Electric Utility Regulatory Reform: Issues for the 109th Congress
CRS Report for Congress
Electric Utility Regulatory Reform:
Issues for the 109 Congress
Updated August 18, 2005
Specialist in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Electric Utility Regulatory Reform:
Issues for the 109th Congress
The Public Utility Holding Company Act of 1935 (PUHCA) and the Federal
Power Act (FPA) were enacted to eliminate unfair practices and other abuses by
electricity and gas holding companies by requiring federal control and regulation of
interstate public utility holding companies. Prior to PUHCA, electricity holding
companies were characterized as having excessive consumer rates, high debt-to-
equity ratios, and unreliable service. PUHCA remained virtually unchanged for 50
years until enactment of the Public Utility Regulatory Policies Act of 1978. PURPA
was, in part, intended to augment electric utility generation with more efficiently
produced electricity and to provide equitable rates to electric consumers. Qualifying
facilities (QFs) are exempt from regulation under PUHCA and the FPA.
Electricity regulation was changed again in 1992 with passage of the Energy
Policy Act (EPACT). The intent of Title 7 of EPACT is to increase competition in
the electric generating sector by creating new entities, called “exempt wholesale
generators” (EWGs), that can generate and sell electricity at wholesale without being
regulated as utilities under PUHCA. This title also provides EWGs with a way to
assure transmission of their wholesale power to their purchasers. The effect of this
act on the electric supply system has been more far-reaching than PURPA.
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued
Orders 888 and 889. FERC issued these rules to remedy undue discrimination in
transmission services in interstate commerce and provide an orderly and fair
transition to competitive bulk power markets. Order 2000, issued December 20,
Comprehensive electricity legislation may involve several components. The
first is PUHCA reform. Some electric utilities want PUHCA changed so they can
more easily diversify their assets. State regulators have expressed concerns that
increased diversification could lead to abuses, including cross-subsidization.
Consumer groups have expressed concern that a repeal of PUHCA could exacerbate
market power abuses in a monopolistic industry where true competition does not yet
The second issue is PURPA’s requirement that utilities purchase power from
QFs. Many investor-owned utilities support repeal of these mandatory purchase
provisions. They argue that their state regulators’ “misguided” implementation of
PURPA has forced them to pay contractually high prices for power that they do not
need. Opponents of this legislation argue that it would decrease competition and
impede development of renewable energy.
The third main issue is reliability. Without mandatory and enforceable reliability
standards, proponents argue that reliability of the electric power system will not be
at acceptable levels. Opponents say these standards are unnecessary.
This report will be updated as events warrant.
Regional Transmission Organizations..............................5
Electric Reliability Organization..................................7
Electric Utility Regulatory Reform:
Issues for the 109 Congress
Historically, electricity service has been defined as a natural monopoly, meaning
that the industry has (1) an inherent tendency toward declining long-term costs, (2)
high threshold investment, and (3) technological conditions that limit the number of
potential entrants. In addition, many regulators have considered unified control of
generation, transmission, and distribution as the most efficient means of providing
service. As a result, most people (about 75%) are currently served by a vertically
integrated, investor-owned utility.
As the electric utility industry has evolved, however, there has been a growing
belief that the historic classification of electric utilities as natural monopolies has
been overtaken by events and that market forces can and should replace some of the
traditional economic regulatory structure. For example, the existence of utilities that
do not own all of their generating facilities, primarily cooperatives and publicly
owned utilities, has provided evidence that vertical integration has not been necessary
for providing efficient electric service. Moreover, recent changes in electric utility
regulation and improved technologies have allowed additional generating capacity
to be provided by independent firms rather than utilities.
The Public Utility Holding Company Act (PUHCA)1 and the Federal Power Act2
(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
1 15 U.S.C. 79 et seq.
2 16 U.S.C. 791 et seq.
the burden of the revenue requirement will be distributed among the various
customer classes (residential, commercial, and industrial).
Under the FPA, federal economic regulation addresses wholesale transactions
and rates for electric power flowing in interstate commerce. Federal regulation
followed state regulation and is premised on the need to fill the regulatory vacuum
resulting from the constitutional inability of states to regulate interstate commerce.
