Summary of Electricity Provisions in the Conference Report on H.R. 6
CRS Report for Congress
Summary of Electricity Provisions in the
Conference Report on H.R. 6, 108 Congress
December 17, 2003
Specialist in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Summary of Electricity Provisions in the Conference
Report on H.R. 6, 108th Congress
Conferees on the House and Senate energy bills (H.R. 6) met on November 17,
2003 and approved a conference report. On November 18, 2003, the House approved
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 in the Senate failed by a vote of 57-40.
This report describes Title XII of the conference report on H.R. 6 which deals
with electric power issues. In part, this Title 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.
The Standard Market Design notice of proposed rulemaking would be remanded
to the Federal Energy Regulatory Commission. The Conference report would clarify
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of 1935 (PUHCA) would be repealed.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 would 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 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. 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 be updated as events warrant.
In troduction ......................................................1
Title XII- Electricity................................................1
Subtitle A- Reliability Standards..................................1
Subtitle B-Transmission Infrastructure Modernization.................2
Subtitle C -Transmission Operation Improvements....................4
Subtitle D - Transmission Rate Reform............................8
Subtitle E - Amendments to PURPA..............................12
Subtitle F- Repeal of PUHCA...................................14
Consumer Protection ......................................19
Subtitle H - Merger Reform....................................21
Subtitle I - Definitions........................................22
Electricity Provisions of the Conference
Report on H.R. 6, 108 Congress
Conferees on the House and Senate energy bills (H.R. 6) met on November 17,
the House approved 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, methyl tertiary butyl ether (MTBE), energy efficiency,
hydroelectricity, renewable energy, oil and gas, coal, Indian energy, nuclear power,
research and development, and energy tax incentives. This report summarizes the
electricity title of H.R. 6, Title XII. The policy context and/or the current 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
Title XII — Electricity
Section 1201. Short title. This title may be cited as 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 rules within 180 days
of enactment to create a FERC-certified electric reliability organization (ERO). The
ERO would develop and enforce reliability standards for the bulk-power system. 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.
Current Law. The North American Electric Reliability Council (NERC) has
responsibility for reliability of the bulk power system. NERC has established
reliability guidelines but has no enforcement authority. The Federal Power Act gives
FERC jurisdiction over unbundled transmission and was intended to regulate
wholesale rates; however, no authority was provided to regulate reliability.
Policy Context. The proposed legislation is intended to provide federal
jurisdiction over activities that are required to support reliability of the United States
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 House-passed and Senate-passed
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. Those opposed to giving FERC
jurisdiction over bulk power system reliability contend that FERC has no experience
in this area. If FERC is given this authority, it would have to rely on NERC for much
of its expertise. Placing FERC in this position may add to the uncertainty associated
with the changes in institutional structure as FERC takes on this new role.
Subtitle B — Transmission Infrastructure Modernization
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 will be required to reimburse
compensation if the rights-of-way are 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 1 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 House-passed H.R. 6.
Current Law. Regulatory jurisdiction over the electricity industry is divided
between federal and state authorities, with individual states overseeing activities
considered intrastate and with FERC regulating the interstate aspects of electricity1
and natural gas commerce. Under the Federal Power Act, siting of transmission
lines is the responsibility of the states.
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 region 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 need 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 2004 through
Current Law. Enabling statutes for power marketing administrations may
restrict third-party financing, construction, operation, and maintenance of
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
1 See Fed. Power Comm’n v. Southern Cal. Edison Co., 376 U.S. 205, 216 (1964).
2 16 U.S.C. 460 (SWPA) and 43 U.S.C. 485 (WAPA).
information on the operating status of all transmission lines. This section was not
included in either the House- or Senate-passed H.R. 6.
Section 1224. Advanced Transmission Technologies. FERC would be
directed to encourage deployment of advanced transmission technologies. This
section was not included in either the House- or Senate-passed H.R. 6.
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 FY2004 through FY2008. In part, a similar provision was included
in the House-passed H.R. 6.
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. A total of $140 million would be
authorized for 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 for FY2004 through FY2010.
Section 1227. Office of Electric Transmission and Distribution. This would
amend Title II of the Department of Energy Organization Act3 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. This
section was not 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 (power marketing
administrations, state entities, and rural electric cooperatives) to charge rates
comparable to what they charge themselves and would require that the terms and
conditions of the sales are comparable to those required of other utilities.
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
3 42 U.S.C. 7131 et seq.
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.” Provisions on open
access were included in both the House- and Senate-passed H.R. 6, but the
conference language differed. 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 (Section 201(f)), federal power
marketing administrations, state entities, and rural electric cooperatives are not
subject to FERC’s ratemaking.
