China’s power industry was built to support rapidly growing demand. As China’s economy matures and climate goals become priorities, the power sector has to adjust. Among the challenges are a lack of price responsiveness to demand and supply shocks, difficulty in integrating non-fossil fuels, and underdeveloped ancillary services markets that are needed to ensure flexible power production and storage capacity. Successful market reforms will require letting power prices fluctuate more freely based on market conditions, strengthening inter-provincial power trading and coordination of local power markets, and scaling up of ancillary services. If done successfully, market reforms will not only improve the efficiency in power generation but also ease the tradeoffs between climate goals and energy security.

Abstract

China’s power industry was built to support rapidly growing demand. As China’s economy matures and climate goals become priorities, the power sector has to adjust. Among the challenges are a lack of price responsiveness to demand and supply shocks, difficulty in integrating non-fossil fuels, and underdeveloped ancillary services markets that are needed to ensure flexible power production and storage capacity. Successful market reforms will require letting power prices fluctuate more freely based on market conditions, strengthening inter-provincial power trading and coordination of local power markets, and scaling up of ancillary services. If done successfully, market reforms will not only improve the efficiency in power generation but also ease the tradeoffs between climate goals and energy security.

Market Reforms in China’s Power Sector1

China’s power industry was built to support rapidly growing demand. As China’s economy matures and climate goals become priorities, the power sector has to adjust. Among the challenges are a lack of price responsiveness to demand and supply shocks, difficulty in integrating non-fossil fuels, and underdeveloped ancillary services markets that are needed to ensure flexible power production and storage capacity. Successful market reforms will require letting power prices fluctuate more freely based on market conditions, strengthening inter-provincial power trading and coordination of local power markets, and scaling up of ancillary services. If done successfully, market reforms will not only improve the efficiency in power generation but also ease the tradeoffs between climate goals and energy security.

A. Introduction

1. China’s power system has been the engine behind the country’s impressive growth over the past two decades. Electricity demand has grown more than 6-fold between 2000 and 2021, making China’s power generation capacity the largest in the world, producing about a third of the world’s electricity. The fuel of choice has been predominantly coal, a domestic resource. In 2021, China began construction on 33 gigawatts of coal-based power generation, the most it has undertaken since 20162, and in the first quarter of 2022, it approved 8.63 gigawatts of additional coal plants.3 There has been some diversification into other fuels including hydro, nuclear, and more recently, wind and solar power.

uA004fig01

Electricity Generation

(In terra-watt hours)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: Our World in Data; BP Statistical Review of World Energy; Ember Global Electricity Review (2022); and Ember European Electricty Review (2022).
uA004fig02

Energy Consumption by Source

(In thousands of terawatt-hours)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: Our World in Data; and BP Statistical Review of World Energy.

2. To meet the extraordinary electricity demand, the regulation framework was designed to ensure sufficient investment. As a result, electricity dispatch and pricing were predominantly administrated with the primary goal to stimulate generation and transmission investments rather than economic efficiency (Guo and others, 2021). The annual administrative procedure for power generation planning converted forecast electricity demand into generation quotas, and then evenly allocated the quotas to the generators. Under this setup, coal power plants, regardless of their age, size, efficiency, or emissions levels, would all be allocated the same numbers of generation hours. This “fair dispatch” rule effectively isolated generators from explicit market competition and led to suboptimal expansion and utilization of generation fleet.

3. As growth moderated and objectives shifted towards emissions reduction, China’s traditional power system has become less compatible with the changing needs. The challenges included low generation asset utilization, low energy efficiency, high pollutant emissions, and wastage (curtailment) in renewable energy generation. Moreover, the increasing importance of environmental welfare was at odds with the power system and its command-and-control pricing framework. While the latter ensured cost recovery for coal plant investments, the inflexibility of the planned operation hours contracts and lack of wholesale power market made renewable energy artificially less economical. The power system’s regulatory framework also lacked incentives to decrease total energy consumption, the development of renewable energy, and the provisions of related products other than energy, such as ancillary services that are required to maintain grid stability and security (Supponen and others, 2021). Furthermore, inadequate inter-provincial power trading platforms and incentives have prevented provinces from purchasing and dispatching power efficiently. Despite some efforts to construct ultra-high-voltage lines between select provinces, the current power market has not created adequate incentives for China’s grid companies to construct new grid networks to connect large renewable energy-producing regions to the populous coastal regions, resulting in curtailment.

