Historically, electricity service has been defined as a natural monopoly, meaning that theindustry has (1) an inherent tendency toward declining long-term costs, (2) high thresholdinvestment, 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 themost efficient means of providing service. As a result, most people (about 75%) are currently servedby a vertically integrated, investor-owned utility. As the electric utility industry has evolved, however, there has been a growing belief that thehistoric classification of electric utilities as natural monopolies has been overtaken by events and thatmarket forces can and should replace some of the traditional economic regulatory structure. Forexample, the existence of utilities that do not own all of their generating facilities, primarilycooperatives and publicly owned utilities, has provided evidence that vertical integration has notbeen necessary for providing efficient electric service. Moreover, recent changes in electric utilityregulation and improved technologies have allowed additional generating capacity to be providedby 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 ofregulating electric utilities that gave specific and separate powers to the states and the federalgovernment. A regulatory bargain was made between the government and utilities. In exchange foran exclusive franchise service territory, utilities must provide electricity to all users at reasonable,regulated rates. State regulatory commissions address intrastate utility activities, including wholesaleand retail rate-making. State authority currently tends to be as broad and as varied as the states arediverse. At the least, a state public utility commission will have authority over retail rates, and oftenover investment and debt. At the other end of the spectrum, the state regulatory body will overseemany facets of utility operation. Despite this diversity, the essential mission of the state regulator in states that have notrestructured is the establishment of retail electric prices. This is accomplished through an adversarialhearing process. The central issues in such cases are the total amount of money the utility will bepermitted to collect and how the burden of the revenue requirement will be distributed among thevarious customer classes (residential, commercial, and industrial). Under the FPA, federal economic regulation addresses wholesale transactions and rates forelectric power flowing in interstate commerce. Federal regulation followed state regulation and ispremised on the need to fill the regulatory vacuum resulting from the constitutional inability of statesto regulate interstate commerce. In this bifurcation of regulatory jurisdiction, federal regulation islimited 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 electricityutility industry, including financial transactions, wholesale rate regulation, transactions involvingtransmission of unbundled retail electricity, interconnection and wheeling of wholesale electricity,and ensuring adequate and reliable service. In addition, to prevent a recurrence of the abusivepractices of the 1920s (e.g., cross-subsidization, self-dealing, pyramiding, etc.), the Securities andExchange Commission (SEC) regulates utilities' corporate structure and business ventures underPUHCA. The electric utility industry has been in the process of transformation. During the past 25years, there has been a major change in direction concerning generation. First, improved technologieshave reduced the cost of generating electricity as well as the size of generating facilities. Priorpreference for large-scale -- often nuclear or coal-fired -- powerplants has been supplanted by apreference 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 electricitygeneration and permitted non-utility entities to build profitable facilities. Recent changes in electricutility regulation and improved technologies have allowed additional generating capacity to beprovided by independent firms rather than utilities. The oil embargoes of the 1970s created concerns about the security of the nation's electricitysupply and led to enactment of the Public Utility Regulatory Policies Act of 1978 (PURPA). (3) For the first time, utilitieswere 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, asdetermined by utility regulators. PURPA was established in part to augment electric utilitygeneration with more efficiently produced electricity and to provide equitable rates to electricconsumers. 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 newgenerating facilities. QFs, which by definition are not utilities, were able to take advantage of newlyabundant natural gas as well as new generating technology, such as combined-cycle plants that usehot exhaust gases from combustion turbines to make steam to generate additional power. Thesetechnologies lowered the financial threshold for entrance into the electricity generation business aswell as shortened the lead time for constructing new plants. FUA was repealed in 1987, but by thistime 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 wholesaletransactions. Before implementation of PURPA, FERC approved wholesale interstate electricitytransactions based on the seller's costs to generate and transmit the power. But, as non-utilitygenerators typically do not have enough market power to influence the rates they charge, FERCbegan approving certain wholesale transactions whose rates were a result of a competitive biddingprocess. These rates are called market-based rates. This first incremental change of traditional electricity regulation started a movement towarda market-oriented approach to electricity supply. Following the enactment of PURPA, two basicissues stimulated calls for further reform: whether to encourage nonutility generation and whetherto permit utilities to diversify into non-regulated activities. The Energy Policy Act of 