Order Code IB10006
Issue Brief for Congress
Received through the CRS Web
Electricity: The Road
Toward Restructuring
Updated October 16, 2002
Amy Abel and Larry Parker
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
CONTENTS
SUMMARY
MOST RECENT DEVELOPMENTS
BACKGROUND AND ANALYSIS
Transmission Issues
Standard Market Design
Market Transparency
Environmental Questions and Proposed Responses
Calls for Additional Electric Regulatory Reform
PUHCA
PURPA
Retail Wheeling
Recent Developments in California
Price Caps
Legislative Activity
Senate Debate
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Electricity: The Road Toward Restructuring
SUMMARY
The Public Utility Holding Company Act
provide an orderly and fair transition to com-
of 1935 (PUHCA) and the Federal Power Act
petitive bulk power markets. Order 2000,
(FPA) were enacted to eliminate unfair prac-
issued December 20, 1999, established crite-
tices and other abuses by electricity and gas
ria for forming transmission organizations.
holding companies by requiring federal con-
trol and regulation of interstate public utility
Comprehensive electricity legislation
holding companies. Prior to PUHCA, elec-
involves three issues. The first is PUHCA
tricity holding companies were characterized
reform. Some electric utilities want PUHCA
as having excessive consumer rates, high
changed so they can more easily diversify
debt-to-equity ratios, and unreliable service.
their assets. State regulators have expressed
PUHCA remained virtually unchanged for 50
concerns that increased diversification could
years until enactment of the Public Utility
lead to abuses, including cross-subsidization.
Regulatory Policies Act of 1978 (PURPA,
Consumer groups have expressed concern that
P.L. 95-617). PURPA was, in part, intended
a repeal of PUHCA could exacerbate market
to augment electric utility generation with
power abuses in a monopolistic industry
more efficiently produced electricity and to
where true competition does not yet exist.
provide equitable rates to electric consumers.
Utilities are required to buy all power pro-
The second issue is PURPA’s mandatory
duced by qualifying facilities (QFs) at
purchase requirement provisions. Many
“avoided cost.” QFs are exempt from regula-
investor-owned utilities support repeal of
tion under PUHCA and the FPA.
these provisions. They argue that their state
regulators’ “misguided” implementation of
Electricity regulation was changed again
PURPA has forced them to pay contractually
in 1992 with the passage of the Energy Policy
high prices for power that they do not need.
Act (EPACT, P.L. 102-486). The intent of
Opponents of this legislation argue that it
Title 7 of EPACT is to increase competition in
would decrease competition and impede
the electric generating sector by creating new
development of renewable energy.
entities, called “exempt wholesale generators”
(EWGs) that can generate and sell electricity
The third is retail wheeling. It involves
at wholesale without being regulated as
allowing retail customers to choose their
utilities under PUHCA. This title also
electric generation supplier. Currently, this is
provides EWGs with a way to assure
under state jurisdiction, and 24 states and the
transmission of their wholesale power to its
District of Columbia have moved toward retail
purchaser. The effect of this Act on the
wheeling. However, some have argued that
electric supply system is potentially more
the federal government should act as a back-
far-reaching than PURPA.
stop to ensure that all states introduce retail
wheeling, preempting state authority if neces-
On April 24, 1996, the Federal Energy
sary. The Senate-passed version of H.R. 4
Regulatory Commission (FERC) issued Or-
contains provisions for electric utility restruc-
ders 888 and 889. FERC believed these rules
turing, but these provisions do not include
would remedy undue discrimination in trans-
retail wheeling. The Conference Committee
mission services in interstate commerce and
is now considering a House counter proposal.
Congressional Research Service ˜ The Library of Congress
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MOST RECENT DEVELOPMENTS
On July 31, 2002, the Federal Energy Regulatory Commission (FERC) issued a Notice
of Proposed Rulemaking (NOPR) on standard market design (Docket No. RM01-12-000)
[http://www.ferc.gov/Electric/RTO/Mrkt-Strct-comments/nopr/Web-NOPR.pdf]. The
proposed rulemaking would create a new tariff under which transmission owners would be
required to turn over operation of their transmission systems to unaffiliated independent
transmission providers.