In this bifurcation of regulatory jurisdiction, federal regulation is limited and
conceived to supplement state regulation. The Federal Energy Regulatory
Commission (FERC) has the principal functions at the federal level for the economic
regulation of the electricity utility industry, including financial transactions,
wholesale rate regulation, transactions involving transmission of unbundled retail
electricity, interconnection and wheeling of wholesale electricity, and ensuring
adequate and reliable service. In addition, to prevent a recurrence of the abusive
practices of the 1920s (e.g., cross-subsidization, self-dealing, pyramiding, etc.), the
Securities and Exchange Commission (SEC) regulates utilities’ corporate structure
and business ventures under PUHCA.
The electric utility industry has been in the process of transformation. During
the past 25 years, there has been a major change in direction concerning generation.
First, improved technologies have reduced the cost of generating electricity as well
as the size of generating facilities. Prior preference for large-scale — often nuclear
or coal-fired — powerplants has been supplanted by a preference for small-scale
production facilities that can be brought online more quickly and cheaply, with fewer
regulatory impediments. Second, this has lowered the entry barrier to electricity
generation and permitted non-utility entities to build profitable facilities. Recent
changes in electric utility regulation and improved technologies have allowed
additional generating capacity to be provided by independent firms rather than
The oil embargoes of the 1970s created concerns about the security of the
nation’s electricity supply and led to enactment of the Public Utility Regulatory
Policies Act of 1978 (PURPA).3 For the first time, utilities were required to purchase
power from outside sources. The purchase price was set at the utilities’ “avoided
cost,” the cost they would have incurred to generate the additional power themselves,
as determined by utility regulators. PURPA was established in part to augment
electric utility generation with more efficiently produced electricity and to provide
equitable rates to electric consumers.
In addition to PURPA, the Fuel Use Act of 1978 (FUA)4 helped qualifying
facilities (QFs) become established. Under FUA, utilities were not permitted to use
natural gas to fuel new generating facilities. QFs, which by definition are not
utilities, were able to take advantage of newly abundant natural gas as well as new
generating technology, such as combined-cycle plants that use hot exhaust gases from
combustion turbines to make steam to generate additional power. These technologies
lowered the financial threshold for entrance into the electricity generation business
3 P.L. 95-617, 16 U.S.C. 2601.
4 P.L. 95-620.
as well as shortened the lead time for constructing new plants. FUA was repealed in
1987, but by this time QFs and small power producers had gained a portion of the
total electricity supply.
This influx of QF power challenged the cost-based rates that previously guided
wholesale transactions. Before implementation of PURPA, FERC approved
wholesale interstate electricity transactions based on the seller’s costs to generate and
transmit the power. But, as non-utility generators typically do not have enough
market power to influence the rates they charge, FERC began approving certain
wholesale transactions whose rates were a result of a competitive bidding process.
These rates are called market-based rates.
This first incremental change of traditional electricity regulation started a
movement toward a market-oriented approach to electricity supply. Following the
enactment of PURPA, two basic issues stimulated calls for further reform: whether
to encourage nonutility generation and whether to permit utilities to diversify into
The Energy Policy Act of 1992 (EPACT)5 removed several regulatory barriers
to entry into electricity generation to increase competition of electricity supply.
Specifically, EPACT provides for the creation of entities, called “exempt wholesale
generators” (EWGs), that can generate and sell electricity at wholesale without being
regulated as utilities under PUHCA. Under EPACT, EWGs are also provided with
a way to assure transmission of their wholesale power to a wholesale purchaser.
However, EPACT does not permit FERC to mandate that utilities transmit EWG
power to retail consumers (commonly called “retail wheeling” or “retail
competition”), an activity that remains under the jurisdiction of state public utility
commissions. PURPA began to shift more regulatory responsibilities to the federal
government, and EPACT continued that shift away from the states by creating new
options for utilities and regulators to meet electricity demand. EPACT allowed for
a robust wholesale market in electricity. The transmission system is now used
extensively for bulk-power transfers between utilities, even though the physical
system was designed to handle primarily intra-utility transfers. Utilities now depend
on a combination of self-generation, merchant generators, and other utilities to meet
their retail electricity demand.
Shortly after enactment of EPACT, states began considering whether to allow
retail choice. It was argued that retail prices would decline with additional
competition. Most state plans have not met initial expectations. Few alternative
suppliers have remained in the market, consumers are reluctant to switch suppliers,
and default service rates set by the states are generally equal to or less than wholesale
market prices plus retail margin needed to cover retail service costs.6 Currently, 24
states and the District of Columbia have either enacted legislation or issued
regulatory orders to implement retail access. California had the first active retail
program. However, California suspended its restructuring program following the
5 P.L. 102-486, Title VII.
6 See Paul L. Joskow, The Difficult Transition to Competitive Electricity Markets in the
U.S., May 2003, available at [http://econ-www.mit.edu/faculty/download_pdf.php?id=537].
