Wholesale Electricity Markets and Pricing in China: How is Reform Going?


Implementation of wholesale electricity markets is a major theme of China’s power sector reform effort, launched in early 2015. The central government has issued guidance documents on market design, and various Chinese provinces and regions have announced pilots for wholesale electricity markets. However, policymakers are still working to specify and build consensus for wholesale price reform that will support the government’s emissions and reliability goals for the power sector.

What’s the Problem with Wholesale Prices in China?

Under China’s status quo approach to wholesale pricing, prices for coal-fired generators were set by the National Development and Reform Commission (NDRC), together with provincial-level officials, on a fixed yuan per kWh basis. These prices are traditionally reviewed annually, but, in practice, there has been little fluctuation, even from year to year. This approach arose in the 1980s, survived various attempts at reform, and is now a target of the current round of power sector reform.

This approach contributes to several significant problems that the country’s power sector faces today. Under the status quo, prices do not adjust to reflect changing economic conditions or shifts in the government’s overall policy goals, such as targets for renewable energy. In recent years, wholesale prices have overcompensated investment in coal-fired capacity by failing to adjust in the face of weakening demand growth and declining coal prices, exacerbating coal-fired generation overcapacity. This overcompensation has exacerbated runaway overcapacity of coal-fired capacity (A significant portion of current coal-fired capacity is now simply not needed, meaning that if generators were operated according to merit order, some power plants would likely not run at all).

As for the coal- and gas-fired generators that are still needed, the status quo approach to pricing fails to offer adequate incentives to these generators to operate efficiently in the context of the overall power system. Less efficient coal-fired plants should, in an efficient system, operate less than their more efficient counterparts and should only be dispatched in hours when the demand for electricity is high. However, the status quo leaves coal-fired generators hungry for hours of operation, with no good business model for operating as peaking or flexibility resources, which are much-needed to support renewable resources. Nor does the status quo offer compensation to other resources that provide capacity and flexibility (e.g., demand response, gas-fired units, or energy storage).

We have addressed these issues at length—including the connections between annual output planning (i.e., allocation of hours to coal-fired generators), inefficient system operations, and renewable curtailment—in a number of other reports (See, for more detail, here, here, and here). In short, the status quo approach to pricing does not support transition to a more flexible power system that meets emissions and reliability goals. What’s worse, the status quo gives coal-fired generators reason to resist market reforms.

The challenge is to reform wholesale pricing, so that it sends better signals for investment in flexible resources (including demand-side and gas-fired resources) and the operation of resources flexibly. There are a range of possible approaches to reforming wholesale prices in China. Indeed, there is a wide variation of possibilities suggested by what has been done in other parts of the world. But first, let’s take a look at what has been going on with China’s reform efforts since early 2015.

How has Reform Gone so far?

Nearly twenty provinces have launched ‘market pilots,’ including several approved in August and September. (There is some precedent for this in China: in the early part of the last decade, several provinces made short-lived attempts to implement competitive wholesale markets.) The NDRC’s Notice on Supporting Electricity Reform Documents (Document 2752; November 2015) provides guidance for provincial pilots for wholesale generation markets (Appendix 2), and provides instructions for how non-pilot provinces should gradually make the transition from planned operating hours to a more market-based approach (Appendix 4). Also in November 2015, the National Energy Administration (NEA) issued a draft document called Basic Rules for Electricity Market Operations. The provisions in the NDRC and NEA documents include calls for expansion of longer-term markets based on contracting between generators on one side, and large end-users or retail companies on the other. (This is conducted through both bilateral negotiation and centralized auctions and is called “direct trading” in China.) They also call for implementation of shorter-term markets (day-ahead and energy balancing mechanisms; typically referred to in Chinese regulatory documents as spot markets), and cross-provincial regional trading.

To date, the market pilots have focused almost entirely on implementation of direct trading. The approach has been to expand direct trading, based on pilots that have been running for several years, and at the same time to gradually scale back planned allocations of generator operating hours. In public and official discussion, this is typically framed in terms of ‘hongli’ (dividends) for large users—that is, about allocating the benefits of lower prices amongst industrial consumers. It appears large industrial consumers and coal-fired generators are negotiating prices that are below the status-quo wholesale price, but higher than variable cost. So far, policymakers are making some effort to discourage the least efficient end-users from participation in direct trading. However, direct trading may expand rapidly: in a draft notice, NEA calls for a 30 percent share of local industrial consumption to be covered by direct trading in 2016, reaching 100 percent of industrial consumption by 2018, with all commercial consumption covered by 2020. (Industrial and commercial consumption together accounted for 85 percent of total consumption in 2015.)

