8: Power Sector Reform

The structure and functioning of China’s power sector will play a significant role in the Chinese government’s ability to meet its climate goals. Chinese policy makers have highlighted the importance of power market reform to meeting these goals, including in the 14th Five-Year Plan for a Modern Energy System, which highlights power market reform as an element of a modern energy system that can enable carbon peaking and carbon neutrality. ¹

Background

The electric power sector accounts for roughly 45% of China’s carbon dioxide (CO₂) emissions. ² In 2021, coal provided 67% of China’s electric power, hydropower provided 16%, wind power 8%, nuclear power 5% and solar power 4%. Coal’s share of electric power production has fallen during the past decade, from 77% in 2010 to 67% in 2021. ³

Electric power in China is delivered predominantly by two state-owned utilities: China State Grid and China Southern Grid. China State Grid—the world’s largest electric utility by far—supplies electricity to more than 1.1 billion people in 26 Chinese provinces. ⁴ China Southern Grid serves more than 250 million people in Guangdong, Guangxi, Yunnan, Guizhou, Hainan, Hong Kong and Macao. ⁵

Historically, electricity was dispatched in China based on province-by-province administrative allocations. At the end of each year, provincial dispatching centers would forecast total power demand for the following year and then allocate power generation quotas to each generator within their province. Generators within the same category (such as coal-fired power plants) would be allocated roughly the same number of annual operating hours. Coal-fired power plants typically received priority, with guarantees of a minimum number of annual operating hours, even if other sources (such as renewable power) were available. ⁶

This system—known as “fair dispatch”—differs significantly from electric dispatch systems in most advanced economies. In the United States, Europe and Japan, for example, most electricity is dispatched based on the marginal cost of the electric generator. Electric utilities start by purchasing the electricity with the lowest marginal cost, then purchase electricity with next lowest marginal cost, and repeat this process until all demand for electricity in a service area is met. This system is known as “economic dispatch.” ⁷

China’s historic system of electricity dispatch created several problems with respect to the government’s climate and clean energy goals.

• First, administrative allocations to coal power plants resulted in significant curtailment of wind and solar power. Although China has led the world in wind and solar power capacity for many years, until recently much of that capacity was underutilized because coal power plants received priority in dispatching to the electric grid. Wind and solar power did not necessarily receive priority, even though they typically have zero marginal cost. ⁸
• Second, province-by-province electricity planning also slowed the growth in wind and solar power. Provincial governments tend to design power market policies to favor generation from within their province, leading to a phenomenon known as “provincial fortresses” in which excess renewable power cannot reach nearby provinces where it may be needed despite ample transmission capacity. ⁹

Electric power market reforms are underway in China to help reduce prices, improve efficiency, cut coal power capacity and promote climate change goals. ¹⁰ These reforms are described below.

Policies

During the latter part of the 20th century, all parts of China’s electric power system were run by a single state-owned enterprise—the State Power Corporation. In 2002, the State Council published Document #5, breaking up the State Electricity Department into two grid companies (China State Grid and China Southern Grid) and five power generation companies. An independent regulator—the State Electricity Regulatory Commission—was established (and later folded into the National Energy Administration). ¹

Reform of the electricity market returned to the national energy policy agenda in 2015 with the publication of Document #9 on Deepening Reform of the Power Sector. ¹² The document laid out a broad agenda for reforms, including changing the revenue model for grid companies, direct retail access to power markets, retail competition, promotion of demand-side management, improved generator dispatch, improved renewable integration and removal of barriers to distributed generation. ¹³ The document’s call for wholesale markets to determine dispatch and investment decisions aligned with the philosophy of the high-profile Third Plenum of the 18th Party Congress in November 2013 to allow markets to play a central role in guiding investment in environmental and energy resources. ¹⁴

Power market reforms in recent years include measures in the following areas:

