Turning On The Lights: Deregulating The Market for Electricity

Studies | Regulations

No. 228
Friday, October 01, 1999
by Vernon L. Smith and Stephen Rassenti


Evolution of Federal Electric Utility Regulation

Figure II - Independent Generators' Share of the Electricity Market

For most of this century, electric power was largely regulated at the state and local level. However, the federal government became involved in electric power beginning in the 1930s, as both regulator and producer.

Public Utility Holding Company Act. Concerns about utility failulates the practices of large multistate utility holding companies and restricts them from entering other energy-related businesses. Because of these restrictions, PUHCA is considered a major impediment to the development of competitive power markets. One industry study estimated that PUHCA imposes costs on the electric industry of $3 billion to $12.6 billion annually.19

Federal Energy Regulatory Commission. Congress also passed the Federal Power Act of 1935, establishing the Federal Power Commission. It was succeeded by the Federal Energy Regulatory Commission (FERC), an independent body now within the Department of Energy.

FERC's powers were expanded by the Public Utility Regulatory Policies Act (PURPA) in 1978 and the Energy Policy Act of 1992 (EPAct). Today, the FERC approves rates for wholesale sales of electricity and for electricity transmission in interstate commerce for investor-owned utilities, power marketers, power pools, power exchanges and independent system operators. It reviews rates set by the federal power marketing administrations, confers exempt wholesale generator status under the EPAct and certifies small power production and cogeneration facilities. In addition, mergers between certain electric utilities require FERC approval - which can take years.20

The Tennessee Valley Authority and Power Marketing Administrations. The federal government is the largest electric power producer in the country - through the Tennessee Valley Authority (TVA) and four regional power marketing administrations (PMAs)21 that generate electric power from dams built and maintained by the U.S. Army Corps of Engineers and the Bureau of Reclamation and several nuclear power plants.

"The federal government is the largest electric power producer."

The TVA was created in 1933 to generate and distribute electric power in the Tennessee Valley region. As America's largest power company, the TVA provides service to more than eight million customers in Tennessee and six other states. A combination of generous tax breaks and special regulatory exemptions keeps prices and rates artificially low.

The power generated by the PMAs represents as little as 2 percent of electricity used in the region served by the Southeastern PMA and as much as 65 percent of that used in the Pacific Northwest area served by the Bonneville PMA. The electricity is sold at highly subsidized nonmarket rates that vary with the type of user.22

Opening the Door to Wholesale Competition. Although Congress cracked down on many utility company abuses in 1935, the basic regulatory structure remained largely unchanged until the 1970s, when energy shortages hit the nation.

In response to the energy crisis, Congress passed the Public Utility Regulatory Policies Act (PURPA) in 1978, opening the door to competition in electric power generation. Among the goals of PURPA were to improve energy efficiency and increase the reliability of electric power supplies. PURPA required utilities to purchase electricity produced by renewable energy sources and cogeneration (where an existing industrial plant generating steam for some other purpose also uses it to generate electric power).

In addition, the act required utilities that owned long distance, high-voltage power lines connected to the growing national grid to convey electricity purchased by local utilities from other utilities or nonutility generators (NUGs) to improve service reliability. This "wheeling" was encouraged by new Federal Energy Regulatory Commission (FERC) regulations that required utilities to account for all the wholesale purchases and sales of electricity. This allowed municipal authorities that did not have generators of their own, or needed additional power for peak demand, to shop for electricity from any utility or NUG.

"Nonutility generators has 3.6 percent of the nationwide generating capacity in 1987, and 7.2 percent by 1995."

The trend toward independent generation accelerated with the Energy Policy Act of 1992, which allowed the FERC to open wholesale markets for competitive purposes. FERC eventually adopted rules (Orders 888 and 889) requiring all utilities owning transmission lines to provide open and equal access to all electricity generators.23 Wholesale power marketers and brokers began to do business.

By 1978, industrial electricity capacity had fallen to a low of 2.7 percent of capacity.24 As Figure II shows, independents (nonutility generators), which had 3.6 percent of the nationwide generating capacity in 1987, had 7.2 percent by 1995. Currently they have around 10 percent.25 Since 1990, NUGs have made more than half of all investments in additional plant capacity.

"The lowest-cost municipal systems have average residential rates 25 percent lower than systems with long-term contracts."

Another reason for NUGs' growing share of generating capacity was the requirement that power be purchased at rates as high as the utility's "avoided cost" - the marginal cost to the utility of building new generating capacity or purchasing electricity elsewhere. Regulators in some states set that price artificially high and required utilities to enter into long-term fixed-price contracts with producers, creating the potential for large profits and encouraging rapid entry into the market. Nonutility generating companies built new, technologically advanced plants at low cost, while the utility companies were saddled with old plants still being depreciated over a long term. The result is a "robust wholesale competition" that is saving customers an estimated $3.5 billion to $5 billion annually, according to FERC.26 Most municipally owned utilities do not generate their own power. So instead of buying electricity from a neighboring monopoly, those municipal authorities that are not locked into long-term power contracts with another utility have access to the wholesale electricity market. They have passed some of the savings on to their customers and are now typically the lowest-cost provider in every state:

  • Nationwide, the residential rate for electric power in the median municipal authority averages 7.1 cents per kwh, which is close to the 7.5 cents per kwh charged by the median investor-owned utility.
  • However, the lowest-cost municipal systems - those free to buy wholesale competitive power - have average residential rates of 5.6 cents per kwh, which is 25 percent below the rates of either investor-owned utilities or municipal power authorities with long-term contracts.

For example, instead of renewing its contract with the Tennessee Valley Authority, a major federally owned power generator, the municipal electric utility of Bristol, Va., was able to solicit bids from competing producers. As a result, it was able to reduce its power costs by 35 percent.27

The High Cost of Green Power. Other provisions of PURPA have hurt consumers. The mandate in PURPA for utilities to purchase renewable energy, such as solar and wind power technologies, at their "avoided cost" is a subsidy consumers pay in the form of higher energy prices.28 For example:

  • PURPA requires Southern California Edison to spend approximately $800 million a year buying electric power from solar power fields at 15 cents per kwh, well above the prevailing market price.
  • Pacific Gas & Electric must pay 11 cents per kwh for wind power generated outside San Francisco at a windmill farm where millions must be spent to prevent birds from flying into the windmills.
  • In total, PURPA will inflate utilities' costs by $37 billion through the year 2000.29

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