The Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act (FPA) were enacted to eliminate unfair practices and other abuses by electricity and gas holding companies by requiring federal control and regulation of interstate public utility holding companies. Prior to PUHCA, electricity holding companies were characterized as having excessive consumer rates, high debt-to-equity ratios, and unreliable service. PUHCA remained virtually unchanged for 50 years until enactment of the Public Utility Regulatory Policies Act of 1978. PURPA was, in part, intended to augment electric utility generation with more efficiently produced electricity and to provide equitable rates to electric consumers. Qualifying facilities (QFs) are exempt from regulation under PUHCA and the FPA. Electricity regulation was changed again in 1992 with passage of the Energy Policy Act (EPACT). The intent of Title 7 of EPACT is to increase competition in the electric generating sector by creating new entities, called "exempt wholesale generators" (EWGs), that can generate and sell electricity at wholesale without being regulated as utilities under PUHCA. This title also provides EWGs with a way to assure transmission of their wholesale power to their purchasers. The effect of this act on the electric supply system has been more far-reaching than PURPA. On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Orders 888 and 889. FERC issued these rules to remedy undue discrimination in transmission services in interstate commerce and provide an orderly and fair transition to competitive bulk power markets. Order 2000, issued December 20, 1999, established criteria for forming transmission organizations. Comprehensive electricity legislation may involve several components. The first is PUHCA reform. Some electric utilities want PUHCA changed so they can more easily diversify their assets. State regulators have expressed concerns that increased diversification could lead to abuses, including cross-subsidization. Consumer groups have expressed concern that a repeal of PUHCA could exacerbate market power abuses in a monopolistic industry where true competition does not yet exist. The second issue is PURPA's requirement that utilities purchase power from QFs. Many investor-owned utilities support repeal of these mandatory purchase provisions. They argue that their state regulators' "misguided" implementation of PURPA has forced them to pay contractually high prices for power that they do not need. Opponents of this legislation argue that it would decrease competition and impede development of renewable energy. The third main issue is reliability. Without mandatory and enforceable reliability standards, proponents argue that reliability of the electric power system will not be at acceptable levels. Opponents say these standards are unnecessary. This report will be updated as events warrant.
The Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act (FPA) were enacted to eliminate unfair practices and other abuses by electricity and gas holding companies by requiring federal control and regulation of interstate public utility holding companies. Prior to PUHCA, electricity holding companies were characterized as having excessive consumer rates, high debt-to-equity ratios, and unreliable service. PUHCA remained virtually unchanged for 50 years until enactment of the Public Utility Regulatory Policies Act of 1978. PURPA was, in part, intended to augment electric utility generation with more efficiently produced electricity and to provide equitable rates to electric consumers. Qualifying facilities (QFs) are exempt from regulation under PUHCA and the FPA.
Electricity regulation was changed again in 1992 with passage of the Energy Policy Act (EPACT). The intent of Title 7 of EPACT is to increase competition in the electric generating sector by creating new entities, called "exempt wholesale generators" (EWGs), that can generate and sell electricity at wholesale without being regulated as utilities under PUHCA. This title also provides EWGs with a way to assure transmission of their wholesale power to their purchasers. The effect of this act on the electric supply system has been more far-reaching than PURPA.
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Orders 888 and 889. FERC issued these rules to remedy undue discrimination in transmission services in interstate commerce and provide an orderly and fair transition to competitive bulk power markets. Order 2000, issued December 20, 1999, established criteria for forming transmission organizations.
Comprehensive electricity legislation may involve several components. The first is PUHCA reform. Some electric utilities want PUHCA changed so they can more easily diversify their assets. State regulators have expressed concerns that increased diversification could lead to abuses, including cross-subsidization. Consumer groups have expressed concern that a repeal of PUHCA could exacerbate market power abuses in a monopolistic industry where true competition does not yet exist.
The second issue is PURPA's requirement that utilities purchase power from QFs. Many investor-owned utilities support repeal of these mandatory purchase provisions. They argue that their state regulators' "misguided" implementation of PURPA has forced them to pay contractually high prices for power that they do not need. Opponents of this legislation argue that it would decrease competition and impede development of renewable energy.
