For China to meet its dual-carbon goals – of peaking emissions before 2030 and reaching carbon neutrality before 2060 – establishing a unified national power market is going to be crucial. This article, part one of two, will analyse the characteristics and current state of electricity trading in China. In part two, we will discuss proposed pathways for establishing a unified power market.
The average temperature across the world this July was 17.23C, the highest monthly temperature on record and a reflection of both global warming and El Niño conditions. High temperatures have persisted throughout much of China since June, driving a surge in electricity load and bringing forward the annual summer peak in electricity consumption.
In the Beijing-Tianjin-Hebei region, high temperatures came early and raised grid load by more than 30% compared with the same period last year. Sichuan and Yunnan, China’s two biggest generators of hydropower and major bases for “west-to-east power transmission”, saw hydroelectricity output fall by 24.4% and 43.1% respectively in May, on account of high temperatures and drought conditions. All this prompts troubling reminders of the power shortages of 2021 and the peak load electricity restrictions in Sichuan and Chongqing during summer 2022.
How does China, with one-third of global power generation and the world’s most complex power grid, ensure secure power supply? Even more significant for the power industry, which accounts for 40% of China’s carbon emissions, is its key role on the road to peak carbon. The sector’s low-carbon transformation will be crucial for achieving the dual-carbon goals.
There are however a number of obstacles to power trading and market development at present. These include barriers to inter-provincial electricity trading, price inelasticity hampering timely reaction to rapid changes in the market, and inadequate support for enabling high-quality development and increased utilisation of renewable energy. One of the keys is to enhance capacity for flexible, inter-provincial and inter-regionalallocation of electricity. In addition to reliance on grid infrastructure channels for smoothing-out inter-regional surpluses and shortages, the underlying market mechanism for electricity is also critically important.
Evolution in China’s electricity trading reforms
China’s electricity industry has undergone a series of reforms since the era of reform and opening-up began in 1978. Since the 1980s, the industry transitioned through several stages of reform, moving from a system of vertically integrated planning and management through to the introduction of pooled financing for development, then separation of government and business, followed by corporatisation. In 2002, the State Council published the intention to “break monopolies, introduce competition, raise efficiency, lower costs and strengthen the tariff mechanism” in its Notice on Issuing the Electricity System Reform Plan (known as document no. 5). This reform left certain problems unresolved, however, including the lack of an electricity-trading mechanism and inability to fully utilise renewable energy resources.
In 2015, China launched a new round of reforms – when the State Council issued its Opinions on Further Deepening the Reform of the Power System (known as document no. 9) – spurring the pace of construction of the market for electricity, and of the spot market in particular. Market trading of electricity has risen year by year since then, and the market has gradually taken shape as one in which electricity is traded mainly at the provincial level and mainly involving medium-to-long-term deals between power generators, users and sellers.
In spatial terms, since the release of document no. 9, China’s electricity market has been constructed around provinces as the basic unit. Reformed transmission and distribution tariffs, which apply nationwide, are likewise being piloted at the provincial level, with two-thirds of provinces now comprehensively trialling the electricity reforms.
According to statistical analysis (see chart below), nationwide market trade in electricity (including intra- and inter-provincial trading) increased year by year between 2017 and 2022, from 1,632 terawatt-hours (TWh) to 5,254 TWh, leaping from 25.9% to 60.8% as a share of China’s total electricity consumption.
Intra-provincial trading currently accounts for more than 80% of the market-traded electricity in China. The rest is traded inter-provincially, rising in share – with fluctuations – from 17.9% in 2017 to 19.7% in 2022. The volume of electricity traded on the intra-provincial market last year totalled 4,218 TWh, compared with 1,036 TWh on the inter-provincial market, both amounts being three times higher than in 2017.
While intra- and inter-provincial market trading of electricity continues to expand, it can be seen from a series of policy documents issued by the government last year that “establishing a unified national electricity market” has now been elevated to national strategy. Expectations for the future cross-provincial and cross-regional electricity market are high, especially considering the needs to promote optimal allocation of resources and smooth out inter-regional surpluses and shortages.
