Electricity: The Road Toward Restructuring

Electricity: The Road Toward Restructuring

Order Code IB10006
CRS Issue Brief for Congress
Received through the CRS Web
Electricity: The Road Toward Restructuring
Updated November 18, 2004
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
History of California Electricity Crisis
Price Caps
Rate Refunds
LEGISLATION

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Electricity: The Road Toward Restructuring
SUMMARY
The Public Utility Holding Company Act
issued December 20, 1999, established crite-
of 1935 (PUHCA) and the Federal Power Act
ria for forming transmission organizations.
(FPA) were enacted to eliminate unfair prac-
tices and other abuses by electricity and gas
Comprehensive electricity legislation
holding companies by requiring federal con-
involves three issues. The first is PUHCA
trol and regulation of interstate public utility
reform. Some electric utilities want PUHCA
holding companies. Prior to PUHCA, elec-
changed so they can more easily diversify
tricity holding companies were characterized
their assets. State regulators have expressed
as having excessive consumer rates, high
concerns that increased diversification could
debt-to-equity ratios, and unreliable service.
lead to abuses, including cross-subsidization.
PUHCA remained virtually unchanged for 50
Consumer groups have expressed concern that
years until enactment of the Public Utility
a repeal of PUHCA could exacerbate market
Regulatory Policies Act of 1978 (PURPA,
power abuses in a monopolistic industry
P.L. 95-617). PURPA was, in part, intended
where true competition does not yet exist.
to augment electric utility generation with
more efficiently produced electricity and to
The second issue is PURPA’s mandatory
provide equitable rates to electric consumers.
purchase requirement provisions. Many inves-
Utilities are required to buy all power pro-
tor-owned utilities support repeal of these
duced by qualifying facilities (QFs) at
provisions. They argue that their state regula-
“avoided cost.” QFs are exempt from regula-
tors’ “misguided” implementation of PURPA
tion under PUHCA and the FPA.
has forced them to pay contractually high
prices for power that they do not need. Oppo-
Electricity regulation was changed again
nents of this legislation argue that it would
in 1992 with passage of the Energy Policy Act
decrease competition and impede develop-
(EPACT, P.L. 102-486). The intent of Title 7
ment of renewable energy. The third is retail
of EPACT is to increase competition in the
wheeling. It involves allowing retail custom-
electric generating sector by creating new
ers to choose their electric generation supplier.
entities, called “exempt wholesale generators”
(EWGs), that can generate and sell electricity
Comprehensive energy legislation has
at wholesale without being regulated as utili-
passed the House and Senate. The House
ties under PUHCA. This title also provides
passed H.R. 6 on April 11, 2003. On July 31,
EWGs with a way to assure transmission of
2003, the Senate suspended debate on S. 14,
their wholesale power to their purchasers. The
inserted the text of H.R. 4 (107th Congress) as
effect of this act on the electric supply system
a substitute, and passed H.R. 6. A conference
is potentially more far-reaching than PURPA.
agreement was reached November 17, 2003,
and passed by the House the next day. H.R. 6
On April 24, 1996, the Federal Energy
includes an electricity title that would, in part,
Regulatory Commission (FERC) issued Or-
repeal PUHCA, would prospectively repeal
ders 888 and 889. FERC believed these rules
the mandatory purchase requirement under
would remedy undue discrimination in trans-
PURPA, and would create an electric reliabil-
mission services in interstate commerce and
ity organization. On June 15, 2004, H.R.
provide an orderly and fair transition to com-
4503, a comprehensive energy policy bill,
petitive bulk power markets. Order 2000,
passed the House.
Congressional Research Service ˜ The Library of Congress

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MOST RECENT DEVELOPMENTS
On June 15, 2004, H.R. 4503, a comprehensive energy policy bill was agreed to by the
House by a vote of 244-178. Conferees on the House and Senate omnibus energy bills (H.R.
6) met on November 17, 2003, and approved a conference report with numerous electricity
provisions. The Senate conferees voted 10-3 to approve an offer to the House conferees.