Conferees on omnibus energy legislation, H.R. 4, have met and exchanged proposals
on electric utility restructuring provisions. The Senate passed its version of H.R. 4 on April
25, 2002; it includes provisions to repeal the Public Utility Holding Company Act (PUHCA),
reform the Public Utility Regulatory Policies Act (PURPA), and create an electric reliability
organization.
On March 4, 2002, the U.S. Supreme Court ruled that FERC has jurisdiction over
transmission, including “unbundled” retail transactions.
On November 7, 2001, FERC issued an order (Docket No. RM01-12-000) that stated
FERC’s goals and process for creating Regional Transmission Organizations
[http://www.ferc.gov/Electric/RTO/rto/issuance/RM01-12.pdf]. (See also the CRS
E l e c t r o n i c B r i e f i n g B o o k o n e l e c t r i c i t y r e s t r u c t u r i n g a t
[http://www.congress.gov/brbk/html/ebele1.shtml].)
BACKGROUND AND ANALYSIS
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. (For additional information on Public Power, see also the CRS Electronic Briefing
Book on electricity restructuring at [http://www.congress.gov/brbk/html/ebele12.html].)
Moreover, recent changes in electric utility regulation and improved technologies have
allowed additional generating capacity to be provided by independent firms rather than
utilities.
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The Public Utility Holding Company Act (PUHCA) 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 (see CRS Report RS20015). A regulatory bargain was made between the
government and utilities. In exchange for an exclusive franchise service territory, utilities
must provide electricity to all users at reasonable, regulated rates. State regulatory
commissions address intrastate utility activities, including wholesale and retail rate-making.
State authority currently tends to be as broad and as varied as the states are diverse. At the
least, a state public utility commission will have authority over retail rates, and often over
investment and debt. At the other end of the spectrum, the state regulatory body will oversee
many facets of utility operation. Despite this diversity, the essential mission of the state
regulator in states that have not restructured is the establishment of retail electric prices. This
is accomplished through an adversarial hearing process. The central issues in such cases are
the total amount of money the utility will be permitted to collect and how the burden of the
revenue requirement will be distributed among the various customer classes (residential,
commercial, and industrial).
Under the FPA, federal economic regulation addresses wholesale transactions and rates
for electric power flowing in interstate commerce. Federal regulation followed state
regulation and is premised on the need to fill the regulatory vacuum resulting from the
constitutional inability of states to regulate interstate commerce. In this bifurcation of
regulatory jurisdiction, federal regulation is limited and conceived to supplement state
regulation. 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
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 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 utilities.
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, P.L. 95-617). 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.
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In addition to PURPA, the Fuel Use Act of 1978 (FUA, P.L. 95-620) helped qualifying
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 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. As more non-utility generators entered the market in the 1980s, these cost-based
rates were challenged. Since 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 to traditional electricity regulation started a movement
towards 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 non-regulated activities.
The Energy Policy Act of 1992 (EPACT, P.L. 102-486) 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. (For
additional background on EPACT and PURPA, see CRS Report 98-419.)
The question now is whether further federal legislative action is desirable to encourage
competition in the electric utility sector and if so at what speed this change would occur.
Currently, 24 states and the District of Columbia have either enacted legislation or issued
regulatory orders to implement retail access. Six states, Arkansas, Montana, Nevada, New
Mexico, Oklahoma and West Virginia, have delayed implementation of retail access. The
map later in this issue brief shows the current status of each state’s restructuring efforts.
Issues discussed in this brief include repeal or alteration of both PUHCA and PURPA;
transmission access and FERC’s Orders 888, 889 and 2000; environmental impact; and
issues related to utility diversification.
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Transmission Issues
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 of 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 are still allowed to own transmission,
distribution, and generation facilities but must maintain separate books and records.