1. Direct power purchases. In 2016, NDRC announced a transition from fixed operating hour contracts between generators and provincial grid companies to a wholesale market involving bilateral contracts between generators and large industrial consumers. ¹⁵ Thousands of retail marketing companies (often subsidiaries of grid companies) sprang up to offer such contracts to end users, typically on a monthly or annual basis. ¹⁶ In 2021, these mid-to-long-term (MLT) contracts accounted for 37% of total electricity consumption (up from 33% in 2020). ¹⁷ After pricing-related power outages in late 2021, the central government announced that all industrial and commercial consumers would be encouraged to move to the bilateral contract market. ¹⁸
   

1. Spot markets. In 2017, the National Energy Administration introduced spot market pilots covering eight regions and provinces. ²⁰ Trade began with trial operations, then proceeded to more continuous operation in certain provinces. ²¹ In designing these pilots, several provinces worked with international organizations such as Nordpool in Europe and the PJM Interconnection in the United States. ²² In 2021, six additional provinces were added to the list of eight original pilots. A 2021 NDRC policy document encouraged commercial and industrial consumers to purchase electricity from the spot market, promoted the full inclusion of renewable energy in spot markets, and discussed the need to integrate provincial and regional spot market designs. ²³
2. Interprovincial power trading. In recent years, numerous policies have promoted greater interprovincial and cross-regional power trading. In 2021, for example, an interprovincial spot market pilot was established between Inner Mongolia and nearby provinces. ²⁴ In 2022, China’s NEA and NDRC issued a guiding opinion calling for a unified national power market framework—targeting an initial design by 2025 and basic implementation by 2030. ²⁵ The unified market would incorporate uniform rules for provinces as well as a national trading center, breaking down the provincial barriers that have hindered market designs in the past, and would harmonize spot markets, MLT trading and ancillary services markets. ²⁶ (However, provincial officials have responded to recent power shortages by increasing investment in within-province power generation rather than by increasing interprovincial power trading. ²⁷)
3. Ancillary services. Ancillary services, such as frequency regulation, voltage control and black start, help maintain the secure and stable operation of the electric grid. Ancillary services markets are especially important as variable renewable power grows in importance on electric grids. In China, ancillary services often refers to ramping plant output up or down to follow load, sometimes called peak regulation. Previously, China’s power system provided only limited funds for ancillary services, and effectively required coal plants to pay one another for such services. Since 2018, reforms have established ancillary service market pilots, starting with Northeast China, focused on peak regulation. ¹⁸ China’s ancillary services markets initially limited participation to coal-fired generators, but more recent policies call for opening up ancillary services markets to renewable energy, batteries and the demand side. ²⁹
4. Transmission and distribution (T&D) pricing. New policies transition the revenue model of China’s grid companies to a cost-plus-reasonable profit model, based on estimates of costs for building and maintaining transmission and distribution grid infrastructure. ³⁰ Prior to T&D reforms, grid company profits depended on the price difference between the cost of generation (purchased by the grid companies under a single-buyer model) and retail electricity prices set administratively. For large transmission projects, revenues were based on the volume of electricity transferred as well as the distance—providing an incentive for grid companies to focus on long-distance, ultra-high voltage (UHV) lines. ³¹ In late 2014, five provinces were designated as T&D reform pilots. This was expanded to a further 12 provinces and cities in early 2016, and then to all remaining provinces in late 2016. ³² Initial reforms focused on setting revenues for existing grid assets within provinces. Subsequent reforms starting in 2017 created a process for setting revenues for newly-added transmission and distribution grids, as well as for cross-provincial transmission projects. ³³
5. Retail pricing for commercial and industrial customers. Retail prices for commercial and industrial customers have traditionally been set administratively by the National Development and Reform Commission (NDRC), and responsibility delegated to local DRC electricity offices. This has gradually changed with the introduction of bilateral power contracts, which began with the largest power consumers, and gradually expanded to include small customers via intermediate power marketing firms. After October 2021, the central government announced the cancellation of all administrative price schedules for industrial and commercial customers, which must now participate in the power market either via bilateral contracts or by accepting a default tariff offered by the grid company. ³⁴
6. Retail prices for residential customers. In 2011, NDRC adopted a policy for residential customers aimed at encouraging electricity conservation. The policy required each household to have one power meter and created an electricity price premium for households consuming more electricity than the district average. The pricing policy, known as ladder pricing, keeps prices unchanged for 80% of customers, but creates a 2nd and 3rd tier of residential customers in the 80–95% percentiles and 95–100% percentiles of local district monthly average household power consumption, charging higher retail prices for these tiers. ³⁵
7. Time-of-use pricing. Most regions in China offer time-of-use (TOU) power price schedules for commercial and industrial customers. In recent years, in line with policies to encourage more demand-side participation in power markets, the government has promoted provincial adoption of TOU prices and encouraged increasing the price differential between peak and trough times. A July 2021 policy targeted a ratio of 4:1 between peak to valley prices. ³⁶ This policy remains in effect despite the cancellation of administrative price schedules for industrial and commercial customers in late 2021.
8. Renewable obligation. Starting in 2018, NEA adopted provincial quotas for renewable energy consumption that apply to provincial grid companies and large industries (which often own their own power supplies). ³⁷ These provincial quotas were short-term administrative measures mandating renewable energy consumption over one to two years, with the goal of integrating existing renewable capacity into power grids. In early 2021, NEA issued a new draft renewable obligation that set out provincial requirements to 2030, showing how non-hydro renewable energy can reach 25% of total generation by that time. ³⁸ NEA subsequently indicated that renewable consumption targets will continue to be published on an annual basis and long-term targets will remain advisory. ³⁹ (Similar policies in the United States—known as renewable portfolio standards— and the United Kingdom—known as the renewable obligation—typically have binding targets for 10–20 years to help guide investment.)
9. In 2017, the Chinese government launched a voluntary market for green certificates and identified green power trading as a potential path for phasing out subsidies and fixed feed-in tariffs. ⁴⁰ To receive a green certificate under this program, a company must relinquish any feed-in-tariff subsidy. As a result of this design, purchase volumes have been low. ⁴¹ More recently, green power trading has started to grow, though only for monthly and annual contracts and only for renewable production hours beyond the hours already guaranteed for purchase by grid companies. ⁴² In 2021, the central government also announced a set of green power trading pilots that would involve interprovincial trading. ⁴³ Several provinces have now participated in an interprovincial green power trading platform organized for contracts of one year or longer. The government plans to eventually link the green certificate and renewable obligation policies.

