Summary of Electricity Provisions in the Conference Report on H.R. 6, 108th Congress
Released: 2003-12-17T00:00:00

Introduction

Conferees on the House and Senate energy bills ( H.R. 6 ) met on November 17,2003 and approved a conference report ( H.Rept. 108-375 ). On November 18, 2003, the Houseapproved the Conference report to H.R. 6 by a vote of 246-180. On November 21,2003, a cloture motion to limit debate on H.R. 6 failed in the Senate by a vote of 57-40. In addition to a title on electricity, the conference report included provisions on ethanol, methyltertiary butyl ether (MTBE), energy efficiency, hydroelectricity, renewable energy, oil and gas, coal,Indian energy, nuclear power, research and development, and energy tax incentives. This reportsummarizes the electricity title of H.R. 6 , Title XII. The policy context and/or thecurrent law is provided for selected sections. For additional discussion on these issues, see CRS Report RL32728 , Electric Utility Regulatory Reform: Issues for the 109th Congress , and CRS Report RL32133 , Federal Merger Review Authority and Electric Utility Restructuring.

Title XII -- Electricity

Section 1201. Short title. This title may be citedas the "Electric Reliability Act of 2003."

Subtitle A -- Reliability Standards

Section 1211. Electric Reliability Standards. This section would require the Federal Energy Regulatory Commission (FERC) to promulgate ruleswithin 180 days of enactment to create a FERC-certified electric reliability organization (ERO). TheERO would develop and enforce reliability standards for the bulk-power system. All ERO standardswould be approved by FERC. Under this title, the ERO could impose penalties on a user, owner,or operator of the bulk-power system that violates any FERC-approved reliability standard. Inaddition, FERC could order compliance with a reliability standard and could impose a penalty ifFERC finds that a user, owner, or operator of the bulk-power system has engaged in or is about toengage in a violation of a reliability standard. This provision would not give an ERO or FERCauthorization to order construction of additional generation or transmission capacity.

This provision would also require that FERC establish a regional advisory body if requestedby at least two-thirds of the states within a region that have more than half of their electric loadserved within that region. The advisory body would be composed of one member from eachparticipating state in the region, appointed by the Governor of each state, and could provide adviceto the ERO or FERC on reliability standards, proposed regional entities, proposed fees, and any otherresponsibilities requested by FERC. The entire reliability provision would not apply to Alaska orHawaii.

Current Law. The North American Electric ReliabilityCouncil (NERC) has responsibility for reliability of the bulk power system. NERC has establishedreliability guidelines but has no enforcement authority. The Federal Power Act gives FERCjurisdiction over unbundled transmission and was intended to regulate wholesale rates; however, noauthority was provided to regulate reliability.

Policy Context. The proposed legislation is intendedto provide federal jurisdiction over activities that are required to support reliability of the UnitedStates bulk power system. Clarifying FERC authority to establish and regulate an ERO is intendedto improve reliability as restructuring of the U.S. bulk power system proceeds. Similar provisionswere included in the House-passed and Senate-passed H.R. 6 .

Advocates of giving FERC authority over the ERO contend that central jurisdiction wouldprovide more accountability. FERC would be ultimately responsible for reliability issues. If thepenalties employed by the ERO were not successful, then FERC would have the authority to enforcepenalties for entities that did not comply with reliability standards. Establishing this newrelationship between FERC and the ERO would have the potential to improve coordination betweenmarket functions and reliability functions. Those opposed to giving FERC jurisdiction over bulkpower system reliability contend that FERC has no experience in this area. If FERC is given thisauthority, it would have to rely on NERC for much of its expertise. Placing FERC in this positionmay add to the uncertainty associated with the changes in institutional structure as FERC takes onthis new role.

Subtitle B -- Transmission Infrastructure Modernization

Section 1221. Siting of Interstate ElectricTransmission Facilities. The Secretary of Energy would be required to conduct a study of electrictransmission congestion every three years. Based on the findings, the Secretary of Energy coulddesignate a geographic area as being congested. Under certain conditions, FERC would beauthorized to issue construction permits. Under proposed Federal Power Act (FPA) section 216(d),affected states, federal agencies, Indian tribes, property owners, and other interested parties wouldhave an opportunity to present their views and recommendations with respect to the need for andimpact of a proposed construction permit. However, there is no requirement for a specific commentperiod. New FPA section 216(e) would allow permit holders to petition in U.S. District Court toacquire rights-of-way through the exercise of the right of eminent domain. Any exercise of eminentdomain authority would be considered to be takings of private property for which just compensationis due. New FPA section 216(g) does not state whether property owners will be required toreimburse compensation if the rights-of-way are transferred back to the owner.

An applicant for federal authorization to site transmission facilities on federal lands couldrequest that the Department of Energy be the lead agency to coordinate environmental review andother federal authorization. Once a completed application is submitted, all related environmentalreviews would be required to be completed within 1 year unless another federal law makes thatimpossible. FPA section 216(h) would give the Department of Energy (DOE) new authority toprepare environmental documents and appears to give DOE additional decision-making authorityfor rights-of-way and siting on federal lands. This would appear to give DOE input into the decisionprocess for creating rights-of-way. Review under section 503 of the Federal Land Policy andManagement Act could be streamlined by relying on prior analyses. If a federal agency has deniedan authorization required by a transmission or distributions facility, the denial could be appealed bythe applicant or relevant state to the Secretary of Energy. The Secretary of Energy would be requiredto issue a decision within 90 days of the appeal's filing. States could enter into interstate compactsfor the purposes of siting transmission facilities and the Secretary of Energy could provide technicalassistance. This section would not apply to the Electric Reliability Council of Texas (ERCOT). Asimilar provision was included in the House-passed H.R. 6 .