On December 20, 1999, FERC issued Order 2000 that described the minimum
characteristics and functions of regional transmission organizations (RTOs)
[http://www.ferc.gov/news/rules/pages/RM99-2A.pdf]. In FERC's NOPR, four primary
characteristics and eight functions are described as essential for Commission approval of an
RTO. The required characteristics are: the RTO must be independent from market
participants; it must serve a region of sufficient size to permit the RTO to perform
effectively; an RTO will be responsible for operational control; and it will be responsible for
maintaining the short-term reliability of the grid. The required functions of an RTO outlined
in Order 2000 are: it must administer its own transmission tariff; it must ensure the
development and operation of market mechanisms to manage congestion; it must address
parallel flow issues both within and outside its region; 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 RTO participation, 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 RTO operation.
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FERC Order 2000 required the existing ISOs to submit to FERC by January 1, 2001,
a plan to describe whether their transmission organization meets the criteria established in
the RTO rulemaking. Electric utilities not currently 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 four 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 (Docket No.
RT01-99-000) [http://www.ferc.gov/Electric/RTO/rto/issuance/RT01-991-9-17.pdf] that
presented a blueprint for creating a single RTO in the Northeast. On December 20, 2002,
FERC granted RTO status [Docket No. RTO1-87-000] to the Midwest Independent
Transmission System Operator (MISO). On September 18, 2002, FERC approved the RTO
West proposal. RTO West includes all, or part of, Washington, Idaho, Montana, Oregon,
Nevada, Wyoming, Utah and a small part of northern California near the Oregon border.
FERC conditionally approved SeTrans RTO and WestConnect RTO on October, 9, 2002
[Docket Nos. EL02,101-000, RTO2-1-000 and EL02-9-000]. SeTrans includes utilities in
Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, South Carolina and Texas.
WestConnect RTO will operate in parts of Arizona, Colorado, New Mexico and Utah.
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 [http://www.ferc.gov/electric/rto/mrkt-strct-comments/rtostudy_final_0226.pdf] that
assessed the potential economic costs and benefits of RTOs. The study concluded the annual
savings from RTO formation could range from $1- $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 the most efficient operations of the
transmission system would take place with large RTOs. On November 7, 2001, FERC issued
a n o r d e r ( D o c k e t N o . R M 0 1 - 1 2 - 0 0 0 )
[http://www.ferc.gov/Electric/RTO/rto/issuance/RM01-12.pdf] that stated FERC’s goals and
process for creating Regional Transmission Organizations. Omnibus energy legislation now
in House-Senate conference, H.R. 4, does not contain provisions mandating RTO
membership for electric utilities.
On May 14, 1999, the U.S. Court of Appeals for the Eighth Circuit ruled in a case
between FERC and Northern States Power. 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 challenges 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,
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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. The ruling is available at:
[http://a257.g.akamaitech.net/7/257/2422/04mar20021030/www.supremecourtus.gov/opi
nions/01pdf/00-568.pdf].
Five bills, the Senate-passed H.R. 4, H.R. 312, H.R. 3406, S. 172, S. 388, and S. 597,
provide for an Electric Reliability Organization to prescribe and enforce mandatory reliability
standards.
Standard Market Design. On July 31, 2002, FERC issued a Notice of Proposed
Rulemaking (NOPR) on standard market design (SMD) (Docket No. RM01-12-
000)[http://www.ferc.gov/Electric/RTO/Mrkt-Strct-comments/nopr/Web-NOPR.pdf].
FERC’s stated goal of 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 has been extended to January 10, 2003, for the following issues:1) market design for
the Western Interconnection; 2) transmission plan in pricing, 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 asserts 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 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.” In general, the industry has been
in favor of FERC’s SMD proposal, but some industry groups have voiced concerns about the
implementation of SMD.
