Electric Utility Restructuring: Maintaining Bulk Power System Reliability

CRS Report for Congress
Electric Utility Restructuring:
Maintaining Bulk Power System Reliability
Updated February 1, 2005
Amy Abel
Specialist in Energy Policy
Resources, Science, and Industry Division
Larry Parker
Specialist in Energy Policy
Resources, Science, and Industry Division
Steven C. Stitt
Research Fellow
Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

Electric Utility Restructuring:
Maintaining Bulk Power System Reliability
In recent years, reliability of the U.S. bulk power system (electricity generation
and high voltage transmission) has become a high priority. California’s attempt at
electric utility restructuring, the Enron bankruptcy, and the August 2003 blackout
have increased the concern about maintaining reliability at a high level while trying
to achieve the desired benefits of a market-oriented electric power system.
Maintaining reliability is important because power interruptions result in economic
losses costing over an estimated $100 billion per year in the United States.
Many attribute the utility industry problems as a loss in reliability brought on
by electric utility restructuring. Restructuring advocates assert that functional
changes in the electric utility industry resulting from restructuring are designed to add
certainty and therefore improve reliability while providing lower prices to consumers.
Functional changes such as improved planning and coordination, the ability to attract
new market participants, increased redundancy, and the development of ancillary
service markets all tend to lower risk and ultimately improve reliability.
Restructuring opponents argue that resulting functional changes in the industry tend
to increase uncertainty. These changes include added complexity, added risk for
investors, unclear responsibilities for reliability, and the potential to manipulate
markets in ways that may cause power supply instability.
Most experts conclude that industry changes from restructuring designed to
improve reliability have not been realized while the factors tending to degrade
reliability are having an effect. In general, the existing bulk power system was
designed for operation by vertically integrated utilities with minimally required
transmission connections between them. Restructuring of the electric utility industry
requires that an ample set of suppliers and consumers negotiate transactions across
a robust transmission system with high capacity. Therefore, the reliability of the
existing bulk power system appears to be degrading because it was not designed to
operate in a restructured environment and market procedures have not been
developed to overcome these deficiencies.
This report will be updated as events warrant.

In troduction ......................................................1
Reliability Definition...............................................3
Reliability Improvements............................................4
Predicting Reliability ..............................................5
Overview of Electric Utility Restructuring..............................5
Risk Factors Created by Industry Changes Made During Restructuring.......10
Institutional Structure..........................................10
Prior to Restructuring......................................10
Transition to Restructuring.................................10
Risk Factors.............................................10
Return on Investment..........................................12
Prior to Restructuring......................................12
Transition to Restructuring.................................12
Risk Factors.............................................12
Wholesale Markets and Competition .............................13
Prior to Restructuring......................................13
Transition to Restructuring.................................13
Risk Factors.............................................13
Reliability Responsibilities.....................................14
Prior to Restructuring......................................14
Transition to Restructuring.................................15
Risk Factors.............................................15
Customer Base...............................................15
Prior to Restructuring......................................15
Transition to Restructuring.................................15
Risk Factors.............................................15
Service Obligations...........................................16
Prior to Restructuring......................................16
Transition to Restructuring.................................16
Risk Factors.............................................16
Summary ...................................................17
Federal and State Jurisdiction.......................................18
Proposed Federal Legislative Solutions................................18
Participation in Regional Transmission Organizations................19
Purpose .................................................19
Issues ..................................................19
FERC Jurisdiction Over Bulk Power System Reliability..............20
Purpose .................................................20
Issues ..................................................20
Transmission Siting...........................................20
Purpose .................................................20