The third main issue is reliability. Without mandatory and enforceable reliability standards, proponents argue that reliability of the electric power system will not be at acceptable levels. Opponents say these standards are unnecessary.
This report will be updated as events warrant.
Historically, electricity service has been defined as a natural monopoly, meaning that the industry has (1) an inherent tendency toward declining long-term costs, (2) high threshold investment, and (3) technological conditions that limit the number of potential entrants. In addition, many regulators have considered unified control of generation, transmission, and distribution as the most efficient means of providing service. As a result, most people (about 75%) are currently served by a vertically integrated, investor-owned utility.
As the electric utility industry has evolved, however, there has been a growing belief that the historic classification of electric utilities as natural monopolies has been overtaken by events and that market forces can and should replace some of the traditional economic regulatory structure. For example, the existence of utilities that do not own all of their generating facilities, primarily cooperatives and publicly owned utilities, has provided evidence that vertical integration has not been necessary for providing efficient electric service. Moreover, recent changes in electric utility regulation and improved technologies have allowed additional generating capacity to be provided by independent firms rather than utilities.
The Public Utility Holding Company Act (PUHCA)(1) and the Federal Power Act (FPA) of 1935 (Title I and Title II of the Public Utility Act)(2) established a regime of regulating electric utilities that gave specific and separate powers to the states and the federal government. A regulatory bargain was made between the government and utilities. In exchange for an exclusive franchise service territory, utilities must provide electricity to all users at reasonable, regulated rates. State regulatory commissions address intrastate utility activities, including wholesale and retail rate-making. State authority currently tends to be as broad and as varied as the states are diverse. At the least, a state public utility commission will have authority over retail rates, and often over investment and debt. At the other end of the spectrum, the state regulatory body will oversee many facets of utility operation.
Despite this diversity, the essential mission of the state regulator in states that have not restructured is the establishment of retail electric prices. This is accomplished through an adversarial hearing process. The central issues in such cases are the total amount of money the utility will be permitted to collect and how the burden of the revenue requirement will be distributed among the various customer classes (residential, commercial, and industrial).
Under the FPA, federal economic regulation addresses wholesale transactions and rates for electric power flowing in interstate commerce. Federal regulation followed state regulation and is premised on the need to fill the regulatory vacuum resulting from the constitutional inability of states to regulate interstate commerce. In this bifurcation of regulatory jurisdiction, federal regulation is limited and conceived to supplement state regulation. The Federal Energy Regulatory Commission (FERC) has the principal functions at the federal level for the economic regulation of the electricity utility industry, including financial transactions, wholesale rate regulation, transactions involving transmission of unbundled retail electricity, interconnection and wheeling of wholesale electricity, and ensuring adequate and reliable service. In addition, to prevent a recurrence of the abusive practices of the 1920s (e.g., cross-subsidization, self-dealing, pyramiding, etc.), the Securities and Exchange Commission (SEC) regulates utilities' corporate structure and business ventures under PUHCA.
The electric utility industry has been in the process of transformation. During the past 25 years, there has been a major change in direction concerning generation. First, improved technologies have reduced the cost of generating electricity as well as the size of generating facilities. Prior preference for large-scale -- often nuclear or coal-fired -- powerplants has been supplanted by a preference for small-scale production facilities that can be brought online more quickly and cheaply, with fewer regulatory impediments. Second, this has lowered the entry barrier to electricity generation and permitted non-utility entities to build profitable facilities. Recent changes in electric utility regulation and improved technologies have allowed additional generating capacity to be provided by independent firms rather than utilities.
The oil embargoes of the 1970s created concerns about the security of the nation's electricity supply and led to enactment of the Public Utility Regulatory Policies Act of 1978 (PURPA).(3) For the first time, utilities were required to purchase power from outside sources. The purchase price was set at the utilities' "avoided cost," the cost they would have incurred to generate the additional power themselves, as determined by utility regulators. PURPA was established in part to augment electric utility generation with more efficiently produced electricity and to provide equitable rates to electric consumers.