1992 (EPACT) (5) removed several regulatory barriers to entry into electricitygeneration to increase competition of electricity supply. Specifically, EPACT provides for thecreation of entities, called "exempt wholesale generators" (EWGs), that can generate and sellelectricity at wholesale without being regulated as utilities under PUHCA. Under EPACT, EWGsare also provided with a way to assure transmission of their wholesale power to a wholesalepurchaser. However, EPACT does not permit FERC to mandate that utilities transmit EWG powerto retail consumers (commonly called "retail wheeling" or "retail competition"), an activity thatremains under the jurisdiction of state public utility commissions. PURPA began to shift moreregulatory responsibilities to the federal government, and EPACT continued that shift away from thestates by creating new options for utilities and regulators to meet electricity demand. EPACTallowed for a robust wholesale market in electricity. The transmission system is now usedextensively for bulk-power transfers between utilities, even though the physical system was designedto 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 notmet initial expectations. Few alternative suppliers have remained in the market, consumers arereluctant to switch suppliers, and default service rates set by the states are generally equal to or lessthan wholesale market prices plus retail margin needed to cover retail service costs. (6) Currently, 24 states and theDistrict of Columbia have either enacted legislation or issued regulatory orders to implement retailaccess. California had the first active retail program. However, California suspended itsrestructuring program following the California energy crises in 2001 that was marked by retail andwholesale price spikes as well as a decrease in reliability. Eighteen states have active restructuringprograms. Six states, Arkansas, Montana, Nevada, New Mexico, Oklahoma, and West Virginia,have delayed implementation of retail access. Since 2000, no additional states have announced plansto 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 utilityindustry has long been a proponent of such a repeal while consumer groups have been opposed. Asa compromise, a provision was included that strengthens FERC's merger review authority. Inaddition, language is included that is intended to prevent cross-subsidization. The mandatorypurchase requirement under the Public Utility Regulatory Policies Act (PURPA) is repealed. AnElectric Reliability Organization(ERO) is created and the ERO will promulgate mandatory,enforceable reliability standards for the electric industry that includes cybersecurity protection. Alsoincluded in the law is a Sense of Congress that FERC should carefully consider the states' objectionsto the locational installed capacity (LICAP) mechanism for New England. In addition to creating a new type of wholesale electricity generator, exempt wholesalegenerators (EWGs), the Energy Policy Act (EPACT) provides EWGs with a system to assuretransmission of their wholesale power to its purchaser. However, EPACT did not solve all of theissues relating to transmission access. As a result of EPACT, on April 24, 1996, FERC issued Orders888 and 889. (7) In issuingits final rules, FERC concluded that these orders will "remedy undue discrimination in transmissionservices in interstate commerce and provide an orderly and fair transition to competitive bulk powermarkets." Under Order 888, the Open Access Rule, transmission line owners are required to offer bothpoint-to-point and network transmission services under comparable terms and conditions that theyprovide for themselves. The rule provides a single tariff providing minimum conditions for bothnetwork and point-to-point services and the non-price terms and conditions for providing theseservices 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 supplyarrangements. 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, establishesstandards of conduct to ensure a level playing field. The rule requires utilities to separate theirwholesale power marketing and transmission operation functions, but does not require corporateunbundling or divestiture of assets. Utilities are still allowed to own transmission, distribution, andgeneration facilities but must maintain separate books and records. On December 20, 1999, FERC issued Order 2000, which described the minimumcharacteristics and functions of regional transmission organizations (RTOs). (8) The required characteristicsof an RTO are: The RTO must be independent from marketparticipants. It must serve a region of sufficient size to permit the RTO to performeffectively. An RTO will be responsible for operational control, and It will be responsible for maintaining the short-term reliability of the grid. The required functions of an RTO outlined in Order 2000 are: It must administer its own transmission tariff. It must ensure the development and operation of market mechanisms tomanage congestion. It must address parallel flow issues both within and outside itsregion. It will serve as supplier of last resort for all ancillary services; it mustadminister an Open Access Same-time Information System. It must monitor markets to identify design flaws and market power and proposeappropriate remedial actions; it must provide for interregional coordination,and An RTO must plan necessary transmission additions and upgrades. Order 2000 does not require a utility to participate in an RTO, set out RTO boundaries, ormandate the acceptable RTO structure. RTOs will be able to file with FERC as an independentsystem operator (ISO), a for-profit transmission company (transco), or another type of entity that hasnot yet been proposed. Although RTO participation is voluntary under Order 2000, FERC built inguidelines and safeguards to ensure independent operation of the transmission grid. RTOs arerequired