In the United States, local electricity grids are connected to form larger networks and improve reliability and economic efficiency. The U.S. electricity system has three main interconnections – the Eastern Interconnection, Western Interconnection, and the Electric Reliability Council of Texas (ERCOT). These three interconnections operate independently of each other and have very limited transfers of power between them.

The operation of the electric system is conducted by balancing authorities, which ensures that power supply and demand are balanced to maintain reliability of the power system. Balancing authorities do this by controlling the generation and transmission of electricity throughout their own regions and between neighboring regions. All RTOs and ISOs in the U.S. are balancing authorities, and some electric utilities also serve in this role. The Eastern Interconnection has 36 balancing authorities, and the Western Interconnection has 37.

Electricity Market Structures – Questions & Answers

What Is The Difference Between Vertically Integrated And Restructured Electricity Markets?

State electricity markets have traditionally been vertically integrated where the utility may own or oversee the generation, transmission, and delivery of electricity to customers. This structure evolved as electrification spread in the early parts of the last century because the provision of electric service was deemed a natural monopoly. In the late 1990’s/early 2000’s, some states began the process of restructuring their energy markets (retail electricity and sometimes natural gas) to increase competition in the generation of electricity. States that restructured required electric utilities to sell their generation assets while the transmission and distribution system remained under their ownership. Thirteen states have fully restructured their retail electricity markets, and in some instances allow consumers to decide from whom to purchase electricity called “retail choice.” Six states suspended restructuring whereas eight others are exploring retail choice options. Some states, like California, have partially restructured markets and only permit certain consumers to engage in retail choice. A map from the Edison Electric Institute of state’s that restructured and key differences between vertically integrated and restructured markets is below.

Vertically integrated states

• Under this structure, utilities are responsible for the generation, distribution and transmission of power to customers. Utilities typically own all or some of the generation assets, distribution lines, as well as some of the transmission lines needed to serve customers. In addition to generating electricity, they also purchase some power through contracts from independent energy suppliers.

• Consumers purchase electricity from the utility that services their area, which has an obligation to serve all customers in that area.

• Utilities must seek approval for energy investments from state commissions, which also oversees the rate of return on utility investments and determines the rates that customers pay.

Restructured states

• Wholesale energy prices are set by the ISO and RTO markets with some federal oversight of these markets. Importantly, state commissions still determine the rates that retail customers pay and still provide oversight of the distribution utility that delivers power to customers.

• In most restructured states, customers are offered the ability to choose the supplier of their electricity.

• In most states, distribution utilities own and operate the distribution system and some portion of the transmission system. They must still serve as the provider of last resort for customers who do not choose an alternate provider of electricity. However, these distribution utilities cannot own their generation assets and must either acquire power from the wholesale markets or from independent energy suppliers under power purchase agreements.

• RTOs and ISOs manage wholesale electricity markets and oversee grid operations.

  
  

What Are The Differences Between Wholesale And Retail Electricity Markets And How Are They Regulated?

U.S. electricity markets have wholesale and retail components. Wholesale markets involve the sale of electricity among generators and resellers, which will then be sold to consumers. Retail markets involve the sale of electricity directly to consumers. Wholesale and retail markets can be found in traditionally regulated states or restructured states.

Wholesale Markets

Wholesale electricity markets can be found in both traditionally regulated states or in restructured markets such as in the Northeast, Midwest, Texas and California. ISOs and RTOs, described below, run competitive markets allowing for independent power producers and non-utility generators to sell their power.  

Retail Markets

Retail markets and how they’re regulated are determined at the state level and can be found in traditionally regulated or restructured markets. In a vertically integrated state, consumers purchase power from the utility that serves their area. Most vertically integrated retail markets are found in the Southeast, Northwest, and much of the West. Competitive retail markets give customers the option to choose their retail electricity supplier.

What Are Regional Transmission Organizations (RTOs) And Independent System Operators (ISOs)?

RTOs and ISOs operate in states with wholesale electricity markets. The terms RTO and ISO are often used interchangeably, and both oversee operation of regional transmission systems. ISOs/RTOs allow independent power producers and non-utility generators to trade power under the supervision of federal regulators.

Source: Sustainable FERC, https://sustainableferc.org/

There are currently seven ISOs/RTOs that operate in the contiguous United States:

• California ISO (CAISO) –covers most of California and a small part of Nevada. It imports about one-third of its energy from the Pacific Northwest and the Southwestern United States.

• Electric Reliability Council of Texas (ERCOT) –covers most of Texas.

• Midcontinent ISO (MISO) – operates in portions of 15 states in the Midwest and the South.

• New York ISO (NYISO) –covers the state of New York

• New England ISO (NE-ISO) –includes all of Vermont, New Hampshire, Massachusetts, Connecticut Rhode Island, and most of Maine.

