Electric Utility Provisions in House-Passed H.R. 6, 109th Congress

RL32925 -- Electric Utility Provisions in House-Passed H.R. 6, 109th Congress

Updated August 18, 2005

CONTENTS

Summary

Title XII Electricity

Section 1201

Subtitle A Reliability Standards

Section 1211. Electric Reliability Standards

Section 1221. Siting of Interstate Electric Transmission Facilities

Section 1222. Third-Party Finance

Section 1223. Transmission System Monitoring

Section 1224. Advanced Transmission Technologies

Section 1225. Electric Transmission and Distribution Programs

Section 1226. Advanced Power System Technology Incentive Program

Section 1227. Office of Electric Transmission and Distribution

Subtitle C Transmission Operation Improvements

Section 1231. Open Nondiscriminatory Access

Section 1232. Sense of Congress on Regional Transmission Organizations

Section 1233. Regional Transmission Organization Applications Progress Report

Section 1234. Federal Utility Participation in Regional Transmission Organizations

Section 1235. Standard Market Design

Section 1236. Native Load Service Obligation

Section 1237. Study on the Benefits of Economic Dispatch

Subtitle D Transmission Rate Reform

Section 1241. Transmission Infrastructure Investment

Subtitle E Amendments to PURPA

Section 1251. Net Metering and Additional Standards

Section 1252. Smart Metering

Section 1253. Cogeneration and Small Power Production Purchase and Sale Requirements

Section 1254. Interconnection

Subtitle F Repeal of PUHCA

Section 1261. Short Title

Section 1262. Definitions

Section 1263. Repeal of the Public Utility Holding Company Act of 1935

Section 1264. Federal Access to Books and Records

Section 1265. State Access to Books and Records

Section 1266. Exemption Authority

Section 1267. Affiliate Transactions

Section 1268. Applicability

Section 1269. Effect on Other Regulations

Section 1270. Enforcement

Section 1271. Savings Provisions

Section 1272. Implementation

Section 1273. Transfer of Resources

Section 1274. Effective Date

Section 1275. Service Allocation

Section 1276. Authorization of Appropriations

Section 1277. Conforming Amendments to the Federal Power Act

Subtitle G Market Transparency, Enforcement, and Consumer Protection

Section 1281. Market Transparency Rules

Section 1282. Market Manipulation

Section 1283. Enforcement

Section 1284. Refund Effective Date

Section 1285. Refund Authority

Section 1286. Sanctity of Contract

Section 1287. Consumer Privacy and Unfair Trade Practices

Subtitle H Merger Reform

Section 1291. Merger Review Reform and Accountability

Section 1292. Electric Utility Mergers

Subtitle I Definitions

Section 1295. Definitions

Section 1297. Conforming Amendments

Subtitle K Economic Dispatch

Section 1298. Economic Dispatch

Other Electric Provisions

Section 504. Four Corners Transmission Line Project

Section 1441. Continuation of Transmission Security Order

Section 1611. Reliability and Consumer Protection Assessment

Footnotes

Summary

Electric utility provisions were included in comprehensive energy legislation (H.R. 6) that passed the House on April 21, 2005. For an analysis of all provisions of House-passed H.R. 6, see CRS Report RL32936, Omnibus Energy Legislation, 109th Congress: Assessment of H.R. 6 as passed by the House. The Senate Passed its version of H.R. 6 on June 28, 2005. Conferees on H.R. 6, the Energy Policy Act of 2005, agreed on a final bill July 26, 2005 (H.Rept. 109-190). On July 28, the House approved the conference report (275-156). Senate approval (74-26) of the conference report followed the next day. The bill was signed into law by President Bush on August 8, 2005.

This report describes Title XII of the House-passed H.R. 6 in the 109th Congress and other sections that deal with electric power issues. In part, Title XII would create an electric reliability organization (ERO) that would enforce mandatory reliability standards for the bulk-power system. All ERO standards would be approved by the Federal Energy Regulatory Commission (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. This title also addresses transmission infrastructure issues. The Secretary of Energy would be able to certify congestion on the transmission lines and issue permits to transmission owners. Permit holders would be able to petition in U.S. district court to acquire rights-of-way for the construction of transmission lines through the exercise of the right of eminent domain. A provision that would have required FERC to approve participant funding for new transmission lines was removed in markup by the House Committee on Energy and Commerce.

The Standard Market Design notice of proposed rulemaking would be remanded to the Federal Energy Regulatory Commission. This provision clarifies native load service obligation. Federal utilities would be allowed to participate in regional transmission organizations.

The electricity title would repeal the mandatory purchase requirements under the Public Utility Regulatory Policy Act. The Public Utility Holding Company Act of 1935 (PUHCA) would be repealed. The Federal Energy Regulatory Commission and state regulatory bodies would be given access to utility books and records.

FERC would be required to issue rules to establish an electronic system that provides information about the availability and price of wholesale electric energy and transmission services. For electric rates that the Federal Energy Regulatory Commission finds to be unjust, unreasonable, or unduly discriminatory, the effective date for refunds could begin at the time of the filing of a complaint with FERC but not later than five months after filing of a complaint. Criminal and civil penalties would be increased. The Federal Power Act would be amended to give FERC review authority for transfer of assets valued in excess of $10 million.

This report will not be updated.

Title XII -- Electricity

Section 1201. Short title. This title may be cited as the "Electric Reliability Act of 2005."