Public Utility Holding Company Act Repeal........................21
Purpose .................................................21
Issues ..................................................21
Mandatory and Enforceable Reliability Standards....................21
Purpose .................................................22
Issues ..................................................22
Responsibility for Standards Development.........................22
Purpose .................................................23
Issues ..................................................23
Conclusion ......................................................24
List of Figures
Figure 1. Traditional Vertically Integrated Utilities........................6
Figure 2. Traditional Regulatory Structure for Vertically Integrated Utilities...7
Figure 3. Main Participants in Electric Industry Restructuring (Generalized)...8
Figure 4. Proposed Regulatory Structure for Restructured
Electric Utility Industry.........................................9
List of Tables
Table 1. Summary of Factors from Functional Changes in the Electric Utility
Industry Resulting from Restructuring That Can Affect Reliability......17
Table 2. Summary of Provisions in Proposed Legislation That Could
Affect Reliability.............................................23
Note: Steven Stitt was a Research Fellow from the Bureau of Reclamation.

Electric Utility Restructuring:
Maintaining Bulk Power System Reliability
As a result of a devastating outage in the northeastern portion of the United
States during November 1965, the North American Electric Reliability Council
(NERC) was formed to promote reliability of the interconnected electric power
system. NERC’s membership consists of representatives from utilities across North
America and provides a forum for the electric utility industry to develop policies,
standards, and guidelines designed to maintain reliability at a high level. Ten
regional councils have been formed to address reliability issues within various
regions of the United States, Canada, and Mexico. In addition, NERC has assumed
a role as a coordinator for the electric utility sector to address security threats and
provide critical infrastructure protection. NERC membership has always been
voluntary. Prior to restructuring, no federal legislation was used to promote
organizations, such as NERC, tasked with maintaining reliability of the bulk power1
system. Reliability was dictated at the retail level by laws enacted by state
legislators and enforced by state Public Utility Commissions (PUCs).
Restructuring of the electric utility industry was initiated at the federal level by
Congress through passage of the 1978 Public Utility Regulatory Policies Act
(PURPA)2 and the 1992 Energy Policy Act (EPACT).3 The restructuring effort is
intended to promote more competition in the industry and ultimately to lower the cost
of electricity for customers in the United States. Reliability of the bulk power system4
was a concern for federal legislators even before the passage of EPACT in 1992.
Many industry experts now assert that restructuring the electric utility industry makes
it difficult to maintain reliability, and this reliability problem is not being addressed

1 The bulk power system is defined as the powerplants, the high voltage transmission
system, and associated equipment. The bulk power system does not normally include the
distribution substations and lower voltage networks that distribute electricity to customers
in a particular city or region. The reliability issues discussed in this report will not include
outages within low voltage distribution systems, which are generally localized but have the
highest probability of occurrence.
2 P.L. 95-617.
3 P.L. 102-486; CRS Report RL32728, Electric Utility Regulatory Reform: Issues for the

109th Congress, by Amy Abel.

4 U.S. Congress, House Committee on Energy and Commerce, Electricity: A New
Regulatory Order?, Committee Print 102-F, Report prepared by CRS, Washington, U.S.
Government Printing Office, June 1991, pages 228-233.

adequately.5 Several assert that the pressures of competition have already lowered
the level of reliability.6 Others contend that restructuring policy changes must be
completed to improve reliability.7 At issue is whether the desired reliability levels
can be maintained or even enhanced as electric industry restructuring continues.
Because the Federal Power Act of 1935 (FPA) gave the federal government
economic regulatory authority over wholesale transactions across the bulk power
system, reliability has become an important concern for Congress as new electricity
legislation is designed to encourage competition and improve performance within the
electric utility industry.
A total of 24 states and the District of Columbia have enacted legislation or
issued orders that provide retail access to multiple suppliers for electricity customers.
Most of those states are in the northeastern portion of the United States. Five of
those states have now delayed their process to provide retail access: Arkansas,
Montana, Nevada, New Mexico, and Oklahoma. A total of 27 states are not actively
pursuing retail access. Most of these states are in the southeastern United States.
California was the first state to implement retail access in 1996, but that state has
suspended competitive market operations indefinitely.8
Several events occurred in recent years that have caused many to conclude that
restructuring of the electric utility industry will result in an unacceptable loss of
reliability. First, the electric utility restructuring in California resulted in forced
blackouts and Federal Energy Regulatory Commission (FERC) investigations into
market manipulation. California’s attempt9 to restructure that state’s utility system
has been analyzed by many.10 There are numerous reasons for the resulting market
and reliability problems. Some argue these problems indicate what will happen in
the future if the United States continues to restructure the electric utility industry.
However, others assert that California made many mistakes in its approach to
restructuring. Proponents of restructuring contend there is a correct approach that
will provide competition while maintaining reliability. These proponents of