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 House- and Senate-passed H.R. 6.
Current Law. 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 U.S.
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. Similar language
was included in the House-passed H.R. 6.
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.4 A similar provision was
included in the House-passed H.R. 6.
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
4 16 U.S.C. 824n
independent system operator filings. H.R. 6, as passed by the House and Senate, did
not include a similar provision.
Policy Context. On July 31, 2002, FERC issued a Notice of Proposed5
Rulemaking (NOPR) on standard market design (SMD). 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) are reportedly planning to fight FERC’s proposed
changes on the grounds that FERC 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
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
5 Docket No. RM01-12-000
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.6 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. 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
6 Conference report H.Rept. 108-10 to accompany H.J.Res. 2.
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 6 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 September 15, 2003. A similar provision was
included in the House-passed H.R. 6.
Current Law. 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). 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.” This section was included in the House-
passed H.R. 6.
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. The House-passed H.R. 6 did not include reliability
in the proposed FERC rule.
Section 1242. Voluntary Transmission Pricing Plans. This would amend the
Federal Power Act to allow any transmission provider including a Regional
Transmission Organization or Independent System Operator to determine how the
cost of new transmission facilities would be allocated. The cost of all transmission
expansion, except what is required for reliability purposes, would be assigned so that
those who benefit from the addition of the transmission would pay an appropriate
share of the costs. This is referred to as participant funding. This provision would
protect native load customers from paying for transmission upgrades needed for new
generator interconnection if the new generation is not required by the native load (the
demand of the utility’s existing customers.) Participant funding was included in the
House-passed H.R. 6.
Policy Context. FERC regulates all transmission including unbundled retail
transactions.7 Under the Federal Power Act (FPA), FERC is required to set “just and
reasonable” rates for wholesale transactions.8 FERC has traditionally used an
embedded cost method for determining 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 way to reflect the regulatory
uncertainty in the industry and encourage transmission investment.
The Energy Policy Act of 1992 (EPAct) created a new category of wholesale
electric generators called Exempt Wholesale Generators (EWGs) that are not
considered utilities.9 EWGs, also referred to as merchant generators, were intended
to create a competitive wholesale electric generation sector. In addition, EPAct
provided a means for these non-utility generators to have access to the transmission
system (the transmission system is owned by incumbent utilities). As a result of
EPAct, FERC issued a policy statement on transmission pricing policy. It stated that:
Greater pricing flexibility is appropriate in light of the significant
competitive changes occurring in wholesale generation markets, and in
7 On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New York et al.
v. Federal Energy Regulatory Commission) that challenged FERC’s authority to regulate
transmission for retail sales if a utility unbundles transmission from other retail charges. In
states that have opened their generation market to competition, unbundling occurs when
customers are charged separately for generation, transmission, and distribution. Nine states,
led by New York, filed suit arguing that the Federal Power Act gives FERC jurisdiction over
wholesale sales and interstate transmission and leaves all retail issues up to the state utility
commissions. Enron argued that FERC clearly has jurisdiction over all transmission and
FERC is obligated to prevent transmission owners from discriminating against those wishing
to use the transmission lines. On March 4, 2002, the U.S. Supreme Court ruled in favor of
FERC and held that FERC has jurisdiction over transmission including unbundled retail
transactions. Ruling available at:
[http://a257.g.akamaitech. n e t / 7 / 257/2422/04mar20021030/ www.supr emecour t u s.go v/ opi
8 16 U.S.C. 824(d)(a).
9 P.L. 102-486. Exempt Wholesale Generators may sell electricity only at wholesale.
However, unlike utility generators that are limited by the Public Utility Holding Company
Act of 1935 (PUHCA) to operate within one state, EWGs may be located anywhere,
including foreign countries.
light of our expanded wheeling authority under the Energy Policy Act of
1992 (EPAct)[footnote omitted]. These recent events underscore the
importance of ensuring that our transmission pricing policies promote
economic efficiency, fairly compensate utilities for providing transmission
services, reflect a reasonable allocation of transmission costs among
transmission users, and maintain the reliability of the transmission grid.
The Commission also recognizes that advances in computer modeling
techniques have made possible certain transmission pricing methods that
once would have been impractical.10
In May 1994, FERC established general guidelines for comparable access to the
transmission system.11 By July 9, 1996, all utilities that own or control transmission
had filed a single open access tariff with FERC that provides transmission service to
eligible wholesale customers at comparable terms to the service that the utilities
provide themselves. Some merchant generators asserted that they continued to be
discriminated against by incumbent transmission utilities and were denied access to
the system. In April 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 larger and more frequent bulk power transfers across a transmission system
designed for local intrastate service. However, investment in infrastructure has not
kept up with increases in the bulk power transfers and electricity demand. Electricity
demand has been growing at 2% to 3% per year, but additions to the transmission
system have been growing by 0.7% per year. As a result, during some of the year
transmission is congested in several regions of U.S. including California, Minnesota
to Wisconsin, New York, and the Ohio Valley.