uA004fig03

Coal Consumption Increased in 2021

(In percent, year-on-year)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Source: National Bureau of Statistics China.
uA004fig04

Wind and Solar PV Curtailment

(In terra-watt hours, percent)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: China National Energy Administration; and staff estimates.Note: PV= photovoltaic.

4. As laid out in greater detail below, more market-based reforms to the power sector can enhance the effectiveness of power generation and reduce the tradeoffs between climate ambitions and energy security.

  • Market reforms to the power sector can increase the efficiency and reliability of power generation. A transition from planned fair dispatch rule where generators produce an allocated energy volume to economic dispatch which enables resources to compete based on their short-run marginal costs and thus, reflects economic optimization will result in lower power system operational costs, increase efficiency, reduce capacity underutilization and renewable energy curtailment. The adoption of a national electricity market convergent across all provinces that offers flexible transactions along with upgraded transmission connectivity will help ensure that power plants operate efficiently by setting their own generation hours to optimize their profitability. By increasing the efficiency of existing power generators, China can also reduce the need to add new coal power capacity.

  • Market-based electricity pricing can help reduce the tradeoffs between China’s climate ambitions and growth as well as energy security. Market reforms to the power sector can enhance the efficiency of the national Emissions Trading Scheme (ETS). A market-based regulatory framework to effectively mobilize power system flexibility would ensure that carbon pricing would be passed through onto final consumers, thus, reducing the demand for energy as well as incentivizing a shift away from fossil fuel investment towards renewable energy sources. Guiding power generators to participate in the market while phasing out price controls and generation quotas will help them recover costs and alleviate the burden from fulfilling energy and carbon intensity targets. The reforms will optimize system cost, enhance system flexibility, and level the playing field for renewable energy.

  • Market reforms in the power sector will also require coordination and harmonization of markets. The coordination and harmonization of regional markets will create an enabling environment for private sector investment in energy storage as well as for coal power plants to reduce operation and stand by for backup generation when necessary. Increasing power trading will also stimulate the development of ancillary services markets. They can fairly compensate reserve capacity that support system reliability and generate incremental revenue streams to energy storage and coal fleets not in use.

These power market reforms will result in transition costs that will require interventions to ensure they are shared in an equitable way. The introduction of economic dispatch is bound to trigger the exit of inefficient coal generators from the market, and this process will likely require active management to compensate the most vulnerable households including workers in coal- and high-energy intensive industries.

B. Brief History and the Challenges of China’s Power Market Reforms

5. China has launched several rounds of power sector reforms with the aim to improve efficiency, reduce electricity prices, and rationalize coal power investment. The 2015 reforms— the most extensive in the series—saw the establishment of market-based mid- to long-term electricity forward markets. These markets allowed for wholesale energy prices to be decided via negotiation or auction between generators or suppliers and large consumers. It also enabled the broadening of ancillary services markets, and the piloting of spots markets which enable day-ahead, real-time energy exchanges, with eight spot market pilots currently operating in China. Since June 2020, more private players have been allowed to participate in the forward market, including distribution, wholesale and energy storage companies, with an estimated 45 percent of total energy consumption being traded on the mid- to long-term market as of end-2021 (Qin, 2021). In another major step towards market pricing of electricity, further reforms took place in late 2021, allowing coal-fired power prices to rise or fall by up to 20 percent from benchmark price levels. The latest set of reforms—announced in 2022—envisions the establishment of a national electricity market by 2025 to further optimize resource allocation, including through increased interprovincial power trading and to better support renewables integration.4

