Introduction

Electricity is an integral part of life in the United States. It is indispensable to factories, commercial establishments, homes, and certain modes of transportation. Lack of electricity causes not only inconvenience, but also economic loss due to reduced commercial and industrial production. This overview provides information about the major components of the industry in 2007.

Traditional Electric Utilities

The more than 3,273 traditional electric utilities in the United States are responsible for ensuring an adequate and reliable source of electricity to all consumers in their service territories at a reasonable cost. Electric utilities include investor-owned, publicly-owned, cooperatives, and Federal utilities. Power marketers buy and sell electricity, but usually do not own or operate generation, transmission, or distribution facilities. Utilities are regulated by local, State, and Federal authorities, and in the case of many electric cooperatives, by their Board of Directors.

Interstate sales of electricity on the wholesale market and by public utilities (e.g., investor-owned utilities, power marketers, independent power producers, and non-exempt electric cooperatives) are subject to regulation by the Federal Energy Regulatory Commission (FERC). FERC also regulates interstate transmission service provided by transmission-owning public utilities. In addition to regulating transactions in interstate commerce, FERC licenses hydroelectric facilities on navigable waterways. Licensing the construction and operation of nuclear power plants, safety and nuclear waste disposal management is under the jurisdiction of the Nuclear Regulatory Commission. Retail sales, and unbundled distribution service provided by investor-owned utilities are subject to State regulation. In some States, municipal utilities and electric cooperatives rates are also subject to State regulation. Approval of the construction of most power plants and transmission line construction is generally regulated by the States.

State public service commissions have jurisdiction primarily over the large, vertically integrated, investor-owned electric utilities that own more than 38 percent of the Nation's generating capacity and serve about 71 percent of ultimate consumers. There are 210 investor-owned electric utilities, 2,009 publicly-owned electric utilities, 883 consumer-owned rural electric cooperatives, and 9 Federal electric utilities. A small amount of electricity is sold by generating facilities directly to end use customers. At least 6 States regulate cooperatives, and at least 7 States regulate municipal electric utilities; many State legislatures, however, defer this control to local municipal officials or cooperative members.

Nonutility Power Producers

The approximately 1,738 nonutility power producers in the United States include:

• Qualifying Facilities (QF) established under the Public Utility Regulatory Policies Act of 1978 (PURPA). QFs include combined heat and power (CHP) plants and small power producers. CHP plants produce process heat (e.g., steam) for primary business activity other than electricity production. The surplus heat is used to generate electricity for sale to utilities. Small power producers are entities that use renewable resources to generate electricity and which are not larger than 80 MW.
• Independent power producers that produce and sell electricity on the wholesale market at market-based rates, and do not have franchised service territories. Most are designated as exempt wholesale generators, which relieves them of many of the regulatory requirements applicable to traditional utilities subject to FERC regulation.
• Other combined heat and power plants that are often co-located at nearby industrial sites. These facilities may be classified as commercial or industrial depending on the North American Industrial Classification System (NAICS) code associated with the co-located industry.

Traditional Electric Utilities

Consumer Sectors. Utility service territories are geographically distinct from one another. Each territory is usually composed of many different types of consumers. Electricity consumers are divided into classes of service or sectors (residential, commercial, industrial, and transportation) based on the type of service they receive. Utilities categorize consumers into classes of service, which are used to determine rates for electric service. Customer classification is determined by each utility and is based on various criteria such as:

• load profile,
• NAICS code,
• voltage level at which electricity is delivered,
• end-use applications, and
• other social and economic characteristics (e.g., such as lifeline rates for low income customers and economic development rates for commercial and industrial customers).

Electric utilities use consumer classifications for planning (i.e., load growth and peak demand) and for determining their sales and revenue requirements (cost-of-service) in order to derive their rates. Utilities typically employ a number of rate schedules for a single sector. The alternative rate schedules reflect consumers' varying consumption levels and patterns and the associated impact on the utility's costs of providing electrical service. For example, a utility may have a basic rate for residential service, as well as a residential rate that applies to residential consumers with electric water heaters. Reclassification of consumers, usually between the commercial and industrial sectors, may occur from year to year due to changes in demand level, economic factors, or other factors.