Current Law. Regulatory jurisdiction over theelectricity industry is divided between federal and state authorities, with individual states overseeingactivities considered intrastate and with FERC regulating the interstate aspects of electricity andnatural gas commerce. (1) Under the Federal Power Act, siting of transmission lines is the responsibility of the states.

Section 1222. Third-Party Finance. The WesternArea Power Administration (WAPA) and the Southwestern Power Administration (SWPA) wouldbe able to either continue to design, develop, construct, operate, maintain, or own transmissionfacilities within their region or participate with other entities for the same purposes if: the Secretaryof Energy designates the area as a National Interest Electric Transmission Corridor and the projectwould reduce congestion, or the project is needed to accommodate projected increases in demandfor transmission capacity. The project would need to be consistent with the needs identified by theappropriate Regional Transmission Organization or Independent System Operator. No more than$100 million from third-party financing may be used during fiscal years 2004 through 2013. Thissection was not included in either the House- or Senate-passed H.R. 6 .

Current Law. Enabling statutes for power marketingadministrations may restrict third-party financing, construction, operation, and maintenance oftransmission facilities. (2)

Section 1223. Transmission System Monitoring. Within six months of enactment, the Secretary of Energy and the Federal Energy RegulatoryCommission would be required to complete a study and report to Congress on what would berequired to create and implement a transmission monitoring system for the Eastern and Westerninterconnections. The monitoring system would provide all transmission system owners andRegional Transmission Organizations real-time information on the operating status of alltransmission lines. This section was not included in either the House- or Senate-passed H.R. 6 .

Section 1224. Advanced TransmissionTechnologies. FERC would be directed to encourage deployment of advanced transmissiontechnologies. This section was not included in either the House- or Senate-passed H.R. 6 .

Section 1225. Electric Transmission andDistribution Programs. The Secretary of Energy acting through the Director of the Office of ElectricTransmission and Distribution would be required to implement a program to promote reliability andefficiency of the electric transmission system. Within one year of enactment, the Secretary of Energywould be required to submit to Congress a report detailing the program's five-year plan. Within twoyears of enactment, the Secretary of Energy would be required to submit to Congress a reportdetailing the progress of the program. The Secretary of Energy would be directed to establish aresearch, development, demonstration and commercial application initiative that would focus onhigh-temperature superconductivity. For this project, appropriations would be authorized forFY2004 through FY2008. In part, a similar provision was included in the House-passed H.R. 6 .

Section 1226. Advanced Power SystemTechnology Incentive Program. A program would be established to provide incentive payments toowners or operators of advanced power generation systems. Eligible systems would includeadvanced fuel cells, turbines, or hybrid power systems. A total of $140 million would be authorizedfor FY2004 through FY2008. A similar provision was included in the House-passed H.R. 6 . In the House-passed version, $70 million would have been authorized forFY2004 through FY2010.

Section 1227. Office of Electric Transmissionand Distribution. This would amend Title II of the Department of Energy Organization Act (3) and would establish an Officeof Electric Transmission and Distribution. The Director of the office would, in part, coordinate anddevelop a strategy to improve electric transmission distribution, implement recommendations fromthe Department of Energy's National Transmission Grid Study, oversee research, development, anddemonstration to support federal energy policy related to electricity transmission and distribution,and develop programs for workforce training and power transmission engineering. This section wasnot included in either the House- or Senate-passed H.R. 6 .

Subtitle C -- Transmission Operation Improvements

Section 1231. Open Nondiscriminatory Access. FERC would be authorized, by rule or order, to require unregulated transmitting utilities (powermarketing administrations, state entities, and rural electric cooperatives) to charge rates comparableto what they charge themselves and would require that the terms and conditions of the sales arecomparable to those required of other utilities. Exemptions are established for utilities selling lessthan 4 million megawatt-hours of electricity per year, for distribution utilities, and for utilities thatown or operate transmission facilities that are not necessary to facilitate a nationwide interconnectedtransmission system. This exemption could be revoked to maintain transmission system reliability. FERC would not be authorized to order states or municipalities to take action under this section ifsuch action would constitute a private use under section 141 of the Internal Revenue Code of 1986. FERC may remand transmission rates to an unregulated transmitting utility if the rates do not complywith this section. FERC is not authorized to order an unregulated transmitting utility to join aRegional Transmission Organization or other FERC-approved independent transmissionorganization. This section is often referred to as "FERC-lite." Provisions on open access wereincluded in both the House- and Senate-passed H.R. 6 , but the conference languagediffered. Termination of exemptions for reliability purposes does not appear in either the House-or Senate-passed H.R. 6 .

Current Law. Under the Federal Power Act (Section201(f)), federal power marketing administrations, state entities, and rural electric cooperatives arenot subject to FERC's ratemaking.

Section 1232. Sense of Congress on RegionalTransmission Organizations. This would establish a sense of Congress that utilities shouldvoluntarily become members of regional transmission organizations. A similar provision wasincluded in the House- and Senate-passed H.R. 6 .

Current Law. Section 202(a) of the Federal PowerAct directs FERC to promote and encourage regional districts for the voluntary interconnection andcoordination of transmission facilities by public utilities and non-public utilities for the purpose ofassuring an abundant supply of electric energy throughout the U.S. with the greatest possibleeconomy.

Section 1233. Regional TransmissionOrganization Applications Progress Report. FERC would be required to report to Congress within120 days of enactment the status of all regional transmission organization applications. Similarlanguage was included in the House-passed H.R. 6 .

Section 1234. Federal Utility Participation inRegional Transmission Organizations. Federal utilities (power marketing administrations or theTennessee Valley Authority) would be authorized to participate in regional transmissionorganizations. A law allowing federal utilities to study formation and operation of a regionaltransmission organization would be repealed. (4) A similar provision was included in the House-passed H.R. 6 .