5 Loehr, George C., “A Market Solution to Reliability?,” The Electricity Journal, June 1998,
p. 81; Boston, Terry, “Electricity: Lifeline or bottom line?,” Forum for Applied Research
and Public Policy, Knoxville, Summer 2000, Vol 15, Issue 2, p. 56.
6 Boschee, Pam, “Changing marketplace jeopardizes transmission reliability,” Electric Light
& Power, July 1998, p. 15; Casazza, Jack, “Electric power supply reliability declines, costs
rise,” IEEE-USA News & Views, September 2001, p. 1, [http://www.todaysengineer.org/
archives/pp_archives/j an01/index.htm] .
7 Edison Electric Institute, “National Energy Policy — Let’s Get It Right,” Washington, DC,
February 2002.
8 For more information on the status of state restructuring plans refer Energy Information
Administration website, [http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf].
9 California was the first state to implement bulk power system wholesale competition.
Even though many changes brought on by restructuring are still in place, the wholesale
competitive energy markets have been abandoned.
10 Congressional Budget Office, “Causes and Lessons of the California Electricity Crisis,”
September 2001.

restructuring believe the nation should continue the restructuring process and learn
from California’s experience.
The collapse of Enron is another indicator to some that restructuring of the
electric utility industry could result in a loss of reliability. Enron’s bankruptcy did
not result in blackouts anywhere in the United States (See Appendix A); however,
some of Enron’s trading practices in California may have contributed to blackouts
during that state’s energy crisis.11 Some have concluded that Enron’s collapse was
primarily due to poor business practices and should not be blamed on industry
restructuring. 12
The August 2003 blackout once again focused concerns on reliability of the U.S.
electric power system as a high priority. When large scale problems in the electric
utility industry occur, there is an immediate reaction by the general public,
legislators, and the Administration. Numerous studies have analyzed power system
outages to determine how to avoid them in the future.13
To consider how restructuring affects reliability, this report will first reference
the NERC definition of reliability and discuss the relationship between maximizing
reliability and minimizing uncertainty. Factors that increase or decrease uncertainty
will be identified. Uncertainty factors that result from the changes promoted by
industry during electric utility restructuring will be identified. Finally, reliability
issues addressed by proposed legislation will be discussed.
Reliability Definition
Reliability of the electric grid has been defined by NERC in terms of two
functional aspects.14 These include:
Adequacy — the ability of the electric system to supply the aggregate electrical
demand and energy requirements of the customers at all times, taking into
account scheduled and reasonably expected unscheduled outages.
Security — the ability of the electric system to withstand sudden disturbances
such as electric short circuits or unanticipated loss of system elements.

11 Yoder, Christian and Hall, Stephen, “Trader Strategies in the California Wholesale Power
Markets/ISO Sanctions,”Enron Memos available on FERC website, December 6, 2002,
[http://www.ferc.gov/industries/electric/indus-act/wem/pa02-2/12-06-00.pdf], and December

8, 2002, [http://www.ferc.gov/industries/electric/indus-act/wem/pa02-2/12-08-00.pdf].

12 Wood, Pat III, “Implications of Enron’s Collapse on Energy Markets,” FERC, Testimony
before Senate Committee on Energy and Natural Resources, January 29, 2002,
[ h t t p : / / www.f e r c .gov/ p r e ss-r oom/ c t -ar chi ves/ 2002/ 01-29-02-wood.pdf ] .
13 Department of Energy, “Report of the U.S. Department of Energy’s Power Outage Study
Team,” Washington, DC: U.S. Department of Energy, March 2000.
14 North American Electric Reliability Council, “Reliability Concepts,” February 1985, See
the NERC website, [http://www.nerc.com/~filez/reports.html].