California energy crises in 2001 that was marked by retail and wholesale price spikes
as well as a decrease in reliability. Eighteen states have active restructuring programs.
Six states, Arkansas, Montana, Nevada, New Mexico, Oklahoma, and West Virginia,
have delayed implementation of retail access. Since 2000, no additional states have
announced plans to introduce retail competition.
Electric utility provisions are included in comprehensive energy legislation
(H.R. 6) that was signed into law by President Bush on August 8, 2005.
In part, this law repeals the Public Utility Holding Company Act (PUHCA). The
electric utility industry has long been a proponent of such a repeal while consumer
groups have been opposed. As a compromise, a provision was included that
strengthens FERC’s merger review authority. In addition, language is included that
is intended to prevent cross-subsidization. The mandatory purchase requirement
under the Public Utility Regulatory Policies Act (PURPA) is repealed. An Electric
Reliability Organization(ERO) is created and the ERO will promulgate mandatory,
enforceable reliability standards for the electric industry that includes cybersecurity
protection. Also included in the law is a Sense of Congress that FERC should
carefully consider the states’ objections to the locational installed capacity (LICAP)
mechanism for New England.
In addition to creating a new type of wholesale electricity generator, exempt
wholesale generators (EWGs), the Energy Policy Act (EPACT) provides EWGs with
a system to assure transmission of their wholesale power to its purchaser. However,
EPACT did not solve all of the issues relating to transmission access. As a result of7
EPACT, on April 24, 1996, FERC issued Orders 888 and 889. In issuing its final
rules, FERC concluded that these orders will “remedy undue discrimination in
transmission services in interstate commerce and provide an orderly and fair
transition to competitive bulk power markets.”
Under Order 888, the Open Access Rule, transmission line owners are required
to offer both point-to-point and network transmission services under comparable
terms and conditions that they provide for themselves. The rule provides a single
tariff providing minimum conditions for both network and point-to-point services
and the non-price terms and conditions for providing these services and ancillary
services. This rule also allows for full recovery of so-called stranded costs, with
those costs being paid by wholesale customers wishing to leave their current supply
arrangements. The rule encourages but does not require creation of independent
system operators (ISOs) to coordinate intercompany transmission of electricity.
Order 889, the Open Access Same-time Information System (OASIS) rule,
establishes standards of conduct to ensure a level playing field. The rule requires
utilities to separate their wholesale power marketing and transmission operation
functions, but does not require corporate unbundling or divestiture of assets. Utilities
7 FERC Order 888, Docket No. RM-8-000; FERC Order 889, Docket No. RM95-9-000.
are still allowed to own transmission, distribution, and generation facilities but must
maintain separate books and records.
Regional Transmission Organizations
On December 20, 1999, FERC issued Order 2000, which described the
minimum characteristics and functions of regional transmission organizations
(RTOs).8 The required characteristics of an RTO are:
!The RTO must be independent from market participants.
!It must serve a region of sufficient size to permit the RTO to
!An RTO will be responsible for operational control, and
!It will be responsible for maintaining the short-term reliability of the
The required functions of an RTO outlined in Order 2000 are:
!It must administer its own transmission tariff.
!It must ensure the development and operation of market mechanisms
to manage congestion.
!It must address parallel flow issues both within and outside its
!It will serve as supplier of last resort for all ancillary services; it
must administer an Open Access Same-time Information System.
!It must monitor markets to identify design flaws and market power
and propose appropriate remedial actions; it must provide for
interregional coordination, and
!An RTO must plan necessary transmission additions and upgrades.
Order 2000 does not require a utility to participate in an RTO, set out RTO
boundaries, or mandate the acceptable RTO structure. RTOs will be able to file with
FERC as an independent system operator (ISO), a for-profit transmission company
(transco), or another type of entity that has not yet been proposed. Although RTO
participation is voluntary under Order 2000, FERC built in guidelines and safeguards
to ensure independent operation of the transmission grid. RTOs are required to
conduct independent audits to ensure that owners do not exert undue influence over
FERC Order 2000 required the existing ISOs to submit to FERC by January 1,
2001, a plan that described whether their transmission organization met the criteria
established in the RTO rulemaking. Electric utilities that were not members of an
ISO had to file plans with FERC by October 1, 2000. The order does not mandate
RTO formation, but if an individual utility opts not to join an RTO, the utility is
required to prove why it would be harmed by joining such an entity.