The House conferees approved a counteroffer by voice vote, and the House conferees’
counteroffer was accepted by eight of the Senate conferees. The House approved the
conference report (H.Rept. 108-375) on November 18, 2003. On November 21, 2003, a
cloture motion to limit debate on H.R. 6 failed in the Senate. (See also CRS Report
RL32178, Summary of Electricity Provisions in the Conference Report on H.R. 6.)
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. 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) 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).
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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.
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
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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 standard market design.
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
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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, which described the minimum
characteristics and functions of regional transmission organizations (RTOs) (see
[http://www.ferc.gov/legal/ferc-regs/land-docs/RM99-2A.pdf]). 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 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.
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) that presented a blueprint for creating a single RTO in the Northeast.
FERC has granted RTO status to three entities and conditional approval to four others.
On December 20, 2001, 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,
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Idaho, Montana, Oregon, Nevada, Wyoming, Utah and a small part of northern California
near the Oregon border. 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 Columbia. Other RTOs have received conditional
approval from FERC. Most recently, FERC conditionally approved the New England RTO
(ISO-NE) on March 24, 2004 (Docket Nos. RTO04-2-000, ER04-157-000,001, and EL01-
39-000). 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 (Docket Nos. RTO04-1-000 and ER04-
48-000). Arkansas-based SPP serves 4 million customers in all, or parts of, Arkansas,
Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, in Texas. FERC
conditionally approved SeTrans RTO and WestConnect RTO on October 10, 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 (see [http://www.ferc.gov/legal/ferc-regs/land-docs/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 an order (Docket No. RM01-
12-000) that stated FERC’s goals and process for creating Regional Transmission
Organizations.
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,
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/opinions/01pdf/
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00-568.pdf]. The conference report on H.R. 6, H.R. 4503, and S. 2095 would allow certain
utilities to give preferential treatment to native load customers.
Many groups assert that difficulty siting transmission lines is one reason that in the past
decade, there has been less transmission capacity added than generation capacity. H.R. 6,
as approved by the conference, H.R. 4503, and S. 2095 would provide for incentive-based
transmission rates. In addition, the conference agreement on H.R. 6, H.R. 4503, S. 2095, and
H.R. 1370 would allow transmission owners in certain instances to exercise the right of
eminent domain to site new transmission lines. (For a discussion on infrastructure
improvements, see CRS Report RL32075, Electric Reliability: Options for Electric
Transmission Infrastructure Improvements.)
S. 14, S. 475, S. 1754, S. 2014, S. 2095, S. 2236, the conference report on H.R. 6, H.R.
1370, H.R. 3004, and H.R. 4503 would 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; see
[http://www.ferc.gov/industries/electric/indus-act/smd/nopr/08-12-03-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 was 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.
On April 28, 2003, FERC staff issued Wholesale Power Market Platform, a White
Paper that intended to clarify FERC’s SMD proposal (see [http://www.ferc.gov/industries/
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electric/indus-act/smd/white_paper.pdf]). The White Paper responds to approximately 1000
sets of formal comments submitted 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 will require utilities to join an RTO or ISO. In the NOPR, FERC
proposed to assert jurisdiction over the transmission component of bundled retail service.
The White Paper reverses this position and states that the final rule will not assert new FERC
jurisdiction over bundled retail sales.
Some state officials have expressed concern that the proposed rule would infringe on
state authority. FERC responded to this in the White Paper by clarifying that the Final Rule
will not include a requirement for a minimum level of resource adequacy. In addition, the
final rule will eliminate the NOPR’s requirement that Firm Transmission Rights be
auctioned. The White Paper noted that each RTO or ISO will need to have a cost recovery
policy outlined in its tariff, but each region may differ on how participant funding will be
used. In addition, FERC stated that the final rule will allow for phased-implementation to
address regional differences.
The report language that accompanied the Omnibus Appropriations Bill for FY2003
(H.Rept. 108-10) asked the Department of Energy to analyze the SMD NOPR’s impact on
wholesale electricity prices, and the safety and reliability of generation transmission
facilities. The Department of Energy (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 an annual increase in electricity demand
of 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; in the non-SMD
case, 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 the consolidation of
control areas from the current level of 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 at 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
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with cost-based rates, the net result could be increased costs associated with wholesale
purchases, which would be passed through to retail customers. For some exporting regions
with cost-based rates, additional utility revenues from exports are expected to lead to lower
retail prices for the region under the SMD case. In contrast, in regions in which most states
have adopted retail choice, increased electricity exports are expected to lead to higher
market-clearing prices in the short-term markets and somewhat higher consumer prices.