In considering these two functional aspects, it is important to consider the
phrase “at all times” used to describe the “adequacy” of the electric grid. Since there
is no storage capability on the grid, supply must meet demand at every moment in
time. If total supply does not meet demand, then the electric grid will respond
automatically to restore the balance. A critical imbalance can happen within seconds
after a large block of power is disconnected or added to the system. Since there are
no real restrictions on the fluctuations of demand on the electric grid, and customers
may change their requirements for power at any time by simply throwing a switch,
imbalance between supply and demand occurs on a regular basis. Changes in overall
supply must respond within minutes to match each demand change. Under normal
conditions, predictions of load are accurate and demand changes that vary from
scheduled predictions are small so the imbalance is restored within minutes.
Reliability Improvements
Reliability improvements to the bulk power system are made, in general, by
minimizing risk and taking away uncertainty. This implies that all potential
operating conditions are known and anticipated. If all potential operating conditions
of the bulk power system can be anticipated, then equipment can be designed,
constructed, and operated to minimize uncertainty. When all known conditions are
identified and addressed, then reliability is maximized. Conditions that must be
anticipated include variations in weather, fuel supplies, population, and industrial
loads, which make bulk power system control a complex operation. In spite of the
difficulty, the electric utility industry has been dealing with these issues for many
years, and industry’s reliability record implies the capability to predict these types of
variations has been adequate and, in many cases, excellent.
There are two basic options for improving reliability. The first option is to
construct the bulk power system with a high level of “adequacy” using large
generation and transmission capability. Under this scenario, risk and uncertainty are
minimized because the bulk power system is constructed to handle stresses well
beyond what are predicted to occur. Unfortunately, the cost of this option is high and
the redundancy in the infrastructure does not contribute to increased electricity
production. The second reliability improvement option is to improve the operational
methods or efficiency of the power system. Demand management is an example of
operational methods that limit or interrupt loads when necessary to improve
reliability. Demand management occurs when a customer allows the utility to shut
down electric services to maintain the balance between generation and load. Another
example of the efficiency improvement option is the training of operators in
procedures to avoid outages or provide quick recovery when outages occur. Risk and
uncertainty are overcome by operating the existing bulk power system in an efficient
way. Cost is reduced by using the second option, but reliability is not assured.
Realistically, some combination of the above two options probably is needed to
reduce risk and uncertainty and ultimately improve reliability. In both cases, the
uncertainty and risks to the bulk power system must be identified and then
eliminated. As the risk level rises, the potential for problems increases and reliability
degrades. Ideally, the added risks are identified and addressed before actual

problems occur. As the risks are eliminated, the potential for problems decreases and
reliability is improved.
Predicting Reliability
It is difficult to predict reliability performance. Measuring reliability after the
fact is easily accomplished by counting the number of times blackouts or other
outages occur. Predicting that a particular system will be reliable in the future is
much more difficult. Rather than quantifying reliability measures, this report will
consider changes to the bulk power system that are adding or taking away risk and
uncertainty. When uncertainty is added, reliability is decreased and problems may
occur. Conversely, if uncertainty is removed, reliability is increased and potential
problems have been eliminated.
The traditional electric power system has provided reliability that is envied in
many other parts of the world. Therefore, this report will further assume that
reliability levels provided by the U.S. electric utility system before restructuring can
be used as a benchmark. That benchmark will be considered the desired minimum
standard for reliability. The report will first look at changes in uncertainty and risk
to the bulk power system that have occurred since restructuring and wholesale
competition was first introduced by EPACT in 1992. Finally, the report will consider
how proposed legislation could affect uncertainty.
Overview of Electric Utility Restructuring
In order to understand the discussions that follow, a brief overview of
restructuring changes occurring within the electric utility industry is necessary.
Figure 1 provides a simple view of the traditional industry structure before
competition was introduced. The U.S. electric utility industry consisted of
approximately 200 “vertically integrated” utilities that provided generation,
transmission, and distribution services. The figure depicts two such utilities with a
transmission connection between them. The utilities each have their own customers
in their particular control areas.15 The utility control area was a geographic area
within one state franchised to the utility by the state government.