Section 1235. Standard Market Design. FERC'sproposed rulemaking on standard market design would be remanded to FERC for reconsideration. No final rulemaking, including any rule or order of general applicability to the standard marketdesign proposed rulemaking, could be issued before October 31, 2006, or could take effect beforeDecember 31, 2006. This section would retain FERC's ability to issue rules or orders and act onregional transmission organization or independent system operator filings. H.R. 6 , aspassed by the House and Senate, did not include a similar provision.

Policy Context. On July 31, 2002, FERC issued aNotice of Proposed Rulemaking (NOPR) on standard market design (SMD). (5) FERC's stated goal of establishing SMD requirements in conjunction with a standardized transmission service is to create"seamless" wholesale power markets that allow sellers to transact easily across transmission gridboundaries. The proposed rulemaking would create a new tariff under which each transmissionowner would be required to turn over operation of its transmission system to an unaffiliatedindependent transmission provider (ITP). The ITP, which could be an RTO, would provide serviceto all customers and run energy markets. Under the NOPR, congestion would be managed withlocational marginal pricing. The NOPR comment period originally was 75 days (November 15,2002), but the comment period was extended to January 10, 2003, for the following issues:1) marketdesign for the Western Interconnection; 2) transmission pricing plan, including participant funding;3) Regional State Advisory Committees and state participation; 4) resource adequacy; and 5)congestion revenue rights and transition issues.

Under the NOPR, FERC would assert jurisdiction over all power transmission, includingservice to bundled retail customers. Commissioners from 15 states (Alabama, Arkansas, California,Georgia, Idaho, Kentucky, Louisiana, Mississippi, New Hampshire, North Carolina, South Carolina,Oregon, South Dakota, Washington, and Wyoming) are reportedly planning to fight FERC'sproposed changes on the grounds that FERC usurps state authority. On August 15, 2002, stateregulators from 22 states and the District of Columbia (Illinois, Indiana, Iowa, Michigan, Minnesota,Missouri, Montana, North Dakota, Ohio, Oklahoma, Texas, Wisconsin, Delaware, the District ofColumbia, New Jersey, New York, Pennsylvania, West Virginia, Connecticut, Maine,Massachusetts, New Hampshire, and Rhode Island) released a statement that "voiced support forFERC's ongoing effort to remedy undue discrimination in the use of the nation's interstate highvoltage transmission system in order to create a truly competitive bulk power market." Someindustry groups have voiced concerns about the implementation of SMD.

On April 28, 2003, FERC staff issued Wholesale Power Market Platform , a White Paper thatintended to clarify FERC's SMD proposal. The White Paper responds to approximately 1,000 setsof formal comments submitted to FERC. In the White Paper, FERC states its intention to eliminatea proposed requirement that utilities join an Independent Transmission Provider. Instead, the finalrule would require utilities to join an RTO or ISO. In the NOPR, FERC proposed to assertjurisdiction over the transmission component of bundled retail service. The White Paper reverses thisposition and states that the final rule will not assert new FERC jurisdiction over bundled retail sales.

Some state officials have expressed concern that the proposed rule would infringe on stateauthority. FERC responded to this in the White Paper by clarifying that the final rule would notinclude a requirement for a minimum level of resource adequacy. In addition, the final rule wouldeliminate the NOPR's requirement that Firm Transmission Rights be auctioned. The White Papernoted that each RTO or ISO would need to have a cost recovery policy outlined in its tariff, but eachregion may differ on how participant funding would be used. In addition, FERC stated that the finalrule would allow for phased implementation to address regional differences.

The report language that accompanied the FY2003 Consolidated Appropriations Resolutionasked the Department of Energy to analyze the SMD NOPR's impact on wholesale electricity prices,and the safety and reliability of generation and transmission facilities. (6) DOE issued its report toCongress on April 30, 2003, but did not include changes from FERC's White Paper in its analysis. DOE, in part, quantitatively analyzed the wholesale and retail price impacts of SMD using twoeconomic models: General Electric's Multi-Area Production Simulation (MAPS) and DOE's PolicyOffice Electricity Modeling System (POEMS).

Some of the assumptions that DOE uses are: the annual increase in electricity demand isassumed to be approximately 1.8% per year from 2005 to 2020; most regions are assumed to havereserve margins of 15%; current environmental laws and regulations are assumed to apply; generatorefficiency for fossil steam plants is assumed to be 2% to 4% higher in new RTO regions with SMD.In the non-SMD case, the models were not able to take into account freezes on retail rates in statesthat are transitioning to competitive markets, and no increase in transmission capacity is assumed. Under the SMD case, a 5% increase in transmission capability by 2005 is assumed by DOE due toimproved operational efficiency at regional seams. In addition, DOE assumes that adopting theSMD would result in some savings that are difficult to quantify but would be a result of severalfactors including the consolidation of control areas from the currently existing 150, the possibleavoidance of capital cost and software expenditures that would have been needed at existing controlcenters, improved regional planning, and consistency of market design. DOE assigns a 10% savingsdue to these efficiency improvements. DOE believes that the assumptions used in the models areconservative and result in an underestimation of the net economic benefits of the SMD.

DOE calculates the median cost of FERC's SMD rule to be about $760 million per year, orabout 21 cents per megawatt-hour. The model's range for uncertainties is estimated to be about $100million. The cost varies significantly by region, ranging from 47 cents per megawatt-hour forGridFlorida to 12 cents per megawatt-hour for PJM. Regions with existing RTOs have zeroadditional costs. Under the SMD case, the effects of SMD on retail rates are influenced to asignificant extent by whether the states in question have cost-of-service regulation or competitiveretail choice. DOE found that for some importing regions with cost-based rates, the net result couldbe increased costs associated with wholesale purchases, which would be passed through to retailcustomers. For some exporting regions with cost-based rates, additional utility revenues fromexports are expected to lead to lower retail prices for the region under the SMD case. In contrast,in regions in which most states have adopted retail choice, increased electricity exports are expectedto lead to higher market-clearing prices in the short-term markets and somewhat higher consumerprices. However, in areas such as California that are projected to see increased imports, lowerwholesale prices and lower prices for consumers are expected. DOE found that the magnitude ofthe projected changes, both positive and negative, decreases through 2020. Overall, DOE projectsthe net benefit for all consumers would be about $1 billion per year over the first 6 years, afterfactoring in the estimated $760 million per year and RTO costs. Over the long-term (2016-2020),the net benefit is expected to be about $700 million per year. However, the projected change in retailprices varies by region. The mid-Atlantic region is expected to see a 4% decrease in retail prices,but Illinois, Wisconsin, and Arizona are expected to have a 3% increase in retail prices as a resultof SMD.