to conduct independent audits to ensure that owners do not exert undue influence over RTOoperation. FERC Order 2000 required the existing ISOs to submit to FERC by January 1, 2001, a planthat described whether their transmission organization met the criteria established in the RTOrulemaking. Electric utilities that were not members of an ISO had to file plans with FERC byOctober 1, 2000. The order does not mandate RTO formation, but if an individual utility opts notto 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 formRegional Transmission Organizations. Even though FERC Order 2000 did not set out RTOboundaries, in effect the July 12, 2001, order does. On September 17, 2001, FERC's AdministrativeLaw Judge Mediator H. Peter Young filed his report, which presented a blueprint for creating asingle RTO in the Northeast. (9) FERC has granted RTO status to three entities and conditional approval to four others. On December 20, 2001, FERC granted RTO status to the Midwest IndependentTransmission System Operator (MISO). (10) On September 18, 2002, FERC approved the RTO West, since renamed GridWest, proposal. RTO West includes all, or part of, Washington, Idaho, Montana, Oregon, Nevada,Wyoming, Utah, and a small part of northern California adjacent to Oregon. FERC granted PJM RTO status on December 19, 2002. PJM manages the gridin parts of Ohio, West Virginia, Pennsylvania, New Jersey, Delaware, Maryland, Virginia, and theDistrict of Columbia. Other RTOs have received conditional approval from FERC. Most recently, FERC conditionally approved the New England RTO (ISO-NE)on March 24, 2004. (11) ISO-NE serves customers in Connecticut, Massachusetts, New Hampshire, Rhode Island, Vermont,and portions of Maine. FERC also granted conditional approval to the Southwest Power Pool (SPP)on February 10, 2004. (12) Arkansas-based SPP serves 4 million customers in all, or parts of, Arkansas, Kansas, Louisiana,Mississippi, Missouri, New Mexico, Oklahoma, and Texas. FERC conditionally approved SeTrans RTO and WestConnect RTO onOctober 10, 2002. (13) SeTrans includes utilities in Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, SouthCarolina, and Texas. WestConnect RTO includes parts of Arizona, Colorado, New Mexico, andUtah. 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 withmultiple control centers and power pools. On February 26, 2002, FERC released a report thatassessed the potential economic costs and benefits of RTOs. (14) The study concluded theannual savings from RTO formation could range from $1 billion to $10 billion. However, the studydid not find significant differences in savings between larger and smaller RTOs. Those in favor oflarge 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 creatingRegional Transmission Organizations. (15) On May 14, 1999, the U.S. Court of Appeals for the Eighth Circuit ruled in a case betweenFERC and Northern States Power Company. The court held that the commission overstepped itsauthority when it ordered Northern States Power Company to treat wholesale customers the sameas it treats native load customers in making electricity curtailment decisions. This decision raisedfederal-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 toregulate 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 customersare 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 andinterstate transmission and leaves all retail issues up to the state utility commissions. Enron arguedthat FERC clearly has jurisdiction over all transmission and FERC is obligated to preventtransmission owners from discriminating against those wishing to use the transmission lines. OnMarch 4, 2002, the U.S. Supreme Court ruled in favor of FERC and held that FERC has jurisdictionover transmission including unbundled retail transactions. (16) At issue for Congress iswhether to allow certain utilities to give preferential treatment to native load customers (customerswithin their service territories.) The blackout of August 2003 in the Northeast, Midwest, and adjoining parts of Canada hashighlighted the need for infrastructure and operating improvements. The North American ElectricReliability Council (NERC) has responsibility for reliability of the bulk power system. NERC hasestablished reliability guidelines, but compliance with the guidelines is voluntary. The FederalPower Act gives FERC jurisdiction over unbundled transmission and was intended to regulatewholesale rates; however, no authority was provided to regulate reliability. As a result of the recommendations of the joint U.S.-Canada task force investigating theAugust 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 September29, 2004, to discuss the status of the Reliability Readiness Reviews. More than two-thirds of theaudited control areas and reliability coordinators need to make staff training improvements and addsupport to their control centers in case of an emergency. (17) At the conference, NERC, FERC, and industry officials agreedthat absent mandatory reliability standards, there is little assurance that operators of the system willcomply 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 signedby the President on August 8, 2005, includes the creation of an ERO. The law requires FERC topromulgate rules to create a FERC-certified electric reliability organization. The ERO will developand enforce reliability standards for the bulk-power system. All ERO standards will be approvedby FERC. Under the law, the ERO can impose penalties on a user, owner, or operator of thebulk-power system that violates any FERC-approved liability standard. In addition, FERC can ordercompliance 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 additionalgeneration or transmission capacity. Generally, the ERO is noncontroversial. Advocates of giving FERC authority over the EROcontend that central jurisdiction would provide more accountability. FERC would be