15 The utility control area contained all the bulk power system equipment owned by the
utility. Within the utility control area, customers received electric power only from that
utility. The control area was also referred to as the franchised area.

Figure 1. Traditional Vertically Integrated
Source: Congressional Research Service.
The two utilities in Figure 1 have a single transmission connection between
them which represents the numerous transmission connections between the
traditional vertically integrated utilities. Beginning in the 1930’s, utilities generally
developed enough generation capacity in their own control areas to provide for all
their own customers. Only small amounts of electricity were purchased at a
wholesale level across these transmission connections between utilities. During the
last quarter of the 20th century, utilities became more and more dependent on
wholesale purchases across the transmission connections as other factors drove up
the cost of providing generation internal to their control areas. In some cases,
utilities constructed large, remotely-located and jointly-owned powerplants requiring
transmission of electricity over long distances to their customers. Greater efficiency
was achieved because the transmission connections allowed utilities to help each
other under changing load conditions without having their own redundant generating
Figure 2 shows the traditional regulatory structure for the “vertically integrated”
utilities. In return for providing service to all retail customers within a
geographically defined control area, utilities received a monopoly status across the
control area. The utility rates for retail customers16 were generally regulated by a
state public utilities commission (PUC). The rates were set to guarantee the utility,
and its investors, revenue17 sufficient to achieve a fair rate of return (ROR). The
rates provided dividends and funded improvements, operations, and maintenance
activities.18 State PUCs enforced laws passed by the individual state legislatures that

16 Retail customers are the ultimate consumers of electricity, while wholesale customers
purchase electricity for resale to others.
17 Also referred to as a “revenue requirement.”
18 Most of the industry consisted of investor-owned utilities with a ROR regulated by the
state PUC; however, approximately 25% of the industry includes public power utilities that

set quality of service standards for electricity. The state laws vary, but they generally
allow the commissions to order service improvements, investigate the methods
employed by utilities to provide service, and to order “such reasonable improvements
as will best promote the public interest, preserve the public health and protect those
using such gas or electric service.”19 In general, standards were set at the retail level
for the amount of time allowed to restore service after an outage, for the required
voltage stability, and for the number of outages allowed in a particular time frame.
The utilities worked to identify improvements required to maintain quality of service,
and the commissions reviewed and authorized costs required to make improvements.
Figure 2. Traditional Regulatory Structure for
Vertically Integrated Utilities
Source: Congressional Research Service.
The Federal Power Act (FPA) of 1935 provides the federal government with the
authority to regulate “interstate” transmission and the contracts between utilities for
wholesale generation. FERC regulates the wholesale electricity market, but these
regulations, prior to restructuring, were primarily economic and did not focus on
reliability of the power system. The Securities and Exchange Commission (SEC)

18 (...continued)
are non-profit and operated to recover costs. These utilities are owned federally, by a state,
a city (municipality), or a rural cooperative.
19 N.Y. Pub.Serv.Law sec. 66(2) (McKinney 1989). See also D.C. Code Ann. Sec. 43-1001;
general commission powers include “power to order reasonable improvements as will
reasonably promote the public interest” and power “to prescribe from time to time the
efficiency of the electric supply system.” See New York State Public Service Commission,

