Bringing Electricity Markets to China: Adapting International Experience in Power Sector Deregulation to Fit China’s Economy
Introducing competitive electricity markets to China could reduce global emissions by 0.4 percent.
The world’s second-largest economy is moving away from its centrally planned roots and is undertaking systemic power sector reforms. Chinese regulators’ motivations are not all that different than those of regulators in the West: they are trying to introduce competition in order to lower prices and optimize system costs. There is also a strong environmental focus, where market reforms stand to integrate more renewables into the power supply and reduce emissions by utilizing the most efficient generators.
According to a study by Rocky Mountain Institute (RMI), these reforms stand to reduce production costs by 3.6 percent annually, and reduce power sector emissions by 4.4 percent overnight, by an amount equal to almost 0.4 percent of global annual emissions. This is likely an underestimate of the potential savings, as RMI’s study uses the most conservative assumptions and the test area suffers from many institutional constraints. According to International Energy Agency research, market dispatch in China could reduce costs and emissions by up to 8 percent today, growing to 12 percent savings by 2035.
What’s the catch?
China’s reforms will create substantial changes, since in the current state all generators, regardless of their efficiency and the cost to operate them, get roughly equal operation hours and are paid roughly the same for kilowatt-hours (kWhs) produced. Moving to differentiated dispatch is not only a huge operational change for generators and grid operators, but also presents great uncertainty to their revenues. Incumbent generator companies are very powerful and could resist these reforms if they expect to lose out in the process.
This familiar challenge, where all power market reforms face fierce resistance from incumbents unaccustomed to market participation, needs to be tackled by market design. Compromises need to be struck that provide the right protections to bring affected generators on board, while not undermining the objective of short-term markets, which is to identify the least-cost resources to meet demand in real time and create competitive pressure. This is why China is conducting a comprehensive survey of international experience on market designs and transition mechanisms to manage stakeholder resistance, determining what works for China and what doesn’t. RMI’s report, Implications of Energy Spot Markets in China: Finding the Right Market Mechanisms to Address the Technical, Economic, and Political Impacts of China’s Market Reform, aims to help regulators with exactly this process. RMI’s modeling helped test different approaches to spot market design, which elements must remain for effective market operation, and which can be managed through the right transition mechanisms. (Transition mechanisms were described in greater detail in another RMI report, available in Chinese only).
In our approach, we used market models to predict how much each generator stands to make in markets, identifying which generators will not make enough money to remain operational, and whether the system would be able to operate reliably if those generators exit. The answer for the modeled region in the North of China is yes: market exit will strengthen market effectiveness and efficiency, reduce costs and emissions, and still maintain system reliability. And we found the savings from reducing the amount of coal burnt in inefficient generators could be used to help pay off some of the remaining loans for the generators forced to shut down, while still passing some savings on to customers.
We believe this kind of analysis is very important for decision makers, who need a concrete picture of what the impacts will be, not just an idea of what might be, to develop real solutions to handle the challenges associated with market competition. This analysis also aims to demonstrate how the reality that not all generators will make it through such reforms could in fact be a good thing for overall economic health. These approaches can be used throughout China to design electricity market reform plans, and can also be used globally as other countries deregulate their power systems. Although the specifics of our analysis are most relevant to Chinese stakeholders, we do believe some of the main findings are useful to regulators working to implement markets anywhere. These are:
- All generators need to participate in the market in order to fully optimize costs, especially renewables, hydropower, nuclear power, and combined heating and power plants, which are often exempt from the market.
- Markets will eliminate unnecessary capacity. It’s important to let inefficient, unnecessary generators exit the market to maintain effective price signaling. The cost savings from optimized dispatch can be used to pay off remaining debt on closed generators.
- Generators in nonmarket systems frequently are not accustomed to having to operate flexibly, and say they must operate steadily. All generators in market environments have learned to operate more flexibly, and must be exposed to economic pressures to improve their flexibility, but also need time to learn and adjust their operations.
We dive deeper into some of the concrete examples of how these high-level principles hold true in China, and how the alternatives would result in China not achieving its emissions- and cost-reduction goals.
Lessons from China
Let all generators enter the market
Renewables, hydropower, nuclear power, and combined heating and power plants are likely to be left out of the market as they are less dispatchable and/or their output is constrained by heating needs, safety, or weather. But excluding these often results in suboptimal utilization of both renewable power and efficient thermal power. If renewable energy and other non-fossil power were to enter the market, with both having close to zero marginal costs, market participants would have a strong economic incentive to ramp down their own generation operations to integrate those resources. Today, even where these resources are legally required to be fully integrated, they are often curtailed for technical reasons. Such curtailment tends to occur more frequently when there is no economic incentive to fully integrate, since the technical challenges of adjusting dispatch in real time pose substantial operation risks that are not worth running without economic incentives.