Section 1236. Native Load Service Obligation. This section would amend the Federal Power Act to clarify that a load-serving entity is entitled touse its transmission facilities or firm transmission rights to serve its existing customers before it isobligated to make its transmission capacity available for other uses. FERC would not be able tochange any approved allocation of transmission rights by an RTO or ISO approved prior toSeptember 15, 2003. A similar provision was included in the House-passed H.R. 6 .

Current Law. Section 201 of the Federal Power Actgives FERC jurisdiction over "the transmission of electric energy in interstate commerce and the saleof such energy at wholesale in interstate commerce." Section 205 of the Federal Power Act prohibitsutilities from granting "undue preference or advantage to any person or subject any person to anyundue prejudice or disadvantage" (16 U.S.C. 824). This section is intended to clarify that reservingtransmission for existing customers (native load) is not considered unduly discriminatory.

Section 1237. Study on the Benefits of EconomicDispatch. The Secretary of Energy, in consultation with the states, would be required to issue anannual report to Congress and the states on the current status of economic dispatch. Economicdispatch would be defined as "the operation of generation facilities to produce energy at the lowestcost to reliably serve consumers, recognizing any operational limits of generation and transmissionfacilities." This section was included in the House-passed H.R. 6 .

Subtitle D -- Transmission Rate Reform

Section 1241. Transmission InfrastructureInvestment. FERC would be required to establish a rule to create incentive-based transmission rates. FERC would be authorized to revise the rule. The rule would promote reliable and economicallyefficient electric transmission and generation, provide for a return on equity that would attract newinvestment in transmission, encourage use of technologies that increased the transfer capacity ofexisting transmission facilities, and allow for the recovery of all prudently incurred costs that arenecessary to comply with mandatory reliability standards. In addition, FERC would be directed toimplement incentive rate-making for utilities that join a Regional Transmission Organization orIndependent System Operator. The House-passed H.R. 6 did not include reliability inthe proposed FERC rule.

Section 1242. Voluntary Transmission PricingPlans. This would amend the Federal Power Act to allow any transmission provider including aRegional Transmission Organization or Independent System Operator to determine how the cost ofnew transmission facilities would be allocated. The cost of all transmission expansion, except whatis required for reliability purposes, would be assigned so that those who benefit from the additionof the transmission would pay an appropriate share of the costs. This is referred to as participantfunding. This provision would protect native load customers from paying for transmission upgradesneeded for new generator interconnection if the new generation is not required by the native load (thedemand of the utility's existing customers.) Participant funding was included in the House-passed H.R. 6 .

Policy Context. FERC regulates all transmissionincluding unbundled retail transactions. (7) Under the Federal Power Act (FPA), FERC is required to set "justand reasonable" rates for wholesale transactions. (8) FERC has traditionally used an embedded cost method fordetermining rates that includes recovery of capital costs, operating expenses, improvements,accumulated depreciation, and a rate of return. Recently, FERC has raised the rate of return as a wayto reflect the regulatory uncertainty in the industry and encourage transmission investment.

The Energy Policy Act of 1992 (EPAct) created a new category of wholesale electricgenerators called Exempt Wholesale Generators (EWGs) that are not considered utilities. (9) EWGs, also referred to asmerchant generators, were intended to create a competitive wholesale electric generation sector. Inaddition, EPAct provided a means for these non-utility generators to have access to the transmissionsystem (the transmission system is owned by incumbent utilities). As a result of EPAct, FERCissued a policy statement on transmission pricing policy. It stated that:

Greater pricing flexibility is appropriate in light of thesignificant competitive changes occurring in wholesale generation markets, and in light of ourexpanded wheeling authority under the Energy Policy Act of 1992 (EPAct)[footnote omitted]. Theserecent events underscore the importance of ensuring that our transmission pricing policies promoteeconomic efficiency, fairly compensate utilities for providing transmission services, reflect areasonable allocation of transmission costs among transmission users, and maintain the reliabilityof the transmission grid. The Commission also recognizes that advances in computer modelingtechniques have made possible certain transmission pricing methods that once would have beenimpractical. (10)

In May 1994, FERC established general guidelines for comparable access to the transmissionsystem. (11) By July 9,1996, all utilities that own or control transmission had filed a single open access tariff with FERCthat provides transmission service to eligible wholesale customers at comparable terms to the servicethat the utilities provide themselves. Some merchant generators asserted that they continued to bediscriminated against by incumbent transmission utilities and were denied access to the system. InApril 1996, FERC clarified its open access transmission tariff policy with Orders 888 and 889,making it easier for merchant generators to gain access to the transmission grid.

The regulatory regime has shifted the operations of the electric utility industry, creating largerand more frequent bulk power transfers across a transmission system designed for local intrastateservice. However, investment in infrastructure has not kept up with increases in the bulk powertransfers and electricity demand. Electricity demand has been growing at 2% to 3% per year, butadditions to the transmission system have been growing by 0.7% per year. As a result, during someof the year transmission is congested in several regions of U.S. including California, Minnesota toWisconsin, New York, and the Ohio Valley.