Relationship to Climate Goals

Power market reforms are widely considered important to achieving carbon neutrality because of their potential to promote energy efficiency and low-carbon energy sources.

Barriers to interprovincial trading of electricity have been an obstacle to wind and solar power generation, since variable renewable energy can be more easily managed when smoothed over larger geographical areas. ⁴⁴ Several studies have shown that more flexible trading of electricity across provincial boundaries offers the lowest cost solution for improving system flexibility and increasing renewable integration. ⁴⁵

Spot markets are also often considered essential for integrating large amounts of renewable power into electric grids. Spot markets tend to favor plants with lower marginal cost of production such as wind and solar power (which have zero fuel costs). Spot markets are also key to ensuring that carbon prices fully incentivize consumers to prioritize energy efficiency and lower-carbon generation (although China’s current carbon markets are based on carbon intensity benchmarks, and the price of carbon emissions allowances does not increase the price of electricity for end consumers or directly affect the dispatch order of power plants). ⁴⁶

A 2022 analysis by the International Energy Agency found that moving from administratively determined dispatch to economic dispatch would strengthen China’s Emissions Trading System by allowing markets to reflect carbon prices in electricity generation costs.⁴⁷ Several studies have found that power market reform in China is likely to reduce the cost of low-carbon energy sources and steps toward carbon neutrality. ⁴⁸