Subtitle A -- Reliability Standards

Section 1211. Electric Reliability Standards. This section would require the Federal Energy Regulatory Commission (FERC) to promulgate rules within 180 days of enactment to create a FERC-certified electric reliability organization (ERO). The North American Electric Reliability Council (NERC) currently has responsibility for reliability of the bulk power system. NERC has established reliability guidelines but has no enforcement authority. The Federal Power Act currently gives FERC jurisdiction over unbundled transmission and authority to regulate wholesale rates; however, no authority was provided to regulate reliability. Under this section, the ERO would develop and enforce reliability standards for the bulk-power system, including cybersecurity protection. All ERO standards would 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. In addition, FERC could order compliance with a reliability standard and could impose a penalty if FERC finds that a user, owner, or operator of the bulk-power system has engaged in or is about to engage in a violation of a reliability standard. This provision would not give an ERO or FERC authorization to order construction of additional generation or transmission capacity.

This provision would also require that FERC establish a regional advisory body if requested by at least two-thirds of the states within a region that have more than half of their electric load served within that region. The advisory body would be composed of one member from each participating state in the region, appointed by the Governor of each state, and could provide advice to the ERO or FERC on reliability standards, proposed regional entities, proposed fees, and any other responsibilities requested by FERC. The entire reliability provision would not apply to Alaska or Hawaii. The state of New York is authorized to develop rules that would result in greater reliability for New York, as long as those rules do not result in lower reliability for neighboring states.

H.R. 6 would require the ERO to be funded through contributions from its utility members. The Congressional Budget Office (CBO) determined that, under the Unfunded Mandates Reform Act (UMRA) of 1995,(1) these contributions would constitute an unfunded mandate both on the private sector and intergovernmentally, because both private sector utilities and those run by local governments (munis) would be obligated to contribute. H.R. 6 would limit the total amount "of all dues, fees, and other charges collected by the ERO" to $50,000,000 annually, with no adjustment for inflation, through 2015. This limit was initially included in H.R. 6 to avoid a point of order based on the budget resolution. UMRA limits would not apply to dues collected from Canadian utilities, and it is unclear whether the $50,000,000 limit on the ERO budget applies to fees collected from U.S. and Canadian utilities or just the U.S. utilities' contributions.(2) This limit would restrict the cost of this mandate to less than the threshold at which UMRA subjects congressional consideration of legislation containing intergovernmental mandates to a point of order. The 2005 budget for NERC and all of its regional entities, however, is $51,950,000, of which munis contributed approximately $6,370,000, and the ERO would be required to engage in functions beyond what NERC already performs. One new function is the ability of the ERO to impose and collect penalties. A $50,000,000 cap on all dues, fees, and other charges that can be collected by the ERO could limit the penalties that could be collected by the ERO.

CBO provided no separate estimate for the cost of the mandates in this subtitle, but estimated that H.R. 6 as a whole contains both intergovernmental and private sector unfunded mandates that would exceed the applicable thresholds. The CBO estimate stated that the cost of complying with intergovernmental mandates, in aggregate, could be significant and likely would exceed the threshold established in UMRA ($62 million in 2005, adjusted annually for inflation) at some point over the next five years because CBO expects future damage awards for state and local governments under the bill's safe harbor provision (Title XV) would likely be reduced.(3)

Section 1211(c) would authorize to be appropriated not more than $50 million per year for FY2006 through FY2015 for all activities under the amendment to the Federal Power Act that creates the ERO. This is in addition to the dues paid by the ERO members. It is unclear whether FERC would be the sole recipient of the $50 million annual authorization, since Section 1211(b) specifically states that the ERO, and its regional entities, are not departments, agencies, or instrumentalities of the United States government.

The proposed legislation is intended to provide federal jurisdiction over activities that are required to support reliability of the U.S. bulk power system. Clarifying FERC authority to establish and regulate an ERO is intended to improve reliability as restructuring of the U.S. bulk power system proceeds. Similar provisions were included in the conference report of H.R. 6 in the 108th Congress.

Advocates of giving FERC authority over the ERO contend that central jurisdiction would provide more accountability. FERC would be ultimately responsible for reliability issues. If the penalties employed by the ERO were not successful, then FERC would have the authority to enforce penalties for entities that did not comply with reliability standards. Establishing this new relationship between FERC and the ERO would have the potential to improve coordination between market functions and reliability functions. Similar legislation has been introduced during the past several sessions of Congress, but has not been enacted, despite general support. Minor opposition to this proposal has centered on giving FERC jurisdiction over bulk power system reliability, contending that FERC has no experience in this area. If FERC is given this authority, it would have to rely on the ERO for much of its expertise. Placing FERC in this position may add to the uncertainty associated with the changes in institutional structure as FERC takes on this new role.

Section 1221. Siting of Interstate Electric Transmission Facilities. The Secretary of Energy would be required to conduct a study of electric transmission congestion every three years. Based on the findings, the Secretary of Energy could designate a geographic area as being congested. Under certain conditions, FERC would be authorized 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 would have an opportunity to present their views and recommendations with respect to the need for and impact of a proposed construction permit. However, there is no requirement for a specific comment period. New FPA Section 216(e) would allow permit holders to petition in U.S. District Court to acquire rights-of-way through the exercise of the right of eminent domain. Any exercise of eminent domain authority would be considered to be takings of private property for which just compensation is due. New FPA Section 216(g) does not state whether property owners would be required to reimburse compensation if the rights-of-way were transferred back to the owner.