6. Despite the steady progress in power market reforms, however, the role of market-based mechanisms is still limited. Dispatch and pricing continue to be largely determined administratively through a planned fair dispatch mechanism as of 2022. One of the biggest obstacles to implement the reforms is the dichotomy in political and economic interests between central and local governments (Hove and others, 2021). The latter has significant autonomy in formulating power sector reform programs, and it optimizes power generation and consumption based on its own needs rather than that of the central government. The provincial structure of markets, so far, has tended to enhance provincial protectionism and self-sufficiency (Guo and others, 2020). Competitive power markets entail market-based pricing that is subject to changes based on supply and demand. While these price fluctuations are intended consequences of market-based pricing, market players could be potentially facing more risks. Ideally, long- and short-term power markets should complement each other and provide hedging instruments that will minimize these risks. In the European Union, for instance, hedging through long term trading is an important and efficient tool for both sellers and buyers. A sufficiently liquid spot exchange acts as a reference market that gives a solid price signal on which the long-term markets can rely, and it allows the procurement of the required amounts of physical electricity at all times (Supponen and others, 2020). China’s heavy reliance on coal—with mines and plants largely operated and owned by local governments—also makes it difficult to switch to more flexible options that are inherent to market-based mechanisms. Moreover, as the share of renewables in the power market increases, prices may experience volatility and even decrease over time, creating a situation of stranded assets where long-standing investments, including those made by local governments, cease to be competitive and become liabilities.

uA004fig06

Clean Energy Power Consumption Target

(In units)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Source: China Energy Administration.

7. The lack of a fully liberalized power market stands in the way of efficiently integrating renewable power. China’s richness in a diversity of energy reserves poses a challenge for distributing the installed renewable capacity evenly. The existing administrative mechanism of power pricing and dispatch does not provide incentives for the development of flexible production and storage technology that are necessary to allow renewable energy generation to become a source of stable power supply. For many imported-end local governments, the resulting on-grid price of wind and solar energy plus a transmission tariff could be potentially larger than the coal power generated in their own province which also helps with the local economy.

8. Other barriers to implement market-based power market reforms include legal and regulatory hurdles, limited transparency, and the lack of inter-provincial coordination. Many provincial markets begin trial operation prior to making the designs accessible to a wide range of actors. China’s grid, dispatch, and power pricing usually operate without public information platforms that could enable market players or the public to analyze their operations or potentially participate via new business models (Hove and others, 2021). The lack of transparency not only hinders the effective operation of power markets but is also inhibiting market monitoring and energy demand-side management. Given the local government’s autonomy over its own design and construction of power markets, including the existing eight spot markets, potential incompatibility issues among the different rules will pose difficulty in the future for the integration of these markets and achieving a higher level of optimization (Guo and others, 2020).

C. Power Market Reforms to Increase Efficiency

9. The switch to economic dispatch and higher levels of regional trading would help reduce operational costs. It would effectively end the guaranteed offtake for coal-fired power under fair dispatch—which has enabled and incentivized the approval of coal-fired capacity. Market-based pricing allows for greater passthrough of costs to end users, industrial and commercial, resulting in greater volatility in prices that in turn should introduce and incentivize greater efficiencies in power use. Over time, this new pricing mechanism should enable power consumers to influence the supply and pricing of power products by making economic choices, and power generators will subsequently invest in new capacity based on the demands of power consumers. The decrease in system cost and emissions is driven by an increase in the utilization of both zero-marginal-cost renewables and more efficient thermal generators. Economic dispatch enables the integration of additional renewables, drops curtailment and drives better scheduling of generators so that those that are already running operate at higher run rates and therefore increase their overall efficiency. Recent work by the International Energy Agency (IEA) has shown that maintaining the current fair dispatch system would lead to major inefficiencies in the capacity mix, including high levels of renewable energy curtailment (IEA, 2019). The switch to economic dispatch would bring operational cost savings of about 11 percent per year in 2035. Moreover, power sector carbon emissions would also fall by 15 percent. In their simulations using latest existing data, Timilsina, Pang and Yang (2021) found that optimal electricity prices under economic dispatch could be lower by about 5 percent compared to electricity prices under the existing dispatch. In the long run, customer tariff rate reductions could be much larger as generators would be able to refine their cost structure and offer lower bids into the market—a trend observed in regions around the world that have previously implemented energy markets (Keay, 2016).