In addition to PURPA, the Fuel Use Act of 1978 (FUA)(4) helped qualifying facilities (QFs) become established. Under FUA, utilities were not permitted to use natural gas to fuel new generating facilities. QFs, which by definition are not utilities, were able to take advantage of newly abundant natural gas as well as new generating technology, such as combined-cycle plants that use hot exhaust gases from combustion turbines to make steam to generate additional power. These technologies lowered the financial threshold for entrance into the electricity generation business as well as shortened the lead time for constructing new plants. FUA was repealed in 1987, but by this time QFs and small power producers had gained a portion of the total electricity supply.
This influx of QF power challenged the cost-based rates that previously guided wholesale transactions. Before implementation of PURPA, FERC approved wholesale interstate electricity transactions based on the seller's costs to generate and transmit the power. But, as non-utility generators typically do not have enough market power to influence the rates they charge, FERC began approving certain wholesale transactions whose rates were a result of a competitive bidding process. These rates are called market-based rates.
This first incremental change of traditional electricity regulation started a movement toward a market-oriented approach to electricity supply. Following the enactment of PURPA, two basic issues stimulated calls for further reform: whether to encourage nonutility generation and whether to permit utilities to diversify into non-regulated activities.
The Energy Policy Act of 1992 (EPACT)(5) removed several regulatory barriers to entry into electricity generation to increase competition of electricity supply. Specifically, EPACT provides for the creation of entities, called "exempt wholesale generators" (EWGs), that can generate and sell electricity at wholesale without being regulated as utilities under PUHCA. Under EPACT, EWGs are also provided with a way to assure transmission of their wholesale power to a wholesale purchaser. However, EPACT does not permit FERC to mandate that utilities transmit EWG power to retail consumers (commonly called "retail wheeling" or "retail competition"), an activity that remains under the jurisdiction of state public utility commissions. PURPA began to shift more regulatory responsibilities to the federal government, and EPACT continued that shift away from the states by creating new options for utilities and regulators to meet electricity demand. EPACT allowed for a robust wholesale market in electricity. The transmission system is now used extensively for bulk-power transfers between utilities, even though the physical system was designed to handle primarily intra-utility transfers. Utilities now depend on a combination of self-generation, merchant generators, and other utilities to meet their retail electricity demand.
Shortly after enactment of EPACT, states began considering whether to allow retail choice. It was argued that retail prices would decline with additional competition. Most state plans have not met initial expectations. Few alternative suppliers have remained in the market, consumers are reluctant to switch suppliers, and default service rates set by the states are generally equal to or less than wholesale market prices plus retail margin needed to cover retail service costs.(6) Currently, 24 states and the District of Columbia have either enacted legislation or issued regulatory orders to implement retail access. California had the first active retail program. However, California suspended its restructuring program following the California energy crises in 2001 that was marked by retail and wholesale price spikes as well as a decrease in reliability. Eighteen states have active restructuring programs. Six states, Arkansas, Montana, Nevada, New Mexico, Oklahoma, and West Virginia, have delayed implementation of retail access. Since 2000, no additional states have announced plans to introduce retail competition.
Electric utility provisions are included in comprehensive energy legislation (H.R. 6) that was signed into law by President Bush on August 8, 2005.
In part, this law repeals the Public Utility Holding Company Act (PUHCA). The electric utility industry has long been a proponent of such a repeal while consumer groups have been opposed. As a compromise, a provision was included that strengthens FERC's merger review authority. In addition, language is included that is intended to prevent cross-subsidization. The mandatory purchase requirement under the Public Utility Regulatory Policies Act (PURPA) is repealed. An Electric Reliability Organization(ERO) is created and the ERO will promulgate mandatory, enforceable reliability standards for the electric industry that includes cybersecurity protection. Also included in the law is a Sense of Congress that FERC should carefully consider the states' objections to the locational installed capacity (LICAP) mechanism for New England.