An applicant for federal authorization to site transmission facilities on federal lands could request that the Department of Energy be the lead agency to coordinate environmental review and other federal authorization. Once a completed application is submitted, all related environmental reviews would be required to be completed within one year unless another federal law makes that impossible. FPA Section 216(h) would give the Department of Energy (DOE) new authority to prepare environmental documents and appears to give DOE additional decision-making authority for rights-of-way and siting on federal lands. This would appear to give DOE input into the decision process for creating rights-of-way. Review under Section 503 of the Federal Land Policy and Management Act could be streamlined by relying on prior analyses. If a federal agency has denied an authorization required by a transmission or distributions facility, the denial could be appealed by the applicant or relevant state to the Secretary of Energy. The Secretary of Energy would be required to issue a decision within 90 days of the appeal's filing. States could enter into interstate compacts for the purposes of siting transmission facilities and the Secretary of Energy could provide technical assistance. This section would not apply to the Electric Reliability Council of Texas (ERCOT). A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1222. Third-Party Finance. The Western Area Power Administration (WAPA) and the Southwestern Power Administration (SWPA) would be able to either continue to design, develop, construct, operate, maintain, or own transmission facilities within their regions or participate with other entities for the same purposes if: the Secretary of Energy designates the area as a National Interest Electric Transmission Corridor and the project would reduce congestion, or the project is needed to accommodate projected increases in demand for transmission capacity. The project would be required to be consistent with the needs identified by the appropriate Regional Transmission Organization or Independent System Operator. No more than $100 million from third-party financing may be used during fiscal years 2006 through 2015. A similar provision was included in the conference report of H.R. 6 in the 108th Congress. Under current law the enabling statutes for power marketing administrations may restrict third-party financing, construction, operation, and maintenance of transmission facilities.(4)

Section 1223. Transmission System Monitoring. Within six months of enactment, the Secretary of Energy and the Federal Energy Regulatory Commission would be required to complete a study and report to Congress on what would be required to create and implement a transmission monitoring system for the Eastern and Western interconnections. The monitoring system would provide all transmission system owners and Regional Transmission Organizations real-time information on the operating status of all transmission lines. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1224. Advanced Transmission Technologies. FERC would be directed to encourage deployment of advanced transmission technologies. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1225. Electric Transmission and Distribution Programs. The Secretary of Energy acting through the Director of the Office of Electric Transmission and Distribution would be required to implement a program to promote reliability and efficiency of the electric transmission system. Within one year of enactment, the Secretary of Energy would be required to submit to Congress a report detailing the program's five-year plan. Within two years of enactment, the Secretary of Energy would be required to submit to Congress a report detailing the progress of the program. The Secretary of Energy would be directed to establish a research, development, demonstration, and commercial application initiative that would focus on high-temperature superconductivity. For this project, appropriations would be authorized for FY2006 through FY2010. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1226. Advanced Power System Technology Incentive Program. A program would be established to provide incentive payments to owners or operators of advanced power generation systems. Eligible systems would include advanced fuel cells, turbines, or hybrid power systems. For FY2006 through FY2012 an annual appropriation of $10 million would be authorized. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1227. Office of Electric Transmission and Distribution. This would amend Title II of the Department of Energy Organization Act(5) and would establish an Office of Electric Transmission and Distribution. The Director of the office would, in part, coordinate and develop a strategy to improve electric transmission distribution, implement recommendations from the Department of Energy's National Transmission Grid Study, oversee research, development, and demonstration to support federal energy policy related to electricity transmission and distribution, and develop programs for workforce training and power transmission engineering. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Subtitle C -- Transmission Operation Improvements

Section 1231. Open Nondiscriminatory Access. FERC would be authorized to require, by rule or order, unregulated transmitting utilities (power marketing administrations, state entities, and rural electric cooperatives) to charge rates comparable to what they charge themselves and require that the terms and conditions of the sales be comparable to those required of other utilities. Currently under the Federal Power Act (Section 201(f)), federal power marketing administrations, state entities, and rural electric cooperatives are not subject to FERC's ratemaking. In §1231, exemptions are established for utilities selling less than 4 million megawatt-hours of electricity per year, for distribution utilities, and for utilities that own or operate transmission facilities that are not necessary to facilitate a nationwide interconnected transmission 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 if such 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 comply with this section. FERC is not authorized to order an unregulated transmitting utility to join a Regional Transmission Organization or other FERC-approved independent transmission organization. This section is often referred to as "FERC-lite." A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1232. Sense of Congress on Regional Transmission Organizations. This would establish a sense of Congress that utilities should voluntarily become members of regional transmission organizations. A similar provision was included in the conference report of H.R. 6 in the 108th Congress. Currently, Section 202(a) of the Federal Power Act directs FERC to promote and encourage regional districts for the voluntary interconnection and coordination of transmission facilities by public utilities and non-public utilities for the purpose of assuring an abundant supply of electric energy throughout the United States with the greatest possible economy.

Section 1233. Regional Transmission Organization Applications Progress Report. FERC would be required to report to Congress within 120 days of enactment the status of all regional transmission organization applications. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1234. Federal Utility Participation in Regional Transmission Organizations. Federal utilities (power marketing administrations or the Tennessee Valley Authority) would be authorized to participate in regional transmission organizations. A law allowing federal utilities to study formation and operation of a regional transmission organization would be repealed.(6) A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1235. Standard Market Design. FERC's proposed 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 market design proposed rulemaking, could be issued before October 31, 2006, or could take effect before December 31, 2006. This section would retain FERC's ability to issue rules or orders and act on regional transmission organization or independent system operator filings. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

On July 31, 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) on standard market design (SMD).(7) 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 grid boundaries. The proposed rulemaking would create a new tariff under which each transmission owner would be required to turn over operation of its transmission system to an unaffiliated independent transmission provider (ITP). The ITP, which could be an RTO, would provide service to all customers and run energy markets. Under the NOPR, congestion would be managed with locational 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) market design 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, including service 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) have argued that the SMD proposal usurps state authority. On August 15, 2002, state regulators from 22 states and the District of Columbia (Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Montana, North Dakota, Ohio, Oklahoma, Texas, Wisconsin, Delaware, the District of Columbia, New Jersey, New York, Pennsylvania, West Virginia, Connecticut, Maine, Massachusetts, New Hampshire, and Rhode Island) released a statement that "voiced support for FERC's ongoing effort to remedy undue discrimination in the use of the nation's interstate high voltage transmission system in order to create a truly competitive bulk power market." Some industry groups have voiced concerns about the implementation of SMD.