uA004fig07

Operational Costs Under Inflexible and Flexible Power Dispatch in 2035 - IEA Modeling

(In US$ per MWh)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Source: International Energy Agency 2019.Note: The introduction of economic dispatch, higher levels of regional trading and additional grid infrastructure can help to reduce operational costs and CO2 emissions and brings savings of USD 63 billion annually.

10. The combination of economic dispatch and rapid trading will allow for more renewable energy integration and reduces the need to add new coal power capacity. The share of renewable energy has grown in the Chinese power system, but there are still integration challenges and significant curtailment of renewable energy. International experiences have demonstrated that a well-functioning short-term market that allows rapid trading (e.g., spot market) for electricity is a very powerful measure to drive power system transformation (IEA, 2019; Qin, 2022). In such an arrangement, the power plant with the lowest generation costs has priority for meeting electricity demand. In most designs, the cost of the last (most costly) plant that is needed to meet demand sets the price paid to all generators. Combining effective spot markets with better utilization of interconnections and increased grid investment brings a more efficient power system that can absorb an increased share of variable renewable energy. The modelling analysis by the IEA (IEA, 2019) shows that the power system can integrate renewable energy at over 20 percent of total generation without any curtailment by improved operations and increased levels of physical interconnections. The capacity value of renewable energy, including solar photovoltaic, wind and hydro power, being used for planning in China is rather low and increasing it from the current level would result in less need for new peaking capacity such as coal that can be provided equally by renewables (WB, 2022).

uA004fig08

Electricity Production Mix 2021

(In percent)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: China Electricity Council; Statista; and Ember.

D. The Importance of Power Market Reform for China’s Climate Ambitions

11. Because the largest share of China’s emissions is energy-related, any successful climate agenda will require a significant transformation of the power sector.

  • Intensity Targets: As China has set out to achieve carbon emissions peak before 2030 and net carbon neutrality before 2060, it has relied heavily on mandatory energy consumption standards and energy intensity targets to drive carbon emissions reductions. These intensity targets, however, have often clashed with growth ambitions and energy security as showcased by the 2021 power crunch (Boxes 1 and 2). The inability of power generators to adjust electricity prices to end users as coal prices were rising significantly, resulted in reduced operations from low coal inventories and rationed energy supply to industrial users. The barriers to inter-provincial trading and the lack of coordination between local governments makes China also vulnerable to localized power shortages, exacerbated by weather-induced climate shocks, especially droughts and its heavy dependence on hydro power as seen in the recent power crunch in Sichuan province in August 2022. Yet, current investment incentives are not aligned with providing more support for bringing on more renewables onto the grid through expanding storage facilities and other ancillary services.

  • ETS: The national ETS could potentially facilitate these incentives, but lacks teeth in its current form and without significant power market reforms. The predominantly administratively set pricing in the power sector limits the extent to which the ETS-implied carbon price will be passed on to downstream sectors and consumers and the incentives for power producers to adjust. Accelerating the dispatch reform would better enable the ETS and amplify its value, as a merit order dispatch system would take into account the carbon cost imposed by the ETS on less-efficient units and authorize lower-emitting technologies to operate more often. Slower reform progress would hold back electricity generators in adjusting their operations based on ETS price signals, and the ETS’s effectiveness in carbon emissions could remain considerably constrained (see below).