However in areas such as California that are projected to see increased imports, lower
wholesale prices and lower prices for consumers are expected. DOE found that the
magnitude of the projected changes, both positive and negative, decrease through 2020.
Overall, DOE projects the net benefit for all consumers is about $1 billion per year over the
first six years, after factoring in the estimated $760 million per year and RTO costs. Over the
long-term (2016-2020), the net benefit is expected to be about $700 billion 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.
S. 14, as introduced, would have remanded the NOPR to FERC for reconsideration.
FERC would not be able to issue an SMD rulemaking before July 1, 2005. H.R. 6, as passed
by the Senate, did not include this provision. S. 954 would require Congress to approve of
any SMD rulemaking. The conference report on H.R. 6, H.R. 4503, and S. 2095 would
remand the rulemaking to FERC. FERC would not be able to issue a similar rule before
October 2006. For additional information on Standard Market Design, see CRS Report
RS21407.
Market Transparency. Some have argued that the wholesale power markets cannot
be competitive without additional market transparency for both generation and transmission.
S. 14, S. 475, S. 2095, the conference report on H.R. 6, H.R. 1254, and H.R. 4503 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. H.R. 1272 would require participants in the electric
markets to provide FERC with records of all transmission and sale transactions.
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.
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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 108th
Congress. For a summary of these bills and legislative action, see CRS Report RL31779 and
CRS Report RS21581. In October 2003, the Senate debated and defeated an amended
version of S. 139, the Climate Stewardship Act of 2003. Senate Admt. 2028, introduced by
Senators McCain and Lieberman, would cap emissions of greenhouse gases from electricity
generation, transportation, industrial, and commercial sectors at year 2000 levels in the year
2010. The vote was 43-55. For a summary and analysis of S. 139 and similar proposals, see
CRS Report RS21637.
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.”
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 (see [http://www.sec.gov/
news/testimony/021302tsich.htm]). However, as a result of Enron’s collapse, some in
Congress have taken a somewhat different view toward significantly amending or repealing
PUHCA (see [http://www.house.gov/commerce_democrats/press/107ltr129.htm]). 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 (Initial Decision Release No. 222 (File No. 3-10909) can be found at
[http://www.sec.gov/litigation/aljdec/id222bpm.htm]). In the case of Enron, PUHCA, and
many other laws, did not deter or prevent fraudulent filing of information with the SEC.
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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.
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.)

S. 14, S. 475, S. 2095, the conference agreement on H.R. 6, and H.R. 4503 would give
FERC and state commissions access to books and records.
PURPA
S. 475 and S. 688 and H.R. 1341 would prospectively repeal §210 of PURPA, the
mandatory purchase requirement provisions. S. 14, S. 2095, the conference agreement on
H.R. 6, and H.R. 4503 would also prospectively repeal §210 of PURPA but only when
certain competitive market conditions are met. Proponents of PURPA repeal — primarily
investor-owned utilities (IOUs) located in the Northeast and in California — argue that their
state regulators’ “misguided” implementation of PURPA in the early 1980s has forced them
to pay contractually high prices for power they do not need. They argue that, given the
current environment for cost-conscious competition, PURPA is outdated. The PURPA
Reform Group, which promotes IOU interests, strongly supports such bills by contending
that the current law’s mandatory purchase obligation was anti-competitive and anti-
consumer.
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Status of Electric Industry Restructuring Activity as of February 2003
Source: Energy Information Administration, [http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf].
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, and Oklahoma.
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, West Virginia, Wisconsin, and Wyoming.
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
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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
Some 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 108th Congress.
History of California Electricity Crisis
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
electric markets and market manipulation, 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. On March 26, 2003, FERC ordered an estimated $3.3
billion in refunds to California for unjust and unreasonable rates that were charged between
October 2000 and June 2001.
