The Wholesale Electricity Market Portal was launched by the U.S. Energy Information Administration (EIA) in March of 2024 to help users examine and access electricity markets data in the seven Regional Transmission Organizations (RTO) and Independent System Operators (ISO). Contact online >>
The Wholesale Electricity Market Portal was launched by the U.S. Energy Information Administration (EIA) in March of 2024 to help users examine and access electricity markets data in the seven Regional Transmission Organizations (RTO) and Independent System Operators (ISO).
The IEA real-time electricity map displays electricity demand, generation, spot prices, trade as well as CO 2 emissions from more than 50 sources. Data is available historically, as well as daily or hourly, and at country or regional levels. Explore the map to discover visuals and analysis.
Electricity explained. Data for the United States for 2022 (except where noted). Note: MW = megawatts, MWh = megawatthours, KW = kilowatts, and kWh = kilowatthours. Total may not equal 100% because of independent rounding. 1 Utility-scale power plants have at least one MW of electric generation capacity.
Shown are annual average real time electricity market prices based on data from all locational marginal price (LMP) nodes in 2023. High wholesale electricity prices in ERCOT and CAISO were driven by different phenomena. In CAISO, high annual prices in 2023 were driven mostly by the high hourly prices in January 2023.
The electricity market in the United States is home to three of the 10 most valuable electric utility companies in the world. Florida-based NextEra Energy led the global utility company...
Electricity explained. Data for the United States for 2022 (except where noted).
IEA (2021), Electricity Market Report - July 2021, IEA, Paris https://, Licence: CC BY 4.0
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An overview of the different types of US electricity markets, how they are regulated, and implications for the future given ongoing changes in the electricity sector.
For definitions of bolded terms and other concepts related to the electricity grid and industry, check out "Electricity 101."
This explainer is part of RFF''s Future of Power Explainer Series, which outlines the fundamentals of electricity markets and policy to convey how electricity systems function today and how they may evolve in the future with decarbonization efforts.
Electricity 101: Terms and DefinitionsUS Electricity Markets 101Renewables 101: Integrating Renewable Energy Resources into the GridElectrification 101 FERC 101: Electricity Regulation and the Federal Energy Regulatory CommissionFERC 102: FERC''s Role in Grid Decarbonization
Prior to the 1990s, most investor-owned electric utilities were regulated and vertically integrated, which means the utilities owned electricity generators and power lines (distribution and transmission lines). Today, only one third of US electricity demand is serviced by these integrated utility markets because many states have abandoned this system in favor of deregulation.
Utilities in traditionally regulated regions operate as a monopoly in their territories, which means that customers only have the option to buy power from them. To keep electricity rates reasonable for customers, state regulators oversee how these electric utilities set electricity prices. Retail electricity prices in these areas are set based on recovering the utility''s operating and investment costs alongside a "fair" rate of return on those investments (collectively called a revenue requirement). This revenue requirement must be approved by the state''s public utilities commission, which prevents utilities from overcharging customers for electricity.
Even though vertically integrated utilities generate their own electricity, many trade with other utilities during times of need. For example, during certain times of the year it may be cheaper for some utilities to purchase excess hydroelectric power from others rather than generate power using their own facilities. This type of wholesale bilateral trading is especially common in the western and southeastern United States where most utilities are still regulated. These wholesale market transactions are subject to regulation by the Federal Energy Regulatory Commission (FERC).
Beginning in the 1990s, many US states decided to deregulate their electricity systems to create competition and lower costs. This transition, known as restructuring, required electric utilities to sell their generating assets and led to the creation of independent energy suppliers that owned generators. Because each new independent energy supplier could not cost-effectively create their own power line infrastructure, electric utilities held onto these assets and became transmission and distribution utilities, which continue to be regulated.
The biggest impacts resulting from deregulation were changes to retail and wholesale electricity sales, with the creation of retail customer choice and wholesale markets.
