How a Power Surplus at the Height of Summer Shows How China’s Electricity Market Has Changed (AI Translation)

【周刊提前读】盛夏不缺电：中国电力供需格局深刻转变

1. Entering the peak summer season, unlike previous years characterized by power shortages and high prices, in 2025 electric prices across China's provinces have seen a pronounced decline. For instance, Guangdong, the nation's top electricity-consuming province, experienced spot market prices in July dipping multiple times below 0.3 yuan/kWh, with a weighted average price as low as 0.2377 yuan/kWh—nearly half of the local benchmark coal power price. Major power company Yue Dian Power A forecasted a staggering 96% year-on-year drop in net profits for the first half of 2025, attributing this to sharply lower power prices, increased power inflow from other regions, and intensified market competition as new units come online. The electricity sector nationwide has entered a period of excess supply, driven by ongoing power market reform, enhanced regional grid interconnection, large-scale integration of renewables, retreating coal prices, and a slowdown in electricity demand growth due to weakening exports and industrial adjustments. While lower prices benefit electricity users, especially commercial and industrial enterprises, power generators face new challenges regarding their long-term business models and investment returns amidst industrial transformation.[para. 1]

2. The downward trend in electric prices is widespread in 2025. According to data, except for Western Inner Mongolia, most spot market prices in early-adopting regions have fallen far below coal power benchmarks, with particularly steep year-on-year drops in places like Inner Mongolia (down 47.17%). Guangdong saw its annual long-term contract prices drop by nearly 30% over two years, coinciding with rapid expansion of its power generation capacity—up 15.5% in 2024, with wind and solar comprising 8% and 18% of capacity respectively. Demand, however, is lagging: Guangdong’s first-quarter electricity consumption growth slowed to 2.99%, while Shenzhen, the province’s largest consumer (dominated by electronics manufacturing), saw exports and industrial electricity usage contract. Similar trends are observed in Jiangsu, where overall power prices dipped below coal benchmarks in certain months, and rapid increases in renewable capacity accompany weaker demand. Inner Mongolia, having aggressively courted silicon PV manufacturing, is confronting declining industrial electricity consumption and negative year-on-year growth in its major industrial city Baotou. Nonetheless, its renewable installations have soared by 170% from 2020 to reach 135 GW. These supply-demand mismatches, including curtailment rates above 40% in some western regions, underscore the challenge of integrating abundant renewables.[para. 2][para. 3][para. 4]

3. Power prices are being collectively driven down by several converging factors: macroeconomic headwinds putting downward pressure on industrial prices and profits, overall slackening in electricity demand growth, historically low coal prices (with thermal coal at Qinhuangdao port dropping over 20% YTD to 620 RMB/ton by June 2025), and rapid, nationwide adoption of marketized electricity trading mechanisms. Spot market pricing has become more “nimble”, better reflecting real-time supply-demand balances. The acceleration of regional market integration, exemplified by the new Southern Regional spot market covering five provinces and reaching a daily trading volume exceeding the combined power use of the UK, France, and Germany, has also helped drive down prices across a larger geographic area. In high-renewables provinces like Shandong and Zhejiang, midday “negative pricing” events are frequent, indicating temporary but acute supply surpluses.[para. 5][para. 6]

4. Meanwhile, these market dynamics are squeezing the returns of renewable energy projects, causing many developers to delay or abandon planned investments—a trend seen in both Shanxi and Ningxia in July 2025. The recently issued “Document 136” mandates competitive market pricing for new renewable projects after June 1, 2025, further increasing revenue uncertainty and making local governments more cautious about setting support prices (“mechanism prices”) too high. Wherever renewable penetration rises, system balancing costs go up: every 1% increase in renewable share is estimated to increase system costs by about 0.01 yuan/kWh. Though user electricity prices have generally declined (e.g., in Gansu, prices fell by 0.08 yuan/kWh after market reforms), the growing costs of balancing services may gradually offset these savings. Aggressive reforms are making power prices more transparent and flexible, benefiting large users in the short term but transferring more of the costs of energy transition to all market participants in the long term.[para. 7][para. 8][para. 9][para. 10]

5. As market complexity and volatility increase, there is a growing call for better information disclosure and user participation in power market design. The government also encourages new business models (such as virtual power plants) to harness flexibility and balance supply and demand. Ultimately, the transition towards high-renewables grids, market-based pricing, and integrated regional markets is likely to continue driving structural shifts in China’s power sector, with continued challenges for generators but ongoing pressure and opportunities for lower electricity costs for end users.[para. 11][para. 12][para. 13]