In addition to creating a new type of wholesale electricity generator, exempt wholesale generators (EWGs), the Energy Policy Act (EPACT) provides EWGs with a system to assure transmission of their wholesale power to its purchaser. However, EPACT did not solve all of the issues relating to transmission access. As a result of EPACT, on April 24, 1996, FERC issued Orders 888 and 889.(7) In issuing its final rules, FERC concluded that these orders will "remedy undue discrimination in transmission services in interstate commerce and provide an orderly and fair transition to competitive bulk power markets."
Under Order 888, the Open Access Rule, transmission line owners are required to offer both point-to-point and network transmission services under comparable terms and conditions that they provide for themselves. The rule provides a single tariff providing minimum conditions for both network and point-to-point services and the non-price terms and conditions for providing these services and ancillary services. This rule also allows for full recovery of so-called stranded costs, with those costs being paid by wholesale customers wishing to leave their current supply arrangements. The rule encourages but does not require creation of independent system operators (ISOs) to coordinate intercompany transmission of electricity.
Order 889, the Open Access Same-time Information System (OASIS) rule, establishes standards of conduct to ensure a level playing field. The rule requires utilities to separate their wholesale power marketing and transmission operation functions, but does not require corporate unbundling or divestiture of assets. Utilities are still allowed to own transmission, distribution, and generation facilities but must maintain separate books and records.
On December 20, 1999, FERC issued Order 2000, which described the minimum characteristics and functions of regional transmission organizations (RTOs).(8) The required characteristics of an RTO are:
The required functions of an RTO outlined in Order 2000 are:
Order 2000 does not require a utility to participate in an RTO, set out RTO boundaries, or mandate the acceptable RTO structure. RTOs will be able to file with FERC as an independent system operator (ISO), a for-profit transmission company (transco), or another type of entity that has not yet been proposed. Although RTO participation is voluntary under Order 2000, FERC built in guidelines and safeguards to ensure independent operation of the transmission grid. RTOs are required to conduct independent audits to ensure that owners do not exert undue influence over RTO operation.
FERC Order 2000 required the existing ISOs to submit to FERC by January 1, 2001, a plan that described whether their transmission organization met the criteria established in the RTO rulemaking. Electric utilities that were not members of an ISO had to file plans with FERC by October 1, 2000. The order does not mandate RTO formation, but if an individual utility opts not to join an RTO, the utility is required to prove why it would be harmed by joining such an entity.
On July 12, 2001, FERC issued several orders requiring utilities to enter into talks to form Regional Transmission Organizations. Even though FERC Order 2000 did not set out RTO boundaries, in effect the July 12, 2001, order does. On September 17, 2001, FERC's Administrative Law Judge Mediator H. Peter Young filed his report, which presented a blueprint for creating a single RTO in the Northeast.(9)
FERC has granted RTO status to three entities and conditional approval to four others.
Other RTOs have received conditional approval from FERC.
In the past, utilities and some state utility commissioners have argued against large RTOs, stating that currently the expertise is not available to integrate a large geographic region with multiple control centers and power pools. On February 26, 2002, FERC released a report that assessed the potential economic costs and benefits of RTOs.(14) The study concluded the annual savings from RTO formation could range from $1 billion to $10 billion. However, the study did not find significant differences in savings between larger and smaller RTOs. Those in favor of large RTOs argue that they would provide the most efficient operations of the transmission system. On November 7, 2001, FERC issued an order that stated FERC's goals and process for creating Regional Transmission Organizations.(15)
On May 14, 1999, the U.S. Court of Appeals for the Eighth Circuit ruled in a case between FERC and Northern States Power Company. The court held that the commission overstepped its authority when it ordered Northern States Power Company to treat wholesale customers the same as it treats native load customers in making electricity curtailment decisions. This decision raised federal-state jurisdictional questions, particularly a state's right to guarantee system reliability.
