This is an extract from a recent report “2025 China Power Market Outlook: 10 Key Trends for Market Players” by RMI. This extract reviews key developments and market dynamics for the period from early 2024 to present in power market construction and pricing system development.
Twenty-nine provincial grids are (trial) operating power spot markets, with spot prices falling due to lower coal price, more renewables, and looser supply-demand balance
Since the end of 2023, development of the power spot market has accelerated significantly, with trial or official operations now underway in 29 provincial grid regions nationwide. After Shanxi and Guangdong took the lead in transitioning from spot market trial operation to official operation at the end of 2023, Shandong, Gansu, and West Inner Mongolia followed and started official operation in June 2024, September 2024, and February 2025, respectively.
In addition, Hubei, Zhejiang, Anhui, and Shaanxi all transitioned from short-/long- term trial operation to continuous trial operation in 2024. At the regional and national levels, the State Grid Interprovincial Spot Market officially launched on October 15, 2024, after more than two years of continuous trial operation — marking a key milestone in the maturity of China’s unified multi-level market model in the State Grid region. In November 2024, the China Southern Power Grid Regional Spot Market — covering Guangdong, Guangxi, Yunnan, Guizhou, and Hainan — completed its first full-month trial. It remains the fastest-advancing regional power market in China.
Except for the State Grid Interprovincial Spot Market, provincial spot markets with continuous (trial) operations saw further price declines in 2024, driven by lower thermal coal prices, a higher share of renewables, and a relatively loose supply-demand balance. Average spot prices fell year-on-year by 31 RMB/MWh (8.9%) in Shanxi, 108 RMB/MWh (24.3%) in Guangdong, 46 RMB/MWh (13.0%) in Shandong, 55 RMB/MWh (18.2%) in Gansu, and 100 RMB/MWh (16.5%) in West Inner Mongolia. Hubei and Zhejiang, which began continuous trials in April and May 2024, saw average prices drop 11.3% and 12.2% below their coal power benchmark prices, respectively. In the interprovincial market, average temperatures during the flood season (April 1–October 23) rose by 2.06°C year-on-year, with frequent heatwaves and autumn droughts in the eastern part of Southwest China and the middle reaches of the Yangtze River. From August to November, spot prices reversed earlier declines, with the clearing prices in August and September more than doubled year-on-year — pushing the annual average up by 15.2%.
Three main factors contributed to spot price trends: First, the price of thermal coal continues to decline. Second, the share of renewables in the power system continues to increase. Third, the supply-demand tension of electricity loosens. Meanwhile, new renewables capacity is expected to exceed 300 GW (360 GW in 2024), while the growth rate of electricity consumption is expected to remain at around 6% (6.8% in 2024). Therefore, competition on the power generation side in the spot market may be more intense.
Buyers now have greater flexibility in allocating shares across M2L transactions, whose prices closely follow thermal coal and spot market trends
M2L transactions remain the dominant component of China’s power market, with steady growth in recent years. In 2024, bilateral M2L volumes reached 4,650 terawatt hours (TWh) — up 5% year-on-year — representing 47% of total electricity consumption, 98% of which transacted within provincial markets. Participation has broadened beyond coal and renewables to include stand-alone storage, VPPs, pumped hydro, and nuclear, reflecting a more diverse and dynamic market.
The 2025 M2L transactions highlight varying provincial annual contract shares for wholesale buyers, with several regions easing shares limit. Fourteen provinces continue to mandate annual contract shares of 80% or more, while six regions — Qinghai, Sichuan, East and West Inner Mongolia, Shanxi, and Ningxia — have reduced the minimum to 60%–70%. Nationally, the “2025 M2L Contract Execution Notice” by NDRC and the National Energy Administration (NEA) allows provinces where renewables and hydropower exceed 40% of generation mix to relax annual contract shares limit: from above 80% to above 60%. These adjustments are subject to regulatory approval and comprehensive assessment.
The relaxed annual contract shares limit reflects the inapplicability of applying coal benchmark price to an energy market with growing renewable penetration. Coal power generators are typically required to secure at least 80% of their coal supply through long-term contracts. Aligning this with an equivalent proportion of M2L electricity contracts minimizes exposure to market risk. In contrast, the inherent variability of renewable output makes long-term contracting less predictable. As a result, provinces generally apply more flexible contracting requirements for renewable generators compared to coal plants. In addition, with the continued growth of renewables, it is expected to see more relaxed limits on annual contract shares and more sub-annual transactions, such as monthly, intramonthly, and multiday transactions.