Revenue. The revenue associated with sales to ultimate consumers is referred to as the operating revenue (Figure 1). Operating revenue is collected through rates that may consist of a number of separate components, including energy charges, demand charges, consumer service charges, environmental surcharges, fuel and purchased power adjustments, and other miscellaneous charges. These rate components allow the utility to recover the costs it incurs in providing service to each class of consumers. The elements of the cost-of-service include operating and maintenance expenses, fuel, purchased power, capital costs (e.g., depreciation, interest expenses, and return on equity), State and Federal income taxes, and taxes other than income taxes. State and local authorities tax the value of plants (property taxes), the amount of revenues (gross receipts taxes), purchases of materials and services (sales and use taxes), and a potentially long list of other items that vary extensively by taxing authority. Costs that vary with the amount of electricity produced are generally recovered through energy charges. Costs that do not vary with production, such as capital costs, are recovered through demand charges.

Electric utilities, like other business enterprises, are required by various taxing authorities to collect and remit taxes assessed on their consumers. In this regard, the utility serves as an agent for the taxing authority. Taxes assessed on consumers, such as sales taxes, are called "pass through" taxes. These taxes do not represent a cost to the utility and are not recorded in the operating revenues of the utility. However, taxing authorities differ on whether a specific tax is assessed to the utility or to the consumer, a difference that in turn determines whether or not the tax is included in the electric utility's operating revenues.

Figure 1. Allocation of Revenue From Electric Operations for Major U.S. Investor-Owned Electric Utilities, 2007

Average Retail Price (Price). Average retail price is defined as the cost per unit of electricity sold and is calculated by dividing retail electric revenue by the corresponding sales of electricity. The average retail price is calculated for all consumers and for each sector (residential, commercial, industrial, and transportation). The average retail price discussed in this primer represents a weighted average of consumer revenue and sales within each sector and across sectors for all consumers. Average retail prices vary across sectors because of the different consumption patterns of residential, commercial, industrial and transportation consumers. In addition, average retail price is affected by changes in the rate schedules used by the electric utilities and by changes in the volume of electricity sales. Because fixed charges remain constant in the short run regardless of the volume of sales, with all other factors remaining constant, average retail price decreases as the volume of sales increases. Sales volumes may increase through a combination of customer growth and an increase in average consumption per customer. In recent years, average consumption per customer has been declining, but has been more than offset by customer growth such that total sales continue to increase.

Historically, the rate schedules used by electric utilities were designed so that as the volume of sales increased, to the extent the increase in revenue was less than the relative increase in sales, the average price of electricity would fall. This type of rate promoted energy consumption over conservation. As the cost of producing electricity has increased, along with concerns about the impact of electricity production on the environment, utilities are implementing rates and other programs that more closely reflect costs and reduce environmental impacts. These activities include demand response programs, green pricing, and real-time pricing.

Classes of Ownership. The electric utility industry in the United States includes 3,273 investor-owned, publicly-owned, cooperative, and Federal electric utilities, as well as retail and wholesale power marketers (Figure 2). Historically, investor-owned electric utilities have served large, consolidated markets where economies of scale afford the lowest prices. However, publicly-owned, cooperative, and Federal electric utilities all have a role in producing, transmitting, and distributing electricity.

Figure 2. Composition of Electric Entities in the United States, 2007

Figure 3. Electric Industry Generating Capacity by Type, 2007 (Net Summer Capability)

Investor-owned electric utilities are privately-owned entities. They operate in all States except Nebraska, where electric utilities consist primarily of municipal systems and public power districts. They represent 6 percent of the total number of electric utilities and approximately 38 percent of utility installed capacity (Figure 3), 42 percent of generation, 66 percent of sales (Figure 4), and 67 percent of revenue in the United States. Investor-owned utilities serve about 100 million ultimate consumers, about 71 percent of the total in the country (Figure 5). Like all private businesses, investor-owned electric utilities have the fundamental objective of producing a profit for their investors. These utilities either distribute profits to stockholders as dividends or reinvest them.

Investor-owned electric utilities are granted service monopolies in certain geographic areas and are obliged to serve all consumers. As franchised monopolies, these utilities are regulated and required to charge reasonable prices, to charge comparable prices to similar classifications of consumers, and to give consumers access to services under similar conditions.