Market Transparency. Some have argued that the transmission and wholesale power
markets cannot be competitive without additional market transparency. S. 1231 and the
Senate-passed H.R. 4 require FERC to issue rules establishing an electronic information
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system to provide information about the availability and price of wholesale electric energy
and transmission services to FERC, state commissions, buyers and sellers of wholesale
electric energy, users of transmission services, and the public.
Environmental Questions and Proposed Responses
The electric industry is a major source of air pollution as well as of greenhouse gases.
Therefore, changes underway in the industry are being closely examined for their potential
environmental effects. At issue is whether proposed legislation to restructure the industry
should include environmental protections.
The Clean Air Act regulates emissions of conventional air pollutants from electric
utilities. While it has historically focused on new construction in applying its most stringent
standards, several current and prospective regulations would significantly increase controls
on existing coal-fired facilities. These controls may diminish the attractiveness of renovating
older, more polluting facilities, but the effectiveness of the regulations in coping with a
restructured industry remains to be seen. In addition, greenhouse gas emissions are not
regulated, so any increases in carbon dioxide would not be controlled under existing
authorities.
Thus the environmental effects of restructuring depend on whether, for conventional air
pollutants, the existing regulatory regimen will work effectively as the industry structure
changes. For some pollutants, such as sulfur oxides, a nationwide emissions "cap" seems
secure; but for others, particularly nitrogen oxides, the state-led implementation process may
have difficulty coping with regional disparities in emissions. For carbon dioxide, any controls
would be contingent on future ratification of the Kyoto Agreement to curtail emissions and
on domestic legislation.
Several bills that deal with these environmental issues have been introduced in the 107th
Congress. For a summary of these bills and legislative action, see CRS Report RL31326.
Calls for Additional Electric Regulatory Reform
PUHCA
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.”
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For a number of years there has been significant bipartisan congressional support for
repealing much of PUHCA. For example, on April 24, 2001, the Senate Committee on
Banking, Housing, and Urban Affairs approved S. 206, a bill to repeal the Public Utility
Holding Company Act of 1935 and to enact the Public Utility Holding Company Act of 2001
(S.Rept. 107-15). However, as a result of Enron’s recent collapse, Congress may take a
somewhat different view toward significantly amending or repealing PUHCA. Even though
Enron was not a registered holding company, it is now being argued by some that without
PUHCA, Enron’s collapse might have adversely affected many other power companies. (For
additional information on Enron, see also the CRS Electronic Briefing Book on electricity
restructuring at [http://www.congress.gov/brbk/html/ebele1.shtml].)
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. The Senate-passed H.R. 4 would repeal
PUHCA and give FERC additional authority over cross subsidization issues and merger
review. The House conferees counteroffer would repeal PUHCA and eliminate FERC’s
merger authority.
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. The National Rural Electric Cooperative Association also
opposes stand-alone changes to PUHCA. (For further information on PUHCA, see CRS
Report RS20015.)
PUHCA repeal legislation has been introduced in the 107th Congress, but
comprehensive electricity restructuring legislation has not. S. 206, S. 388, Senate-passed
H.R. 4, H.R. 1101, and H.R. 3406 would repeal PUHCA and give FERC additional
authority.
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Figure 1. Status of State Electric Utility Restructuring as of October 1, 2002
1. Arizona, Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts,
Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island,
Texas, and Virginia.
2. Arkansas, Montana, Nevada, New Mexico, Oklahoma, and West Virginia.
3. California.
4. Alabama, Alaska, Colorado, Florida, Georgia, Hawaii, Idaho, Indiana, Iowa, Kansas, Kentucky,
Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Carolina, North Dakota, South
Carolina, South Dakota, Tennessee, Utah, Vermont, Washington, Wisconsin, and Wyoming.
Source: Energy Information Administration
[http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html]
PURPA
H.R. 381, H.R. 3406, S. 388, S. 552 and Senate-passed H.R. 4 would prospectively
repeal §210 of PURPA, the mandatory purchase requirement provisions. Proponents of such
stand-alone bills — primarily investor-owned utilities (IOUs) located in the Northeast and
in California — argue that their state regulators’ “misguided” implementation of PURPA in
the early 1980s has forced them to pay contractually high prices for power they do not need.