Looking ahead, as market participants improve their trading capabilities and spot market development progresses, the integration between spot and M2L markets will deepen. For shorter-cycle M2L products (e.g., intramonth or multiday trades), the closer proximity between trading and delivery dates provides more accurate forecasting inputs, making price and volume predictions easier. These products are expected to align more quickly with spot market price limits.
Capacity pricing restructures the revenue stream of conventional power plants; a new capacity tariff adjustment could further lower thermal power’s capacity factor
2024 marked the first year of coal power capacity pricing. On the generation side, the capacity tariff reconstructed the revenue model of coal power plants to adapt to the energy transition. On the electricity user side, the coal power capacity fee embedded in the system operation fee began to become an important part of the electricity cost, though it has not yet significantly affected the users’ electricity bills. For coal power generators, the capacity tariff shifted the revenue model from purely energy-based to a two-part structure, combining energy and capacity revenues. In 2024, it is estimated that the introduction of coal power capacity tariff converted on average about 6.4% of the generator’s revenue into capacity revenue.
In areas where the capacity tariff is 100 RMB/kW per year, the proportion of capacity revenue in the total revenue (i.e., energy revenue and capacity revenue) is mostly in the range of 3% to 7%, with an average of about 5%; in areas where the capacity tariff is 165 RMB/kW per year, this proportion is 6% to 16%, with an average of about 10%. From a regional perspective, coal power operators in the southwest, northwest, and northeast regions are currently more dependent on capacity revenue, but the reasons for the high dependence in the three regions are different.
The southwest region is mainly affected by the level of capacity tariff setting: the capacity tariff in Sichuan, Chongqing, Yunnan, and Guangxi is priced at 165 RMB/kW per year, resulting in the capacity income share generally approaching or exceeding 10%. The northwest region is mainly affected by the energy market price. Due to the relatively low price in the energy market, the total revenue is relatively low compared to other provinces, making capacity income a larger share by comparison. The northeast region is mainly affected by the capacity factor. The relatively low-capacity factor reduces the income from selling energy, thereby increasing the proportion of capacity income in the total income.
For electricity users, the coal power capacity fee is generally 0.010–0.030 RMB/kWh, with an average level of about 0.019 RMB/kWh. This capacity fee now accounts for about 2.8% of the total electricity bill, where most provinces fall into the range of 2%–3.7%. A further look into the total electricity price paid by consumers reveals that the introduction of coal power capacity tariff has not increased the consumer’s electricity cost. The energy price in consumers’ electricity bills dropped by about 0.028 RMB/kWh on average in 2024 compared with 2023, due to both the downward trend in coal prices and the introduction of coal power capacity tariff. Considering that the coal power capacity fee is around 0.019 RMB/kWh, the total cost in 2024 saw a net decrease compared with the previous year.
Renewable generation fully entering the market, with over-the-counter pricing mechanisms playing a key transitional role
After participating in the energy market transaction, renewables included in this mechanism can also settle the price difference, which could be in negative value, over-the-counter. This is effectively the two-way contract-for-difference with the benchmark adjusted monthly.
The scope, cost, and duration of this pricing system will be decided at the provincial level. National guidelines, however, set different requirements for existing and new renewable projects. Projects that connected to the grid before June 1, 2025, are expected to transition gradually to market pricing, ensuring continuity with the current system. Projects connected from June 1, 2025 onward will be subject to the new pricing structure from the start of commission — resulting in greater exposure to market uncertainty.
Once mechanism pricing takes effect, generation covered by the mechanism can no longer engage in bundled green power transactions — and likely cannot participate in the energy-only M2L transaction either. This means such projects may be limited to the spot market, where they receive benchmark prices for difference settlement. At the same time, the associated GECs are barred from market trading. Provinces have yet to clarify the procedures for GEC cancellation or transfer. By the end of 2025, all provinces must establish and execute customized mechanism pricing in accordance with the national guidelines. It is anticipated that every province would reflect their own values and factors in their policies. Shanxi, Guangdong, Shandong, Gansu, and West Inner Mongolia are currently leading the way in the spot market’s official operation and they are expected to be the front-runners in releasing provincial guidelines.
Grid connection challenge requires that distributed PV prioritize on-site consumption, leading to uncertainty in returns
In 2024, the installed capacity of distributed PV systems continued to grow steadily, but the proportion of residential distributed PV declined. Distributed PV added 118.18 GW in 2024, with a year-on-year 23% increase. Due to grid constraints and rising risks in project returns, the residential PV capacity additions in 2024 dropped to 29.55 GW, down 32% year-on-year. Its share in total incremental capacity of distributed PV fell from 45% in 2023 to 25% in 2024. Distributed PV capacity additions were mainly concentrated in coastal provinces with high electricity demand.