Some transmission-owning utilities argue that the current pricing mechanism
for transmission discourages investment. Currently, transmission owners are
compensated for use of their lines based on a contract path for the movement of
electricity, generally the shortest path between the generator and its customer.
However, electricity rarely follows a contract path and instead follows the path based
on least impedance.12 Transmission lines often carry electricity that has been
contracted to move on a different path. Therefore, some transmission owners are not
being compensated for use of their lines and lack the incentive to increase capacity.
Under Order 2000, FERC stated its interest in incentive ratemaking and in
particular performance-based ratemaking. Those in favor of incentive ratemaking
argue that incentives are needed: 1) to encourage participation in regional
transmission organizations; 2) because participation in a regional transmission
10 Inquiry Concerning the Commission’s Pricing Policy for Transmission Services Provided
by Public Utilities Under the Federal Power Act; policy statement, Oct. 26, 1994, Docket
No. RM 93- 19-000, 18 CFR 2, 59 FR 55031.
12 Impedance is a measure of the resistive and reactive attributes of a component in an
organization is perceived to increase financial risk; and 3) to facilitate efficient
expansion of the transmission system.13
Currently FERC uses a “license plate” rate for transmission, a single rate based
on customer location. As FERC is encouraging formation of large regional
transmission organizations, FERC is moving toward a uniform access charge,
sometimes called postage stamp rates. With a postage stamp rate, users pay one
charge for moving electricity anywhere within the regional transmission organization.
Postage stamp rates eliminate so-called rate pancaking, or a series of
accumulated transmission charges as the electricity passes through adjacent
transmission systems, and increases the pool of available generation. On the other
hand, by moving to postage stamp rates, customers in low-cost transmission areas
may see a rate increase, and high-cost transmission providers in the same area may
not recover embedded costs as costs are determined on a regional basis.
FERC-approved tariffs do not necessarily increase with the addition of new
transmission capacity. FERC could approve a new higher transmission tariff, thus
increasing all users’ costs to move electricity on the transmission system. However,
the revenue requirement of the transmission utility may be met with current tariffs.
Local retail customers are charged for transmission based on an individual
customer’s usage of electricity. Therefore, depending on a transmission
interconnection’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 the power to a customer in another state or region (sometimes referred to as
wheeling), the wholesale customer will pay a FERC-approved transmission tariff that
is the same as for wholesale customers whose 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 of the
region are being penalized by wholesale generators that do wheel power. They argue
that tariffs reflect capital costs for which they do not receive a benefit. Opponents
of the amendment argue that transmission interconnection should be offered at
comparable rates and service levels to all generators in order to create a competitive
generating market. Further, opponents of participant funding argue that requiring
merchant generators to pay up-front for all interconnection could inhibit wholesale
competition and favor incumbent generators. Proponents argue, however, that
merchant generators should locate where it is economic to interconnect to the
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 and is a departure from all previous FERC
ratemaking. However, FERC’s Standard Market Design Notice of Proposed
Rulemaking would allow for participant funding.
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 House- and Senate-passed H.R. 6.
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 Act14
of 1978 (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 House- and
Senate-passed H.R. 6.
Section 1253. Cogeneration and Small Power Production Purchase and Sale
Requirements. 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 House- and Senate-passed H.R. 6.
Current Law. Section 210 of PURPA requires utilities to purchase power
from qualifying facilities and small power producers at a rate based on the utilities’
14 P.L. 95-617.
15 16 U.S.C. 824a-3.
Policy Context. 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 qualifying16
facilities (QFs) become established. 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
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 reform: whether
to encourage nonutility generation and whether to permit utilities to diversify into
EPACT removed several regulatory barriers for entry into electricity generation
to increase competition of electricity supply. However, EPACT does not permit
FERC to mandate that utilities transmit EWG power to retail consumers (commonly
called “retail wheeling” or “retail competition”), an activity that remains under the
jurisdiction of state public utility commissions. PURPA began to shift more
regulatory responsibilities to the federal government, and EPACT continued that shift
away from the states by creating new options for utilities and regulators to meet
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
16 P.L. 95-620.
current environment for cost-conscious competition, PURPA is outdated. The
PURPA Reform Group, which promotes IOU interests, strongly supports repeal of
§210 of PURPA by contending that the current law’s mandatory purchase obligation
was 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.