They argue that, given the current environment for cost-conscious competition, PURPA is
outdated. The PURPA Reform Group, which promotes IOU interests, strongly supports such
bills by contending that the current law’s mandatory purchase obligation was
anti-competitive and anti-consumer.
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Opponents of these types of bills (IPPs, 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. The Electric Power Supply Association (EPSA)
also wants comprehensive legislation to look at all aspects of electricity regulation. State
regulators are concerned that this legislation would prevent them from deciding matters
currently under their jurisdiction. The National Association of Regulatory Utility
Commissioners has opposed legislation that would allow FERC to protect utilities from costs
associated with PURPA contracts.
Retail Wheeling
Many analysts believe the next logical step in restructuring is retail competition.
Encouraging competition in the electric supply system is already occurring as some states
allow generating utilities to arrange for transmission of electricity from its sources to a retail
consumer whether or not this transaction occurs within their service territory. EPACT
expressly prevents FERC from ordering retail competition (retail wheeling). Such
transactions remain under state regulatory control; FERC’s open access Orders address
wheeling at the wholesale level only. However, it is clear that FERC hopes that its Orders
will pave the way for states to permit retail customers to shop for their electricity needs
anywhere they want, rather than being limited to buying electricity from their local utility.
Indeed, who should determine the pace and boundaries of retail wheeling efforts is a
fundamental issue. Electric service is a vital component of a modern economy; thus, national
interests are at stake in what direction the restructuring debate takes. Concerns about
economic efficiency and the treatment of various participants (such as electric utilities) may
suggest to some that the federal government provide direction to current state initiatives. In
contrast, others argue that the states, which have traditionally had responsibility over retail
electricity issues, have the expertise and experience necessary to handle the situation (more
so than the federal government) and that the national interest in electricity supply is neither
threatened by state initiatives nor a justification for federal preemption of states’ rights.
Currently, retail choice is under state jurisdiction, and 24 states and the District of Columbia
have moved toward retail competition. Congress may consider whether expanding federal
jurisdiction is warranted in the continuing evolution of the electric utility industry or whether
a “wait and see” attitude toward state proceedings is more appropriate at this point. No bills
addressing retail wheeling have been introduced in the 107th Congress.
Recent Developments in California
California’s experience in 2001 with a marked decrease in reliability of electricity
supply as well as retail price spikes in the San Diego region has now been replaced with
excess generating supply. The original situation was partly due to California’s restructured
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electric markets, increased demand, generating plant outages and lack of new transmission
and generating capacity. Currently, California has more long-term contracts than it needs to
meet demand, and the contracts are locked-in at prices higher than the current market price
of electricity. (See also the CRS Electronic Briefing Book on electricity restructuring at
[http://www.congress.gov/brbk/html/ebele1.shtml].)
Price Caps
Several bills have been introduced that would impose wholesale price caps in
California, a return to cost-of-service wholesale rate regulation or demand-based time-of-use
rates. Cost-of-service rate regulation allows for recovery of generating costs plus a
reasonable rate of return. Those in favor of price caps argue that competition does not yet
exist in California’s wholesale generating sector and wholesale prices do not reflect what
would be expected in a functional market. In addition, it is argued that generators in
California are exerting market power by intentionally withholding generating capacity to
increase wholesale prices. Those opposed to price caps, including President Bush, argue that
price caps would discourage investment in new generating facilities and would further distort
the wholesale electricity market. For further discussion on price controls, see
[http://www.congress.gov/brbk/html/ebele23.html].
H.R. 264, H.R. 268, H.R. 1468, S. 80, and S. 287 would impose cost-of-service
regulation for wholesale sales of electricity. H.R. 238 and S. 26 would impose an interim
regional wholesale price cap or cost-of-service based rates. S. 597 and S. 764 would require
either cost-of-service based rates or load-differentiated rates. In addition, H.R. 1941, H.R.
