Commentary: Why Electricity Prices in China’s Hydropower Heartland Turned Negative

Sichuan, China's hydropower hub, has encountered a unique power market crisis. On September 20, 2025, during a trial of its spot electricity market, the province saw negative electricity prices for an entire day, with the price sinking as low as minus 50 yuan per megawatt-hour and locked at this floor for most of the trading periods. This meant power plants not only gave away electricity for free but even paid to continue operations without shutting down—a phenomenon more common in coal-powered regions like Shandong or Zhejiang, but highly unusual for hydropower-dominated Sichuan, which should, in theory, have greater operational flexibility and resilience against such market anomalies. The event set a new national record for deep and prolonged negative pricing in the Chinese power market [para. 1][para. 2][para. 3].

Sichuan's power system relies heavily on hydropower, with 160 gigawatts of installed capacity, over 60% from hydro sources. Typically, such systems handle fluctuations efficiently by adjusting hydropower output. Common explanations like a simple supply surge or reduced demand do not suffice; Sichuan’s full-day negative prices require deeper investigation into market structure and operation [para. 3].

Analysis of public data and market processes points to key causes. Most significantly, Sichuan’s power market is highly fragmented, with many generation arrangements decided outside the marketplace. This lack of fluidity compresses the spot market, turning it into a mere “residual market” that bears the burden of inflexible generation and pushes prices into extreme territory [para. 4]. One main issue is the physical execution of long-term contracts: many generation units are obliged to continue producing or are centrally dispatched, regardless of market demand. Even when renewables exceed local consumption, out-of-market units (notably, coal-fired plants) maintain output, so the spot market becomes saturated with excess supply. On September 20, the province’s supply-to-demand ratio reached 1.5, and at least 20 GW of coal power remained online despite sufficient renewable generation—a rigid arrangement that sent spot prices plummeting [para. 5].

Additionally, these units could theoretically buy power to fulfill contracts instead of producing physically, but contractual inflexibility leads to artificial surpluses, a similar issue having caused negative prices elsewhere like in Shandong and Zhejiang during holidays [para. 6]. Market design flaws exacerbate the issue: with demand-side participants locked out early, negative prices don't attract extra consumption, so supply cuts and demand boosts—which would restore balance—never materialize [para. 7].

Another major factor involved full hydro reservoirs following heavy rainfall (up nearly 60% year-over-year). With little storage space left, hydro plants were compelled to generate even at a loss to avoid spillage, a disciplinary action not just economic, as spilling can affect flood control, irrigation, and operator evaluations [para. 8]. Discipline and administrative requirements therefore outweighed market signals, forcing generators to operate at a loss instead of rationally exiting during losses [para. 9].

Furthermore, excessive coal units were kept dispatching outside of market logic, sometimes to maintain grid stability or for administrative reasons. These rigid-generation mandates made negative prices inevitable and persistent [para. 10]. Some have speculated about 'mechanical failures' or the weakened incentives coal plants face due to secure long-term contracts, but these explanations are at best partial and likely unsustainable for long-term operation [para. 11].

Underlying these issues is a fundamental fragility in China’s power-management system: it struggles with near-real-time changes, locking in plans via contracts and dispatch orders well in advance, with little ability for dynamic adjustment. This causes mismatches between actual needs and supply—sometimes even resulting in exports during local shortages [para. 12]. Efforts to optimize dispatch and recognize these shortcomings have so far failed to address the root cause—outdated, inflexible scheduling and market design, leaving zero-cost hydropower underused and the system vulnerable to imbalances [para. 13].

["Author and note about third-party views omitted as per summary requirements."]