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Price Caps
As a result of the California electricity crisis, several bills were introduced in the 107th
Congress that would have imposed wholesale price caps in California, a return to cost-of-
service wholesale rate regulation or demand-based time-of-use rates. Additional bills have
been introduced in the 108th Congress. 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 were exerting market power by intentionally withholding
generating capacity to increase wholesale prices. Those opposed to price caps, including
President Bush, argue that price caps discourage investment in new generating facilities and
would further distort the wholesale electricity market.
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
(see [http://www.ferc.gov/industries/electric/indus-act/wem/2001/06-19-01.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 expired in September 2002.
On July 17, 2002, FERC issued a new price mitigation order for the Western markets
(Docket Number ER02-1656-000 et al.). Unlike the 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.
Rate Refunds
Under current law, FERC may order refunds for rates found to be unjust, unreasonable,
unduly discriminatory or preferential. However, the effective date of such refunds begins a
minimum of 60 days after the original complaint is filed with FERC (16 U.S.C.8 2 4e(b)).
H.R. 964 and H.R. 1272 would allow refunds to be retroactive to the date a rate complaint
is filed with FERC. S. 723 would require FERC to order refunds of at least $8.9 billion for
unjust and unreasonable rates charged between June 1, 2000 and June 19, 2001.
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LEGISLATION
H.R. 6 (Tauzin)
Title VI, in part, provides for incentive-based transmission rates, allows transmission
owners in certain instances to exercise the right of eminent domain to site new transmission
lines, allows transmission owners that do not belong to a regional transmission organization
to preferentially serve native load customers, creates an Electric Reliability Organization, and
gives new, but limited, authority to the Federal Energy Regulatory Commission (FERC) over
municipal and cooperative transmission systems. It repeals PUHCA and gives FERC and
state public utility commissions access to books and records, prospectively repeals the
mandatory purchase requirement of the Public Utility Regulatory Policies Act of 1978 if a
competitive wholesale market exists, and requires utilities to provide real-time rates and
time-of-use metering. It establishes market transparency rules, explicitly prohibits round-trip
trading, and significantly increases criminal penalties under the Federal Power Act.
Introduced April 7, 2003; referred to multiple committees. Passed House April 11, 2003;
passed Senate July 31, 2003. Conference agreement reached on November 17, 2003.
Conference report (H.Rept. 108-375) passed by House on November 18, 2003.
H.R. 964 (Ose)
Makes electric rate refunds retroactive to the date a complaint is filed with FERC.
Introduced February 27, 2003; referred to Committee on Energy and Commerce .
H.R. 1254 (Walden)
Requires 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. Prohibits round-trip electricity trading. Increases
criminal penalties under the Federal Power Act. Introduced March 12, 2003; referred to
Committee on Energy Commerce.
H.R. 1272 (Dingell)
Prohibits fraudulent, manipulative, or deceptive acts in electric and natural gas markets.
Provides for audit trails. Increases criminal and civil penalties under the Federal Power Act.
Makes electric rate refunds retroactive to the date a complaint is filed with FERC. Requires
FERC to review all market-based rates on annual basis. Introduced March 13, 2003; referred
to Committee on Energy and Commerce.
H.R. 1338 (Shadegg)
Amends the Federal Power Act to provide for federal and state coordination of
permitting for electric transmission facilities. Introduced March 18, 2003; referred to
Committee on Energy and Commerce.
H.R. 1341 (Stearns)
Prospectively repeals §210 of PURPA. Introduced March 1 18, 2003; referred to
Committee on Energy and Commerce.
H.R. 1370 (Wynn)
Establishes an Electric Reliability Organization. In some instances, allows
transmission companies to exercise the right of eminent domain to acquire transmission
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rights-of-way. Exempts regional transmission organizations from PUHCA. Introduced
March 19, 2003; referred to Committees on Energy, and Commerce and Ways and Means.
H.R. 1627 (Pickering)
Repeals PUHCA and gives FERC and state utility commissions access to books and
records. Introduced April 3, 2003; referred to Committee on Energy and Commerce.
H.R. 3004 (Dingell)
Creates an Electric Reliability Organization. Introduced September 4, 2003; referred
to Committee on Energy and Commerce.
H.R. 3506 (Filner)
Amends the Federal Power Act to allow a state to regulate wholesale sales of electricity
that is generated, transmitted, and distributed within that state. Introduced November 18,
2003; referred to Committee on Energy and Commerce.
