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Wholesale Electricity Market Operations

Researchers at NREL are studying wholesale electricity market operations to understand how they currently maximize competition, efficiency, and fairness and the ways that renewable energy resources and other emerging technologies may be impacting the outcomes of these markets. About two-thirds of the United States' electricity load is operated under restructured electricity markets administered by independent system operators (ISOs) and regional transmission organizations (RTOs). These markets are highly complex and combine the physics of electricity with the principles of economics. Most electricity markets were designed in the 1990s and early 2000s, when renewable electricity resources and other emerging technologies were not as common as they are today. Researchers are looking at the four main electricity market components and whether potential market design changes may be necessary to allow for better integration of new technologies while maintaining system reliability, efficiency, competition, and equitable treatment.

The two main questions of focus for wholesale electricity market operations are:

  • Are resources needed for long-term reliability able to recover both variable and capital costs when energy prices and energy schedules are reduced from increased renewable generation?

  • Are resources needed to provide flexibility to meet the increased variability and uncertainty of variable renewable resources being incentivized to offer and provide that flexibility?

Energy Markets

In the United States' restructured electricity markets, energy is bought and sold in the wholesale market through a two-settlement system. First, the day-ahead market clears energy to meet the bid-in load for the entire day, one day in advance. Then the real-time market buys and sells energy at real-time spot prices to make up imbalances when system conditions change from the day-ahead. Resources bid in three-part bids that include energy costs, costs to be online, and costs for starting up. Then, prices are based on on the locational marginal price (LMP) concept, where the price at every node is equal to the marginal cost of serving the next increment of load. The price ensures that any locational differences from transmission congestion or electrical losses are incorporated. Potential impacts of variable generation to the energy market include:

  • Variable generation can reduce average LMPs because of its low variable costs.

  • Variable generation can cause more occurrences of zero or negative LMP periods because of its variable cost and zero or negative bid-in costs.

  • The increased variability can cause LMPs to be more volatile from one time period to another.

  • The increased uncertainty can cause greater differences between day-ahead and real-time market LMPs (although on average they are likely to remain converged as a result of virtual trading).

  • Variable generation can cause a greater need for flexible resources in the energy market, and the energy market may or may not provide sufficient incentive for this flexibility.

Forward Capacity Markets

Assessing the need for future power plants to meet long-term reliability needs is called resource adequacy, and it has always been an important part of power system planning. It answers the question of how much capacity is needed. Because excess time and certainty are required to invest in building high-capital-cost supply resources, and these capital costs may not be able to be recovered on the energy market alone, forward capacity markets are established in some, but not all, market regions in the United States. Forward capacity markets are separate auctions for capacity that typically look at least 6 months and up to a few years ahead. Below are some potential impacts of variable generation on capacity markets.

  • The reduction in LMP and energy schedules from conventional resources will result in reduced revenues in the energy market. If these resources are still required to be available for short periods of time, more resources become capacity based rather than energy based.

  • The variability and uncertainty can cause the need for different types of resources to be built and available. In other words, variable generation may require planning and building more flexible resources to prepare for future needs rather than focusing on the need for megawatt capacity alone.

  • The variability and uncertainty may require existing resources to modify their flexible capability potential. Market designs may need to incentivize the existing resources to spend the capital on retrofits to increase the flexible capability that they can provide.

Ancillary Service Markets

Ancillary services are those services, in addition to energy provision, that support power system reliability. Numerous ancillary services exist today, and in restructured markets, ancillary service markets ensure ancillary services are co-optimized with energy to provide a least-cost solution and incentivize resources to provide the services most needed for reliability. Typical ancillary service markets are spinning contingency reserve, nonspinning contingency reserve, and regulating reserve. Other ancillary services like voltage control and black start services do not typically have auction-based markets. Below are some potential impacts of variable generation on ancillary service markets.

  • Variable generation can increase the requirements for normal balancing reserve, such as regulating reserve, which can increase the prices for those services.

  • With higher balancing reserve demands and increased variability and uncertainty, administratively set scarcity prices may be triggered more often, resulting in more frequent extreme price spikes.

  • Variable generation can displace synchronous, frequency-responsive resources, and when not equipped with technology to provide a comparable response, it can cause the need for supplemental actions or market designs to ensure that sufficient frequency response and/or system inertia is available.

  • Variable generation can cause the ancillary service requirements to change from one day to another and from day-ahead to real-time, if the requirements are based on correcting the variability and uncertainty of variable generation, which can cause uncertainty in ancillary service demands and changing demands for the same time periods between the day-ahead and real-time markets, similar to load.

  • Variable generation may require greater flexibility from the resources that correct for its variability and uncertainty. Certain forms of flexibility may or may not be built into the current ancillary service markets.

Financial Transmission Rights Markets

Financial transmission rights (FTRs) are forward auctions in which bidders can earn the right to collect revenue from locational differences in energy prices. This is mainly an instrument to hedge against locational price volatility. When the transmission system is congested, the load at the receiving side of a transmission constraint pays more for energy than the generators supplying energy at the sending side. The difference is allocated to the FTR holder. Below are some potential impacts of variable generation on FTR markets.

  • The increased variability and uncertainty can cause greater variation on power flow, which causes FTR holders to be uncertain about expected congestion patterns.

  • The increased uncertainty can cause greater deviations of power flows between the day-ahead and real-time markets. Because FTR revenues are typically based on the day-ahead market, there could be greater divergence between FTR revenues and actual congestion patterns.

For More Information

For more information about NREL's work on wholesale electricity market operation, see the following resources. Additional publications can be found in the NREL Publications Database.