On April 28, 2003, FERC staff issued Wholesale Power Market Platform, a White Paper that intended to clarify FERC's SMD proposal. The White Paper responds to approximately 1,000 sets of formal comments submitted to FERC. In the White Paper, FERC states its intention to eliminate a proposed requirement that utilities join an Independent Transmission Provider. Instead, the final rule would require utilities to join an RTO or ISO. In the NOPR, FERC proposed to assert jurisdiction over the transmission component of bundled retail service. The White Paper reverses this position 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 state authority. FERC responded to this in the White Paper by clarifying that the final rule would not include a requirement for a minimum level of resource adequacy. In addition, the final rule would eliminate the NOPR's requirement that Firm Transmission Rights be auctioned. The White Paper noted that each RTO or ISO would need to have a cost recovery policy outlined in its tariff, but each region may differ on how participant funding would be used. In addition, FERC stated that the final rule would allow for phased implementation to address regional differences.

The report language that accompanied the FY2003 Consolidated Appropriations Resolution asked 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.(8) DOE issued its report to Congress 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 two economic models: General Electric's Multi-Area Production Simulation (MAPS) and DOE's Policy Office Electricity Modeling System (POEMS).

Some of the assumptions that DOE uses are: the annual increase in electricity demand is assumed to be approximately 1.8% per year from 2005 to 2020; most regions are assumed to have reserve margins of 15%; current environmental laws and regulations are assumed to apply; generator efficiency 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 states that 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 to improved operational efficiency at regional seams. In addition, DOE assumes that adopting the SMD would result in some savings that are difficult to quantify but would be a result of several factors including the consolidation of control areas from the currently existing 150, the possible avoidance of capital cost and software expenditures that would have been needed at existing control centers, improved regional planning, and consistency of market design. DOE assigns a 10% savings due to these efficiency improvements. DOE believes that the assumptions used in the models are conservative 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, or about 21 cents per megawatt-hour. The model's range for uncertainties is estimated to be about $100 million. The cost varies significantly by region, ranging from 47 cents per megawatt-hour for GridFlorida to 12 cents per megawatt-hour for PJM.(9) Regions with existing RTOs have zero additional costs. Under the SMD case, the effects of SMD on retail rates are influenced to a significant extent by whether the states in question have cost-of-service regulation or competitive retail choice. DOE found that for some importing regions with cost-based rates, the net result could be increased costs associated with wholesale purchases, which would be passed through to retail customers. For some exporting regions with cost-based rates, additional utility revenues from exports 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 expected to lead to higher market-clearing prices in the short-term markets and somewhat higher consumer prices. However, in areas such as California that are projected to see increased imports, lower wholesale prices and lower prices for consumers are expected. DOE found that the magnitude of the projected changes, both positive and negative, decreases through 2020. Overall, DOE projects the net benefit for all consumers would be about $1 billion per year over the first six years, after factoring 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 retail prices 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 result of SMD.

Section 1236. Native Load Service Obligation. This section would amend the Federal Power Act to clarify that a load-serving entity is entitled to use its transmission facilities or firm transmission rights to serve its existing customers before it is obligated to make its transmission capacity available for other uses. FERC would not be able to change any approved allocation of transmission rights by an RTO or ISO approved prior to January 1, 2005. This section contains language not included in the conference report on H.R. 6 from the 108th Congress to allow for public power utilities to enter into long-term contracts to serve their native load as well as giving them access to the transmission system.

Currently Section 201 of the Federal Power Act gives FERC jurisdiction over "the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate commerce." Section 205 of the Federal Power Act prohibits utilities from granting "undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage" (16 U.S.C. 824). The new language of this section is intended to clarify that reserving transmission for existing customers (native load) is not considered unduly discriminatory.

Section 1237. Study on the Benefits of Economic Dispatch. The Secretary of Energy, in consultation with the states, would be required to issue an annual report to Congress and the states on the current status of economic dispatch. Economic dispatch would be defined as "the operation of generation facilities to produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits of generation and transmission facilities." A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Subtitle D -- Transmission Rate Reform

Section 1241. Transmission Infrastructure Investment. 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 economically efficient electric transmission and generation, provide for a return on equity that would attract new investment in transmission, encourage use of technologies that increased the transfer capacity of existing transmission facilities, and allow for the recovery of all prudently incurred costs that are necessary to comply with mandatory reliability standards. In addition, FERC would be directed to implement incentive rate-making for utilities that join a Regional Transmission Organization or Independent System Operator. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Subtitle E -- Amendments to PURPA

Section 1251. Net Metering and Additional Standards. For states that have not considered implementation and adoption of net metering standards, within three years of enactment, state regulatory authorities would be required to consider whether to implement net metering. Net metering service is defined as service to an electric consumer under which electric energy generated by that electric consumer from an eligible on-site generating facility (e.g., solar or small generator) and delivered to local distribution facilities may be used to offset electric energy provided by the electric utility to the electric consumer during the applicable billing period. Net metering provisions were included in the conference report of H.R. 6 in the 108th Congress.

Section 1252. Smart Metering. For states that have not considered implementation and adoption of a smart metering standard, state regulatory authorities would be required to initiate an investigation within one year of enactment, and issue a decision within two years of enactment, whether to implement a standard for time-based meters and communications devices for all electric utility customers. These devices would allow customers to participate in time-based pricing rate schedules. This section would amend the Public Utility Regulatory Policies Act of 1978(10) (PURPA) and would require the Secretary of Energy to provide consumer education on advanced metering and communications technologies, to identify and address barriers to adoption of demand response programs, and issue a report to Congress that identifies and quantifies the benefits of demand response. The Secretary of Energy would provide technical assistance to regional organizations to identify demand response potential and to develop demand response programs to respond to peak demand or emergency needs. FERC would be directed to issue an annual report, by region, to assess demand response resources. A provision for real-time pricing and time-of-use metering standards was included in the conference report of H.R. 6 in the 108th Congress.