Most investor-owned electric utilities are operating companies that provide basic services for the generation, transmission, and distribution of electricity. The majority of investor-owned utilities perform all three functions. Many investor-owned utilities that operate in regulated retail markets continue to operate on a vertically integrated basis (e.g., provide generation, transmission and delivery service at a bundled price to retail customers).

For those States that have adopted retail competition and that are located within the footprint of organized wholesale markets, many investor-owned utilities have divested their generation and placed their transmission assets under the operational control of independent system operators (ISOs). Thus, these investor-owned utilities’ primary function is providing distribution service and serving as the supplier of last resort for those retail customers that have not chosen an alternative retail energy service provider.

Publicly-owned electric utilities are nonprofit government entities that are organized at either the local or State level. There are 2,009 publicly-owned electric utilities in the United States. They represent about 61 percent of the number of electric utilities, supply approximately 9 percent of generating capability, 8 percent of generation, and account for about 15 percent of retail sales and 13 percent of revenue. They obtain their financing from the sale of general obligation bonds and from revenue bonds secured by proceeds from the sale of electricity. Publicly-owned electric utilities include:

• municipals,
• public utility districts and public power districts,
• State authorities,
• irrigation districts, and
• joint municipal action agencies.

Local, or municipal, utilities were established to provide service to their communities and nearby consumers at cost. Municipal utilities typically return a portion of their net income to consumers in the form of a general funds transfer. Retail rates may be lower than neighboring investor-owned utilities because they are not subject to State and Federal income tax. Municipal utilities, as well as other publicly owned utilities, are able to issue low cost, tax exempt debt to finance construction. Most municipal utilities simply distribute power, although some large ones produce and transmit electricity as well. Public power districts and public utility districts are concentrated in Nebraska, Washington, Oregon, and California.

Voters in a public utility district elect commissioners or directors to govern the district independent of any municipal government. State authorities, like the New York Power Authority (NYPA) or the South Carolina Public Service Authority (Santee Cooper), are agencies of their respective State governments. NYPA is primarily a wholesale power supplier to municipal and cooperative utilities, but also provides direct service to certain eligible industrial customers. Santee Cooper, in South Carolina, provides both retail and wholesale electric service. The Salt River Agricultural and Improvement District, in Arizona, is a dual purpose agency that provides both retail electric service and water supply services. Irrigation districts are primarily located in the western United States. They were organized by local citizens initially to manage water resources for agricultural purposes. Because electricity is integral to this function, many also provide retail electric service. Some States have created joint municipal action agencies for the purpose of constructing power plants and purchasing wholesale power for resale to municipal distribution utilities participating in the organization. Some of these entities include the Massachusetts Municipal Wholesale Electric Company, the Indiana Municipal Power Agency and the Municipal Electric Authority of Georgia.

Cooperative electric utilities are owned by their members (i.e., the consumers they serve). Distribution cooperatives provide retail electric service to their members. Generation and transmission cooperatives provide wholesale power and transmission service to their members (distribution cooperatives). There are 883 cooperatives operating in 47 States; none operate in Connecticut, Massachusetts, Rhode Island, or the District of Columbia. Cooperative electric utilities represent about 27 percent of U.S. electric utilities, 10 percent of sales and revenue, and around 4 percent of generation and generating capability. These electric utilities generally operate in rural areas. Cooperative service territories generally reflect areas that historically were viewed as unprofitable to service by investor-owned utilities because of the relative low number of customers per line-mile.

Cooperatives are incorporated under State laws and are governed by the organization’s board of directors elected by the members. The Board of Directors selects a manager. Cooperatives are required to provide electric service to their members at cost, as that term is defined by the Internal Revenue Service. Electric cooperatives set rates similar to municipal utilities. However, while municipal utilities may return a portion of net income to the general fund of the local government, the net margins earned by cooperatives (net margins is a term used in electric cooperative financial statements and equals revenues in excess of the cost of providing service) are considered a contribution of equity by the members that are required to be returned to the members consistent with the organization’s bylaws and lender limitations imposed as a condition of loans. The members’ equity is referred to as patronage capital. The Rural Utilities Service (formerly the Rural Electrification Administration), the National Rural Utilities Cooperative Finance Corporation, and CoBank ACB are important sources of debt financing for cooperatives.