On July 12, 2001, FERC issued several orders requiring utilities to enter into
talks to form Regional Transmission Organizations. Even though FERC Order 2000
did not set out RTO boundaries, in effect the July 12, 2001, order does. On
September 17, 2001, FERC’s Administrative Law Judge Mediator H. Peter Young
filed his report, which presented a blueprint for creating a single RTO in the
Nort heast . 9
FERC has granted RTO status to three entities and conditional approval to four
!On December 20, 2001, FERC granted RTO status to the Midwest
Independent Transmission System Operator (MISO).10
!On September 18, 2002, FERC approved the RTO West, since
renamed Grid West, proposal. RTO West includes all, or part of,
Washington, Idaho, Montana, Oregon, Nevada, Wyoming, Utah, and
a small part of northern California adjacent to Oregon.
!FERC granted PJM RTO status on December 19, 2002. PJM
manages the grid in parts of Ohio, West Virginia, Pennsylvania,
New Jersey, Delaware, Maryland, Virginia, and the District of
Other RTOs have received conditional approval from FERC.
!Most recently, FERC conditionally approved the New England RTO
(ISO-NE) on March 24, 2004.11 ISO-NE serves customers in
Connecticut, Massachusetts, New Hampshire, Rhode Island,
Vermont, and portions of Maine.
!FERC also granted conditional approval to the Southwest Power
Pool (SPP) on February 10, 2004.12 Arkansas-based SPP serves 4
million customers in all, or parts of, Arkansas, Kansas, Louisiana,
Mississippi, Missouri, New Mexico, Oklahoma, and Texas.
!FERC conditionally approved SeTrans RTO and WestConnect RTO
on October 10, 2002.13 SeTrans includes utilities in Alabama,
Arkansas, Florida, Georgia, Louisiana, Mississippi, South Carolina,
and Texas. WestConnect RTO includes parts of Arizona, Colorado,
New Mexico, and Utah.
9 FERC Docket No. RT01-99-000.
10 FERC Docket No. RTO1-87-000.
11 FERC Docket Nos. RTO04-2-000, ER04-157-000,001, and EL01-39-000.
12 FERC Docket Nos. RTO04-1-000 and ER04-48-000.
13 FERC Docket Nos. EL02-101-000, RTO2-1-000 and EL02-9-000.
In the past, utilities and some state utility commissioners have argued against
large RTOs, stating that currently the expertise is not available to integrate a large
geographic region with multiple control centers and power pools. On February 26,
2002, FERC released a report that assessed the potential economic costs and benefits
of RTOs.14 The study concluded the annual savings from RTO formation could range
from $1 billion to $10 billion. However, the study did not find significant differences
in savings between larger and smaller RTOs. Those in favor of large RTOs argue
that they would provide the most efficient operations of the transmission system. On
November 7, 2001, FERC issued an order that stated FERC’s goals and process for
creating Regional Transmission Organizations.15
On May 14, 1999, the U.S. Court of Appeals for the Eighth Circuit ruled in a
case between FERC and Northern States Power Company. The court held that the
commission overstepped its authority when it ordered Northern States Power
Company to treat wholesale customers the same as it treats native load customers in
making electricity curtailment decisions. This decision raised federal-state
jurisdictional questions, particularly a state’s right to guarantee system reliability.
On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New
York et al. v. Federal Energy Regulatory Commission) that challenged FERC’s
authority under Order 888 to regulate transmission for retail sales if a utility
unbundles transmission from other retail charges. In states that have opened their
generation market to competition, unbundling occurs when customers are charged
separately for generation, transmission, and distribution. Nine states, led by New
York, filed suit, and argued that the Federal Power Act gives FERC jurisdiction over
wholesale sales and interstate transmission and leaves all retail issues up to the state
utility commissions. Enron argued that FERC clearly has jurisdiction over all
transmission and FERC is obligated to prevent transmission owners from
discriminating against those wishing to use the transmission lines. On March 4,
2002, the U.S. Supreme Court ruled in favor of FERC and held that FERC has
jurisdiction over transmission including unbundled retail transactions.16 At issue for
Congress is whether to allow certain utilities to give preferential treatment to native
load customers (customers within their service territories.)