Section 1253. Cogeneration and Small Power Production Purchase and Sale Requirements. Currently, §210 of PURPA requires utilities to purchase power from qualifying facilities and small power producers at a rate based on the utilities' avoided cost.(11) This section would repeal the mandatory purchase requirement under §210 of PURPA for new contracts if FERC finds that a competitive electricity market exists and a qualifying facility has access to independently administered, auction-based day-ahead and real-time wholesale markets and long-term wholesale markets. Qualifying facilities would also need to have access to transmission and interconnection services provided by a FERC-approved regional transmission entity that provides non-discriminatory treatment for all customers. Ownership limitations under PURPA would be repealed. Repeal of the mandatory purchase requirement was included in the conference report of H.R. 6 in the 108th Congress.

The oil embargoes of the 1970s created concerns about the security of the nation's electricity supply and led to enactment of the Public Utility Regulatory Policies Act of 1978. For the first time, utilities were required to purchase power from outside sources. The purchase price was set at the utilities' "avoided cost," the cost they would have incurred to generate the additional power themselves, as determined by utility regulators. PURPA was established in part to augment electric utility generation with more efficiently produced electricity and to provide equitable rates to electric consumers.

In addition to PURPA, the Fuel Use Act of 1978 (FUA) helped qualifying facilities (QFs) become established.(12) 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 as new generating technology, such as combined-cycle plants that use hot gases from combustion turbines to generate additional power. These technologies lowered the financial threshold for entrance into the electricity generation business as well as shortened the lead time for constructing new plants. FUA was repealed in 1987, but by this time QFs and small power producers had gained a portion of the total electricity supply.

This influx of QF power challenged the cost-based rates that previously guided wholesale transactions. Before implementation of PURPA, FERC approved wholesale interstate electricity transactions based on the seller's costs to generate and transmit the power. Since nonutility generators typically do not have enough market power to influence the rates they charge, FERC began approving certain wholesale transactions whose rates were a result of a competitive bidding process. These rates are called market-based rates.

This first incremental change to traditional electricity regulation started a movement toward a market-oriented approach to electricity supply. Following the enactment of PURPA, two basic issues stimulated calls for further change: whether to encourage nonutility generation and whether to permit utilities to diversify into non-regulated activities.

The Energy Policy Act of 1992 (EPACT) removed several regulatory barriers for entry into electricity generation to increase competition of electricity supply.(13) However, EPACT does not permit FERC to mandate that utilities transmit exempt wholesale generator (EWG) power to retail consumers (commonly called "retail wheeling" or "retail competition"), an activity that remains under the jurisdiction of state public utility commissions. PURPA began to shift more regulatory responsibilities to the federal government, and EPACT continued that shift away from the states by creating new options for utilities and regulators to meet electricity demand.

Proponents of PURPA repeal -- primarily investor-owned utilities (IOUs) located in the Northeast and in California -- argue that their state regulators' "misguided" implementation of PURPA in the early 1980s has forced them to pay contractually high prices for power they do not need. They argue that, given the current environment for cost-conscious competition, PURPA is outdated. The PURPA Reform Group, which promotes IOU interests, strongly supports repeal of §210 of PURPA contending that the current law's mandatory purchase obligation is anti-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 energy industry, 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 the same time, helped promote wider use of cleaner, alternative fuels to generate electricity. Since the electric generating sector is not yet fully competitive, they argue, repeal of PURPA would decrease competition and impede the development of the renewable energy industry. Additionally, opponents of PURPA repeal argue that it would result in less competition and greater utility monopoly control over the electric industry. Some state regulators have expressed concern that §210 repeal would prevent them from deciding matters currently under their jurisdiction.

Section 1254. Interconnection. Each state regulatory authority and each nonregulated utility shall consider establishing an interconnection standard for on-site generating facilities wishing to be connected to the local distribution facilities, if it has not already done so. Consideration of the standard must be commenced not later than one year after enactment and completed not later than two years after the date of enactment.

Subtitle F -- Repeal of PUHCA

Section 1261. Short Title. This subtitle may be cited as the "Public Utility Holding Company Act of 2005."

Section 1262. Definitions. This section would provide 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 Utility Holding Company Act of 1935. The Public Utility Holding Company Act of 1935 (PUHCA) would be repealed. The provision to repeal PUHCA was included in the conference report of H.R. 6 in the 108th Congress.

In general, the Public Utility Holding Company Act of 1935 currently sets forth the structure of holding companies by prohibiting all holding companies that are more than twice removed from the operating subsidiaries. It also federally regulates holding companies of investor-owned utilities, and provides for Securities and Exchange Commission (SEC) regulation of mergers and diversification proposals. Registered holding companies of subsidiaries are required to have SEC approval prior to issuing securities; all loans and intercompany financial transactions are regulated by the SEC. A holding company can be exempt from PUHCA if its business operations and those of its subsidiaries occur within one state or within contiguous states.

Historically, electricity service was defined as a natural monopoly, meaning that the industry has (1) an inherent tendency toward declining long-term costs, (2) high threshold investment, and (3) technological conditions that limit the number of potential entrants. In addition, many regulators have considered unified control of generation, transmission, and distribution as the most efficient means of providing service. As a result, most people (about 75%) are currently served by a vertically integrated, investor-owned utility.

As the electric utility industry has evolved, however, there has been a growing belief that the historic classification of electric utilities as natural monopolies has been overtaken by events and that market forces can and should replace some of the traditional economic regulatory structure. For example, the existence of utilities that do not own all of their generating facilities, primarily cooperatives and publicly owned utilities, has provided evidence that vertical integration has not been necessary for providing efficient electric service. Moreover, recent changes in electric utility regulation and improved technologies have allowed additional generating capacity to be provided by independent firms rather than utilities.