regulates the financial transactions of the industry. Reliability standards have been
the responsibility of NERC. NERC, whose membership is taken from the utility
industry, provides operational standards that all utilities voluntarily follow. Larger
utilities have tended to participate more heavily in NERC since their liabilities for
poor reliability are much greater. Several voluntary methods are used to encourage
compliance with the voluntary standards, such as publishing compliance reports that
recognize high performance levels.
Figure 3. Main Participants in Electric Industry Restructuring
Source: Congressional Research Service.
Beginning with the passage of EPACT in 1992, the structure of the electric
utility industry began to change. Figure 3 shows the main participants in the present-
day structure. The structure is designed to provide competition within both retail and
wholesale markets. In order to accomplish this, the classic vertically integrated
utility has been broken into, at most, four companies. First, a separate transmission
company has been formed by many utilities. The separate transmission company is
generally required by FERC to assure open and fair transmission access without
giving preference to any energy supplier. In some cases, vertically integrated utilities
have become both a transmission and distribution company by selling their
generation assets. Figure 3 shows how service to retail customers is provided, in
some cases, by forming a separate distribution company. The powerplants, owned
previously by the utility, are sold to one or more generation owners. Finally, a
marketing company provides the financial connection between the generation
owners, the transmission owners, and the distribution companies. The ultimate goal
is to provide retail customers the ability to purchase electricity from any electric
supplier, either a marketer without its own generation capacity or an electric supplier
that owns generating capacity. The transmission owner and distribution owner

receive fees for the usage of their systems, but fair competition between the
generation owners will dictate how the transmission system is used.
Figure 4. Proposed Regulatory Structure for
Restructured Electric Utility Industry
Source: Congressional Research Service.
Proposed legislation would authorize the regulatory structure for the electric
utility industry shown in Figure 4. The goal of the legislation is to improve bulk
power system efficiency and promote competition. FERC’s Order 2000 encouraged
the formation of Regional Transmission Organizations (RTOs) that would provide
a vehicle for transition to competitive markets for wholesale electricity. RTOs are
expected to provide both operational and planning functions for a group of generation
and transmission owners. Proposals also advocate the formation of an Electric
Reliability Organization (ERO) based on the traditional NERC structure. An ERO
would develop mandatory standards for all activities on the bulk power system.
Violation of mandatory standards would result in penalties, and the threat of penalties
might encourage participants to maintain reliability features even when the standards
were not perceived as economically beneficial to the transmission owner. State
PUCs would continue to regulate the retail markets and protect retail customers.

Risk Factors Created by Industry Changes Made
During Restructuring
As a result of restructuring activities in the electric utility industry, several
changes are occurring that have the potential to affect reliability. The various
changes can be grouped into the following six areas:
1. Institutional structure
2. Return on investments
3. Wholesale markets and competition
4. Reliability responsibilities
5. Retail customer base
6. Retail service obligations
For each of these six areas, this report will compare functionality before and
after restructuring. Risk factors associated with the changes that may contribute to
increased or decreased reliability are discussed. Some of the risk factors identified
are projected for the future while others are already occurring. A summary of all
identified risk factors is provided in Table 1 at the end of this section.
Institutional Structure
Prior to Restructuring. Prior to restructuring, the electric utility industry had
a comparatively simple structure (See Figure 1). Utilities were vertically integrated.
Each utility owned a major portion of the bulk power system (generation and high-
voltage transmission) within its control area, and the utility was required to support
the retail customers who were connected to the distribution system in its control area.
Transition to Restructuring. As restructuring occurs, vertically integrated
utilities give way to multiple companies providing multiple individual services
(Figure 3). In FERC Order 888, electric services, which previously were bundled
into one product, are now being unbundled. Ideally, the unbundling will restructure
the industry such that multiple companies provide generation, transmission, and
distribution services, and marketing companies will link suppliers with users in
competitive markets. NERC has developed a reliability model that can be used as
a basic guide for participants in competitive markets.20 The model shows
relationships among 11 various functions performed by individual companies or
entities in a competitive market.
Risk Factors. FERC hopes to decrease risk and improve reliability by
providing centralized coordinators or Regional Transmission Organizations (RTOs).
FERC Order 200021 proposed that RTOs be formed to provide centralized