The 9 Federal electric utilities in the United States are part of several agencies in the U.S. Government:

• the Army Corps of Engineers;
• the Bureau of Indian Affairs and the Bureau of Reclamation in the Department of the Interior,
• the International Boundary and Water Commission in the Department of State,
• the Power Marketing Administrations in the Department of Energy (Bonneville, Southeastern, Southwestern, and Western), and
• the Tennessee Valley Authority (TVA).

Three Federal agencies operate generating facilities:

• TVA, the largest Federal producer;
• the U.S. Army Corps of Engineers; and
• the U.S. Bureau of Reclamation.

The TVA markets its own power. Generation owned by the U.S. Army Corps of Engineers (except for the North Central Division, for example, Saint Mary's Falls at Sault Ste. Marie, Michigan) and the U.S. Bureau of Reclamation is marketed by the Federal power marketing administrations: Bonneville, Southeastern, Southwestern, and Western. The four power marketing administrations also purchase energy for resale from other electric utilities in the United States and Canada. Federal electric utilities represent less than 1 percent of all electric utilities, provide approximately 7 percent of all generating capability and 4 percent of generation, and account for about 1 percent of total sales to ultimate consumers and less than 1 percent of the associated revenue. Federal electric utility generation is primarily sold at wholesale to municipal and cooperative electric utilities and to other nonprofit preference consumers, as required by Federal law. Federal power is sold not for profit, but to recover the costs of operations and repay the Treasury for funds borrowed to construct generation and transmission facilities. While the Federal utilities are not subject to rate regulation, they must submit their rates to the FERC for purposes of demonstrating that they are at a level sufficient to repay debt owed to the Federal government. Federal electric utilities operate approximately 200 power plants. Most of the Federal power plants are hydroelectric projects designed for flood control, irrigation purposes and pursuant to statutory obligations to supply wholesale power to publicly-owned utilities and electric cooperatives.

Figure 4. U.S. Electric Utility Sales to Ultimate Consumers by Class of Ownership, 2007

Figure 5. Number of Ultimate Consumers Served by U.S. Electric Utilities by Class of Ownership, 2007

Nonutility Power Producers

Qualifying Facilities. The Public Utilities Regulatory Policies Act of 1978 (PURPA) facilitated the emergence of a group of nonutility electricity-generating companies called qualifying facilities or QFs. Under PURPA, small power producers and cogenerators receive status as a QF by meeting certain requirements for ownership, operating methods, and efficiency. Those requirements were established by the Federal Energy Regulatory Commission (FERC). Before passage of the Energy Policy Act of 2005, utilities were required to purchase QF power at avoided cost. That is the incremental cost the utility would otherwise incur to supply power otherwise available for purchase from the QF. This requirement was eliminated for QFs operating in competitive wholesale markets meeting certain requirements prescribed by the FERC.

Combined Heat and Power (CHP) Plants. Facilities which produce electricity and another form of useful thermal energy through the sequential use of energy (usually heat or steam for industrial processes or heating/cooling purposes) are called combined heat and power plants--many of which have status as QFs. CHP plants are primarily engaged in business activities (such as agriculture, mining, manufacturing, transportation, education). The electricity that they generate is mainly for their own use, but any excess may be sold in the wholesale market.

Independent Power Producers. Also known as IPPs, their primary business is to generate electricity. However, they have no assigned service territory. Their service obligation is defined by the terms of their power sales contracts. IPPs are precluded from owning transmission facilities and must use transmission facilities of other utilities to deliver power to their customers. By definition, a facility that has QF status is not an IPP. Some IPPs are exempt wholesale generators (EWGs), and as such are exempt from certain FERC financial reporting and ownership restrictions. IPPs sell power at market-based rates subject to receiving FERC authorization.

Energy Sources Used To Generate Electricity

Various sources of energy can be converted into electric energy or electricity. The major or dominant sources include fossil fuels, uranium, and water.

Figure 6. Electric Power Industry Generation by Energy Source, 2007

Total net generation in the country in 2007 was 4,157 billion kilowatthours, of which 2,504 billion kilowatthours was generated by electric utilities (Figure 6). About 72 percent of generation in the United States comes from fossil fuels. Coal and natural gas are currently the dominant fossil fuels used by the industry. Nuclear contributes approximately 20 percent, while the contribution from conventional hydroelectric fluctuates between 6 and 8 percent.