On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New York et al. v. Federal Energy Regulatory Commission) that challenged FERC's authority under Order 888 to regulate transmission for retail sales if a utility unbundles transmission from other retail charges. In states that have opened their generation market to competition, unbundling occurs when customers are charged separately for generation, transmission, and distribution. Nine states, led by New York, filed suit, and argued that the Federal Power Act gives FERC jurisdiction over wholesale sales and interstate transmission and leaves all retail issues up to the state utility commissions. Enron argued that FERC clearly has jurisdiction over all transmission and FERC is obligated to prevent transmission owners from discriminating against those wishing to use the transmission lines. On March 4, 2002, the U.S. Supreme Court ruled in favor of FERC and held that FERC has jurisdiction over transmission including unbundled retail transactions.(16) At issue for Congress is whether to allow certain utilities to give preferential treatment to native load customers (customers within their service territories.)
The blackout of August 2003 in the Northeast, Midwest, and adjoining parts of Canada has highlighted the need for infrastructure and operating improvements. The North American Electric Reliability Council (NERC) has responsibility for reliability of the bulk power system. NERC has established reliability guidelines, but compliance with the guidelines is voluntary. The Federal Power Act gives FERC jurisdiction over unbundled transmission and was intended to regulate wholesale rates; however, no authority was provided to regulate reliability.
As a result of the recommendations of the joint U.S.-Canada task force investigating the August 2003 blackout, NERC is conducting reliability readiness audits of reliability coordinators. All audits are expected to be completed by 2006. FERC held a technical conference on September 29, 2004, to discuss the status of the Reliability Readiness Reviews. More than two-thirds of the audited control areas and reliability coordinators need to make staff training improvements and add support to their control centers in case of an emergency.(17) At the conference, NERC, FERC, and industry officials agreed that absent mandatory reliability standards, there is little assurance that operators of the system will comply with more rigorous guidelines.
Both NERC and FERC agree that implementation of an electric reliability organization (ERO) will improve the reliability of the electric system. The Energy Policy Act of 2005, as signed by the President on August 8, 2005, includes the creation of an ERO. The law requires FERC to promulgate rules to create a FERC-certified electric reliability organization. The ERO will develop and enforce reliability standards for the bulk-power system. All ERO standards will be approved by FERC. Under the law, the ERO can impose penalties on a user, owner, or operator of the bulk-power system that violates any FERC-approved liability standard. In addition, FERC can order compliance with the reliability standard and can impose a penalty if FERC finds that a user, owner, or operator of the bulk-power system has engaged in a violation of the reliability standard. However, this law would not give an ERO or FERC authorization to order construction of additional generation or transmission capacity.
Generally, the ERO is noncontroversial. Advocates of giving FERC authority over the ERO contend that central jurisdiction would provide more accountability. FERC would be ultimately responsible for reliability issues. If the penalties employed by the ERO are not successful, then FERC will have the authority to enforce penalties for entities that did not comply with reliability standards. Establishing this new relationship between FERC and the ERO could have the potential to improve coordination between market functions and reliability functions. Those opposed to giving FERC jurisdiction over bulk power system reliability contend that FERC has no experience in this area. They argue that by giving FERC this authority, it will have to rely on NERC for much of its expertise. Placing FERC in this position may add to the uncertainty associated with the changes in institutional structure as FERC takes on this new role.
A conflict exists between the apparent goal of increasing competition in the generation sector and assuring adequate transmission capacity and management of the system to move the power. Additions to generating capacity are occurring at a more rapid pace than transmission additions. The traditional vertically integrated utility no longer dominates the industry structure.(18) In addition, demand for electric power continues to increase. Unresolved regulatory issues that have emerged after 1992 have resulted in considerable uncertainty in the financial community. As a result of all of these factors, investment in the transmission system has not kept pace with demand for transmission capacity.
Siting. One reason transmission lines have not been built in recent years is the difficulty in siting lines. Even though the transmission of electricity is considered interstate commerce, the siting of transmission lines is the responsibility of the states. In addition, several federal agencies play various roles in the siting process, primarily with regard to environmental impacts. Siting and building transmission lines have been very difficult because of citizen opposition as well as inconsistent siting requirements among states. While controversial, since the blackout of 2003, FERC commissioners are now supporting federal siting backstop authority.(19) In addition, the electric industry is in favor of giving FERC siting authority.(20) States are generally opposed to this proposal. The Energy Policy Act of 2005 includes federal backstop authority for siting transmission lines.