Some transmission-owning utilities argue that the current pricing mechanism for transmissiondiscourages investment. Currently, transmission owners are compensated for use of their lines basedon a contract path for the movement of electricity, generally the shortest path between the generatorand its customer. However, electricity rarely follows a contract path and instead follows the pathbased on least impedance. (12) Transmission lines often carry electricity that has beencontracted to move on a different path. Therefore, some transmission owners are not beingcompensated for use of their lines and lack the incentive to increase capacity.

Under Order 2000, FERC stated its interest in incentive ratemaking and in particularperformance-based ratemaking. Those in favor of incentive ratemaking argue that incentives areneeded: 1) to encourage participation in regional transmission organizations; 2) because participationin a regional transmission organization is perceived to increase financial risk; and 3) to facilitateefficient expansion of the transmission system. (13)

Currently FERC uses a "license plate" rate for transmission, a single rate based on customerlocation. As FERC is encouraging formation of large regional transmission organizations, FERC ismoving toward a uniform access charge, sometimes called postage stamp rates. With a postagestamp rate, users pay one charge for moving electricity anywhere within the regional transmissionorganization.

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 as costs are determined on a regional basis.

FERC-approved tariffs do not necessarily increase with the addition of new transmissioncapacity. FERC could approve a new higher transmission tariff, thus increasing all users' costs tomove electricity on the transmission system. However, the revenue requirement of the transmissionutility may be met with current tariffs. Local retail customers are charged for transmission based onan individual customer's usage of electricity. Therefore, depending on a transmissioninterconnection's impact on the tariff, a retail customer's transmission rates may or may not change.

If a wholesale customer uses transmission lines in one state or region solely to move thepower to a customer in another state or region (sometimes referred to as wheeling), the wholesalecustomer will pay a FERC-approved transmission tariff that is the same as for wholesale customerswhose ultimate retail consumer is in the region. Embedded in the tariff is recovery of capital costs.Proponents of this amendment argue that wholesale customers who do not wheel their power out ofthe region are being penalized by wholesale generators that do wheel power. They argue that tariffsreflect capital costs for which they do not receive a benefit. Opponents of the amendment argue thattransmission interconnection should be offered at comparable rates and service levels to allgenerators in order to create a competitive generating market. Further, opponents of participantfunding argue that requiring merchant generators to pay up-front for all interconnection could inhibitwholesale competition and favor incumbent generators. Proponents argue, however, that merchantgenerators should locate where it is economic to interconnect to the transmission system.

FERC has the authority and has been working to address transmission interconnection issues. Participant-funded investment deviates from past FERC policy for allocating transmission costs andis a departure from all previous FERC ratemaking. However, FERC's Standard Market DesignNotice of Proposed Rulemaking would allow for participant funding.

Subtitle E -- Amendments to PURPA

Section 1251. Net Metering and AdditionalStandards. For states that have not considered implementation and adoption of net meteringstandards, within three years of enactment, state regulatory authorities would be required to considerwhether to implement net metering. Net metering service is defined as: service to an electricconsumer under which electric energy generated by that electric consumer from an eligible on-sitegenerating facility (e.g., solar or small generator) and delivered to local distribution facilities maybe used to offset electric energy provided by the electric utility to the electric consumer during theapplicable billing period. Net metering provisions were included in the House- and Senate-passed H.R. 6 .

Section 1252. Smart Metering. For states thathave not considered implementation and adoption of a smart metering standard, state regulatoryauthorities would be required to initiate an investigation within one year of enactment, and issue adecision within two years of enactment whether to implement a standard for time-based meters andcommunications devices for all electric utility customers. These devices would allow customers toparticipate in time-based pricing rate schedules. This section would amend the Public UtilityRegulatory Policies Act of 1978 (14) (PURPA) and would require the Secretary of Energy to provideconsumer education on advanced metering and communications technologies, to identify and addressbarriers to adoption of demand response programs, and issue a report to Congress that identifies andquantifies the benefits of demand response. The Secretary of Energy would provide technicalassistance to regional organizations to identify demand response potential and to develop demandresponse programs to respond to peak demand or emergency needs. FERC would be directed toissue an annual report, by region, to assess demand response resources. A provision for real-timepricing and time-of-use metering standards was included in the House- and Senate-passed H.R. 6 .

Section 1253. Cogeneration and Small PowerProduction Purchase and Sale Requirements. This section would repeal the mandatory purchaserequirement under Â§210 of PURPA for new contracts if FERC finds that a competitive electricitymarket exists and a qualifying facility has access to independently administered, auction-basedday-ahead and real-time wholesale markets and long-term wholesale markets. Qualifying facilitieswould also need to have access to transmission and interconnection services provided by aFERC-approved regional transmission entity that provides non-discriminatory treatment for allcustomers. Ownership limitations under PURPA would be repealed. Repeal of the mandatorypurchase requirement was included in the House- and Senate-passed H.R. 6 .

Current Law. Section 210 of PURPA requires utilitiesto purchase power from qualifying facilities and small power producers at a rate based on theutilities' avoided cost. (15)

Policy Context. The oil embargoes of the 1970screated concerns about the security of the nation's electricity supply and led to enactment of thePublic Utility Regulatory Policies Act of 1978. For the first time, utilities were required to purchasepower from outside sources. The purchase price was set at the utilities' "avoided cost," the cost theywould 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 producedelectricity and to provide equitable rates to electric consumers.

In addition to PURPA, the Fuel Use Act of 1978 (FUA) helped qualifying facilities (QFs)become established. (16) Under FUA, utilities were not permitted to use natural gas to fuel new generating technology. QFs,which are by definition not utilities, were able to take advantage of abundant natural gas as well asnew generating technology, such as combined-cycle plants that use hot gases from combustionturbines to generate additional power. These technologies lowered the financial threshold forentrance into the electricity generation business as well as shortened the lead time for constructingnew plants. FUA was repealed in 1987, but by this time QFs and small power producers had gaineda 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. Since nonutilitygenerators 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 to 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.