Electricity generation from renewable sources other than water is growing in importance. Electricity generation from wind, in particular, has been growing rapidly in recent years, 156 percent between 2002 and 2006, while wind capacity also increased by 151 percent between 2002 and 2006. Some renewable sources of energy that are converted into electricity include:

• geothermal energy,
• wind energy
• solar thermal energy,
• photovoltaic energy, and
• biomass

Environmental Aspects

When fossil fuels are burned to generate electricity, a variety of airborne gases and particulates are formed. If these gases and particulates are not captured by some pollution control equipment, they are released into the atmosphere. Among the gases emitted during the burning of fossil fuels are sulfur dioxide (SO2), nitrogen oxides (NOx), and carbon dioxide (CO2). In 2007, conventional power plants and combined-heat-and-power plants emitted approximately 2,517 million metric tons of CO2, 9.0 million metric tons of SO2, and 3.7 million metric tons of NOx. Compared to 2006, CO2 emissions increased by 56.8 million metric tons, while SO2 and NOx decreased by 0.5 and 0.2 million metric tons, respectively. The 2007 CO2 figures are 16.4 percent higher than those from 1996, while the SO2 emissions are 30.4 percent lower, and the NOx emissions are 43.6 percent lower than in 1996.

Electric Power Transactions and the Interconnected Networks

Power Transactions

An electric power system is an integrated system consisting of generating plants, high voltage transmission lines, local distribution facilities, communication, and other facilities that must operate as a contemporaneous network in real-time or in a synchronous manner to provide stable and reliable electricity to consumers. The flow of electricity within the system is maintained and controlled by dispatch centers. It is the responsibility of the dispatch center to match the supply of electricity with the demand for it. In order to carry out its responsibilities, the dispatch center is authorized to buy and sell electricity based on system requirements. Authority for those transactions has been preapproved under interconnection agreements signed by all the electric utilities physically interconnected or with coordination agreements among utilities that are not connected.

The Interconnected Networks

The U.S. bulk power system has evolved into three major interconnected systems (power grids), within which regional transmission organizations and independent system operators in some geographic regions exist to operate transmission systems in a non-discriminatory manner. They also manage organized competitive markets for the purchase and sale of wholesale electricity. The major networks consist of extra-high-voltage connections between individual utilities designed to permit the transfer of electrical energy from one part of the network to another. These transfers are restricted, on occasion, because of a lack of contractual arrangements or because of limited transmission capability. The three networks are:

• the Eastern Interconnected System,
• the Western Interconnected System, and
• the Texas Interconnected System.

The Texas Interconnected System is not interconnected with the other two networks (except by certain direct current lines). The other two networks have limited interconnections to each other. Both the Western and the Texas Interconnect are linked with different parts of Mexico. The Eastern and Western Interconnects are completely integrated with most of Canada or have links to the Quebec Province power grid. Virtually all U.S. utilities are interconnected with at least one other utility by these three major grids. The exceptions are in Alaska and Hawaii. The bulk power system makes it possible for utilities to engage in wholesale (sales for resale) electric power trade. Wholesale trade has historically played an important role, allowing utilities to reduce power costs, increase power supply options, and improve reliability. Historically, most wholesale trade was between interconnected utilities within the continental United States. With open access and deregulation of wholesale markets cross-border trade has become more prominent in meeting domestic electricity requirements. U.S. international trade is mostly imports. Normally, most imports are from Canada, with a small portion coming from Mexico.

Figure 7. North American Electric Reliability Corporation Regions

Overall reliability planning and coordination of the interconnected power systems are the responsibility of the North American Electric Reliability Corporation (NERC), which was originally formed in 1968 as a voluntary association by the electric utility industry after the 1965 power failure in the Northeast. NERC's eight regional entities cover the 48 contiguous States and portions of Canada and Mexico (Figure 7). The regional entities are responsible for overall coordination of bulk power policies that affect the reliability and adequacy of electricity service in their areas. They also regularly exchange operating and planning information among their member utilities.