ultimatelyresponsible for reliability issues. If the penalties employed by the ERO are not successful, thenFERC will have the authority to enforce penalties for entities that did not comply with reliabilitystandards. Establishing this new relationship between FERC and the ERO could have the potentialto improve coordination between market functions and reliability functions. Those opposed togiving FERC jurisdiction over bulk power system reliability contend that FERC has no experiencein this area. They argue that by giving FERC this authority, it will have to rely on NERC for muchof its expertise. Placing FERC in this position may add to the uncertainty associated with thechanges in institutional structure as FERC takes on this new role. A conflict exists between the apparent goal of increasing competition in the generation sectorand 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. Thetraditional vertically integrated utility no longer dominates the industry structure. (18) In addition, demand forelectric power continues to increase. Unresolved regulatory issues that have emerged after 1992have resulted in considerable uncertainty in the financial community. As a result of all of thesefactors, investment in the transmission system has not kept pace with demand for transmissioncapacity. Siting. One reason transmission lines have notbeen built in recent years is the difficulty in siting lines. Even though the transmission of electricityis 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 regardto environmental impacts. Siting and building transmission lines have been very difficult becauseof citizen opposition as well as inconsistent siting requirements among states. While controversial,since the blackout of 2003, FERC commissioners are now supporting federal siting backstopauthority. (19) In addition,the electric industry is in favor of giving FERC siting authority. (20) States are generallyopposed to this proposal. The Energy Policy Act of 2005 includes federal backstop authority forsiting transmission lines. Pricing. Some transmission-owning utilitiesargue that the current pricing mechanism for transmission discourages investment. FERC regulatesall 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 traditionallydetermined rates by using an embedded cost method that includes recovery of capital costs, operating expenses, improvements, accumulated depreciation, and a rate of return. Traditionally, transmissionowners have been compensated for use of their lines based on a contract path for the movement ofelectricity, generally the shortest path between the generator and its customer. However, electricityrarely follows a contract path and instead follows the path based on least impedance. (22) Transmission lines oftencarry electricity that has been contracted to move on a different path. As more bulk power transfersare occurring on the transmission system, transmission owners not belonging to RTOs are not alwaysbeing compensated for use of their lines because a contract path rarely follows the actual flow. Thiscreates a disincentive for transmission owners to increase capacity. (23) Under Order 2000, (24) FERC stated its interest in incentive ratemaking and, inparticular, performance-based ratemaking. Those in favor of incentive ratemaking argue thatincentives are needed (1) to encourage participation in regional transmission organizations(RTOs) (25) ; (2) tocompensate for perceived increases in financial risk because of participation in a regionaltransmission 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 movetoward 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 accumulatedtransmission charges as the electricity passes through adjacent transmission systems, and increasesthe pool of available generation. On the other hand, by moving to postage stamp rates, customersin low-cost transmission areas may see a rate increase, and high-cost transmission providers in thesame area may not recover embedded costs because costs are determined on a regional basis. Regulatory Uncertainty. Transmission ownersand investors have expressed concern that the regulatory uncertainty for electric utilities is inhibitingnew investment in and construction of transmission facilities. For example, repeal of PUHCA hasbeen debated since 1996 without resolution. Without clarification on whether PUHCA will berepealed, utilities state that they are reluctant to invest in infrastructure. Repeal could significantlyexpand the ability of utilities to diversify their investment options. In addition, FERC has been moving toward requiring participation in regional transmissionorganizations to create a more seamless transmission system. A fully operational regionaltransmission organization would operate the entire transmission system in a region and be able toreplace multiple control centers with a single control center. (26) This type of control canincrease efficiencies in the operation of the transmission system. RTO participants are required toadhere to certain rules, but these are not currently enforceable in court. Uncertainty over the form of an RTO, its operational characteristics, and the transmissionrates for a specific region have apparently made utilities wary of investing in transmission. FERChas granted RTO status to several entities and conditionally approved others. If RTOs are able tooperate successfully and develop a track record, some regulatory uncertainty will diminish. Some have argued that the wholesale power markets cannot be competitive withoutadditional market transparency for both generation and transmission. Some proposals would requireFERC to issue rules to establish an electronic information system to provide the public, FERC, statecommissions, buyers and sellers of wholesale electric energy, and users of transmission services withinformation 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 reviewauthority. One