1974, H.R. 2274, H.R. 2757, S. 1068 and Senate-passed H.R. 4 would give FERC additional
wholesale refund authority. This would allow FERC to order wholesalers to provide refunds
to consumers if it is determined that unjust and unreasonable rates have been charged. H.R.
3406 clarifies FERC’s existing refund authority and gives FERC authority to order refunds
from sellers of electricity and transmission that are normally unregulated whenever they
engage in sales of wholesale electricity or transmission to regulated utilities.
On June 18, 2001, FERC extended its price mitigation Order of April 26, 2001, to
include the 11 states in the Western System Coordinating Council (WSCC). FERC's Order
[http://www.ferc.gov/electric/bulkpower/el00-95-031-6-19.PDF] provided for a two-tiered
rate structure for the day-ahead and hour-ahead spot market. If California entered a Stage 1
electricity emergency (reserves fall below 7%), the spot market clearing price for California
was based on the bid from the least efficient gas-fired plant located in California that was
needed by the Independent System Operator (ISO). All sellers into the California ISO spot
market received the spot market clearing price. For sellers outside of California, California's
spot market clearing price was the maximum price, but sellers could bid and receive less than
the spot market clearing price. Generators, but not power marketers, had the ability to justify
their cost if it exceeded the established spot market clearing price. When operating reserves
were above 7% in California, the maximum price that could be charged was 85% of the spot
market clearing price set during the most recent Stage 1 emergency. These price caps were
due to expire in September 2002. For a chronological listing of important events in the
California electricity situation, see the Chronology in the CRS Electronic Briefing Book at
[http://www.congress.gov/brbk/html/ebele18.html].
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On July 17, 2002, FERC issued a new price mitigation order for the Western markets
(Docket Number ER02-1656-000 et al.). Unlike the existing order described above, the new
price mitigation plan has no end date, and went into effect October 1, 2002. Unlike the soft
cap of $91.87 per megawatt hour that has been in effect since June 2001, the plan establishes
a hard price cap of $250 per megawatt hour for spot market sales. In addition, the plan
creates an automated mitigation procedure (AMP) that will screen all bids that exceed $91.87
per megawatt hour for possible market abuses.
On September 26, 2002, FERC approved the California Independent System Operator’s
request to extend through October 30, 2002, the $91.87/megawatt-hour price cap that was
to be replaced with a $250/megawatt-hour cap on October 1, 2002.
Legislative Activity
The electric utility crisis in California in early 2001 shifted the focus of electricity
restructuring legislation away from comprehensive bills that dominated the electric utility
restructuring debate in the 106th Congress. In the 107th Congress, the majority of electric
utility legislation introduced relates to reliability in wholesale rate-making. Six bills, H.R.
312, H.R. 2814, H.R. 3406, S. 172, S. 388, and S. 597, provide for an Electric Reliability
Organization (ERO) to prescribe and enforce mandatory reliability standards. In addition,
Amendment No. 2917 to S. 517 (the Senate floor vehicle for debate on omnibus energy
legislation, H.R. 4) would have required the Federal Energy Regulatory Commission to
prescribe and enforce reliability standards. However, H.R. 4 as passed by the Senate would
give an electric reliability organization the primary authority to develop reliability standards.
FERC is moving to require transmitting utilities to join a Regional Transmission
Organization (RTO). H.R. 3406 requires transmitting utilities to join an RTO. In addition,
H.R. 3406 dictates standards for RTO structure. H.R. 2814 gives FERC authority to develop
voluntary RTOs.
Reacting to the price spikes in the Western United States in early 2001, most rate-
making legislation focuses on a return to cost-of-service based regulation. H.R. 264, H.R.