When renewables enter power markets, they are dispatched to the greatest extent possible due to their low marginal costs. The test area of our study integrates 1.4 TWh of additional renewables and drops curtailment from 31 percent to 17 percent for the year of data we tested. This improves the economics of renewables substantially and supports government goals to transfer renewables from relying on subsidies to relying on market revenues for their development.
Combined heating and power (CHP) plants are plants that play the dual role of providing heat in the winter and electricity. They are very efficient, but when sufficient renewable energy supply is available, it is still most cost-effective to integrate it. But CHP often is allowed to operate (and get paid) according to whatever heating needs exist. This means CHP operators never have any incentive to ramp down to integrate renewables, since they will get full payment by operating as before. By requiring CHP to competitively bid into the market, CHP operators will have to decide to either ramp down to incorporate cheaper generation or continue to generate at prices below their costs of production, putting pressure on CHP to become more flexible and efficient.
Based on some of the flexibility seen in China’s current pilot projects, increased economic pressure could help integrate more renewables, dropping curtailment rates to near zero in some provinces. This economic pressure won’t devastate CHP’s economics; even with this pressure CHP will stay profitable under the new market system.
Market exit needs to be managed
Policymakers need to come to terms with the fact that market reform means redundant, inefficient generators will be eliminated. Obviously, the retiring of certain generators may cause problems in some regions, threatening jobs and potentially causing generators that have not fully paid off their debts to go out of business. But it’s a natural result for a market achieving system equilibrium via competition, and thereby maintaining accurate price signals.
This is particularly true for China, as it suffers from serious overcapacity. We found in this analysis that the market price of power will be significantly depressed due to current supply and demand relationships in the test area. In the current overcapacity situation, average wholesale payment drops to 0.2666 RMB/kWh, and this market price is too low to cover the ongoing costs of the 31 percent of generation capacity that is necessary to meet the reserve margin. But if redundant generating units leave the market, market prices will rise to levels that sustain all essential generators and still maintain reliable electricity provision. When an energy spot market is fully implemented, average wholesale payments to generators could be reduced 2.9 percent from 0.3803 RMB/kWh to 0.3691 RMB/kWh, enough to maintain a 24 percent reserve margin, 14 percent more than the 10 percent required by current grid standards.
Reductions in wholesale payments to current generators could be directed to those generators forced to exit, instead of being passed directly on to customers in the short term. In particular, revenue guarantee contracts, which keep current payments to each generator the same, regardless of how much they are dispatched, can naturally manage this in the short term, since any cost savings from buying cheaper energy from the market instead of generating it accumulate to existing generators. Additionally, this will provide opportunities for generators to learn by trying out different bidding and operating strategies without being seriously exposed to economic consequence if they get these wrong early on.
Before adopting such a program, policymakers could first assess what generators are likely to exit the market, and then identify which mechanisms are best to manage those plants and transition their workers to new industries.
Flexibility is not the obstacle
Market dispatch doesn’t increase the overall amount of ramping required of generators, but as more flexibility does become necessary in the future, markets can naturally extract more flexibility from existing plants without retrofitting them.
Not being able to operate flexibly is often cited by thermal generators as a reason not to move to market dispatch. However, despite this common (mis)perception, energy spot markets in China could likely reduce the frequency of start-up and shutdown operations for generators and reduce the amount of ramping they perform by means of better overall scheduling. Previously, prearranged “shifts,” in which plants came on and off the grid (to help balance operation evenly across all generators), were not aligned with other ramping needs in the system and frequently caused situations that required plants to ramp up further and faster to cover for a prescheduled shutdown of another plant.
Our analysis further shows that shifting to market dispatch does not require additional thermal power plant flexibility; all dispatch efficiencies can be achieved using existing assets without violating any technical constraints, including minimum run rates and ramping rates. But markets do lay an important foundation for getting future flexibility at lower cost. Spot markets put pressure on generators to ramp down when prices are below their marginal costs lest they lose money at those low prices, and incentivize them to ramp up quickly when prices spike to really high levels. Internationally, many plants operators that previously said they had limited flexibility changed their minds and lowered their stated minimum run rates and increased ramp rates once markets created the economic signals to do so. China’s current market pilots to help coal plants ramp down to integrate more renewables have shown this increase in flexibility is possible in China too, provided you create the right economic incentives.
Similarities to other emerging markets
Many of those emerging markets have stated-owned utility structures and use cross-subsidies in power prices. They are facing the same demand-growth situation that China faced earlier. And they may face the same renewables-integration and coal-transition problem that China is facing today without intervention. Therefore, lessons from China’s power market design could provide a point of reference and guide power market reform globally.