argument for additional PUHCA reform has been made by electric utilities that wantto further diversify their assets. Under PUHCA, a holding company could acquire securities orutility assets only if the Securities and Exchange Commission (SEC) found that such a purchasewould improve the economic efficiency and service of an integrated public utility system. It hasbeen argued that reform to allow diversification would improve the risk profile of electric utilitiesin much the same way as in other businesses: The risk of any one investment is diluted by the riskassociated with all investments. Utilities have also argued that diversification would lead to betteruse of underutilized resources (due to the seasonal nature of electric demand). Utility holdingcompanies that have been exempt from SEC regulation argue that PUHCA discourageddiversification because the SEC could repeal exempt status if exemption would be "detrimental tothe public interest." For a number of years there has been significant bipartisan congressional support forrepealing 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 manyprovisions of PUHCA are no longer relevant and other provisions are redundant with state and otherfederal regulations. (27) However, as a result of Enron's collapse, some in Congress have taken a somewhat different viewtoward significantly amending or repealing PUHCA. (28) Even though Enron had claimed exemption from PUHCA, onFebruary 6, 2003, Securities and Exchange Commission Chief Administrative Law Judge BrendaP. Murray denied Enron's PUHCA exemption applications of February 28, 2002, amended on May31, 2002, and April 12, 2000. (29) In the case of Enron, PUHCA and many other laws did not deteror 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 anargument against PUHCA repeal. In the case of electric and gas companies, non-utility ventures thatare undertaken as a result of diversification may benefit from the regulated utilities' allowed rate ofreturn. Moneymaking non-utility enterprises would contribute to the overall financial health of aholding company. However, unsuccessful ventures could harm the entire holding company,including utility subsidiaries. In this situation, utilities would not be penalized for failure in termsof 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 exacerbatemarket power abuses in what they see as a monopolistic industry where true competition does notyet exist. A prospective repeal of Â§210 of PURPA, the mandatory purchase requirement provisions,is included in the Energy Policy Act of 2005. Proponents of PURPA repeal -- primarilyinvestor-owned utilities (IOUs) located in the Northeast and in California -- argued that their stateregulators' "misguided" implementation of PURPA in the early 1980s has forced them to paycontractually high prices for power they do not need. They argued that, given the currentenvironment for cost-conscious competition, PURPA is outdated. The PURPA Reform Group,which promotes IOU interests, strongly supported repeal by contending that the PURPA's mandatorypurchase obligation was anti-competitive and anti-consumer. Opponents of PURPA reform (industrial power customers, some segments of the natural gasindustry, the renewable energy industry, and environmental groups) have many reasons to supportPURPA as it was enacted. Mainly, their argument was that PURPA introduced competition in theelectric generating sector and, at the same time, helped promote wider use of cleaner, alternativefuels to generate electricity. Since the electric generating sector is not yet fully competitive, theyargued, repeal of PURPA would decrease competition and impede the development of the renewableenergy industry. Additionally, opponents of PURPA repeal argued that it would result in lesscompetition and greater utility monopoly control over the electric industry. State regulatorsexpressed concern that mandatory purchase requirement repeal would prevent them from decidingmatters currently under their jurisdiction. The National Association of Regulatory UtilityCommissioners has opposed legislation that would allow FERC to protect utilities from costsassociated with PURPA contracts. 

Summary: 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 holdingcompanies by requiring federal control and regulation of interstate public utility holding companies. Prior to PUHCA, electricity holding companies were characterized as having excessive consumerrates, high debt-to-equity ratios, and unreliable service. PUHCA remained virtually unchanged for50 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 toprovide equitable rates to electric consumers. Qualifying facilities (QFs) are exempt from regulationunder 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 sectorby creating new entities, called "exempt wholesale generators" (EWGs), that can generate and sellelectricity at wholesale without being regulated as utilities under PUHCA. This title also providesEWGs with a way to assure transmission of their wholesale power to their purchasers. The effect ofthis 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 888and 889. FERC issued these rules to remedy undue discrimination in transmission services ininterstate 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 PUHCAreform. 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 PUHCAcould exacerbate market power abuses in a monopolistic industry where true competition does notyet exist. The second issue is PURPA's requirement that utilities purchase power from QFs. Manyinvestor-owned utilities support repeal of these mandatory purchase provisions. They argue that theirstate regulators' "misguided" implementation of PURPA has forced them to pay contractually highprices for power that they do not need. Opponents of this legislation argue that it would decreasecompetition 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.