H.R. 4503 (Barton)
Omnibus energy bill. Introduced June 3, 2004; referred to Committees on Energy and
Commerce, Science, Ways and Means, Transportation and Infrastructure, Financial Services,
Agriculture, and Budget. Passed House on June 15, 2004.
S. 14 (Domenici)
Comprehensive energy policy legislation. In part, creates an Electric Reliability
Organization. Remands the Standard Market Design NOPR to FERC and not allow FERC
to issue a final rule before July 1, 2005. Gives FERC additional authority to assure that
municipalities and coops charge transmission rates that are comparable to the rates the
municipalities and coops charge themselves (so-called FERC-Lite.) Requires FERC to issue
a rule on transmission pricing. Repeals §210 of PURPA when independently administered,
auction-based day ahead and real time markets exist. Requires utilities to offer time-of-use
rates and net-metering. Repeals PUHCA and gives FERC and state utility commissions
access to books and records. Requires FERC to establish an electronic information system
to provide market transparency. Prohibits slamming and cramming. Introduced April 30,
2003. On July 31, 2003, the Senate suspended debate on S. 14, and inserted the text of H.R.
4 from the 107th Congress as a substitute and passed H.R. 6.
S. 475 (Thomas)
Establishes an Electric Reliability Organization. Repeals PUHCA and gives FERC and
state utility commissions access to books and records. Prospectively repeals §210 of
PURPA. Requires 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. Prohibits round-trip trading. Makes
electric rate refunds retroactive to the date a complaint is filed with FERC. Introduced
February 27, 2003; referred to Committee on Energy and Natural Resources.
S. 681 (Cantwell)
Requires FERC to revoke market-based rates upon determination that effective
competition does not exist. Introduced March 21, 2003; referred to Committee on Energy
and Natural Resources.
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S. 688 (Graham)
Prospective repeal of §210 to of PURPA. Introduced March 21, 2003; referred to
Committee on Energy and Natural Resources.
S. 716 (Landrieu)
Establishes participant funding for transmission facilities. Requires FERC to establish
technical standards and procedures for transmission interconnection. Requires cooperative
and municipal utilities to provide transmission services with rates and conditions that are
comparable to what the cooperative or municipality charges itself. Introduced March 26,
2003; referred to Committee on Energy and Natural Resources.
S. 723 (Boxer)
Requires FERC to order refunds of at least $8.9 billion for unjust and unreasonable rates
charged between June 1, 2000 and June 19, 2001. Introduced March 26, 2003; referred to
Committee on Energy and Natural Resources.
S. 954 (Shelby)
Allows states to regulate bundled retail sales, including the transmission component.
Holders of existing wholesale contractual obligation would have preferential rights to
transmission capacity. Requires participant funding for certain new transmission facilities.
Congress would be required to approve any Standard Market Design proposed by FERC.
Introduced April 30, 2003; referred to Committee on Energy and Natural Resources.
S. 1754 (Jeffords)
In part, creates an Electric Reliability Organization. Allows for interstate compacts for
regional transmission planning. Establishes an Electricity Outage Investigation Board.
Creates a System Benefits Trust Fund Board. Allows for net metering and requires FERC
to promulgate interconnection standards. Introduced October 17, 2003; referred to
Committee on Energy and Natural Resources.
S. 2014 (Cantwell)
Creates an Electric Reliability Organization. Introduced January 21, 2004; referred to
Committee on Energy and Natural Resources.
S. 2015 (Cantwell)
Prohibits energy market manipulation. Introduced January 21, 2004; referred to
Committee on Energy and Natural Resources.
S. 2095 (Domenici)
Comprehensive energy legislation. Title XII is nearly identical to the electricity
provisions in the conference report to H.R. 6. In S. 2095, the third-party finance provision
which allows Western Area and Southwestern Power Marketing Administrations to go to
third parties to finance future expansions to the electricity grid, has been delayed to FY2005
as compared to FY2004 in H.R. 6 to avoid a Budget Act Point of Order on FY2004 spending.
Introduced February 12, 2004.
S. 2236 (Cantwell)
Creates an Electric Reliability Organization. Introduced March 25, 2004; placed on
Senate Legislative Calendar under General Orders. Calendar No. 465.
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