Early last year, the National Development and Reform Commission (NDRC) and National Energy Administration (NEA) issued the Guiding Opinions on Accelerating the Construction of a National Unified Power Market System. This included proposals for systematically planning and progressing the construction of a national, multi-level, unified electricity market system by 2030, on the basis that existing provincial-level electricity markets will be retained.
Released in March of the same year, the 14th Five Year Plan (FYP) for a modern energy system provides for listing “the establishment of a unified national electricity market” among the key electricity reforms of the FYP period.
In January this year, “the establishment of a unified national electricity market” headed the NEA’s list of Energy Regulatory Work for 2023. The document also stressed the need to draw up plans and parameters for developing the electricity market, move forward with the electricity market mechanism for southern China, and accelerate construction of electricity markets in the Yangtze River Delta, the Beijing-Tianjin-Hebei region, and elsewhere.
Spot market still growing strong
In terms of timeframes, electricity trading currently comprises medium-to-long-term (MLT) transactions in the main, supplemented with spot trading. Being a commodity that is produced, distributed and consumed in real time, and that cannot be stored in large quantities, electricity has to be precisely controlled by the dispatching authorities. The wholesale market for electricity, when traded as a commodity, is usually divided into the MLT market and the spot market, according to duration of trading cycle.
The MLT electricity market refers to the undertaking of multiyear, annual, quarterly, monthly, weekly and multi-day wholesale electricity transactions by market methods such as bilateral negotiation and centralised trading. Such transactions are made among generators, users and sellers of electricity, as well as other market players meeting the conditions for access. The spot market, meanwhile, generally indicates transactions covering day-ahead and intra-day periods, characterised by short trading cycles and high price volatility. Last year, 79% of China’s total market-traded electricity was traded on the MLT market, totalling 4,141 TWh.
Things are now changing. China has been setting up more flexible, inter-provincial and inter-regional spot markets to complement the MLT market, since trial operation of the spot market in 2018. The pace of construction of spot markets is accelerating.
Last November, the NEA issued the Basic Rules for Electricity Spot Markets (consultation draft) and Regulatory Measures for the Electricity Spot Market (consultation draft), further extending the pilot spot markets to a national scale and laying foundations for consistency and efficiency across the electricity market. Meanwhile, construction of the southern China electricity market, beginning with Guangdong, has played a pioneering role in establishing a unified spot market for electricity at national level. Data shows that during trial operation of the inter-provincial electricity spot market (State Grid operating region) in 2022, the cumulative volume of electricity traded across the whole year was 27.8 TWh.
Uneven trading pattern
At present, intra-provincial transactions account for the bulk of trade on China’s power market. Nationwide, more than 80% of market-traded electricity in the last five years has been traded within provinces and less than 20% between provinces. And even in 2022, inter-provincial spot trading accounted for less than 1% of total market-traded electricity. Factors underlying the predominance of intra-provincial over inter-provincial trading are reflected in the following three facets.
The first is policy. Taking into account the different ways power and energy are structured in the provinces and the difficulty of reform, it was document no. 9 that laid the ground in 2015 for electricity market reform to be driven at the provincial scale, with provinces empowered to determine pathways and pilot programmes for their own internal electricity markets. The piloting of electricity spot trading, launched in 2019, is similarly province-based. This set of policies and practices, while enabling province-level electricity markets to mature, has also given rise to discrepancies among their respective rules, standards, and transmission and distribution tariffs, making it harder to achieve inter-provincial coordination.
The second is inter-provincial transmission. There is still a need to optimise and improve inter-provincial and inter-regional transmission channels. For example, last year’s power restrictions in Sichuan exposed the problem of channels linking Sichuan with other provinces being mainly one-way lines for outward transmission. While Sichuan’s capacity for outward transmission was about 30 gigawatts (GW), only 6 GW of support electricity was available in the other direction during the shortages, making for serious difficulties in the coordination of incoming emergency power supply.