EPACT removed several regulatory barriers for entry into electricity generation to increasecompetition of electricity supply. However, EPACT does not permit FERC to mandate that utilitiestransmit EWG power to retail consumers (commonly called "retail wheeling" or "retailcompetition"), an activity that remains under the jurisdiction of state public utility commissions. PURPA began to shift more regulatory responsibilities to the federal government, and EPACTcontinued that shift away from the states by creating new options for utilities and regulators to meetelectricity demand.

Proponents of PURPA repeal -- primarily investor-owned utilities (IOUs) located in theNortheast and in California -- argue that their state regulators' "misguided" implementation ofPURPA in the early 1980s has forced them to pay contractually high prices for power they do notneed. They argue that, given the current environment for cost-conscious competition, PURPA isoutdated. The PURPA Reform Group, which promotes IOU interests, strongly supports repeal ofÂ§210 of PURPA by contending that the current law's mandatory purchase obligation wasanti-competitive and anti-consumer.

Opponents of mandatory purchase requirement repeal (independent power producers,industrial power customers, most segments of the natural gas industry, the renewable energyindustry, and environmental groups) have many reasons to support PURPA as it stands. Mainly,their argument is that PURPA introduced competition in the electric generating sector and, at thesame time, helped promote wider use of cleaner, alternative fuels to generate electricity. Since theelectric generating sector is not yet fully competitive, they argue, repeal of PURPA would decreasecompetition and impede the development of the renewable energy industry. Additionally, opponentsof PURPA repeal argue that it would result in less competition and greater utility monopoly controlover the electric industry. Some state regulators have expressed concern that Â§210 repeal wouldprevent them from deciding matters currently under their jurisdiction.

Subtitle F-- Repeal of PUHCA

Section 1261. Short Title. This subtitle may becited as the "Public Utility Holding Company Act of 2003."

Section 1262. Definitions. This section wouldprovide definitions for: affiliate, associate company, commission, company, electric utility company,exempt wholesale generator and foreign utility company, gas utility company, holding company,holding company system, jurisdictional rates, natural gas company, person, public utility,public-utility company, state commission, subsidiary company, and voting security.

Section 1263. Repeal of the Public UtilityHolding Company Act of 1935. The Public Utility Holding Company Act of 1935 (PUHCA) wouldbe repealed. The provision to repeal PUHCA was included in both the House- and Senate-passed H.R. 6 .

Current Law. In general, the Public Utility HoldingCompany Act of 1935 regulates the structure of holding companies by prohibiting all holdingcompanies that are more than twice removed from the operating subsidiaries, federally regulatesholding companies of investor-owned utilities, and provides for Securities and ExchangeCommission (SEC) regulation of mergers and diversification proposals. Registered holdingcompanies of subsidiaries are required to have SEC approval prior to issuing securities; all loans andintercompany financial transactions are regulated by the SEC. A holding company can be exemptfrom PUHCA if its business operations and those of its subsidiaries occur within one state or withincontiguous states.

Policy Context. Historically, electricity service wasdefined as a natural monopoly, meaning that the industry has (1) an inherent tendency towarddeclining long-term costs, (2) high threshold investment, and (3) technological conditions that limitthe number of potential entrants. In addition, many regulators have considered unified control ofgeneration, transmission, and distribution as the most efficient means of providing service. As aresult, most people (about 75%) are currently served by a vertically integrated, investor-ownedutility.

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 and the Federal Power Act (FPA) of 1935 (TitleI and Title II of the Public Utility Act) established a regime of regulating electric utilities that gavespecific and separate powers to the states and the federal government. A regulatory bargain wasmade 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 regulatorycommissions address intrastate utility activities, including wholesale and retail rate-making. Stateauthority currently tends to be as broad and as varied as the states are diverse. At the least, a statepublic 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 utilityoperation. 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. FERC has the principal functions at thefederal level for the economic regulation of the electric utility industry, including financialtransactions, wholesale rate regulation, transactions involving transmission of unbundled retailelectricity, interconnection and wheeling of wholesale electricity, and ensuring adequate and reliableservice. In addition, to prevent a recurrence of the abusive practices of the 1920s (e.g.,cross-subsidization, self-dealing, pyramiding, etc.), SEC regulates utilities' corporate structure andbusiness ventures under PUHCA.

The electric utility industry has been in the process of transformation. During the past twodecades, there has been a major change in direction concerning generation. First, improvedtechnologies 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 bya preference for small-scale production facilities that can be brought on line more quickly andcheaply, with fewer regulatory impediments. Second, this has lowered the entry barrier to electricitygeneration and permitted non-utility entities to build profitable facilities.

One argument for additional PUHCA reform has been made by electric utilities that want tofurther diversify their assets. Currently under PUHCA, a holding company can acquire securitiesor utility assets only if the SEC finds that such a purchase will improve the economic efficiency andservice of an integrated public utility system. It has been argued that reform to allow diversificationwould improve the risk profile of electric utilities in much the same way as in other businesses: Therisk of any one investment is diluted by the risk associated with all investments. Utilities have alsoargued that diversification would lead to better use of under-utilized resources (due to the seasonalnature of electric demand). Utility holding companies that have been exempt from SEC regulationargue that PUHCA discourages diversification because the SEC could repeal exempt status ifexemption would be "detrimental to the public interest."

For a number of years there has been significant bipartisan congressional support forrepealing much of PUHCA. Since the 1980s, the Securities and Exchange Commission has testifiedbefore Congress that many provisions of PUHCA are no longer relevant and other provisions areredundant with state and other federal regulations. (17) However, as a result of Enron's collapse, some in Congress havetaken a somewhat different view toward significantly amending or repealing PUHCA. (18) Even though Enron hadclaimed exemption from PUHCA, on February 6, 2003, Securities and Exchange Commission ChiefAdministrative Law Judge Brenda P. Murray denied Enron's PUHCA exemption applications ofApril 12, 2000 and February 28, 2002, amended on May 31, 2002. (19) In the case of Enron,PUHCA, and many other laws, did not deter or prevent fraudulent filing of information with theSEC.