The Public Utility Holding Company Act and the Federal Power Act (FPA) of 1935 (Title I and Title II of the Public Utility Act) established a regime of regulating electric utilities that gave specific and separate powers to the states and the federal government. A regulatory bargain was made between the government and utilities. In exchange for an exclusive franchise service territory, utilities must provide electricity to all users at reasonable, regulated rates. State regulatory commissions address intrastate utility activities, including wholesale and retail rate-making. State authority currently tends to be as broad and as varied as the states are diverse. At the least, a state public utility commission will have authority over retail rates, and often over investment and debt. At the other end of the spectrum, the state regulatory body will oversee many facets of utility operation. Despite this diversity, the essential mission of the state regulator in states that have not restructured is the establishment of retail electric prices. This is accomplished through an adversarial hearing process. The central issues in such cases are the total amount of money the utility will be permitted to collect and how the burden of the revenue requirement will be distributed among the various customer classes (residential, commercial, and industrial).

Under the FPA, federal economic regulation addresses wholesale transactions and rates for electric power flowing in interstate commerce. Federal regulation followed state regulation and is premised on the need to fill the regulatory vacuum resulting from the constitutional inability of states to regulate interstate commerce. In this bifurcation of regulatory jurisdiction, federal regulation is limited and conceived to supplement state regulation. FERC has the principal functions at the federal level for the economic regulation of the electric utility industry, including financial transactions, wholesale rate regulation, transactions involving transmission of unbundled retail electricity, interconnection and wheeling of wholesale electricity, and ensuring adequate and reliable service. In addition, to prevent a recurrence of the abusive practices of the 1920s (e.g., cross-subsidization, self-dealing, pyramiding, etc.), SEC regulates utilities' corporate structure and business ventures under PUHCA.

The electric utility industry has been in the process of transformation. During the past two decades, there has been a major change in direction concerning generation. First, improved technologies have reduced the cost of generating electricity as well as the size of generating facilities. Prior preference for large-scale -- often nuclear or coal-fired -- powerplants has been supplanted by a preference for small-scale production facilities that can be brought on line more quickly and cheaply, with fewer regulatory impediments. Second, this has lowered the entry barrier to electricity generation and permitted non-utility entities to build profitable facilities.

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

For a number of years there has been significant bipartisan congressional support for repealing much of PUHCA. Since the 1980s, the Securities and Exchange Commission has testified before Congress that many provisions of PUHCA are no longer relevant and other provisions are redundant with state and other federal regulations.(14) However, as a result of Enron's dealings and collapse, some in Congress have taken a somewhat different view toward significantly amending or repealing PUHCA.(15) Even though Enron had claimed exemption from PUHCA, on February 6, 2003, Securities and Exchange Commission Chief Administrative Law Judge Brenda P. Murray denied Enron's PUHCA exemption applications of April 12, 2000, and February 28, 2002, amended on May 31, 2002.(16) In the case of Enron, PUHCA, and many other laws, did not deter or prevent fraudulent filing of information with the SEC.

State regulators have expressed concerns that increased diversification could lead to abuses, including cross-subsidization: a regulated company subsidizing an unregulated affiliate. Cross-subsidization was a major argument against the creation of exempt wholesale generators (EWGs) and has reemerged as an argument against further PUHCA change. In the case of electric and gas companies, non-utility ventures that are undertaken as a result of diversification may benefit from the regulated utilities' allowed rate of return. Moneymaking non-utility enterprises would contribute to the overall financial health of a holding company. However, unsuccessful ventures could harm the entire holding company, including utility subsidiaries. In this situation, opponents fear that utilities would not be penalized for failure in terms of reduced access to new capital, because they could increase retail rates.

Several consumer and environmental public interest groups, as well as state legislators, have expressed concerns about PUHCA repeal. PUHCA repeal, such groups argue, could only exacerbate market power abuses in what they see as a monopolistic industry where true competition does not yet exist.

Section 1264. Federal Access to Books and Records. Federal access to books and records of holding companies and their affiliates would be provided. Affiliate companies would have to make available to FERC books and records of affiliate transactions. Federal officials would have to maintain confidentiality of such books and records. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Currently, registered holding companies and subsidiary companies are required to preserve accounts, cost-accounting procedures, correspondence, memoranda, papers, and books that the SEC deems necessary or appropriate in the public interest or for the protection of investors and consumers.(17)

Section 1265. State Access to Books and Records. A jurisdictional state commission would be able to make a reasonably detailed written request 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 be a holding company solely by reason of ownership of one or more qualifying facilities. Response to such a request would be mandatory. Compliance with this section would be enforceable in U.S. District Court. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Currently under the Federal Power Act, state commissions may examine the books, accounts, memoranda, contracts, and records of a jurisdictional electric utility company, an exempt wholesale generator that sells to such electric utility, and an electric utility company or holding company that is an associate company or affiliate of an exempt wholesale generator. In its order the state commissions currently are not required to specify which books, account, memoranda, contracts, and records it is requesting.(18)

Section 1266. Exemption Authority. FERC would be directed to promulgate rules to exempt qualifying facilities, exempt wholesale generators (EWGs), and foreign utilities, from the federal access to books and records provision (Section 1264). A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1267. Affiliate Transactions. FERC would retain the authority to prevent cross-subsidization and to assure that jurisdictional rates are just and reasonable. FERC and state commissions would retain jurisdiction to determine whether associate company activities could be recovered in rates. A similar provision was included in the conference report of H.R. 6 in the 108th Congress. Currently, the Federal Power Act requires that jurisdictional rates are just and reasonable and prohibits cross-subsidization.(19)