• PJM Interconnection (PJM) – includes portions of 13 states in the Midwest, Mid-Atlantic or Northeast.

• Southwest Power Pool (SPP) – operates in portions of 14 states in the Great Plains states and parts of the South and West.

  
  

What Are The Types Of Electricity Financial Markets That Operate In ISOs/RTOs?

Most RTOs/ISOs operate day-ahead and real-time energy markets, and ancillary services markets. Some, but not all, also operate capacity markets. These different markets are described below:

• Day-ahead: 95 percent of market transactions, sales and purchase of electricity are based on the next day’s forecasted load (demand for electricity). The day-ahead market allows purchasers to hedge against price fluctuations that can occur in real time. RTOs that operate day-ahead markets include PJM, SPP, ISO-NE and ERCOT.

• Real-time: Sales and purchase of electricity to meet the real-time demand for electricity withing the ISO/RTO. Prices can vary from minute to minute; the real-time market accounts for any differences between the day-ahead schedule and actual demand and supply changes. RTOs that operate real-time markets include PJM, SPP, and ERCOT.

  • Energy Imbalance Markets: is a voluntary real-time market; SPP and CAISO both operate energy imbalance markets.

  • EIMs do not require a participating utility to join an RTO. Utilities are typically vertically integrated. These can also leverage neighboring RTO’s existing platforms to allow limited, voluntary, real-time energy trades without being RTO members.

• Ancillary services market: This market is for services that are necessary to maintain transmission system operation and provide reliability support. Ancillary services include voltage control and support, reactive power, frequency control, spinning reserves, and standby power. These ancillary services are provided by generators in vertically integrated states, but must be separately procured in all of the ISOs/RTOs.

• Capacity market: This market helps ensure grid reliability standards are met by selecting power plants to meet peak electricity demand at a future date, which in some RTOs may be three years in the future. In capacity markets, the grid operator (ISO/RTO) commonly holds an auction based on projections for electricity demand in three years. Generators set bid prices equal to the cost required to operate their plant, bids are arranged from low to high, then the ISO/RTO will accept bids up to the amount of electricity needed to meet demand. Once that is met, the market clears, and generator’s bids are selected. Energy generators that cleared then receive the same price, which comes from the highest-bidding selected generator. These payments help cover some fixed costs, but capacity markets are mainly intended to secure reliability in a competitive manner. RTOs that use capacity markets include MISO, NYISO, PJM and ISO-NE.

Other Key Market Purposes and Tools

• Resource Adequacy: is the ability of the electricity system to meet electricity demand at all times. RTOs may meet reliability standards through resource adequacy and operational reliability requirements. CAISO and SPP require resource adequacy standards to meet load obligations, whereas other RTOs may have resource adequacy standards to augment reliability metrics from capacity markets.

• Transmission Congestion Costs: When transmission capacity for selecting all least-cost generators is insufficient, congestion occurs. To overcome these issues, RTOs utilize financial transmission rights (FTRs), which protects customers against the risk of congestion driven price increases in the day-ahead market in RTOs. FTRs protect customers from transmission congestion costs associated with a specific transmission path on the grid. FTRs are used in all six FERC jurisdictional RTOs: ISO-NE, NYISO, CAISO, MISO, PJM, and SPP; along with ERCOT.

Electricity Markets Timeline

FERC announced an Advance Notice of Proposed Rulemaking to plan for interregional transmission planning to accommodate for increased distributed energy resources. This process will seek input on transmission planning, shifting energy loads, and new cost allocations. The Bipartisan Infrastructure Framework (if passed) calls for $73 billion in spending for electric grid infrastructure projects. Of note, it directs DOE to study capacity constraints when designating National Interest Electric Transmission Corridors, requires state regulators to consider rate mechanisms to allow utility cost recovery for demand response.

In the 1880s, Thomas Edison was the first to provide electricity to a wide area, focusing on a neighborhood in New York City. This began the process of providing electricity to large areas, which in turn developed economies of scale. As more people were served, costs were spread out among the customers to pay for electrical infrastructure.

Between the 1920s and the 1970s power plants and lines were built to supply electricity and were typically vertically integrated – meaning the utility owned the generation, transmission, and distribution. A key to keeping electricity rates low was due to utilities sharing reserve margins with others. In the case of outages, generators had to ensure reliable backup power and sharing those reserves with neighboring utilities through interconnections or power pools cut costs significantly. Power pools formed during this time included PJM, New York, New England, ERCOT, and SPP.

1935

The Federal Power Act first delineated federal and state jurisdictions for wholesale and retail sales. It eventually enabled the Federal Energy Regulatory Commission (FERC) to have regulatory authority.