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 has reemerged as anargument against further PUHCA reform. In the case of electric and gas companies, non-utilityventures 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 financialhealth of a holding company. However, unsuccessful ventures could harm the entire holdingcompany, including utility subsidiaries. In this situation, utilities would not be penalized for failurein 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, haveexpressed 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.

Section 1264. Federal Access to Books andRecords. Federal access to books and records of holding companies and their affiliates would beprovided. Affiliate companies would have to make available to FERC books and records of affiliatetransactions. Federal officials would have to maintain confidentiality of such books and records. A similar provision was included in the House-and Senate-passed H.R. 6 .

Current Law. Registered holding companies andsubsidiary companies are required to preserve accounts, cost-accounting procedures, correspondence,memoranda, papers, and books that the SEC deems necessary or appropriate in the public interestor for the protection of investors and consumers. (20)

Section 1265. State Access to Books andRecords. A jurisdictional state commission would be able to make a reasonably detailed writtenrequest to a holding company or any associate company for access to specific books and records,which would be kept confidential. This section would not apply to an entity that is considered to bea holding company solely by reason of ownership of one or more qualifying facilities. Response tosuch a request would be mandatory. Compliance with this section would be enforceable in U.S.District Court. A similar provision was included in the House -and Senate-passed H.R. 6 .

Current Law. Under the Federal Power Act, statecommissions may examine the books, accounts, memoranda, contracts, and records of ajurisdictional electric utility company, an exempt wholesale generator that sells to such electricutility, and an electric utility company or holding company that is an associate company or affiliateof an exempt wholesale generator. (21)

Section 1266. Exemption Authority. FERCwould be directed to promulgate rules to exempt qualifying facilities, exempt wholesale generators,and foreign utilities, from the federal access to books and records provision (Section 1264). Asimilar provision was included in the House- and Senate-passed H.R. 6 .

Section 1267. Affiliate Transactions. FERCwould retain the authority to prevent cross-subsidization and to assure that jurisdictional rates arejust and reasonable. FERC and state commissions would retain jurisdiction to determine whetherassociate company activities could be recovered in rates. A similar provision was included in theHouse- and Senate-passed H.R. 6 .

Current Law. The Federal Power Act requires thatjurisdictional rates are just and reasonable and prohibits cross-subsidization. (22)

Section 1268. Applicability. Except asspecifically noted, this subtitle would not apply to the U.S. government, a state or any politicalsubdivision of the state, or foreign governmental authority operating outside the U.S. A similarprovision was included in the House- and Senate-passed H.R. 6 .

Section 1269. Effect on Other Regulations. FERC or state commissions would not be precluded from exercising their jurisdiction underotherwise applicable laws to protect utility customers. A similar provision was included in theHouse- and Senate-passed H.R. 6 .

Section 1270. Enforcement. FERC would haveauthority to enforce this provision under sections 306-317 of the Federal Power Act. A similarprovision was included in the House- and Senate-passed H.R. 6 .

Current Law. The Securities and ExchangeCommission has authority to investigate and enforce provisions of the Public Utility HoldingCompany Act of 1935. (23)

Section 1271. Savings Provisions. Personswould be able to continue to engage in legal activities in which they have been engaged or areauthorized to engage in on the effective date of this Act. This subtitle would not limit the authorityof FERC under the Federal Power Act or the Natural Gas Act. A similar provision was included inthe House- and Senate-passed H.R. 6 .

Section 1272. Implementation. Not later than12 months after enactment, FERC would be required to promulgate regulations necessary toimplement this subtitle and submit to Congress recommendations for technical or conformingamendments to federal law that would be necessary to carry out this subtitle. A similar provisionwas included in the House- and Senate-passed H.R. 6 .

Section 1273. Transfer Resources. The Securitiesand Exchange Commission would be required to transfer all applicable books and records to FERC. However, no time frame for transfer of books and records is provided. A similar provision wasincluded in the House- and Senate-passed H.R. 6 .

Current Law. The Securities and ExchangeCommission maintains books and records and regulates security transactions. (24)

Section 1274. Effective Date. Twelve monthsafter enactment, this subtitle would take effect.

Section 1275. Service Allocation. FERC wouldbe required to review and authorize cost allocations for non-power goods or administrative ormanagement services provided by an associate company that was organized specifically for thepurpose of providing such goods or services. This section would not preclude FERC or statecommissions from exercising their jurisdiction under other applicable laws with respect to reviewor authorization of any costs. FERC would be required to issue rules within six months of enactmentto exempt from the section any company and holding company system if operations are confinedsubstantially to a single state. This section was not included in either the House- or Senate-passed H.R. 6 .

Section 1276. Authorization of Appropriations. Necessary funds to carry out this subtitle would be authorized to be appropriated. A similar provisionwas included in the House- and Senate-passed H.R. 6 .

Section 1277. Conforming Amendments to theFederal Power Act. The Federal Power Act would be amended to reflect the changes to the PublicUtility Holding Company Act of 1935. (25)

Subtitle G -- Market Transparency, Enforcement, and Consumer Protection

Section 1281. Market Transparency Rules. Within 180 days after enactment, FERC would be required to issue rules to establish an electronicsystem that provides information about the availability and price of wholesale electric energy andtransmission services. FERC would exempt from disclosure any information that, if disclosed, couldbe detrimental to the operation of the effective market or jeopardize system security. FERC wouldbe required to assure that consumers in competitive markets are protected from adverse effects ofpotential collusion or other anti-competitive behaviors that could occur as a result of untimely publicdisclosure of transaction-specific information. This section would not affect the exclusivejurisdiction of the Commodity Futures Trading Commission with respect to accounts, agreement,contracts, or transactions in commodities under the Commodity Exchange Act. FERC would notbe allowed to compete with, or displace, any price publisher or regulate price publishers or imposeany requirements on the publication of information. Creation of market transparency rules wasincluded in the House- and Senate-passed H.R. 6 .