20 Control Area Criteria Task Force, “The NERC Functional Model — Functions and
Relationships for Interconnected Systems Operation and Planning,” NERC, Jan. 20, 2002,
ftp://www.nerc.com/pub/sys/all_updl/oc/cactf/ CACT F-Final-Report-Functional-M o d e l.pdf.
21 FERC, Docket RM99-2-000,

coordination functions. The RTO is expected to oversee operations and planning
functions covering large, multi-state regions of the bulk power system in the United
States. This coordination could eliminate the multiple control centers for each
individual utility that existed prior to restructuring by replacing them with a
coordinator to oversee the entire regional area. As an independent coordinator, the
RTO would identify reliability problems at a regional level without bias toward a
particular market participant. FERC has argued that the broader RTO view could
provide a more efficient approach to maintaining reliability in the region.
The FERC RTO policy has been difficult to implement. In some cases, industry
participants are reluctant to proceed, while in other cases participants have faced
obstacles in implementing the RTO policy. FERC has granted RTO status to three
entities. On December 20, 2001, FERC granted RTO status to the Midwest
Independent Transmission System Operator (MISO).22 On September 18, 2002,
FERC approved the RTO West proposal.23 RTO West includes all, or part of,
Washington, Idaho, Montana, Oregon, Nevada, Wyoming, and Utah, as well as a
small part of northern California near the Oregon border. FERC granted PJM RTO
status on December 19, 2002.24 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. FERC
conditionally approved SeTrans RTO and WestConnect RTO on October, 9, 2002.25
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.
The addition of many new companies with new responsibilities makes the
coordination task complex. One example of failed coordination, from the California
perspective, was controlling maintenance schedules of generators. After most
California utilities sold their generation facilities to independent power producers,
the California ISO had no real control over units taken out of service for
maintenance. In order to encourage generators to return to service, the California
ISO developed a website that provides public access to generator outage schedules.26
Eventually, FERC provided the ISO with the authority to demand outage schedules
from generators. Allowing these schedules to be driven only by market mechanisms
resulted in allegations that several powerplants were taken out of service based on
market decisions rather than on predicted system needs for generation.

21 (...continued)
[ h t t p : / / www.f e r c .gov/ l e ga l / f er c-r e gs / l a nd-docs/ RM99-2A.pdf ] .
22 FERC, Docket RTO1-87-000.
23 FERC, Dockets RT01-35-005 and RT01-35-007.
24 FERC, Dockets RT01-2-001 and RT01-2-002.
25 FERC, Dockets EL02-101-000, RTO2-1-000 and EL02-9-000
26 California ISO public website, [http://www.caiso.com/unitstatus/index.cgi].

Return on Investment
Prior to Restructuring. Before restructuring began, the return on investment
for a vertically integrated utility was primarily dependent upon retail rates that were
regulated by the state PUC. Because the return was regulated, the risk associated
with investment was relatively low. The advantage of the process was a consistent,
and predictable, rate-of-return for the utility. Therefore, the financial risk to utility
investors for capital improvements was relatively low.
Transition to Restructuring. Restructuring directs companies to participate
in competitive generation markets. The responsibility for obtaining a return on
investments is now dependent on performance in a competitive market. If a company
builds or purchases a new powerplant, the return on that investment will depend on
market-based rates. The company’s ability to analyze the market is a key factor in
providing investors with an acceptable rate of return (ROR).
Risk Factors. Reliability improvements result when a profitable rate of return
is achieved by companies providing good quality service in regions where there is a
demand for power. The potential to receive a profitable rate of return dictated by
market-based rates is expected to attract a new set of more efficient participants to
electricity markets. It is argued that these participants will provide new investments
in the bulk power system that otherwise would not be available. Such new
investments would hold the potential to not only improve the reliability of the power
system, but to provide technology improvements as well.
The transmission portion of the bulk power system has been characterized by
a lack of investment in recent years. According to a study sponsored by the Edison
Electric Institute (EEI), average transmission system growth exceeded the growth in
summer peak usage between 1979 and 1989, when both were approximately 3% per
year.27 Since that time, the transmission system has grown an average of
approximately 0.5% per year while the summer peak usage has grown an average of
approximately 2.5% percent per year. The cost to maintain the current level of
adequacy for the next 10 years is estimated at $56 billion in investment.
In another EEI study, two primary barriers to building new transmission lines
were identified.28 First, the study shows that difficulties in siting transmission lines
have discouraged investors. Second, the study asserts that adequate return on equity
(ROE) for investors does not exist. There are several reasons provided for the lack
of financial incentives, which include uncertainty about rate caps, uncertainty about