The electric power industry and the Federal Energy Regulatory Commission (FERC) continue to implement the requirements of the Energy Policy Act of 2005. This Act amended the Federal Power Act by adding Section 215, which set the responsibility for overseeing operations, developing procedures, and enforcing mandatory reliability standards in the electric power industry to a new electricity reliability organization (ERO). Section 215 requires FERC to certify the ERO and approve reliability standards proposed by the ERO. In July 2006, FERC certified NERC to be the ERO, and by doing so NERC became the North American Electric Reliability Corporation. FERC also provided guidance on a pro forma Delegation Agreement between NERC and Regional Entities under which Regional Entities would have the authority to recommend reliability standards to the ERO and enforce them. In Order Nos. 693 and 693-A, the FERC approved 83 of 107 proposed Reliability Standards for which the ERO assumed enforcement responsibilities in June 2007. Under this new authority FERC may undertake enforcement actions independent of the ERO, including the imposition of penalties. The FERC, under its new general oversight responsibilities, continues to examine, provide input, and approve new mandatory standards as proposed by the ERO.

The Changing Electric Power Industry

The electric power industry is evolving from a monopolistic industry characterized by vertically integrated electric utilities providing generation, transmission and distribution service to consumers at cost-based rates to an industry where ownership and/or operation of generation, transmission and distribution facilities have been increasingly separated functionally or by divestiture of generating assets. Increasingly wholesale and retail electricity prices are determined by competitive market forces, subject to a regulatory framework that is based on rules that monitor market participants’ behavior to ensure workable competition. Monopoly transmission and distribution service providers generally operate under a traditional cost-based regulatory framework. However, the FERC and certain States are implementing ratemaking methods that provide regulated utilities greater financial incentives to operate, maintain and expand their transmission and distribution systems on an efficient, reliable and cost-effective basis.

As of 2008, there are 14 States, including Maine, New Hampshire, Massachusetts, Rhode Island, Connecticut, New York, New Jersey, Pennsylvania, Delaware, Maryland, Ohio, Michigan, Illinois, Texas, and the District of Columbia, that operate retail markets in which customers may choose alternative power suppliers. Those customers that choose not to participate in the market continue to purchase retail from their historical utility. However, some, or all, of the energy portion of the retail price of electricity is determined through competitive bidding processes. Because of the lack of competition for residential customers, and substantial rate increases that have occurred or are anticipated to occur, following the end of rate freezes implemented during the transition to retail competition, a number of States have either suspended deregulation or amended laws and regulations governing competition and energy procurements by regulated utilities. There are eight States that have suspended retail competition, including Virginia, Arkansas, New Mexico, Arizona, Nevada, California, Oregon and Montana. In May of 2001, New Mexico passed legislation that delayed opening the retail electricity market to competition, and in 2003 the Electric Utility Restructuring Act of 1997 was repealed. In 2003, Arkansas repealed deregulation legislation in order to continue the regulation of electric utility rates. During 2008, Delaware, Illinois and Ohio enacted legislation directing regulators to implement regulations that continue to provide customers the right to choose alternative energy suppliers, but also allow the utilities to return to building their own generation capacity subject to this self-build option being scrutinized through a formal competitive procurement process. Additionally, Illinois created a new governmental entity with power procurement authority, including the authority to build new capacity.

At the Federal level, the Congress and FERC continue to work on the wholesale legal and regulatory framework. These activities focus on promoting the efficient expansion of the Nation’s high voltage transmission system to alleviate transmission constraints that impact reliability and the efficient operation of regional wholesale markets. The refinement of market structures and rules in organized wholesale markets will enhance efficiency in (1) the supply of electricity and (2) purchasing decisions by entities responsible for purchasing power to meet obligations to retail consumers. Recent notable events include:

• Enactment of the Energy Policy Act of 1992 (EPAct 1992), which modified existing provision of the Federal Power Act that enhanced the FERC’s authority to order utilities to provide transmission service.
• FERC Order No. 888 which, in 1996, required all jurisdictional public utilities to file open access transmission tariffs and offer non-discriminatory open access transmission service comparable to the utilities’ own use of its transmission system to serve its own customers. Order No. 888 also established guidelines for the formation of independent system operators (ISOs). FERC issued Order No. 890 to reform the open-access transmission regulatory framework established in Order No. 888. Among other matters, Order No. 890 required utilities to formally address transmission planning issues, including openness in the planning process, transparency in calculating Available Transmission Capacity, dispute resolution, and other revisions to the pro forma open access tariff.
• FERC Order No. 2000 (issued in 1999), which encouraged transmission utilities to form and participate in a Regional Transmission Organization (RTO). The order encouraged competition in wholesale electricity markets by establishing independent organizations with operational control of utility transmission systems to preclude utilities from operating and providing access to their transmission systems to the advantage of their own generation assets. Since then, six RTO/ISOs under FERC’s jurisdiction have evolved, encompassing all of the New England States, the Mid-Atlantic States, much of the Midwest, portions of the Southwest and California. A seventh RTO/ISO formed in Texas under the jurisdiction of Texas regulators. These organizations have broad operational control of participating utilities’ transmission systems, ensuring non-discriminatory access to market participants. Additionally, they operate competitive wholesale markets for energy services and demand response, and have authority over transmission system planning.

