Electricity prices have suddenly surged across multiple southern provinces; in Guangdong, prices approached RMB 1 per kWh several times in April. Why is this happening? Will prices continue to rise?

The winds from the Middle East have reached South China. As the world’s largest energy importer, China’s electricity prices—normally stable during the traditional off-peak season—have surged abruptly due to sudden external supply-side shocks. Meanwhile, local market pricing mechanisms, accustomed to inertia, failed to adjust swiftly, resulting in a temporary misalignment between supply and price. Only the confluence of these two forces can explain why the price volatility has proven so persistent—and this year’s early signs of an El Niño event only add further upward pressure on CPI. Let’s look at the data: since April 2026, spot electricity prices in China’s southern regional power market have spiked sharply across multiple provinces, with Guangdong experiencing the most dramatic surge. On April 7 and April 11, real-time spot prices hit RMB 0.976/kWh and RMB 0.978/kWh respectively—repeatedly nearing the RMB 1/kWh threshold. According to data from the Guangzhou Power Exchange Center, the average day-ahead spot price across the five southern provinces from April 1 to April 23 stood at RMB 468 per MWh (RMB 0.468/kWh), up 38% month-on-month. Guangdong’s average price soared even higher—to RMB 533 per MWh—more than double its level from the same period last year—breaking the historical pattern of relaxed supply-demand balance and stable pricing during spring. This anomaly can be initially attributed to the Middle East geopolitical conflict, whose ripple effects caused a sharp spike in imported fuel costs—the primary driver behind this round of electricity price hikes. Specifically, since March 2026, shipping through the Strait of Hormuz has nearly ground to a halt, leaving numerous tankers stranded in the Persian Gulf. This directly disrupted China’s LNG import supply chain. Guangdong Energy Group’s long-term LNG procurement contract with Qatar was suspended, and related LNG production facilities sustained damage. By mid-April, China’s comprehensive LNG import landed price had risen 9.38% month-on-month. Guangdong’s current power generation mix remains highly dependent on imported fuels: as of end-2025, coal-fired and gas-fired installed capacity accounted for 30.3% and 21.9% respectively—over 52% combined. Moreover, China’s electricity spot market employs a marginal clearing pricing mechanism: under tight supply-demand conditions, the last unit dispatched—the highest-cost gas-fired unit—sets the clearing price for the entire grid. Consequently, soaring gas-power generation costs are fully passed through to all consumers, dramatically amplifying price increases. This mechanism led to Guangdong raising its gas-power price cap from RMB 0.649/kWh to RMB 1.118/kWh in 2026—an increase of 72%, effectively lifting the ceiling on peak-hour electricity prices. On the demand side, trade-driven activities—including export surges and inventory restocking in Q1—have kept industrial electricity consumption at elevated levels. Guangdong’s total societal electricity consumption rose 7.57% year-on-year in Q1, and this upward trend continued into April.

Guangdong’s electricity spot price approached RMB 1 per kWh in April. On June 24, another piece of news emerged: the mandatory full-consumption mechanism is significantly driving up electricity prices across the southern market.

In April, Guangdong’s electricity spot market price approached RMB 1 per kWh several times. On June 24, another development emerged: the mandatory full-consumption mechanism is substantially inflating electricity prices across the southern market. Many people’s first reaction upon reading this news is frustration—“Electricity bills are going up again.” But let’s reframe it: this isn’t just a simple price hike—it’s a mathematical problem currently being solved, and the solution to this problem will decisively shape the energy storage industry’s trajectory over the next decade. 1 It’s not the electricity that’s expensive—it’s the last generating unit First, let’s clarify how this mechanism works. Guangdong’s electricity spot market uses a uniform marginal clearing pricing strategy: during centralized bidding, offers are matched from highest bid (buyers) to lowest ask (sellers); the price of the final matched pair sets the uniform clearing price, and all units are settled at that single price—not at their individual bid/ask prices. Put simply: whatever price the last unit dispatched to meet demand bids, that becomes the settlement price for *all* units. Crucially, it’s not an average—it’s the price set by the *most expensive* unit. This sentence is the key to understanding the entire situation. Under normal conditions, low-cost coal, hydro, and nuclear units cover base load, leaving gas units idle—so the clearing price stays low. But when system load peaks and gas units must be dispatched as the marginal unit, their high bid drags the entire market’s settlement price skyward. Guangdong fits this exact profile. As of Q1 2025, its cumulative installed generation capacity reached 227 million kW, with coal- and gas-fired units accounting for approximately 35.1% and 21.1% respectively, while pumped hydro and battery storage together made up only 4.9%. Gas-fired capacity exceeds one-fifth of the total—meaning that whenever wind and solar output plummets unexpectedly or demand spikes sharply, gas units are almost inevitably called upon as the marginal supplier. And because natural gas has a far higher marginal cost than coal, once gas units become the price-setter, the entire market’s settlement price surges instantly. This isn’t a one-off supply-demand imbalance—it’s an inherent structural feature of this pricing mechanism, destined to recur—and with increasing frequency. 2 Mandatory full-consumption: a double-edged sword Why will it happen more often? The answer lies in another key term: mandatory full-consumption. The original intent behind this mechanism is sound: given the intermittency of wind and solar power, grid operators are required to prioritize integrating renewable generation and minimize curtailment. Yet this mechanism carries a widely overlooked cost: when wind and solar output drops suddenly—say, during cloudy or windless periods—the system must rapidly fill the resulting gap to maintain supply reliability. The only resources capable of responding quickly enough are typically high-cost, fast-ramping gas units. In other words: the more thoroughly renewables are consumed, the deeper the system’s dependence on expensive marginal units—and the more volatile electricity prices become. This appears paradoxical but is logically inevitable: the more you insist on using *all* renewable generation, the more you rely on a costly, on-call backup—and that backup’s price determines the system’s final price. Such seasonal factors will increasingly—and more concretely—feed into commercial electricity tariffs. This isn’t alarmist rhetoric. It’s the mathematical inevitability built into this mechanism. 3 Only one thing can suppress such volatility

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