Pricing. Some transmission-owning utilities argue that the current pricing mechanism for transmission discourages investment. FERC regulates all transmission, including unbundled retail transactions. Under the Federal Power Act (FPA), FERC is required to set "just and reasonable" rates for wholesale transactions.(21) FERC has traditionally determined rates by using an embedded cost method that includes recovery of capital costs, operating expenses, improvements, accumulated depreciation, and a rate of return. Traditionally, transmission owners have been compensated for use of their lines based on a contract path for the movement of electricity, generally the shortest path between the generator and its customer. However, electricity rarely follows a contract path and instead follows the path based on least impedance.(22) Transmission lines often carry electricity that has been contracted to move on a different path. As more bulk power transfers are occurring on the transmission system, transmission owners not belonging to RTOs are not always being compensated for use of their lines because a contract path rarely follows the actual flow. This creates a disincentive for transmission owners to increase capacity.(23)
Under Order 2000,(24) FERC stated its interest in incentive ratemaking and, in particular, performance-based ratemaking. Those in favor of incentive ratemaking argue that incentives are needed (1) to encourage participation in regional transmission organizations (RTOs)(25); (2) to compensate for perceived increases in financial risk because of participation in a regional transmission organization, and (3) to facilitate efficient expansion of the transmission system.
FERC uses a "license plate" rate for transmission: a single rate based on customer location. As FERC is encouraging formation of large regional transmission organizations, FERC may move toward a uniform access charge, sometimes called postage stamp rates. With a postage stamp rate, users pay one charge for moving electricity anywhere within the regional transmission organization.
Postage stamp rates eliminate so-called rate pancaking, or a series of accumulated transmission charges as the electricity passes through adjacent transmission systems, and increases the pool of available generation. On the other hand, by moving to postage stamp rates, customers in low-cost transmission areas may see a rate increase, and high-cost transmission providers in the same area may not recover embedded costs because costs are determined on a regional basis.
Regulatory Uncertainty. Transmission owners and investors have expressed concern that the regulatory uncertainty for electric utilities is inhibiting new investment in and construction of transmission facilities. For example, repeal of PUHCA has been debated since 1996 without resolution. Without clarification on whether PUHCA will be repealed, utilities state that they are reluctant to invest in infrastructure. Repeal could significantly expand the ability of utilities to diversify their investment options.
In addition, FERC has been moving toward requiring participation in regional transmission organizations to create a more seamless transmission system. A fully operational regional transmission organization would operate the entire transmission system in a region and be able to replace multiple control centers with a single control center.(26) This type of control can increase efficiencies in the operation of the transmission system. RTO participants are required to adhere to certain rules, but these are not currently enforceable in court.
Uncertainty over the form of an RTO, its operational characteristics, and the transmission rates for a specific region have apparently made utilities wary of investing in transmission. FERC has granted RTO status to several entities and conditionally approved others. If RTOs are able to operate successfully and develop a track record, some regulatory uncertainty will diminish.
Some have argued that the wholesale power markets cannot be competitive without additional market transparency for both generation and transmission. Some proposals would require FERC to issue rules to establish an electronic information system to provide the public, FERC, state commissions, buyers and sellers of wholesale electric energy, and users of transmission services with information on the availability and price of wholesale electric energy and transmission services.
The Energy Policy Act of 2005 repeals PUHCA and gives FERC additional merger review authority. One argument for additional PUHCA reform has been made by electric utilities that want to further diversify their assets. Under PUHCA, a holding company could acquire securities or utility assets only if the Securities and Exchange Commission (SEC) found that such a purchase would improve the economic efficiency and service of an integrated public utility system. It has been argued that reform to allow diversification would improve the risk profile of electric utilities in much the same way as in other businesses: The risk of any one investment is diluted by the risk associated with all investments. Utilities have also argued that diversification would lead to better use of underutilized resources (due to the seasonal nature of electric demand). Utility holding companies that have been exempt from SEC regulation argue that PUHCA discouraged diversification because the SEC could repeal exempt status if exemption would be "detrimental to the public interest."