The top five provinces — Jiangsu, Zhejiang, Guangdong, Anhui, and Shandong — accounted for 50.5% of the national incremental capacity. Guangdong, Jiangsu, Shandong, and Zhejiang are China’s largest electricity consuming provinces. Jiangsu led the nation in distributed PV additions from 2023 to 2024, with a 48% year-on-year growth in 2024. This rapid expansion can be attributed to Jiangsu’s solid support for the PV industry, increasing demand for green power, and sufficient distribution grid capacity. Henan province, despite ranking first in distributed PV additions nationwide in 2023, saw a significant downturn in performance in 2024 due to grid constraints in many counties, as exposed by grid assessments. The province saw a drop of more than 50% in new distributed PV installations, with residential additions plummeting by over 90%.
As distributed PV enters spot markets, uncertainty around returns will increase. Historically, some of their on-grid energy was settled at local coal power benchmark prices, ensuring stable and predictable returns. However, spot market prices — subject to significant fluctuations from supply-demand dynamics — introduce significant volatility, making it difficult to guarantee stable revenue streams. To maximize market returns, distributed PV will need to enhance forecasting and optimize the management of both energy production and consumption.
Stand-alone energy storage: core revenue from energy market arbitrage, with frequency regulation and capacity earnings sensitive to market and policy shifts
In 2024, China’s novel energy storage capacity (mainly battery energy storage systems) reached 73.76 GW, representing a year-on-year growth of over 130%. In China, energy storage is typically divided by application into three categories: variable renewable energy (VRE)-paired storage, stand-alone storage, and demand-side storage. Stand-alone storage led growth, comprising 56% of total installed capacity by year end. This surge was largely driven by supportive national and provincial policies. As market rules for ancillary services evolve across regions, the business model for stand-alone energy storage is taking shape. In some provinces, a combined revenue model of “energy market + ancillary services + capacity mechanism” has been established, enabling more diversified, market-driven income streams. Spot market revenues still account for the largest share, but ancillary services and capacity payments now play a critical role in the overall revenue mix.
China’s provincial power markets are evolving rapidly, with frequent updates to pricing policies and trading rules aimed at better reflecting the value of stand-alone energy storage. However, revenue from ancillary services and capacity mechanisms remains highly sensitive to policy and market shifts. As such, any earnings forecast must carefully account for potential regulatory changes and market volatility. Frequency regulation is the major product currently being traded in the ancillary services market in China. In the frequency regulation market, earnings are determined by the product of three factors: the cleared regulation mileage, settlement performance index, and declared prices. Changes in trading rules and pricing can significantly affect the earnings level.
VPPs are still in the demonstration stage and entering power spot markets may be a breakthrough for commercialization
At present, most operational VPP platforms in China are led by the provincial power grid operators or local governments with participation from market-oriented resource aggregators. Shenzhen and Shanghai are typical megacity power grids reliant on imported electricity. They focus their VPP platforms on demand-side load management. The goal is to ease supply-demand imbalances, relieve distribution grid congestion during peak periods, and reduce land use for grid expansion. On the other hand, North Hebei and Shanxi are major power exporters with high renewable penetration. Their VPP platforms aim to better leverage demand-side flexibility to integrate more intermittent renewable generation.
VPP operators in Shenzhen and Shanghai mainly rely on demand response mechanisms, but their revenue streams remain narrow and uncertain. In Shenzhen and the Lin-gang Special Area of Shanghai, demand response subsidies are funded by local government budgets, with amounts and durations determined annually. These subsidies typically last only 1–3 years, limiting the frequency, scale, and reliability of DR events and making it hard to build a sustainable business model. For instance, Guangdong Province conducted nine day-ahead demand response transactions in 2022, achieving a peak demand response of 2.77 GW and generating 160 million RMB in user income. However, no demand response trading occurred in 2023 or 2024.
In the future, VPP operators must actively participate in power market trading, including spot and ancillary services markets to earn stable returns. The above-mentioned VPP platforms in North Hebei and Shanxi have provided valuable demonstrations. From 2019 to 2022, VPP operators in North Hebei earned 6.2 million RMB through the North China Peak Regulation Ancillary Service Market. However, this market may be phased out if the electricity spot market in the Beijing-Tianjin-Hebei region begins official operation. In Shanxi, VPP operators earned 2.6 million RMB in the spot market between September 2023 and January 2025, though only five pilot projects have officially joined the market so far. Therefore, the regular and large-scale participation of VPPs in the power market needs further development.