Section 1282. Market Manipulation. It would beunlawful to willfully and knowingly file a false report on any information relating to the price ofelectricity sold at wholesale or availability of transmission capacity, with the intent to fraudulentlyaffect data being compiled by a federal agency. It would be unlawful for any individual, corporation,or government entity (municipality, state, power marketing administration) to engage in round-tripelectricity trading. Round-trip trading is defined to include contracts in which purchase and saletransactions have no specific financial gain or loss and are entered into with the intent to distortreported revenues, trading volumes, or prices.

Current Law. Mail fraud laws in part apply to use ofthe mail for the purpose of executing, or attempting to execute, a scheme or artifice to defraud or forobtaining money or property by false or fraudulent pretenses, representations, or promises. (26) Wire fraud statutes coveruse of wire, radio, or television communication in interstate or foreign commerce to transmit or tocause to be transmitted any writings, signs, signals, pictures, or sounds for the purpose of executinga scheme or artifice to defraud or for obtaining money or property by means of false or fraudulentpretenses, representations, or promises. (27)

Section 1283. Enforcement. The Federal PowerAct would be amended to allow electric utilities to file a complaint with FERC and to allowcomplaints to be filed against transmitting utilities. Criminal and civil penalties under the FederalPower Act would be increased. Criminal penalties would not exceed $1 million and/or five yearsimprisonment. In addition, a fine of $25,000 could be imposed. A civil penalty not exceeding $1million per day per violation could be assessed for violations of sections 211, 212, 213, or 214 ofthe Federal Power Act.

Current Law. Criminal penalties may not exceed$5,000 and/or two years' imprisonment. An additional fine of $500 can be imposed. A civil penaltynot exceeding $10,000 per day per violation may be assessed for violations of sections 211, 212, 213,or 214 of the Federal Power Act.

Section 1284. Refund Effective Date. Section206(b) of the Federal Power Act would be amended to allow the effective date for refunds to beginat the time of the filing of a complaint with FERC but not later than five months after such a filing. If FERC does not make its decision within the time-frame provided, FERC would be required tostate its reasons for not acting in the provided time-frame for the decision. A similar provision wasincluded in the House- and Senate-passed H.R. 6 .

Current Law. Refunds for rates that FERC finds tobe unjust, unreasonable, unduly discriminatory, or preferential begin a minimum of 60 days after acomplaint is filed. (28)

Section 1285. Refund Authority. Any entity thatis not a public utility (including an entity referred to under Â§ 201(f) of the Federal Power Act) andenters into a short-term sale of electricity would be subject to the FERC refund authority. Ashort-term sale would include any agreement to the sale of electric energy at wholesale that is for aperiod of 31 days or less. This section would not apply to electric cooperatives, or any entity thatsells less than 8 million megawatt hours of electricity per year. FERC would have refund authorityover voluntary short-term sales of electricity by Bonneville Power Administration if the rates chargedare unjust and unreasonable. FERC would have authority over all power marketing administrationsand the Tennessee Valley Authority to order refunds to achieve just and reasonable rates. Refundauthority was provided for in the House-passed H.R. 6 .

Current Law. Section 201(f) of the Federal Power Actexempts government entities from FERC rate regulation. (29)

Section 1286. Sanctity of Contract. Upondetermining that failure to take action would be contrary to protection of the public interest, FERCwould be authorized to modify or abrogate any contract entered into after enactment of this section. FERC would not be able to abrogate or modify contracts that expressly provide for a standard ofreview other than the public interest standard. A similar provision was included in the House-passed H.R. 6 .

Section 1287. Consumer Privacy and UnfairTrade Practices. The Federal Trade Commission would be authorized to issue rules to prohibitslamming and cramming. Slamming occurs when an electric utility switches the customer's electricprovider without the consumer's knowledge. Cramming occurs when an electric utility addsadditional services and charges to a customer's account without permission of the customer. If theFederal Trade Commission determines that a state's regulations provide equivalent or greaterprotection, then the state regulations would apply in lieu of regulations issued by the Federal TradeCommission. The House-and Senate-Passed H.R. 6 would have required the FederalTrade Commission to issue rules to prohibit slamming and cramming.

Subtitle H -- Merger Reform

Section 1291. Merger Review Reform andAccountability. Within 180 days of enactment, the Secretary of Energy would be required totransmit to Congress a study on whether FERC's merger review authority is duplicative with otheragencies' authority and that would include recommendations for eliminating any unnecessaryduplication. FERC would be required to issue an annual report to Congress describing allconditions placed on mergers under section 203(b) of the Federal Power Act. FERC would also berequired to include in its report whether such a condition could have been imposed under any otherprovision of the Federal Power Act. A similar provision was included in the House-passed H.R. 6 .

Section 1292. Electric Utility Mergers. TheFederal Power Act would be amended to give FERC review authority for transfer of assets valuedin excess of $10 million. FERC would be required to give state public utility commissions andgovernors reasonable notice in writing. FERC would be required to establish rules to comply withthis section. A similar provision was included in the Senate-passed H.R. 6 .

Current Law. Under Section 203(a) of the FederalPower Act, FERC review of asset transfers applies to transactions valued at $50,000 or more. (30)

Subtitle I -- Definitions

Section 1295. Definitions. The definitions for"electric utility" and "transmitting utility" under the Federal Power Act would be amended. Definitions for the following terms would be added to the Federal Power Act: electric cooperative,regional transmission organization, independent system operator, and commission.

Section 1297. Conforming Amendments. TheFederal Power Act would be amended to conform with this title.