China: The Impacts of Intensity Targets on Climate and Energy1

Relying on medium-term policy frameworks is an established way for China to implement its policy objectives. Like in the 12th and 13th Five-Year Plans (2011-2015, 2016-2020, respectively), China also set binding reduction targets for energy intensity and carbon intensity in its 14th FYP (2021-2025). These key interim climate targets include a 13.5 percent reduction for energy intensity and an 18 percent reduction of carbon intensity of GDP. A cap on energy consumption growth was set at 2 percent per year as well. These guidelines provide a basis for calculating the implied future emissions and energy needs under various assumptions of growth. All values (e.g., GDP, energy efficiency, energy use, emissions) in the baseline year are set at 100. Values for 2021 are based on outturns where available. The scenarios are extended to 2030 based on the targets of the 13th and 14th FYP. The following analysis illustrates the issue at stake using two different GDP scenarios, one based on a “baseline”growth path (based on the October 2022 World Economic Outlook (WEO)) and the other based on 5.5 percent annual “high growth” scenario after 2025.

uA004fig09

CO2 Emissions and Energy Trajectories Under Oct22 WEO Growth

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: IMF World Economic Outlook database; and IMF staff calculations.

In the “baseline” scenario, Chinese carbon emissions would peak around the year 2026, four years ahead of the current ambitions. This scenario would lead to around 5 percent more carbon emissions compared to 2020 levels. As for energy consumption, the annual two-percent growth cap was violated in 2021 due to the strong recovery from the pandemic recession in 2020, but in all subsequent years, energy consumption growth would be below the cap.

In the “high growth” scenario after 2025, Chinese carbon emissions would peak in 2029, just one year before the target year of 2030, but with carbon emissions having grown by over 7 percent compared to levels in 2020. However, the energy consumption cap would be violated again in years 2026 and 2027.

uA004fig10

CO2 Emissions and Energy Trajectories Under 5.5% Growth

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Sources: IMF World Economic Outlook database; and IMF staff calculations.

These scenarios illustrate two important points. The first one is that the intensity targets are highly dependent on the growth trajectory. Given the strong rebound in growth in 2021, it was not surprising that local governments found it challenging to meet these targets (Box 2). The second insight is that even if carbon intensity falls by the targeted amount, there is a risk that carbon emission levels could still increase and force a much more intensive decarbonization effort after 2030 (IMF, 2021). For example, allowing coal capacity to increase in the near term could require sharp capacity reduction down the road. The absence of absolute caps on coal use—new coal plants might be forced to retire early given their average lifespan of around 50 years—and carbon emissions leaves room for emissions to increase over the next several years, implying sharper policy shifts later on—and if the availability and costs of clean technology alternatives do not evolve as expected, or future growth paths change unexpectedly on the downside, China will have made it even tougher for future generations to curb emissions.

1 Prepared by Wenjie Chen

China: China’s “Power Crunch” of 20211

The power supply shortage in the second half of 2021 provided a stark reminder of the difficult tradeoffs between energy security and climate ambitions. In early 2021, the government set a target for energy intensity to decline by around 3 percent during the year, broken down further into provincial targets. The unbalanced nature of China’s recovery from the pandemic recession, however, has led to a significant jump in energy consumption in 2021. Heavy industries like steel, non-ferrous metals, chemicals, and building materials like cement and glass have led the charge to satisfy increased manufactured export demand and the boom in domestic construction and infrastructure investment. This posed difficulty in fulfilling annual climate targets at the provincial level. In fact, in the first half of 2021, there were more than 12 provinces lacking on both counts of the targets, and several local governments proceeded to ration power supplies in order to meet the intensity goals (Meidan and Andrews-Speed, 2021).

On the supply side, the immediate cause of the crisis was that the electricity prices paid to generators were On the supply side, the immediate cause of the crisis was that the electricity prices paid to generators were regulated, while coal prices were and still are set on the market. When coal prices rose, it became unprofitable for coal power plants to supply electricity. As a result, coal power plants cut back on coal purchases, running down coal inventories instead, and coal mines did not ramp up output in time, as the price and demand signals were dampened. The gap was exacerbated by supply-side disruptions: an anti-corruption campaign in Inner Mongolia, mining safety campaigns, heavy rains, and an intensive restructuring of the coal mining industry. Surging coal mine output eventually closed this gap.

uA004fig11

Unit Price of Listing Agreement Transactions and Block Deals

(In RMB per ton)

Citation: IMF Staff Country Reports 2023, 081; 10.5089/9798400233517.002.A004

Source: CEIC Data Company Limited.