Enhanced coordination between retail and wholesale market pricing mechanisms with fair and effective market competition
Various regions in China are actively optimizing retail electricity package designs, with a focus on enhancing TOU price signals for end-users. Most provinces now require fixed-price packages for large I&C users to include mandatory peak/off-peak pricing coefficients. In provinces with official operational spot markets, retail packages tied to wholesale prices are encouraged to pass real-time price signals directly to end-users. Fixed-price packages — typically incorporating TOU pricing — remain the dominant packages in China’s retail power market. For instance, in Shandong, TOU-based packages constitute 62% of the 265 standardized retail packages for 2025 listed on the Shandong Power Exchange Center’s website.
Similarly, in Guangdong, fixed-price contracts with TOU pricing account for 88.4% of the total signed electricity volume. Provinces with advanced spot market development have taken the lead in promoting price-linked retail packages, significantly enhancing the alignment between retail and wholesale electricity prices. Shandong’s 2025 market plan encourages flexible-demand users to adopt price-linked packages. Shanxi’s 2025 framework goes further, eliminating fixed-price models under its “base price + premium/discount” structure and requiring all base prices to float with wholesale market rates. While both provinces integrate spot and M2L market linkages, their implementation strategies differ.
China’s electricity retail market has transitioned from its initial rapid-growth phase to a new stage focused on standardization and transparency. Local governments are continuously optimizing retail package designs while providing standardized contract templates to help users better understand terms. Moreover, provinces are accelerating the rollout of online retail platforms, where companies must disclose detailed pricing mechanisms — greatly enhancing transparency and enabling more informed consumer choices.
However, this evolving market landscape faces significant challenges, particularly from generator retailers that dominate the supply side. These vertically integrated players enjoy substantial competitive advantages, including preferential access to generation resources and lower procurement costs, allowing them to offer more attractive pricing packages and gain large market share. In Guangdong, for instance, such companies made up only 8% of retail providers but accounted for 59% of total retail transaction volume in 2024. This imbalance highlights the need for targeted policy measures to preserve market competitiveness while curbing excessive concentration of power.
The green power and GEC trading system is improving, with trading volume influenced by mechanism ratios, certificate ownership, and usage
In 2024, green power trading and GEC markets expanded rapidly as prices fell. Green power trading volume reached 233. TWh in 2024,16 and its share of the power market continues to grow year over year. GEC trading volume in 2024 totaled 446 million, and it shifted to predominantly unbundled GEC trading from volume dominated by green power bundled trades in 2022. In terms of pricing, 2024 data from the State Grid region shows that the average prices were 417.09 RMB/MWh for green power and 9.6 RMB per GEC. In the China Southern Power Grid region, the average environmental value of green power traded in the first half of 2024 was 9 RMB/MWh. The average GEC price was 3.51 RMB. 20 Both green power and GEC prices declined compared to 2023.
The GEC scheme has been rapidly refined, firmly establishing GECs as the sole representation of green power’s environmental attributes. Policies eliminated the overlap of GECs with International Renewable Energy Certificates and China Certified Emissions Reductions (CCERs), reinforcing GECs’ uniqueness and clarifying retirement and oversight rules. This has bolstered international recognition, with some multinationals shifting from international certificates to Chinese GECs. GECs are also now eligible for offsetting energy consumption in provincial and stakeholder energy saving assessments, further boosting demand.
Several provinces have adopted TOU pricing for residential EV charging, on a voluntary basis, following existing residential pricing structures
In early 2024, the Opinions on Strengthening the Integration of New Energy Vehicles and the Power Grid was issued and called for independent TOU pricing for flexible loads like residential EV charging, with full rollout targeted by end of 2025.22 It mandates distinct rates from household use and guides provincial TOU policy design. Since 2023, multiple provinces have progressively rolled out TOU pricing schemes for residential EV charging, with variations in implementation across provinces. As of the end of 2024, 22 provincial-level regions in China had implemented TOU pricing for residential EV charging, mostly on a voluntary basis. Four provinces — Jiangsu, Hainan, Guangdong, and Gansu — have made TOU the default option.
EV charging TOU period definition typically follows residential TOU periods, though some provinces reference I&C TOU pricing or create custom periods for EV charging. TOU pricing levels are generally based on residential levels, with adjustments made within defined ranges. According to the Hubei Electric Power Marketing Service Center, EV charging TOU implementation led to an 11.04% drop in residential charging peak load, with a 9.4 MW peak reduction. Participating users saw an 86.7% drop in their individual peak demand. The implementation of TOU pricing for residential EV charging will be further expanded, featuring more granular time periods and more detailed pricing structures.
Access the report here
