BMCUM would allow them to raise the trading price on the basis of the benchmark price. NewsChina learned that on September 2 Beijing Electric Power Industry Association also sent a letter to the BMCUM, backing up the 11 companies’ appeal. But up to now, there is no clear feedback from the BMCUM yet. 　

In 2017, four major power groups including China Huaneng Group and China Huadian Corp in Ningxia Hui Autonomous Region, together with other companies, wrote to local authorities hoping they would reduce the constantly rising coal prices. In 2018, the four power groups submitted reports to the NDRC again to cut coal prices. At that time, the coal stockpiles of many power companies in the Jingjintang area, Northeast China and Inner Mongolia were lower than the minimum usually allowed due to high coal prices. 　

Some of the requests were responded to while others were not, which is decided by the economic environment at the time, Lin said. “But generally speaking, compared with raising electricity prices, the government is more willing to reduce coal prices. After all, a big jump in electricity prices will increase costs for all industries and businesses,” Lin noted. 　

“Particularly this year, the rising price of bulk commodities has already impacted middle and downstream companies. If the electricity price rises in line with coal prices, the effect on these companies and the overall economy would be obvious, which may cause them to fail,” Lin said. 

In July, the NDRC put in place measures to crack down on hyping the issue to the public with news of coal price rises and malicious bidding up of coal prices, and ensuring supply, including approving permits for previously suspended coal mines. Lin estimated that coal prices would drop following these measures, particularly as the season of peak electricity use has already passed. In this sense, the BMCUM probably will ignore the 11 companies’ demand to raise electricity prices. But as China has opened its trading market for carbon dioxide emissions, there are expectations that the pricing mechanism for electricity will improve, Lin said. 　

Yuan pointed out that coal prices are unlikely to drop much as the winter heating season approaches in northern China. He suggested the government remove the limits on rises over the benchmark price and let the market determine how much the price should float.” 　

Observers see this as having the least impact on the economy, as the “benchmark price plus fluctuations” system mainly targets big industrial users that directly sign medium or long-term contracts with power plants. Most SMEs and households that buy electricity from power grids will not be directly affected. 　

Some places have already started to increase the trading price as coal prices kept soaring. In July, Inner Mongolia allowed the power price in western Inner Mongolia to rise by the maximum 10 percent over the benchmark price, following large-scale losses in the coal-fired power industry. In August, Ningxia released a similar notice. 　

Now that coal prices have gone far beyond expectations, the government should act, particularly as the reform on the electricity market and power pricing mechanism has entered a crucial stage, Yuan said. 　

If electricity prices rise too much, it will be hard for the government and society to bear. But it is not appropriate to let coalfired power enterprises shoulder the burden alone as it will threaten their survival, Yuan said. “If the situation continues, coal-fired power enterprises will be up against it for several years. It is too big a blow to a fundamental industry that concerns the national economy and people’s livelihoods,” Yuan said. “The government needs to strike a balance.”