As at least one observer has argued (here, in Chinese), that implementation of direct trading can be seen as a fairly conservative reform that fits the ‘space’ of the annual output planning process that it is gradually replacing. That is, annual allocation of hours is being gradually replaced by annual contracts that also specify a number of hours that the generator in question will operate. However, relatively little concrete progress has been made in any of the market provinces towards implementation of short-term markets. In addition, it is not clear that much progress has been made in terms of improving system operations. The observer suggests that the dispatch centers may intend to continue operating according to the annual contracts in a way that is similar to (and similarly inflexible) the previous approach of operating according to the annual allocation of planned hours.

In sum, ‘market’ reform since early 2015 has mainly taken the form of expanded direct trading. This is partly in reaction to pressure from large-users for lower electricity prices. Coal-fired generators have also been supportive of the emphasis on direct trading, given their interest in finding use for excess capacity. Policymakers have proceeded cautiously so far, limiting the access of relatively inefficient end-users, in line with China’s longstanding policies on differential pricing. It also appears that policymakers have limited the ability of coal-fired generators to offer excess capacity at fire-sale prices. Meanwhile, however, there is much work to be done to solve the underlying challenges of wholesale price reform.

Mapping a Reform Path

The challenge is to implement practical reforms that meet the broad principles set out in Document #9, including reliability, emissions reduction, consumer protection, better planning, and increased use of market mechanisms. On a somewhat more detailed level, as we argued in our recent discussion paper, the challenge is to reform wholesale pricing in line with four goals:

  1. Supporting dispatch reforms and efficient system operations;
  2. Fairly compensating generators and other resources that are needed for reliability;
  3. Discouraging unneeded investment and encouraging existing generators that are not needed to retire; and
  4. Sending the right signals for investment in any new flexible resources that are needed.

There are a number of possibilities. As the NDRC and NEA documents indicate, provinces and broader regions could establish spot markets based on competitive bidding from generators. These markets would produce wholesale prices that fluctuate on day-ahead and intraday timescales. If implemented well, competitive bids in these markets should reflect the short-term costs of various generators, and power plants could be committed and dispatched according to these bids.

There are substantial challenges in setting up this type of competitive regime. The United States, Europe, and other places are still working to perfect market design. The advent of large amounts of variable generation (e.g. wind and solar) has added to the challenge. There continue to be many debates about how to get the details right in order to meet emissions and reliability goals while delivering acceptable outcomes for  consumers. One issue is that electricity markets are particularly susceptible to manipulation. China will face particular challenges in establishing competitive bidding in spot markets: institutions to support transparency, monitoring, and enforcement are somewhat lacking in capacity, and state-owned enterprises currently dominate the industry.

Officials are reportedly debating some of these issues and considering a new push, including issuance of a new regulation for spot market implementation. Some official statements call for a spot market to be implemented by 2018, with broader implementation by 2020. However, other officials—pointing to the experience in other countries – argue that more than five years may be needed. There is also much discussion about which provincial pilot should take the lead in this area. (An announcement from NEA, dated September 9, calls for “exploration of establishment of a market mechanism for coordinating spot trading and long-term trading” in Gansu Province. The Jing-Jin-Ji region around Beijing is also under consideration.)

Policymakers might also find it worthwhile to consider relatively easy-to-implement (and relatively low risk) alternatives—perhaps as an interim measure before competitive spot markets are launched. In particular, we have previously suggested implementation of an energy price (per kWh, based on estimated variable operating costs) and a capacity price (per KW) for each generator (See also Section 4, here). The capacity price could be determined by competitive auction, with relatively little difficulty. The capacity price would ideally be based not just on KW of capacity, but on desired flexibility characteristics of that capacity, and determined according to a competitive auction mechanism. (It is worth noting that, given the large-scale overcapacity of coal-fired generation that has emerged in recent years in China, capacity payments would tend to be quite low—with possible exceptions such as gas-fired capacity that is currently scarce in China and that would be valued for its flexibility.) China already has some useful experience in this area: some two-part wholesale pricing schemes (featuring just this kind of capacity price and energy price) have been set up in recent years for gas-fired capacity in Zhejiang, Shanghai, and for pumped hydro generators across the country—although these have not attracted much attention in the power sector reform debate. Building on this type of pilot effort could help set the stage for further development of competitive markets, perhaps including allowing entry of new participants and building the experience of government agencies with market oversight responsibility.