For a number of years there has been significant bipartisan congressional support for repealing much of PUHCA, and giving FERC and state commissions access to books and records. Since the 1980s, the Securities and Exchange Commission has testified before Congress that many provisions of PUHCA are no longer relevant and other provisions are redundant with state and other federal regulations.(27) However, as a result of Enron's collapse, some in Congress have taken a somewhat different view toward significantly amending or repealing PUHCA.(28) Even though Enron had claimed exemption from PUHCA, on February 6, 2003, Securities and Exchange Commission Chief Administrative Law Judge Brenda P. Murray denied Enron's PUHCA exemption applications of February 28, 2002, amended on May 31, 2002, and April 12, 2000.(29) In the case of Enron, PUHCA and many other laws did not deter or prevent fraudulent filing of information with the SEC.
State regulators have expressed concerns that increased diversification could lead to abuses, including cross-subsidization: a regulated company subsidizing an unregulated affiliate. Cross-subsidization was a major argument against the creation of EWGs and re-emerged as an argument against PUHCA repeal. In the case of electric and gas companies, non-utility ventures that are undertaken as a result of diversification may benefit from the regulated utilities' allowed rate of return. Moneymaking non-utility enterprises would contribute to the overall financial health of a holding company. However, unsuccessful ventures could harm the entire holding company, including utility subsidiaries. In this situation, utilities would not be penalized for failure in terms of reduced access to new capital, because they could increase retail rates.
Several consumer and environmental public interest groups, as well as state legislators, expressed concerns about PUHCA repeal. PUHCA repeal, such groups argue, could only exacerbate market power abuses in what they see as a monopolistic industry where true competition does not yet exist.
A prospective repeal of §210 of PURPA, the mandatory purchase requirement provisions, is included in the Energy Policy Act of 2005. Proponents of PURPA repeal -- primarily investor-owned utilities (IOUs) located in the Northeast and in California -- argued that their state regulators' "misguided" implementation of PURPA in the early 1980s has forced them to pay contractually high prices for power they do not need. They argued that, given the current environment for cost-conscious competition, PURPA is outdated. The PURPA Reform Group, which promotes IOU interests, strongly supported repeal by contending that the PURPA's mandatory purchase obligation was anti-competitive and anti-consumer.
Opponents of PURPA reform (industrial power customers, some segments of the natural gas
industry, the renewable energy industry, and environmental groups) have many reasons to support
PURPA as it was enacted. Mainly, their argument was that PURPA introduced competition in the
electric generating sector and, at the same time, helped promote wider use of cleaner, alternative
fuels to generate electricity. Since the electric generating sector is not yet fully competitive, they
argued, repeal of PURPA would decrease competition and impede the development of the renewable
energy industry. Additionally, opponents of PURPA repeal argued that it would result in less
competition and greater utility monopoly control over the electric industry. State regulators
expressed concern that mandatory purchase requirement repeal would prevent them from deciding
matters currently under their jurisdiction. The National Association of Regulatory Utility
Commissioners has opposed legislation that would allow FERC to protect utilities from costs
associated with PURPA contracts.
6. (back) See Paul L. Joskow, The Difficult Transition to Competitive Electricity Markets in the U.S., May 2003, available at http://econ-www.mit.edu/faculty/download_pdf.php?id=537.
17. (back) A transcript of the Technical
Conference is available at
18. (back) According to the Energy Information Administration, in 1996, 10% of generating capacity was owned by non-utility generators. By 2000, 26% of generating capacity was owned by non-utility generators. In addition, to encourage competition, Maine and New Hampshire have required utilities to fully divest of either generation or transmission assets, and Rhode Island has partial divestiture requirements.
20. (back) Edison Electric Institute, Federal Siting Authority: Key to Expanding Electricity Infrastructure, available at http://www.eei.org/industry_issues/energy_infrastructure/transmission/federalsiting.pdf.
23. (back) See National Economic Research Associates, Transmission Pricing Arrangements and Their Influence on New Investments, World Bank Institute, July 6, 2000, available at http://www.worldbank.org/wbi/infrafin/pdfs/samples/dc2000-weektwo/berry_trans_pricing.ppt.
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