Electric Reliability Organization
The blackout of August 2003 in the Northeast, Midwest, and adjoining parts of
Canada has highlighted the need for infrastructure and operating improvements. The
North American Electric Reliability Council (NERC) has responsibility for reliability
of the bulk power system. NERC has established reliability guidelines, but
compliance with the guidelines is voluntary. The Federal Power Act gives FERC
14 See [http://www.ferc.gov/legal/ferc-regs/land-docs/rtostudy_final_0226.pdf].
15 FERC Docket No. RM01-12-000.
16 New York v. F.E.R.C., 535 U.S. 1 (2002).
jurisdiction over unbundled transmission and was intended to regulate wholesale
rates; however, no authority was provided to regulate reliability.
As a result of the recommendations of the joint U.S.-Canada task force
investigating the August 2003 blackout, NERC is conducting reliability readiness
audits of reliability coordinators. All audits are expected to be completed by 2006.
FERC held a technical conference on September 29, 2004, to discuss the status of the
Reliability Readiness Reviews. More than two-thirds of the audited control areas and
reliability coordinators need to make staff training improvements and add support to
their control centers in case of an emergency.17 At the conference, NERC, FERC,
and industry officials agreed that absent mandatory reliability standards, there is little
assurance that operators of the system will comply with more rigorous guidelines.
Both NERC and FERC agree that implementation of an electric reliability
organization (ERO) will improve the reliability of the electric system. The Energy
Policy Act of 2005, as signed by the President on August 8, 2005, includes the
creation of an ERO. The law requires FERC to promulgate rules to create a FERC-
certified electric reliability organization. The ERO will develop and enforce
reliability standards for the bulk-power system. All ERO standards will be approved
by FERC. Under the law, the ERO can impose penalties on a user, owner, or
operator of the bulk-power system that violates any FERC-approved liability
standard. In addition, FERC can order compliance with the reliability standard and
can impose a penalty if FERC finds that a user, owner, or operator of the bulk-power
system has engaged in a violation of the reliability standard. However, this law
would not give an ERO or FERC authorization to order construction of additional
generation or transmission capacity.
Generally, the ERO is noncontroversial. Advocates of giving FERC authority
over the ERO contend that central jurisdiction would provide more accountability.
FERC would be ultimately responsible for reliability issues. If the penalties
employed by the ERO are not successful, then FERC will have the authority to
enforce penalties for entities that did not comply with reliability standards.
Establishing this new relationship between FERC and the ERO could have the
potential to improve coordination between market functions and reliability functions.
Those opposed to giving FERC jurisdiction over bulk power system reliability
contend that FERC has no experience in this area. They argue that by giving FERC
this authority, it will have to rely on NERC for much of its expertise. Placing FERC
in this position may add to the uncertainty associated with the changes in institutional
structure as FERC takes on this new role.
A conflict exists between the apparent goal of increasing competition in the
generation sector and assuring adequate transmission capacity and management of
the system to move the power. Additions to generating capacity are occurring at a
more rapid pace than transmission additions. The traditional vertically integrated
17 A transcript of the Technical Conference is available at
[ h t t p : / / www.f e r c .gov/ Eve nt Cal e ndar / Fi l e s/ 20041013132249-t r anscr i pt .pdf ] .
utility no longer dominates the industry structure.18 In addition, demand for electric
power continues to increase. Unresolved regulatory issues that have emerged after
1992 have resulted in considerable uncertainty in the financial community. As a
result of all of these factors, investment in the transmission system has not kept pace
with demand for transmission capacity.
Siting. One reason transmission lines have not been built in recent years is the
difficulty in siting lines. Even though the transmission of electricity is considered
interstate commerce, the siting of transmission lines is the responsibility of the states.
In addition, several federal agencies play various roles in the siting process, primarily
with regard to environmental impacts. Siting and building transmission lines have
been very difficult because of citizen opposition as well as inconsistent siting
requirements among states. While controversial, since the blackout of 2003, FERC
commissioners are now supporting federal siting backstop authority.19 In addition,20
the electric industry is in favor of giving FERC siting authority. States are generally
opposed to this proposal. The Energy Policy Act of 2005 includes federal backstop
authority for siting transmission lines.