The Energy Policy Act of 2005 contained a number of key provisions that are expected to affect industry structure. Among the most significant components are:

• A provision requiring the Secretary of Energy to identify critically-constrained transmission corridors that cross the borders of two or more States. Proposed transmission projects in these corridors may petition the FERC, under certain conditions, to exercise Federal eminent domain authority to allow acquisition of rights-of-way to construct new transmission facilities. Historically, transmission siting and eminent domain authority have been left to State governmental authorities. The FERC was granted this authority to resolve impediments to construction of multi-state transmission.
• Authority granted to FERC to approve incentive rates for the construction of transmission facilities to enhance reliability and expand the system to increase efficiency of the supply of generation in wholesale power markets. In accordance with this authority, FERC issued Order No. 679, which set forth the criteria for new transmission infrastructure to qualify for incentive rate treatment.
• Establishment of a loan guarantee program within the Department of Energy for advanced generation technologies including nuclear, coal and renewables, as well as other technologies enhancing the efficient delivery and use of electricity.

In December 2007, The Energy Independence and Security Act of 2007 (EISA) provided a legislative framework for transmission system modernization, including initiating “smart grid” expansion, providing tax incentives for investment, creating Federal “smart grid” committees, and assigning Federal funding for research and development. “Smart grids” would present consumers with real-time electricity prices, thereby encouraging efficient consumption and possibly reducing demand.

Conclusion

Between 2004 and 2007, the National average price of electricity increased 19.7 percent from 7.6 cents per kilowatthour (kWh) in 2004 to 9.1 cents per kWh in 2007. Much of this increase is attributable to the increase in fuel costs. However, as noted above, the expiration of transitional rate caps in States that implemented retail competition resulted in higher prices as utilities were able to adjust rates to recover higher distribution and transmission costs, as well as higher wholesale power costs, particularly for customers purchasing standard offer service. From the standpoint of industry structure, the response to higher rates resulted in a number of states suspending or modifying retail competition in an effort to contain retail price increases. Regulators and legislators in the States that have chosen not to adopt retail competition are refocusing on issues such as renewable portfolio standards and regulation of greenhouse gas emissions.

At the Federal level, the FERC continues to work to promote efficiency and transparency in organized and bilateral wholesale markets and in the provision of non-discriminatory open access transmission service. However, the footprint of existing RTOs/ISOs has been fairly static in recent years. The wholesale segment of the industry appears to be settling into two market structures. The Northeast, Midwest and California are characterized by organized wholesale markets operated by RTOs/ISOs. The remaining regions’ wholesale markets are characterized by bi-lateral markets that are facilitated by transmission service under Order No. 888/890 open access tariffs. With the abandonment of its effort to adopt regulations for standardized wholesale market design, the FERC and the industry appear to be settling on alternative regional market structures that reflect regional trading practices and preferences that reflect a consensus of stakeholders that include State regulators, utilities, IPPs and customers.

Finally, 2007 marked for the first time renewable energy sources, other than conventional hydroelectric capacity, accounting for the largest portion of capacity additions. Total net summer capacity increased by 13,845 MW in 2007 (before 5,173 MW of retirements and revisions). Wind capacity accounted for 5,186 MW of this new capacity. Natural gas-fired generation accounted for 4,582 MW. Because the location of wind, solar and geothermal resources is constrained to areas where their respective primary energy sources are plentiful, they tend to be in specific and remote regions of the country. This is resulting in the planning of new high voltage transmission lines to transport the output of their intermittent and geographically constrained resources to markets. In response, merchant transmission companies are forming to serve renewable energy suppliers and their wholesale customers.