Energy Spot Price | August Proxy Electricity Price Rises 6.3% Month-on-Month: National Average Price is 0.3532 Yuan/kWh, Exceeding Seasonal Trends and Signaling a Reversal in the Power Market

On August 7th, as multiple provinces across the country released their proxy electricity purchase prices for August 2026, a set of data quickly became a focus of energy market attention: the national average proxy electricity price increased by 6.3% month-on-month, rising to 0.3532 yuan/kWh, with a single-month increase of 2.08 fen/kWh. In comparison, the year-on-year increases for the same periods in 2024 and 2025 were only 1.3% and 1.1%, corresponding to increases of just 0.41 fen and 0.48 fen/kWh. This month's month-on-month increase is four to five times that of the same periods in the past two years, clearly breaking the conventional seasonal upward trend of electricity prices during the "peak summer" period, and releasing a strong signal of a potential bottom reversal in electricity market prices. Why the electricity price curve "changed its tune" after an initial downturn? Looking at the trajectory within the year, this round of electricity price increases was not smooth. Since the beginning of the year, although the price of thermal coal rose, the arithmetic average of proxy electricity prices in each province continued to decline in the first half of the year due to the transmission lag between coal-fired electricity prices and coal prices. The turning point occurred in July—when proxy electricity prices shifted from a decline to an increase, and the month-on-month increase in August further expanded, forming a steep upward trend of "gaining momentum in the latter half." This "downturn followed by an upturn" trend precisely confirms the judgment repeatedly emphasized by the market: a bottom reversal in market-based electricity prices is continuously unfolding against the backdrop of rising energy costs. If 2026 is confirmed to be the bottom of the electricity price cycle, then looking ahead to 2027, electricity revenue is expected to move out of a deflationary range, and the profit bottom for various power assets will also become clearer, presenting an opportunity for a turning point upward. Regional Differentiation: General Rise in Central and West, Decline in Coastal Areas It is worth noting that this round of increases was not uniform; rather, it showed a distinct pattern of regional differentiation. In August, the month-on-month performance of proxy electricity prices was characterized by a general rise in Central and West China and a decline in coastal regions—the latter having seen significant increases in previous months and entering a digestion phase this month. Central China led the nation: Henan rose by 26.1%, Sichuan by 22.4%, Jiangxi by 11.9%, and Hunan by 9.4%; North China showed steady growth: Shandong rose by 12.8%, and Shanxi by 14.9%; Northwest regions led the increase: Gansu rose by 22.3%, and Shaanxi by 17.3%; Year-on-year, Henan rose by 10.8%, Shandong by 6.6%, Hebei by 5.0%, and Fujian by 0.6%. The mismatch in rises and falls between regions reflects the differences in the power generation structure, supply-demand patterns, and electricity price levels of different provinces. Central and western provinces have a high proportion of thermal and hydro power generation, making them more directly affected by water flow fluctuations and coal price transmission; coastal provinces, however, experienced a moderate decline in prices this month due to a faster rise in the initial price base and relatively abundant green power supply, which is considered a high-level digestion rather than a trend reversal. Three Factors Resonate: Coal Prices, Demand, and Reform The driving force behind the super-seasonal increase in electricity prices this round can be attributed to three levels. First, the upward shift in the coal price center initiated cost transmission. On August 5th, all three tiers of the CCI thermal coal index rose, with the 5500 kcal price reporting 839 yuan/ton, an cumulative increase of 39 yuan from 800 yuan/ton on July 10th, an increase of nearly 5%. The spot coal price in Qinhuangdao for 5500 kcal also rose to 823 yuan/ton, which is 171 yuan/ton higher year-on-year. Tightened safety supervision in production areas, coupled with declines in output and inventory, and tightening international coal prices, provided the most direct cost support for the electricity price increase.

Secondly, record summer demand is met

The demand side is also "firing at full power." In July, Guangdong's total social power consumption reached 100.798 billion kilowatt-hours, making it the first province in the nation to exceed 100 billion kilowatt-hours in a single month. On July 31, Jiangsu's power grid reached a peak load of 160.9 million kilowatts, becoming the first provincial power grid within the State Grid system to exceed 160 million kilowatts. The six major coastal power consumption days remained above 940,000 tons, and the pressure on power plant storage remains, with the tight supply-demand structure providing strong support for electricity prices.

Thirdly, power marketization reform deepens

Since the comprehensive rollout of the marketization reform for coal-fired power generation electricity prices in 2021, "agent power purchasing" has become a vital channel for industrial and commercial users to enter the power market. Users who have not directly purchased power from the market are served by power grid enterprises through unified agent purchasing, with prices announced monthly. The agent purchasing price comprehensively reflects the grid power price, ancillary service fees, and market transaction results, serving as a key window for observing the center of the power market price. As medium-to-long-term transactions, spot markets, and capacity pricing mechanisms continuously mature, the transmission of coal price signals to terminal electricity prices has become increasingly sensitive, and the expansion of this round of price increases is a manifestation of the effectiveness of the market-based pricing mechanism.

Industry Interpretation: Electricity Price Bottom Reversal, Deeper Dividend Logic

For the power industry, electricity price is a "lifeline." Over the past two years, under the dual squeeze of falling electricity prices and rising coal prices, the thermal power sector's performance has been under pressure, and the fund holdings of the public utility sector have dropped to 0.26%, the lowest since 2021, placing it in a historically low allocation state. This super-seasonal rise in agent purchasing prices is viewed by institutions as a critical node—a "clear signal of the electricity price bottom"—if the electricity price bottom is confirmed in 2026, electricity revenue in 2027 is expected to experience deflation, and assets such as thermal and hydropower are expected to achieve a "double boost" in performance and valuation, while the coal sector can also maintain outperformance through both volume and profit increases.

At the same time, the pace of green power installed capacity and consumption, and power system reform policies, remains an important variable influencing the long-term center of electricity prices. For investors, the electricity price inflection point signifies a deepening of the dividend asset allocation logic: not only do traditional high-dividend thermal and hydropower benefit, but green power operators with cost advantages and consumption guarantees will also gain clearer profit expectations.

Asia-Pacific Perspective: Electricity Price Signals Reshaping Regional Energy Landscape

Looking at the Asia-Pacific, changes in China's electricity price curve are not isolated events. In July, Laos's inflation rate rose to 7.6%, with a significant rise in electricity prices being the main driver, and energy costs are taking over from exchange rates as a new engine of regional inflation; Southeast Asian countries such as Vietnam and Indonesia are also facing pressure from tight power supply and demand and rising electricity prices. As a "Southeast Asian battery," Laos exports electricity to neighboring countries based on rich hydropower resources. The deepening of China's power marketization reform and the upward shift of the electricity price center are expected to help raise the pricing benchmark for cross-border green power trading in the medium to long term, and open up broader space for China-Laos power interconnection and ASEAN grid integration.

For investors monitoring the Asia-Pacific energy market, electricity price is not just a cost, but a cyclical signal. From coal price transmission and demand peaks to market mechanisms, every variable is reshaping the value coordinates of regional power assets. The trend of energy spot prices often precedes the valuation inflection point of assets and is worth continuous tracking.

(This article is compiled based on public market data and institutional research and does not constitute investment advice.)