Pricing. Some transmission-owning utilities argue that the current pricing
mechanism for transmission discourages investment. FERC regulates all
transmission, including unbundled retail transactions. Under the Federal Power Act
(FPA), FERC is required to set “just and reasonable” rates for wholesale
transactions.21 FERC has traditionally determined rates by using an embedded cost
method that includes recovery of capital costs, operating expenses, improvements,
accumulated depreciation, and a rate of return. Traditionally, transmission owners
have been compensated for use of their lines based on a contract path for the
movement of electricity, generally the shortest path between the generator and its
customer. However, electricity rarely follows a contract path and instead follows the
path based on least impedance.22 Transmission lines often carry electricity that has
been contracted to move on a different path. As more bulk power transfers are
occurring on the transmission system, transmission owners not belonging to RTOs
are not always being compensated for use of their lines because a contract path rarely
18 According to the Energy Information Administration, in 1996, 10% of generating capacity
was owned by non-utility generators. By 2000, 26% of generating capacity was owned by
non-utility generators. In addition, to encourage competition, Maine and New Hampshire
have required utilities to fully divest of either generation or transmission assets, and Rhode
Island has partial divestiture requirements.
19 Statement of Nora Mead Brownell, FERC Reverses Position, Will Now Take Federal
Backstop Authority, Energywashington.com, September 2, 2003.
20 Edison Electric Institute, Federal Siting Authority: Key to Expanding Electricity
Infrastructure, available at [http://www.eei.org/industry_issues/energy_infrastructure/
21 16 U.S.C. 824(d)(a).
22 Impedance is a measure of the resistive and reactive attributes of a component in an
follows the actual flow. This creates a disincentive for transmission owners to
Under Order 2000,24 FERC stated its interest in incentive ratemaking and, in
particular, performance-based ratemaking. Those in favor of incentive ratemaking
argue that incentives are needed (1) to encourage participation in regional
transmission organizations (RTOs)25; (2) to compensate for perceived increases in
financial risk because of participation in a regional transmission organization, and (3)
to facilitate efficient expansion of the transmission system.
FERC uses a “license plate” rate for transmission: a single rate based on
customer location. As FERC is encouraging formation of large regional transmission
organizations, FERC may move toward a uniform access charge, sometimes called
postage stamp rates. With a postage stamp rate, users pay one charge for moving
electricity anywhere within the regional transmission organization.
Postage stamp rates eliminate so-called rate pancaking, or a series of
accumulated transmission charges as the electricity passes through adjacent
transmission systems, and increases the pool of available generation. On the other
hand, by moving to postage stamp rates, customers in low-cost transmission areas
may see a rate increase, and high-cost transmission providers in the same area may
not recover embedded costs because costs are determined on a regional basis.
Regulatory Uncertainty. Transmission owners and investors have expressed
concern that the regulatory uncertainty for electric utilities is inhibiting new
investment in and construction of transmission facilities. For example, repeal of
PUHCA has been debated since 1996 without resolution. Without clarification on
whether PUHCA will be repealed, utilities state that they are reluctant to invest in
infrastructure. Repeal could significantly expand the ability of utilities to diversify
their investment options.
In addition, FERC has been moving toward requiring participation in regional
transmission organizations to create a more seamless transmission system. A fully
operational regional transmission organization would operate the entire transmission
system in a region and be able to replace multiple control centers with a single
control center.26 This type of control can increase efficiencies in the operation of the
transmission system. RTO participants are required to adhere to certain rules, but
these are not currently enforceable in court.
23 See National Economic Research Associates, Transmission Pricing Arrangements and
Their Influence on New Investments, World Bank Institute, July 6, 2000, available at
[http://www.wo rldbank.org/ wbi/infrafin/pdfs/samples/dc2000-weektwo/be r r y_ t r a n s _ p r i c i n g.
24 89 FERC 61,285.
25 A regional transmission organization is an independent organization that does not own the
transmission lines but operates a regional transmission system on a non-discriminatory basis.
26 PJM operates with a single control center.
Uncertainty over the form of an RTO, its operational characteristics, and the
transmission rates for a specific region have apparently made utilities wary of
investing in transmission. FERC has granted RTO status to several entities and
conditionally approved others. If RTOs are able to operate successfully and develop
a track record, some regulatory uncertainty will diminish.