268, H.R. 1468, S. 80, and S. 287 would impose cost-of-service regulation for wholesale
sales of electricity. H.R. 238 and S. 26 would impose an intra regional wholesale price cap
or cost-of-service based rates. S. 597 and S. 764 would require either cost-of-service based
rates or load-differentiated rates. Load-differentiated rates reflect differences in the demand
for electric energy during various times of day, months, seasons, or other time periods.
H.R. 268, H.R. 1941, H.R. 1974, H.R. 3406, H.R. 2274, H.R. 2757, S. 80, S. 1068 and
Senate-passed H.R. 4 would give FERC wholesale refund authority. In most cases, this
allows FERC to order wholesalers to provide refunds to consumers if it is determined that
unjust and unreasonable rates have been charged. In addition, S. 2716 would increase civil
penalties for violations under the Federal Power Act.
Some have argued that the transmission and wholesale power markets cannot be
competitive without additional market transparency, or access to market information. S.
1231 and Senate-passed H.R. 4 require FERC to issue rules establishing an electronic
information system to provide information about the availability and price of wholesale
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electric energy and transmission services to FERC, state commissions, buyers and sellers of
wholesale electric energy, users of transmission services, and the public.
Legislation to repeal the Public Utility Holding Company Act has been introduced in
the 107th Congress. S. 206, S. 388, Senate-passed H.R. 4, H.R. 1101, and H.R. 3406 would
repeal PUHCA and give FERC additional authority. H.R. 381, H.R. 3406, S. 388, and S. 552
prospectively repeal Section 210 of the Public Utility Regulatory Policies Act, the section
that requires utilities to purchase power produced by certain small and renewable electric
generators. The Senate-passed H.R. 4 prospectively repeals Section 210 of PURPA if FERC
finds that a competitive market exists.
Several bills have been introduced to require net metering. Net metering allows
residential and small commercial distributed generation facilities to produce electricity for
their own use and sell excess electricity to the local distribution company. H.R. 954, H.R.
3089, S. 1403 and Senate-passed H.R. 4 would require local distribution companies to
provide net metering services for certain small electric generating systems using fuel cells
or renewable energy resources. H.R. 1045 and S. 933 would require local distribution
companies to provide interconnection for distributed generation.
Senate Debate. On April 25, 2002, the Senate passed the Energy Policy Act of
2002 (its version of H.R. 4). This included Senator Thomas’ amendments to S.Amdt. 2917
that affects the electricity provisions (S.Amdt. 3000, S.Amdt. 3001, S.Amdt. 3002, S.Amdt.
3003, S.Amdt. 3004, S.Amdt. 3012 and S.Amdt. 3006). These amendments were agreed
to by the Senate by voice vote on March 13 and 14, 2002. In general, Senator Thomas’
amendments would: give FERC additional review authority over certain electric utility
mergers; require FERC to apply cost-of-service rates when market-based rates are unjust,
unreasonable, unduly discriminatory or preferential; require an electric reliability
organization to develop and enforce mandatory reliability standards; provide access to the
transmission system for certain intermittent generators; and give states the authority to
prescribe and enforce laws regarding the application of the Consumer Protection Subtitle.
S.Amdt. 3917 also was included in the Senate-passed H.R. 4, maintaining the §210
mandatory purchase requirement of PURPA until FERC determines that qualifying facilities
have access to a competitive market.
In meetings of the Conference Committee, the House has offered a counter-proposal to
the Senate-passed H.R. 4 electricity provisions. The House proposal would, in part, create
an electric reliability organization, require FERC to issue rules on market transparency,
create federal transmission siting authority, create incentives for utilities to join RTOs, repeal
PUHCA with federal and state access to books and records, prospectively repeal the
mandatory purchase requirement of PURPA, and repeal FERC’s merger review authority.
For a complete description of H.R. 4, see CRS Report RL31427, Omnibus Energy
Legislation: H.R. 4 Side-by-side Comparison. For a listing of current electric utility
restructuring legislation, see CRS Report RL31210, Electric Utility Restructuring Legislation
in the 107th Congress.
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