1962

The North American Power Systems Interconnection Committee became the informal and voluntary organization to coordinate the bulk power system.

1968

The National Electric Reliability Corporation (NERC) is established after a major blackout. NERC was formed as a nonprofit regulatory authority for North America, with a mission to assure an effective, efficient, and secure grid.

1977

FERC is formed as an independent agency with regulatory authorities granted by the Federal Power Act, which was established in 1935. While it has many tasks, a key focus is the regulation of transmission and wholesale electricity sales in interstate commerce.

1978

The Public Utility Regulatory Policies Act (PURPA) was enacted in response to the oil crisis and high prices in the 1970s. It focused on encouraging cogeneration, integrating renewable resources, increasing generation competition, and conserving electricity. It has been revised at multiple points and will reappear on the timeline.

1992

The Energy Policy Act gave FERC authority to allow open transmission access.

1996

FERC Order 888 required mandatory open transmission access to all users, which filled in the patchwork left by the Energy Policy Act from 4 years earlier. Additionally, it promoted the concept of independent system operators (ISOs) to build competition for wholesale market participants. It left FERC with jurisdiction over wholesale electric sales, transmission, and left state commissions with jurisdiction over distribution and generation components of retail service.

1999

FERC Order 2000 encouraged utilities to join regional transmission organizations (RTO). While not mandatory, the emergence of RTOs led to a shift away from utility owned generation as nearly half of electricity generation in the U.S. is owned by non-utilities. This process of restructuring, meant that electric utilities no longer had natural monopolies across all of generation, distribution, and transmission, and introduced competition into certain electric generation markets.

2005

The Energy Policy Act strengthened frameworks for competitive wholesale markets. It allowed the use of eminent domain for acquiring electric transmission rights-of-way in areas designated as congested by the Secretary of Energy. It repealed a PURPA requirement that had required utilities to purchase power from qualifying facilities and small power producers at a rate based on the utilities’ avoided cost, if there were competitive electricity markets available. Finally, FERC is tasked to prohibit any price manipulation in wholesale transactions, in response to the Western energy crisis which revealed market deficiencies.

2007

FERC Order 890 reformed its open access transmission rules to promote transmission service is provided on a just and reasonable basis, as well as provide more transparency in grid operation.

2008

FERC Order 719 eliminated barriers to demand response in organized energy markets and treat it comparably to other resources.

2009

The American Recovery and Reinvestment Act allocated $14 billion for electric power transmission grid development, $14.1 billion for renewable energy tax incentives and $1.4 billion for state and local government energy bonds.

2011

FERC Order 745 required RTOs and ISOs to pay demand respond resources the market price for energy when it’s used to balance demands as a replacement for new generation. FERC Order 1000 provided a new framework for planning large-scale transmission projects, with a focus on renewables projects. It increased participation in regional transmission planning, expanding planning from a sole company.

2012

Superstorm Sandy battered much of the Northeast, leaving 8.5 million people in 21 states without power. This prompted a focus on improving critical energy infrastructure and energy resilience.

2019

FERC expanded the controversial Minimum Offer Price Rule which established predetermined prices for renewables if they received revenues from state programs. In turn, it assisted baseload resources like coal and nuclear power to compete in capacity markets. This order was later rescinded after a change in FERC leadership.

2020

FERC Order 2222 aimed to remove barriers for distributed energy resources (DER) to compete in capacity, energy and ancillary services markets. Specifically, it allows for DERs to aggregate resources to satisfy minimum size requirements. FERC Order 841 intends to remove barriers to distributed and behind-the-meter energy storage participation in electricity markets. The Energy Policy Act of 2020 was passed as part of the omnibus bill with a broad update to the nation’s energy policies. It directs the Department of Energy coordinate with stakeholders on grid modeling and integrated energy systems plans, as well as assist those to develop electricity distribution plans through resource assessments and demand analysis.

2021

FERC announced an Advance Notice of Proposed Rulemaking to plan for interregional transmission planning to accommodate for increased distributed energy resources. This process will seek input on transmission planning, shifting energy loads, and new cost allocations. The Bipartisan Infrastructure Framework (if passed) calls for $73 billion in spending for electric grid infrastructure projects. Of note, it directs DOE to study capacity constraints when designating National Interest Electric Transmission Corridors, requires state regulators to consider rate mechanisms to allow utility cost recovery for demand response.

Market Jurisdictions – Questions & Answers

What Types Of Electricity Markets Do Each ISO/RTO Operate?

CAISO Operates day-ahead, and real-time markets, ancillary services, and congestion revenue rights along with convergence bidding activities.