In deregulated areas, electricity customers have the option of selecting an electric supplier (known as customer choice) rather than being required to purchase electricity from their local electric utility. This introduces competition for retail electricity prices. Since many electric suppliers can exist within a region with customer choice, electric retailers offer competitive prices to acquire customers. For customers who choose not to select an independent power supplier, their local utility is still obligated to provide them with electricity that the utility will purchase from generators.
Unlike regulated states that plan for investment, deregulated states use markets to determine which power plants are necessary for electricity generation. As utilities and competitive retailers in deregulated regions do not generate their own electricity, they must acquire power elsewhere for their customers. Centralized wholesale markets—in which generators sell power and load-serving entities purchase it and sell it to consumers—provide an economically efficient method of doing so (discussed more in the next section). Notably, under this structure, investment risk in power plants falls to the electric suppliers and not to customers, unlike in regulated markets.
Following deregulation, regional transmission organizations (RTOs) replaced utilities as grid operators and became the operators of wholesale markets for electricity. These RTOs have evolved over time.
Since many RTOs operate wholesale markets that encompass multiple states, they are regulated by FERC (with the exception of the Texas RTO, the Electric Reliability Council of Texas—or ERCOT). FERC has oversight of all wholesale power transactions on the two large, interconnected grids: the eastern and western interconnects.
While regulated utilities base retail rates on a regulated rate of return on investments (as described above), deregulated retail utilities purchase electricity at market-determined wholesale prices and then sell that electricity to customers at market-determined retail prices, given competition from other retailers. RTOs typically run three kinds of markets that determine wholesale prices for these services: energy markets, capacity markets, and ancillary services markets.
Energy markets are auctions that are used to coordinate the production of electricity on a day-to-day basis. In an energy market, electric suppliers offer to sell the electricity that their power plants generate for a particular bid price, while load-serving entities (the demand side) bid for that electricity to meet their customers'' energy demand. Supply side quantities and bids are ordered in ascending order of offer price. The market "clears" when the amount of electricity offered matches the amount demanded, and generators receive this market price per megawatt hour of power generated.
RTOs typically run two energy markets: the day-ahead and real-time markets. The day-ahead market, which represents about 95 percent of energy transactions, is based on forecasted load for the next day and typically occurs the prior morning in order to allow generators time to prepare for operation. The remaining energy market transactions take place in the real-time market, which is typically run once every hour and once every five minutes to account for real-time load changes that must be balanced at all times with supply.
RTOs use energy markets to decide which units to dispatch, or run, and in what order. In the day-ahead market, RTOs compile the list of generators available for next-day dispatch and order them from least expensive to most expensive to operate. For example, since wind plants operate without fuel, they are able to bid $0 into the energy market and get dispatched first. Dispatching units by lowest cost allows the market to meet energy demand at the lowest possible price. During periods of high demand, wholesale prices rise accordingly because more high-cost units need to be dispatched to meet electric load.
Base wholesale market prices typically reflect the price for power when it can flow freely without transmission constraints across the RTO''s territory. When that is not possible, RTOs account for congestion on transmission lines by allowing prices to differ by location. As a result, areas with high demand and scarce electric resources typically have higher prices than those with abundant generation relative to load.
Electricity retailers are required by the North American Electric Reliability Corporation (NERC), an independent organization that ensures grid reliability, to support enough generating capacity to meet forecasted load plus a reserve margin to maintain grid reliability. Some RTOs run a capacity auction to provide retailers with a way to procure their capacity requirements while also enabling generators to recover fixed costs, i.e., costs that do not vary with electricity production, that may not be covered in the energy markets alone.
The capacity market auction works as follows: generators set their bid price at an amount equal to the cost of keeping their plant available to operate if needed. Similar to the energy market, these bids are arranged from lowest to highest. Once the bids reach the required quantity that all the retailers collectively must acquire to meet expected peak demand plus a reserve margin, the market "clears", or supply meets demand. At this point, generators that "cleared" the market, or were chosen to provide capacity, all receive the same clearing price which is determined by the bid price of the last generator used to meet demand.
Payments to generators in the capacity market are essentially a reward for that generator being available to operate and provide electricity if needed. Consequently, if generators are unavailable to operate during a time when they are called upon, they may face fees under capacity performance requirements.
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