National Development and Reform Commission: Further refine the time-of-use electricity pricing mechanism.

Recently, the National Development and Reform Commission issued a notice on further improving the time-of-use electricity pricing mechanism, stating that, while keeping the overall level of retail electricity prices broadly stable, it will refine the catalog-based time-of-use pricing system to better encourage consumers to shift peak demand to off-peak periods, enhance the balance between electricity supply and demand, and facilitate the integration of new energy sources. This move aims to support the development of a new type of power system dominated by new energy and ensure the safe, stable, and economical operation of the power grid.

(1) Improve the peak–valley electricity pricing mechanism.

1. Scientifically delineate peak and off-peak periods. All localities should comprehensively consider factors such as the regional electricity supply‑demand balance, system load characteristics, the share of installed renewable capacity, and system regulation capabilities. They should designate periods of tight supply‑demand conditions and high marginal generation costs as peak hours to encourage consumers to conserve electricity and shift or avoid peak demand; conversely, they should identify periods of ample supply and low marginal generation costs as off‑peak hours to facilitate the integration of renewable energy and guide consumers in adjusting their load profiles. In regions with a high proportion of installed renewable generation capacity, full consideration must be given to the variability of renewable output and the characteristics of the net load curve.

2. Reasonably determine the price differential between peak and off-peak electricity rates. All localities shall comprehensively take into account factors such as the local power system’s peak-to-valley difference ratio, the share of installed renewable energy capacity, and the system’s regulation capability, and accordingly determine an appropriate peak–valley electricity price differential. In areas where the projected maximum peak–valley difference ratio for the previous year or the current year exceeds 40%, the peak–valley price differential shall, in principle, be no less than 4:1; in other areas, it shall, in principle, be no less than 3:1.

(2) Establish a peak‑time electricity pricing mechanism. All localities shall, in light of their specific circumstances, implement a super‑peak electricity pricing mechanism on the basis of time‑of‑use pricing. The super‑peak period shall be determined reasonably according to the times when electricity demand reaches 95% or more of the local power system’s maximum load over the preceding two years, with flexible adjustments taking into account annual supply‑demand conditions, weather variations, and other relevant factors. The surcharge applied to super‑peak rates shall, in principle, be no less than 20% above the peak‑period rate. In areas where cogeneration units are prevalent or where renewable energy capacity accounts for a substantial share, and where temporary oversupply in the power system is particularly pronounced, a deep‑valley pricing mechanism may be established by analogy with the super‑peak pricing framework. Efforts should be strengthened to align and coordinate the super‑peak and deep‑valley pricing mechanisms with demand‑side management policies, thereby fully unlocking demand‑side flexibility and adjustment potential.

(3) Improve the seasonal electricity pricing mechanism. Daily electricity load or the balance between electricity supply and demand exhibits pronounced seasonal variations.   Localities should further establish and improve seasonal electricity pricing mechanisms, delineating peak and off-peak periods by season and setting appropriate seasonal price differentials between these periods. In regions where hydropower and other renewable energy sources account for a significant share, it is necessary to comprehensively consider the complementary nature of wind, solar, and hydro resources, and further develop and refine a pricing mechanism that reflects wet and dry seasons; during wet and dry periods, consideration should be given to multi‑energy complementarity based on long‑term trends in water availability,   Load‑following characteristics and other relevant factors should be appropriately categorized, and the electricity price fluctuation ratio should be set in line with system supply‑and‑demand conditions. Northern regions are encouraged to develop seasonal electric‑heating tariff policies that, by moderately extending off‑peak periods and reducing off‑peak rates, further lower the cost of clean heating and effectively meet residents’ winter heating needs.

Clearly define the scope of implementation for the time-of-use electricity pricing mechanism. All localities are to accelerate the expansion of the time-of-use pricing mechanism to cover all commercial and industrial electricity users, except for electrified railway traction power, which is subject to separate national regulations. For certain general commercial and industrial users for whom peak‑shaving is not feasible, authorities may consider establishing an average tariff—calculated as the average electricity price paid by time‑of‑use customers—and allow these users to opt in voluntarily. Local governments must not unilaterally suspend the implementation of the time‑of‑use pricing mechanism or narrow its scope, nor may they, under the guise of refining the mechanism, introduce preferential tariffs in disguise. Commercial and industrial consumers are encouraged to reduce peak‑demand loads and increase off‑peak consumption through measures such as energy storage deployment and integrated energy utilization, thereby lowering electricity costs by shifting their usage patterns. Where conditions permit, local authorities should, in accordance with established procedures, extend time‑of‑use pricing policies to residential customers and gradually widen the price differential between peak and off‑peak periods.

