Heilongjiang Has Zero Electricity Prices for 13 Consecutive Days: The Dilemma of “Rigid Power Demand” Amid High Shares of New Energy

In December 2025, an unprecedented event unfolded in Heilongjiang’s electricity market: for 13 consecutive days, the hourly electricity price remained at zero throughout the entire day.

Although, since the liberalization of the electricity market, we no longer find zero or even negative electricity prices surprising, a situation in which electricity prices remain at zero for more than ten consecutive days is nonetheless astonishing.

Cause Analysis

From the perspective of power system operation, this extreme phenomenon is not triggered by a single factor; rather, it arises from the combined effects of supply-side structural changes, operational mechanisms, and seasonal characteristics.

First, during the heating season, a large number of thermal power units operate under combined heat and power (CHP) mode, which is a fundamental factor underlying the sustained decline in electricity prices. The centralized heating system in northern China imposes rigid constraints on heating supply security; under the “heat‑first, power‑second” operating principle, unit output is primarily determined by heat demand rather than by market price signals.

During the heating season, heat demand from residential and public buildings persists around the clock, forcing cogeneration units to operate continuously 24/7. Even when the power system is clearly experiencing a supply surplus, there is little room on the generation side to proactively reduce output. As a result, cogeneration units accumulate substantial “rigid electricity” in winter, which proves difficult to dispatch efficiently through market mechanisms.

Secondly, the substantial output of wind power during winter has significantly increased the intensity of new‑energy supply. Unlike solar PV, wind power in Heilongjiang exhibits a pronounced winter peak, characterized by high wind speeds and prolonged durations; while its output fluctuates considerably, its overall level remains relatively high. With heating demand already locking in thermal‑power generation, the large‑scale, concentrated dispatch of wind power further constrains the system’s flexibility for ancillary services. When wind power enters its peak generation period, the shortage of adjustable resources is rapidly exacerbated, driving electricity prices downward—sometimes even into the zero‑price range.

Third, the high share of new energy has amplified the impact of the preceding factor. In recent years, Heilongjiang’s new‑energy sector has experienced rapid growth, with its wind‑power installed capacity now ranking among the highest in the country. On December 29, 2024, with the grid connection of Phase III of the National Photovoltaic and Energy‑Storage Demonstration Platform (Daqing Base), the province’s total new‑energy installed capacity increased further. By that date, the province’s total new‑energy generation capacity had reached 25.17 million kilowatts, accounting for more than 50% of the region’s overall power‑source capacity and, for the first time, becoming the largest source category in terms of installed capacity.

By October 2025, Heilongjiang Province reported that, since the start of the 14th Five-Year Plan, the province’s new energy sector has achieved leapfrog development, with its installed capacity surpassing that of coal-fired power for the first time in history. As of the end of September 2025, the grid-connected installed capacity of new energy reached 31.494 million kilowatts, up 149.6% from the end of the 13th Five-Year Plan, and its share of total installed capacity had risen to 57.9%.

While the installed capacity is expanding rapidly, there are certain lags in developing grid peak‑shaving capabilities, power transmission channels for outbound delivery, and market mechanisms to absorb renewable energy. As a result, when new energy sources release large volumes of power within short time windows, the system’s carrying capacity falls short, and price signals fail to promptly reflect actual supply‑demand conditions.

Finally, overall winter electricity demand remains subdued, weakening the market’s ability to absorb excess supply. Unlike heating loads, which exhibit strong rigidity, industrial electricity consumption does not scale up in tandem during the winter; many high‑energy‑intensive sectors are either undergoing maintenance or operating at reduced capacities, while emerging load segments such as electric heating and electric vehicles have yet to achieve sufficient scale to provide meaningful support. With limited demand‑side flexibility, a concentrated release of supply-side capacity is more likely to translate into a rapid decline in prices rather than a natural increase in demand.

Cogeneration or decoupling?

The core contradiction revealed by the sustained decline in electricity prices points to an unavoidable issue: under conditions of high‑share integration of new energy sources, the conventional operation model of combined heat and power (CHP) can no longer meet the requirements of the emerging power system, and thermal‑electric decoupling is shifting from a “voluntary option” to an “essential requirement.” This does not imply a rejection of CHP’s historical value; rather, it underscores the need for a fundamental shift in its development logic and technological pathways.

For a considerable period, combined heat and power (CHP) was the dominant option in northern China’s energy system. In 2016, five government departments, including the National Development and Reform Commission and the National Energy Administration, jointly issued the Measures for the Administration of Combined Heat and Power, explicitly designating it as a key tool for advancing air pollution control and enhancing energy efficiency. Against this policy backdrop, demand for centralized heating in northern regions grew rapidly, while the environmental challenges posed by decentralized coal‑fired heating became increasingly acute. CHP, with its centralized heat supply and cascaded energy utilization, came to be regarded as the “optimal solution” that balances efficiency and environmental protection.

Under the aforementioned management measures, cogeneration units must adhere to the fundamental principle of “sizing electricity generation to heat demand,” meaning that power generation is subordinate to heating load requirements. Accordingly, power generation is not a market‑driven activity but rather a byproduct of ensuring reliable heat supply. This approach offers distinct advantages: the waste heat generated during electricity production is utilized for urban district heating or industrial process heat, resulting in an overall primary energy utilization efficiency of 70%–85%, significantly higher than that of conventional condensing units. Meanwhile, centralized heating systems are characterized by strong stability and high degrees of scale, long serving as a stabilizing anchor within the heating infrastructure of northern urban areas.

However, as the structure of the power system undergoes fundamental changes, this advantage is increasingly turning into a new constraint. With the rapid expansion of renewable energy capacity, the power system’s demand for flexible regulation has risen sharply, yet conventional combined heat and power (CHP) units inherently lack such flexibility. Constrained by rigid heat‑supply requirements, these units must maintain a relatively high and stable output during the heating season, making it difficult to respond promptly to fluctuations in electricity supply and demand.

Relevant technical studies indicate that, under the conventional “heat‑first, power‑second” operating mode, cogeneration units have very limited capacity for peak‑shaving. Taking Guoneng Energy Conservation Company’s research on thermal‑electrical decoupling technology for coal‑fired steam turbine units as an example, the maximum peak‑shaving capability of a single conventional cogeneration unit is only about 50%, far below the deep‑peak‑shaving requirements of systems with a high share of renewable energy. When wind and solar power generate at full capacity during specific time periods, cogeneration units are unable to effectively cede generation capacity, forcing the grid to rely on passive measures—such as lowering electricity prices or even setting them to zero—to achieve balance.

It is against this backdrop that thermal‑electric decoupling has been increasingly placed on the policy agenda. Far from merely abolishing cogeneration, thermal‑electric decoupling employs technologies such as heat storage systems, electric boilers, heat pumps, and energy storage to separate the heating supply system from the power generation side, thereby enabling generating units to achieve greater flexibility in electricity dispatch while ensuring reliable heat supply. Its core objective is to shift from a “heat‑driven power” paradigm to one of “coordinated heat‑and‑power operation and flexible dispatch.”

It is foreseeable that, as the share of new energy sources continues to rise, the operating dynamics of the power system will irrevocably shift toward greater flexibility. In this context, conventional combined heat and power (CHP) plants, if they remain locked in their traditional operating modes, will find it increasingly difficult to integrate into the market framework. Consequently, decoupling heat and power generation is no longer merely a matter of technological upgrading; it has become a systemic choice that bears on heating‑supply security, the absorption of renewable energy, and the stable functioning of the electricity market.