The power crunch in 2021 led to several important changes in the power price controls. China had a narrow price band in which generation prices could fluctuate. In October 2021, reforms were passed, allowing the band to modestly expand up to 20 percent, and the prices for high energy-consuming enterprises and spot market trading no longer being subjected to the price control band range. All coal power plants were guided to participate in the market, which accelerated phase-out of generation quota. All industrial and commercial consumers were required to purchase electricity from the market. These changes helped coal generators recover increasing cost to some extent, however, it is not clear whether this has helped increase renewable energy utilization. Moreover, in early 2022, China published its 14th Five-Year Plan for energy as well as issued other important power market regulations including guidelines calling for a unified national energy market.

1 Prepared by Wenjie Chen

12. Progress in power market reform can significantly enhance the effectiveness of China’s national ETS. The ETS is a central component of China’s efforts to implement its mitigation objectives, but in its current setting, emissions reductions are unlikely to be cost effective (IMF, 2021; Chateau and others, 2022). A transition from administratively determined dispatch to economic dispatch could strengthen the effectiveness of the ETS by allowing markets to reflect carbon prices in electricity generation costs and thus, to directly impact dispatch decisions. Without this reform, the ETS risks playing a limited role in reducing power sector emissions while coal power plants would not need to adjust their operation in response to the price signal stemming from the ETS allowance allocation. The transition to an economic dispatch mechanism would also allow cost passthrough from generators to energy consumers, and hence strengthen incentives for demand-side response. Together, power market reforms and effective carbon pricing could help to significantly reduce power system operational costs, improve wind and solar power integration, and achieve a considerable drop in power sector emissions. In turn, the ETS can support power market reforms by integrating carbon costs into dispatch decisions and providing incentives for plants to operate more flexibility depending on their carbon emissions levels. If externality costs are not taken into consideration and high-emitting sources remain cost-competitive, the power market reform might optimize the cost of electricity production in a manner not necessarily aligned with the transition to a low-carbon electricity mix (IEA, 2021a).

13. By allowing more market forces to guide resource allocation and emissions abatement, an ETS can achieve significant carbon emissions reductions more effectively than mandatory intensity targets. Model simulations show that compared to carbon emission reductions under a command-and control approach of imposing energy intensity and total energy consumption targets, the ETS in combination with power sector reforms would achieve the same emissions reductions at less additional cost to the system (IEA, 2019, 2021a, 2021b). The reason that the ETS with power market reforms could achieve more cost-effective emissions reduction than mandatory consumption standard is because allowance trading with flexible electricity prices leads to the most affordable emissions abatement measures in the system to be deployed first. In contrast, under mandatory energy consumption targets, technologies need to reduce their respective energy consumption by a similar scale regardless of the relative cost. Moreover, with more stringent allowances in combination with economic dispatch, the ETS would encourage high-efficiency units to run significantly more than they currently do, thus, improving utilization rates. Less-efficient—usually older units—would either serve as back-up capacity with low annual hours or be retired. In addition to changing operating patterns and optimizing the energy mix, the ETS— unlike the intensity target approach—provides incentives to accelerate and enlarge the deployment of carbon capture, utilization and storage (CCUS) in the power sector as well as ancillary service markets that would provide further support to renewable energy.