Some have argued that the wholesale power markets cannot be competitive
without additional market transparency for both generation and transmission. Some
proposals would require FERC to issue rules to establish an electronic information
system to provide the public, FERC, state commissions, buyers and sellers of
wholesale electric energy, and users of transmission services with information on the
availability and price of wholesale electric energy and transmission services.
The Energy Policy Act of 2005 repeals PUHCA and gives FERC additional
merger review authority. One argument for additional PUHCA reform has been
made by electric utilities that want to further diversify their assets. Under PUHCA,
a holding company could acquire securities or utility assets only if the Securities and
Exchange Commission (SEC) found that such a purchase would improve the
economic efficiency and service of an integrated public utility system. It has been
argued that reform to allow diversification would improve the risk profile of electric
utilities in much the same way as in other businesses: The risk of any one investment
is diluted by the risk associated with all investments. Utilities have also argued that
diversification would lead to better use of underutilized resources (due to the
seasonal nature of electric demand). Utility holding companies that have been
exempt from SEC regulation argue that PUHCA discouraged diversification because
the SEC could repeal exempt status if exemption would be “detrimental to the public
For a number of years there has been significant bipartisan congressional
support for repealing much of PUHCA, and giving FERC and state commissions
access to books and records. Since the 1980s, the Securities and Exchange
Commission has testified before Congress that many provisions of PUHCA are no
longer relevant and other provisions are redundant with state and other federal
regulations.27 However, as a result of Enron’s collapse, some in Congress have taken
a somewhat different view toward significantly amending or repealing PUHCA.28
Even though Enron had claimed exemption from PUHCA, on February 6, 2003,
Securities and Exchange Commission Chief Administrative Law Judge Brenda P.
Murray denied Enron’s PUHCA exemption applications of February 28, 2002,
amended on May 31, 2002, and April 12, 2000.29 In the case of Enron, PUHCA and
many other laws did not deter or prevent fraudulent filing of information with the
State regulators have expressed concerns that increased diversification could
lead to abuses, including cross-subsidization: a regulated company subsidizing an
unregulated affiliate. Cross-subsidization was a major argument against the creation
of EWGs and re-emerged as an argument against PUHCA repeal. In the case of
electric and gas companies, non-utility ventures that are undertaken as a result of
diversification may benefit from the regulated utilities’ allowed rate of return.
Moneymaking non-utility enterprises would contribute to the overall financial health
of a holding company. However, unsuccessful ventures could harm the entire
holding company, including utility subsidiaries. In this situation, utilities would not
be penalized for failure in terms of reduced access to new capital, because they could
increase retail rates.
Several consumer and environmental public interest groups, as well as state
legislators, expressed concerns about PUHCA repeal. PUHCA repeal, such groups
argue, could only exacerbate market power abuses in what they see as a monopolistic
industry where true competition does not yet exist.
A prospective repeal of §210 of PURPA, the mandatory purchase requirement
provisions, is included in the Energy Policy Act of 2005. Proponents of PURPA
repeal — primarily investor-owned utilities (IOUs) located in the Northeast and in
California — argued that their state regulators’ “misguided” implementation of
PURPA in the early 1980s has forced them to pay contractually high prices for power
they do not need. They argued that, given the current environment for cost-conscious
competition, PURPA is outdated. The PURPA Reform Group, which promotes IOU
interests, strongly supported repeal by contending that the PURPA’s mandatory
purchase obligation was anti-competitive and anti-consumer.
Opponents of PURPA reform (industrial power customers, some segments of
the natural gas industry, the renewable energy industry, and environmental groups)
have many reasons to support PURPA as it was enacted. Mainly, their argument was
that PURPA introduced competition in the electric generating sector and, at the same
time, helped promote wider use of cleaner, alternative fuels to generate electricity.
Since the electric generating sector is not yet fully competitive, they argued, repeal
of PURPA would decrease competition and impede the development of the
renewable energy industry. Additionally, opponents of PURPA repeal argued that
it would result in less competition and greater utility monopoly control over the
electric industry. State regulators expressed concern that mandatory purchase
requirement repeal would prevent them from deciding matters currently under their
jurisdiction. The National Association of Regulatory Utility Commissioners has
29 Initial Decision Release No. 222 (File No. 3-10909) can be found at [http://www.sec.gov/
litigation/alj dec/id222bpm.htm] .
opposed legislation that would allow FERC to protect utilities from costs associated
with PURPA contracts.