Section 1268. Applicability. Except as specifically noted, this subtitle would not apply to the U.S. government, a state or any political subdivision of the state, or foreign governmental authority operating outside the United States. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1269. Effect on Other Regulations. FERC or state commissions would not be precluded from exercising their jurisdiction under otherwise applicable laws to protect utility customers. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1270. Enforcement. FERC would have authority to enforce these provisions under Sections 306-317 of the Federal Power Act. Currently, the Securities and Exchange Commission has authority to investigate and enforce provisions of the Public Utility Holding Company Act of 1935.(20) A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1271. Savings Provisions. Persons would be able to continue to engage in legal activities in which they have been engaged or are authorized to engage in on the effective date of this act. This subtitle would not limit the authority of FERC under the Federal Power Act or the Natural Gas Act. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1272. Implementation. Not later than 12 months after enactment, FERC would be required to promulgate regulations necessary to implement this subtitle and submit to Congress recommendations for technical or conforming amendments to federal law that would be necessary to carry out this subtitle. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1273. Transfer of Resources. The Securities and 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. Currently, the Securities and Exchange Commission maintains books and records and regulates security transactions.(21) A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

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

Section 1275. Service Allocation. FERC would be required to review and authorize cost allocations for non-power goods or administrative or management services provided by an associate company that was organized specifically for the purpose of providing such goods or services. This section would not preclude FERC or state commissions from exercising their jurisdiction under other applicable laws with respect to review or authorization of any costs. FERC would be required to issue rules within six months of enactment to exempt from the section any company and holding company system if operations are confined substantially to a single state. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1276. Authorization of Appropriations. Necessary funds to carry out this subtitle would be authorized to be appropriated. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1277. Conforming Amendments to the Federal Power Act. The Federal Power Act would be amended to reflect the changes to the Public Utility Holding Company Act of 1935.(22)

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 electronic system that provides information about the availability and price of wholesale electric energy and transmission services. FERC would exempt from disclosure any information that, if disclosed, could be detrimental to the operation of the effective market or jeopardize system security. FERC would be required to assure that consumers in competitive markets are protected from adverse effects of potential collusion or other anti-competitive behaviors that could occur as a result of untimely public disclosure of transaction-specific information. This section would not affect the exclusive jurisdiction of the Commodity Futures Trading Commission with respect to accounts, agreement, contracts, or transactions in commodities under the Commodity Exchange Act. FERC would not be allowed to compete with, or displace, any price publisher or regulate price publishers or impose any requirements on the publication of information. Creation of market transparency rules was included in the conference report of H.R. 6 in the 108th Congress.

Section 1282. Market Manipulation. It would be unlawful to willfully and knowingly file a false report on any information relating to the price of electricity sold at wholesale or the availability of transmission capacity, with the intent to fraudulently affect 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-trip electricity trading. Round-trip trading is defined to include contracts in which purchase and sale transactions have no specific financial gain or loss and are entered into with the intent to distort reported revenues, trading volumes, or prices. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Currently, mail fraud laws in part apply to use of the mail for the purpose of executing, or attempting to execute, a scheme or artifice to defraud or for obtaining money or property by false or fraudulent pretenses, representations, or promises.(23) Wire fraud statutes cover use of wire, radio, or television communication in interstate or foreign commerce to transmit or to cause to be transmitted any writings, signs, signals, pictures, or sounds for the purpose of executing a scheme or artifice to defraud or for obtaining money or property by means of false or fraudulent pretenses, representations, or promises.(24)

Section 1283. Enforcement. The Federal Power Act would be amended to allow electric utilities to file complaints with FERC and to allow complaints to be filed against transmitting utilities. Criminal and civil penalties under the Federal Power Act would be increased. Criminal penalties would not exceed $1 million and/or five years imprisonment. In addition, a fine of $25,000 could be imposed. A civil penalty not exceeding $1 million per day per violation could be assessed for violations of Sections 211, 212, 213, or 214 of the Federal Power Act. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Currently, criminal penalties may not exceed $5,000 and/or two years' imprisonment. An additional fine of $500 can be imposed. A civil penalty not 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. Section 206(b) of the Federal Power Act would be amended to allow the effective date for refunds to begin at 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 to state its reasons for not acting in the provided time-frame for the decision. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Currently, refunds for rates that FERC finds to be unjust, unreasonable, unduly discriminatory, or preferential begin a minimum of 60 days after a complaint is filed.(25)

Section 1285. Refund Authority. Any entity that is not a public utility (including an entity referred to under § 201(f) of the Federal Power Act) and enters into a short-term sale of electricity would be subject to the FERC refund authority. A short-term sale would include any agreement to the sale of electric energy at wholesale that is for a period of 31 days or less. This section would not apply to electric cooperatives, or any entity that sells less than 8 million megawatt hours of electricity per year. FERC would have refund authority over voluntary short-term sales of electricity by Bonneville Power Administration if the rates charged are unjust and unreasonable. FERC would have authority over all power marketing administrations and the Tennessee Valley Authority to order refunds to achieve just and reasonable rates. Currently, Section 201(f) of the Federal Power Act exempts government entities from FERC rate regulation.(26) Refund authority was provided for in the conference report of H.R. 6 in the 108th Congress.

Section 1286. Sanctity of Contract. Upon determining that failure to take action would be contrary to protection of the public interest, FERC would 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 of review other than the public interest standard. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1287. Consumer Privacy and Unfair Trade Practices. The Federal Trade Commission would be authorized to issue rules to prohibit slamming and cramming. Slamming occurs when an electric utility switches a customer's electric provider without the consumer's knowledge. Cramming occurs when an electric utility adds additional services and charges to a customer's account without permission of the customer. If the Federal Trade Commission determines that a state's regulations provide equivalent or greater protection, then the state regulations would apply in lieu of regulations issued by the Federal Trade Commission. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Subtitle H -- Merger Reform

Section 1291. Merger Review Reform and Accountability. Within 180 days of enactment, the Secretary of Energy would be required to transmit to Congress a study on whether FERC's merger review authority is duplicative with other agencies' authority and that would include recommendations for eliminating any unnecessary duplication. FERC would be required to issue an annual report to Congress describing all conditions placed on mergers under Section 203(b) of the Federal Power Act. FERC would also be required to include in its report whether such a condition could have been imposed under any other provision of the Federal Power Act. A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

Section 1292. Electric Utility Mergers. The Federal Power Act would be amended to give FERC review authority for transfer of assets valued in excess of $10 million. FERC would be required to give state public utility commissions and governors reasonable notice in writing. FERC would be required to establish rules to comply with this section. Currently, under Section 203(a) of the Federal Power Act, FERC review of asset transfers applies to transactions valued at $50,000 or more.(27) A similar provision was included in the conference report of H.R. 6 in the 108th Congress.