Another example is the construction of inter-provincial and inter-regional power grids, characterised by ultra-high voltage (UHV) projects, which unfortunately lags behind the development of power supply in China’s main bases for wind and solar PV, thereby restricting the full exchange of power between provinces. The approval and construction cycle for UHV outward transmission channels is about three years, whereas it can take just a year or two to complete a 10 GW centralised solar PV project. Against the backdrop of this mismatch between grid construction and feverish investment in new energy, there needs to be an urgent reassessment of demand for new transmission channels, with market mechanisms used to direct the optimal inter-provincial and inter-regional allocation of electricity resources and improve utilisation rates for existing channels.
The third facet is barriers between provinces. There are objective barriers presenting challenges to inter-provincial trading, because inter-provincial and inter-regional exchanges of electricity involve much manoeuvring by provinces on issues relating to economic development and security of supply.
An example is provided by the quarrel between Yunnan as electricity-transmitting province and Guangdong as receiving province. In 2015, around the time that document no. 9 was released and when conditions for domestic supply and demand were still relaxed, declining demand for electricity in Yunnan combined with increased generation of hydropower resulted in the province transmitting 2% more electricity to Guangdong that year – higher than the 1.4% growth in Guangdong’s electricity consumption. This squeezed the utilisation hours and profit margins of thermal power generators in Guangdong, triggering dispute and disagreement between the two sides.
When conditions for power supply and demand were getting tight, during 2021–2022, the added pressure to guarantee electricity supply, all over the country, made inter-provincial coordination more difficult. Yunnan cut back on outward power transmission during this period, partly because of the sharp drop in hydropower output associated with dry conditions and partly because Yunnan, like other clean-energy-transmitting provinces, wanted to use low hydropower tariffs and the value of green energy to draw in industry and reap the economic benefits. For example, the relocation into Yunnan of high-energy-consuming production typified by the electrolytic aluminium industry drove up electricity consumption in the province and added to the pressure on maintaining local supply.
As a receiver of electricity, Guangdong wanted to reduce its dependence on external supply at times of tight supply, in order to mitigate the security and stability risks of transferred-in electricity and avoid being subject to the whims of other regions. The proportion of Guangdong’s electricity supplied from outside the province fell from around 30% in 2020 to 23% in 2022, along with a corresponding decline in the volume of electricity received from western China, from 200.9 TWh to 177.2 TWh. With its target for 90 GW of newly installed capacity within three years, declared in May 2023, Guangdong’s rising demand for electricity in the future will come to be supported by locally added capacity, while the need to buy external electricity under long-term agreements will drop away.
Urgent need to break down inter-provincial barriers
While factors such as competing development efforts and inter-provincial barriers pose challenges to inter-provincial and inter-regional electricity trading as a whole, there has been a marked increase in market trading and clear demand for procurement on inter-provincial spot markets. This reflects fluctuating prices for primary energy, globally, along with seasonal supply shortages domestically. In 2022, 230.7 TWh of electricity was traded across provinces and regions in southern China, a 1.4% decrease year-on-year, but conversely there was a 13.4% increase in market-traded power, accounting for 76.2 TWh of that total.
The past two years have seen pressure to guarantee electricity supply through the peak loads of summer and winter. Inter-provincial spot trading, which has the advantages of extensive reach and short cycles, can be a market-based means for guiding the timely allocation of surplus power towards regions where supply is tight. This incentivises peak generation by power firms on the basis of meeting their province’s electricity supply and demand needs, thereby improving the power supply and balancing capability of the whole grid.
On the Shanxi spot market, for example, the spot price reached the cap of 1.5 yuan/kWh during the evening peak hours – when supply is tight – of July and August 2021. This fully incentivised generators to supply for peak demand, guaranteeing reliable supply of power within the province and inter-provincial outward transmission.
Improving the capacity of the entire grid to ensure energy supply, by means of inter-provincial and inter-regional spot markets, and using market means to direct electricity from areas of surplus to areas where the balance is tight, is of major significance in the current environment for electricity supply and demand.