CAISO does not have a formal capacity market, but it does have a mandatory resource adequacy requirement.Ancillary services offered include regulation, spinning and non-spinning reserves.Operates the Energy Imbalance Market (EIM), a real-time voluntary market, which operates in an 8-state region in the west.ERCOTOperates day-ahead and real-time, ancillary service, and congestion revenue rights markets.It does not run a capacity market, but instead relies on price signals in the energy markets to address reliability requirements.The RTO features an operating reserve demand curve designed to ensure reliability and sufficient reserves.

ISO NE Operates day-ahead and real-time energy markets, forward capacity markets, and ancillary services.

Transmission congestion costs are offset by annual or monthly financial transmission rights (FTRs)The ancillary services offered include ten-minute spinning reserves, ten-minute supplemental reserves, thirty-minute supplemental reserves, and regulation.Forward Capacity Market holds auctions annually, 3 years in advance of the operating period.

MISO Operates day-ahead and real-time markets, capacity market, and ancillary services.

Transmission congestion costs are addressed through an auction for FTRs.The ancillary services offered include spinning reserves, supplemental reserves, and regulation.The capacity market is on an annual basis for generators to meet the load forecast plus reserve needs.

NYISO Operates day-ahead and real-time markets, capacity market, and ancillary services.

The ISO’s capacity market covers three different durations, capability period (six months), monthly auction, and the spot market auction.It also addresses transmission congestion through instruments called transmission congestion contracts.PJMOperates day-ahead and real-time markets, capacity markets, and ancillary services.Transmission congestion costs are offset by financial transmission rights.PJM’s capacity market is called the Reliability Pricing Model and is based on three-year, forward-looking annual obligations for locational capacity needs.The ancillary services offered are the Synchronized Reserve Market, the Non-Synchronized Reserve Market, the Day-Ahead Scheduling Reserve Market and the Regulation Market.

SPP Began operating its energy imbalance market in 2007, which transitioned to the Western Energy Imbalance Services (WEIS) market, balancing generation and load in real-time for participants in the Western Interconnection beginning in 2021.

Operates day-ahead market, real-time market, ancillary services and operating reserve markets since 2014.It also addresses transmission congestion through instruments called transmission congestion rights.

What Authorities Do States Have Over Electricity Markets?

States maintain certain authorities over electricity markets, primarily overseeing retail electricity rates and distribution service. These authorities can vary in vertically integrated and restructured states. In vertically integrated states, regulators set utility rates at just and reasonable prices, ensure consumer protections, and balance utility cost recovery for new investments. In restructured states, regulations are enforced on the distribution side. Generators in these states compete in energy markets to serve customers and are out of state regulatory purview.

State regulators adopt policies to set prices and terms of service for investor-owned utilities, as well as cooperative and municipal utilities in certain states. Regulators review utility capital investment planning and retail electricity rates for different customer classes. States also have authority over siting and permitting of power production facilities, outside of nuclear or hydropower facilities. Finally, some states in RTO/ISO territories have kept resource adequacy responsibilities, instead of requiring the RTO/ISO to enforce.

Outside of regulation, states can set energy policies such as requiring a certain percentage of retail electricity sales in the state to come from renewable generation under a renewable portfolio standards (RPS), or can set energy efficiency resource standards (EERS) or clean energy standards (CES). These policies incorporate tools that affect generation capacity as well as pricing in electricity markets, with financial incentives such as renewable energy credits (RECs) or Zero Emission Credits (ZECs) creating more demand for certain types of cleaner generation such as renewables, energy storage, and nuclear.

Finally, while ISO/RTO membership has been static for nearly two decades, some states are exploring whether to join RTOs/ISOs. For example, Colorado signed legislation, SB 72, requiring the state to consider joining an RTO by 2030. Joining an RTO/ISO provides the market signals to advance transmission buildout to deliver renewable generation to population centers, and can help Western states address electricity reliability challenges from climate change. Nevada additionally signed similar legislation to consider joining an RTO within the same time frame as Colorado.

What Authorities Do Federal Agencies Have Over Electricity Markets?

The Federal Energy Regulatory Commission (FERC) regulates interstate transmission and wholesale power sales. the U.S. Environmental Protection Agency (EPA) and other agencies such as the Department of the Interior (DOI) also issue regulations impacting the energy sector. For example, the EPA regulates air pollutant emissions from power plants and other sources of emissions like mercury and smog forming pollutants (NOx, and SOx) and regulates greenhouse gas emissions from certain types of new fossil fuel-based generators. The DOI oversees some aspects of the permitting and siting of generation and transmission lines that cross federal lands, including potential impacts on threatened and endangered species and issues leases for offshore wind projects along the East coast. The Department of Energy helps accelerate technology development and deployment by providing funding for new technologies such as nuclear energy, renewable energy, energy storage, as well as electric and alternative fuel vehicle technologies.