Subtitle F— Repeal of PUHCA
Section 1261. Short Title. This subtitle may be cited as the “Public Utility
Holding Company Act of 2003.”
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
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 both the House- and Senate-passed H.R.
Current Law. In general, the Public Utility Holding Company Act of 1935
regulates the structure of holding companies by prohibiting all holding companies
that are more than twice removed from the operating subsidiaries, 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
Policy Context. 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
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
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
One argument for additional PUHCA reform 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.17 However, as a result of Enron’s collapse, some in
Congress have taken a somewhat different view toward significantly amending or
repealing PUHCA.18 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,
PUHCA, and many other laws, did not deter or prevent fraudulent filing of
information with the SEC.
State regulators have expressed concerns that increased diversification could
lead to abuses, including cross-subsidization: a regulated company subsidizing an
unregulated affiliate. Cross-subsidization was a major argument against the creation
of EWGs and has reemerged as an argument against further PUHCA reform. In the
case of electric and gas companies, non-utility ventures that are undertaken as a result
of diversification may benefit from the regulated utilities’ allowed rate of return.
Moneymaking non-utility enterprises would contribute to the overall financial health
of a holding company. However, unsuccessful ventures could harm the entire
holding company, including utility subsidiaries. In this situation, utilities would not
be penalized for failure in terms of reduced access to new capital, because they could
increase retail rates.
17 Testimony is available at [http://www.sec.gov/news/testimony/021302tsich.htm].
18 See [http://www.house.gov/commerce_democrats/press/107ltr129.htm].
19 Initial Decision Release No. 222 (File No. 3-10909) can be found at:
[http://www.sec.go v/litigation/alj dec/id222bpm.htm] .
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 House-and Senate-passed
Current Law. 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.20
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 House -and Senate-passed H.R. 6.
Current Law. 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.21
Section 1266. Exemption Authority. FERC would 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). A
similar provision was included in the House- and Senate-passed H.R. 6.
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 House- and Senate-passed H.R. 6.
20 15 U.S.C. 79o.
21 16 U.S.C. 24.
Current Law. The Federal Power Act requires that jurisdictional rates are just
and reasonable and prohibits cross-subsidization.22
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 U.S. A similar provision 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 under otherwise applicable
laws to protect utility customers. A similar provision was included in the House- and
Senate-passed H.R. 6.
Section 1270. Enforcement. FERC would have authority to enforce this
provision under sections 306-317 of the Federal Power Act. A similar provision was
included in the House- and Senate-passed H.R. 6.
Current Law. The Securities and Exchange Commission has authority to
investigate and enforce provisions of the Public Utility Holding Company Act of
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 House- and Senate-passed H.R. 6.
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 House- and Senate-passed H.R. 6.
Section 1273. Transfer 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. A similar provision was
included in the House- and Senate-passed H.R. 6.
Current Law. The Securities and Exchange Commission maintains books24
and records and regulates security transactions.
Section 1274. Effective Date. Twelve months after enactment, this subtitle
would take effect.
22 16 U.S.C. 791a et seq.
23 15 U.S.C. 79r.
24 15 U.S.C. 79 et seq.
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.
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 provision was
included in the House- and Senate-passed H.R. 6.
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 1935.25
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 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 House- and
Senate-passed H.R. 6.
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 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
25 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
no specific financial gain or loss and are entered into with the intent to distort
reported revenues, trading volumes, or prices.
Current Law. 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, or26
promises. 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 fraudulent27
pretenses, representations, or promises.
Section 1283. Enforcement. The Federal Power Act would be amended to
allow electric utilities to file a complaint 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.
Current Law. 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
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 House- and Senate-passed H.R. 6.
Current Law. Refunds for rates that FERC finds to be unjust, unreasonable,
unduly discriminatory, or preferential begin a minimum of 60 days after a complaint
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
26 18 U.S.C. 1341.
27 18 U.S.C. 1343.
28 16 U.S.C. 824e(b).
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. Refund authority was provided for in the House-passed H.R.
Current Law. Section 201(f) of the Federal Power Act exempts government29
entities from FERC rate regulation.
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 House-passed H.R. 6.
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 the 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. The
House-and Senate-Passed H.R. 6 would have required the Federal Trade Commission
to issue rules to prohibit slamming and cramming.
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 House-passed H.R. 6.
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. A similar provision was included in the Senate-passed
29 16 U.S.C. 824
Current Law. Under Section 203(a) of the Federal Power 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
Section 1297. Conforming Amendments. The Federal Power Act would be
amended to conform with this title.
30 16 U.S.C. 824b.