Establish a dynamic adjustment mechanism for time-of-use electricity pricing. Localities shall, based on changes in the local power system’s electricity demand or net load characteristics and with reference to time-of-use price signals from the electricity spot market, timely adjust the time-period segmentation and floating rates of the catalog-based time-of-use tariffs. In areas where the electricity spot market is operational, market trading rules should be refined, and capacity limits for renewable energy sources should be set appropriately.   In regions where the share of flexible resources is high and the power system faces pronounced, temporary oversupply, a deep‑valley pricing mechanism may be established by drawing on the peak‑load pricing framework. Strengthen the coordination and alignment between peak‑load and deep‑valley pricing mechanisms and demand‑side management policies to fully unlock demand‑side flexibility.

(3) Improve the seasonal electricity pricing mechanism. In regions where intraday electricity demand or the supply‑demand balance exhibits pronounced seasonal variations, it is necessary to further refine and institutionalize a seasonal pricing mechanism, delineating peak and off‑peak periods by season and appropriately setting the price differentials between them. In areas with a high share of hydropower and other renewable energy sources, it is essential to comprehensively account for the complementary nature of wind, solar, and hydro resources, and to further develop and institutionalize a pricing scheme that reflects wet and dry seasons; during wet and dry periods, consideration should be given to multi‑energy complementarity based on long‑term trends in water availability,   Load‑profile characteristics and other relevant factors should be appropriately categorized, and the electricity price‑fluctuation ratio should be set in line with system supply‑and‑demand conditions. Northern regions are encouraged to develop seasonal electric‑heating tariff policies that, by moderately extending off‑peak periods and reducing off‑peak rates, further lower the cost of clean heating and effectively meet residents’ winter heating needs.  。

Clearly define the scope of implementation for the time-of-use electricity pricing mechanism. All localities are to accelerate the expansion of the time-of-use pricing mechanism to cover all commercial and industrial electricity users, except for electrified railway traction power, which is subject to separate national regulations. For certain general commercial and industrial users for whom peak‑shaving is not feasible, authorities may consider establishing an average tariff—calculated as the average electricity price paid by time‑of‑use customers—and allow these users to opt in voluntarily. Local governments must not unilaterally suspend the implementation of the time‑of‑use pricing mechanism or narrow its scope, nor may they, under the guise of refining the mechanism, introduce preferential tariffs in disguise. Commercial and industrial consumers are encouraged to reduce peak‑demand loads and increase off‑peak consumption through measures such as energy storage deployment and integrated energy utilization, thereby lowering electricity costs by shifting their usage patterns. Where conditions permit, local authorities should, in accordance with established procedures, extend time‑of‑use pricing policies to residential customers and gradually widen the price differential between peak and off‑peak periods.

Establish a dynamic adjustment mechanism for time-of-use electricity pricing. Localities shall, based on changes in the electricity system’s load profile or net load characteristics and with reference to time‑of‑use price signals from the electricity spot market, timely adjust the time‑of‑use tariff schedule and the corresponding floating rates. In areas where the electricity spot market is operational, market trading rules should be refined, price caps should be set appropriately, and mechanisms should be put in place to ensure that the market generates effective time‑of‑use pricing signals, thereby providing a basis for the dynamic adjustment of the regulated time‑of‑use tariff framework.

Improve the implementation mechanisms for market-based electricity users. In regions where the electricity spot market has not yet been launched, it is necessary to refine the rules governing medium- and long-term market transactions and guide market participants to submit load profiles when entering into such contracts, thereby reflecting prices for each time period. In principle, the price differential between peak and off‑peak periods under the spot market should not be lower than that stipulated in the catalog‑based time‑of‑use tariff. If a market transaction contract fails to specify a load profile or does not establish time‑of‑use pricing, the purchase price at settlement shall be determined in accordance with the peak‑off‑peak time periods and the corresponding price‑fluctuation ratios set forth in the catalog‑based time‑of‑use tariff mechanism.

--Reprinted from “Henan Nonferrous Metals Brief, Issue 7”