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. The Federal Power Act would be amended to conform with this title.

Subtitle K -- Economic Dispatch

Section 1298. Economic Dispatch. FERC is directed to convene regional boards to study "security constrained economic dispatch." A member of FERC will chair each regional joint board that is to be composed of a representative from each state. Within one year of enactment, FERC is required to submit a report to Congress on the recommendations of the joint regional boards. This section does not define "security constrained economic dispatch" but it generally means a dispatch system that ensures that all normal and contingency limits of the system are simultaneously met under a base case with one contingency (i.e, the loss of a critical network element, N-1 security analysis).

Other Electric Provisions

Section 504. Four Corners Transmission Line Project. The Dine Power Authority, an enterprise of the Navajo nation, would be eligible to receive grants and other assistance to develop a transmission line from the Four Corners Area to southern Nevada, including related generation facilities.

Section 1441. Continuation of Transmission Security Order. On August 28, 2003, the Secretary of Energy issued Order No. 202-03-2, allowing the Cross Sound Cable between Connecticut and Long Island to begin transmitting electric power. This provision would require the order to remain in effect unless rescinded by federal statute.

In 2002, a 24-mile 330-megawatt (MW) transmission cable was installed beneath the seabed of Long Island Sound between Connecticut and Long Island. Shortly after the line was installed, it was determined that in several places, the cable was not buried to depths specified in permits issued by the U.S. Army Corps of Engineers (Corps) and the Connecticut Department of Environmental Protection (CDEP). While the Corps determined that operation of the cable would not pose environmental or navigational harm and did not object to the operation of the transmission line, the CDEP objected to the operation of the line based on procedural grounds. CDEP's position was that operation of the cable would violate the permit, unless the cable was installed to the permitted depth requirements. CDEP denied a request to modify the permit.

On June 12, 2003, Cross-Sound, the owners of the cable, filed a new permit application with the CDEP. However, on June 26, 2003, Connecticut Governor John Rowland signed into law a bill extending a prohibition on considering permits or applications related to certain infrastructure crossings of the sound. On August 14, 2003, the Northeast experienced a widespread electric blackout. In response, Secretary of Energy Spencer Abraham issued an emergency order to energize the cross-sound cable. This order was rescinded on May 7, 2004. Long Island Power Authority (LIPA) and Cross-Sound filed a petition with FERC to have the cable re-energized by July 1, 2004. At a June 17, 2004, FERC meeting, Chairman Pat Wood asked the parties to negotiate a settlement within seven days, after which FERC was ready to issue an order. On June 25, 2004, the parties came to an agreement and the cross-sound cable was re-energized.

Section 1611. Reliability and Consumer Protection Assessment. Within five years of enactment, and every five years thereafter, FERC would be required to assess the effects of electric cooperative and government-owned utilities' exemption from FERC ratemaking regulation under Section 201(f) of the Federal Power Act. If FERC found that the exemption resulted in adverse effects on consumers or electric reliability, FERC would be required to make recommendations to Congress.

Footnotes

1. (back) P.L. 104-4, 109 Stat. 48 et seq.

2. (back) According to NERC, Canadian utilities contribute approximately 12.5% to the total NERC budget, leaving U.S. utilities contributing approximately $45,500,000 to the 2005 NERC budget.

3. (back) Congressional Budget Office. Letter to Honorable David Dreier. April 19, 2005. The safe harbor provision would potentially provide a liability shield for all those who might be sued for supplying a defective renewable fuel or methyl tertiary butyl ether (MTBE).

4. (back) 16 U.S.C. 460 (SWPA) and 43 U.S.C. 485 (WAPA).

5. (back) 42 U.S.C. 7131 et seq.

6. (back) 16 U.S.C. 824n

7. (back) Docket No. RM01-12-000

8. (back) Conference report H.Rept. 108-10 to accompany H.J.Res. 2.

9. (back) The PJM control area includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

10. (back) P.L. 95-617.

11. (back) 16 U.S.C. 824a-3.

12. (back) P.L. 95-620.

13. (back) P.L. 102-486.

14. (back) Testimony is available at http://www.sec.gov/news/testimony/021302tsich.htm.

15. (back) See http://www.house.gov/commerce_democrats/press/107ltr129.shtml.

16. (back) Initial Decision Release No. 222 (File No. 3-10909) can be found at http://www.sec.gov/litigation/aljdec/id222bpm.htm.

17. (back) 15 U.S.C. 79o.

18. (back) 16 U.S.C. 824.

19. (back) 16 U.S.C. 791a et seq.

20. (back) 15 U.S.C. 79r.

21. (back) 15 U.S.C. 79 et seq.

22. (back) Current jurisdiction of the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935 is referenced by 16 U.S.C. 825q; 16 U.S.C. 824(g)(5), and 16 U.S.C. 824m.

23. (back) 18 U.S.C. 1341.

24. (back) 18 U.S.C. 1343.

25. (back) 16 U.S.C. 824e(b).

26. (back) 16 U.S.C. 824

27. (back) 16 U.S.C. 824b.

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