14. Enhancing and developing China’s ancillary service market will enable a more efficient integration of renewables. Ancillary services markets are important to ensuring flexibility in systems with a high proportion of renewable energy. China’s ancillary services are dominated by peak shaving, reserves, voltage regulation, and frequency regulation. Peak shaving allocates power according to predictable demand patterns, while reserves provide back-up for the entire system. So far, most ancillary services markets are at the early stages of development and may only allow participation of some generators. They are also designed and operated by local governments and not necessarily compatible across provinces. The integration of renewables relies on having the technology and infrastructure to turn the inherent intermittency of renewable energy sources into stable power supply. Thus, making ancillary services markets operate more freely and market-based in tandem with power market reforms and the ETS would signal for more investments into the necessary technologies, including those in retrofitting coal plants for greater flexibility. The recent reforms announced by the NEA to expand ancillary services markets and to change the cost allocation mechanism to include power end-users for the first time are promising first steps.5

E. Policy Implications

15. Despite significant progress, many challenges remain in China’s power sector, but market reforms can improve its compatibility with the changing needs. This includes reducing the tradeoffs between climate objectives and energy security. In particular, these include the following:

  • Electricity pricing needs to be more cost-reflective, convergent across the provinces and flexible to market conditions. China can expedite the elimination of the administrated price range set for market transactions with coal power plants, including by gradually abandoning the pricing band around electricity.

  • Expanding spot market trading has the potential to help reduce generation capacity reserve, increase flexibility and improve renewable energy integration. Consistent with the vision outlined in the energy reform plans announced in 2022, regional pilot spot markets should be scaled up towards the adoption of a national spot market that offers flexible transactions for short time periods for the whole country. This will also require coordination between local governments to harmonize provincial power markets while increasing the transparency and independence of energy exchanges from grid, generation and retail companies.

  • Strengthening inter-provincial power trading platforms and incentives can ensure provinces purchase and dispatch power efficiently. The current power market has, so far, not created adequate incentives for China’s grid companies to construct new grid networks to connect large renewable energy-producing regions to the populous coastal regions although it is a central focus in the 2022 energy reform package. Inter-provincial power trading is still limited in scale and inflexible in terms of the amount of power provided from one province to another. Integrating provincial grids would allow one province to take advantage of reserve capacity in other provinces and reduce or eliminate the need of additional coal power capacity for system reliability subject to the extent of integration. It requires both physical investment for rapid expansion of inter-provincial transmission capacity and reform to optimize dispatch, moving dispatch operation and responsibility from provincial level to regional level and national level to enable dispatch optimization across provinces.

  • Incentivizing ancillary services markets and potentially a capacity market to support the integration of renewable energy. These markets can fairly compensate reserve capacity or other ancillary services that support system reliability and generate incremental revenue streams to energy storage and coal fleets not in use. These markets will create an enabling environment for private sector investment in energy storage as well as for coal power plants to reduce operation and stand by for backup generation when necessary. Together with effective carbon pricing like the ETS, these key reform measures will optimize system cost, enhance system flexibility, level playing field for renewable energy, and recalibrate the role of coal fleets from a baseload supplier to a supportive facility for serving peak load and offering reserve capacity or other valuable ancillary services.

  • Building a conducive investment climate will encourage private sector participation. To meet the scale of the investment needs for power sector decarbonization, attracting private sector investment is critical, especially for renewable energy and energy storage. Enhancing the predictability of the policy framework could help encourage stronger private investment. Expanding the green electricity certificate (GEC) market and allowing larger participation from renewable energy generators and voluntary purchasers may also enhance cash flow to private sector investors (see SIP on Climate Finance).

  • The capacity value of renewable energy in China may be further enhanced by revisiting approaches and regulations that align them with international standards. There remains considerable potential to improve economic dispatch and utilization of hydro power and energy storage to meet peak demand following international best practices. In parallel, the potential of demand side management including demand response can be further harnessed to slow down peak load growth and support integration of variable renewable energy.

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1

Prepared by Wenjie Chen. The author would like to thank for the very helpful discussions with Ximing Peng and Govinda Timilsina from the World Bank as well as Xiushan Chen and David Fischer at the International Energy Agency.

4

China State Council announcement on April 10, 2022.

People’s Republic of China: Selected Issues
Author: International Monetary Fund. Asia and Pacific Dept