27 Hirst, Eric and Kirby, Brendan, “Transmission Planning for a Restructuring U.S.
Electricity Industry,” Consultants, Oak Ridge, Tennessee, Funded by Edison Electric
Institute, Washington, D.C., June 2001, [http://www.eei.org/industry_issues/energy_
infrastructure/transmissi on/transmission_hirst.pdf].
28 Hirst, Eric, “Expanding U.S. Transmission Capacity,” Consultant, Oak Ridge, Tennessee,
Funded by Edison Electric Institute, Washington, D.C., August 2000, [http://www.eei.org/

RTO rate methodology, state and federal regulatory changes, and lower FERC-
recommended ROE.29
Wholesale Markets and Competition
Prior to Restructuring. Wholesale markets, prior to restructuring, accounted
for a relatively small amount of the entire electricity production in the United States.
Utilities normally performed system planning with the goal of providing enough
generation internal to their control area to supply a high percentage of their own
customers with electricity (see Figure 1). In many cases, the wholesale markets were
characterized by long term, fairly stable contracts between utilities to take advantage
of seasonal variations.
Transition to Restructuring. During restructuring, the number and size of
transactions occurring in the wholesale market have increased dramatically. The
increase in the number of wholesale market transactions is a direct result of the
unbundling of the generation services. Generation and transmission services are now
generally sold separately. The number of merchant powerplants30 is increasing and
contributing to the increased number of wholesale market transactions. Today’s
wholesale markets are characterized by contracts with much shorter time frames that
use day-ahead and hour-ahead markets.
Risk Factors. The increase in market activity is characteristic of a healthy,
growing market that should support improved reliability. The economic health of the
market supports reliability by encouraging new investments where demands for
transmission and generation resources are high. The increased number of participants
creates more opportunities to receive assistance during emergencies and provides
greater redundancy.
A wholesale market development that improves reliability (by decreasing risk)
is the implementation of ancillary services markets.31 Ancillary services have been
identified as an operational commodity that needs to be purchased by an independent
system operator for wholesale consumers and are used to maintain transmission

29 In the EEI study, “Expanding U.S. Transmission Capacity,” the author cites two California
cases where FERC granted ROE that was approximately 2% below the ROE granted under
state regulation.
30 Merchant powerplants sell generation and ancillary services as commodities into
electricity markets at market-based rates in an effort to provide the highest possible ROR
for their company investors.
31 Ancillary services are both generation and voltage services that are required to support
reliability of the power system. Services include spinning reserves that can be used when
generation is needed quickly, generation whose power output can be regulated up or down
automatically for changing load conditions, generation that can be started and placed on-line
quickly, loads that can be taken off-line quickly, generation that can be started without any
outside power source (black-start), and generation that can provide automatic control of
system voltage.

system reliability.32 Ancillary service markets provide a method to value such
services and encourage their production. FERC proposed in Order 2000 that RTOs
be given the responsibility of setting requirements for ancillary services.
Although active markets are assumed to promote reliability, their complexity,
number of transactions, and short time frames represent a challenge to the reliability
of the bulk power system. All of these factors tend to contribute to increased
volatility and uncertainty. Therefore, it is possible for a marketer to initiate
transactions that push the bulk power system closer to capability limits because
proper system studies are not performed. Transmission system congestion results
when bulk power transactions force transmission system operation beyond capacity
limits. This is a problem because the wholesale transactions focus on matching
desired suppliers with consumers and do not give as much consideration to the
resulting transmission system congestion.
EEI reported that transmission congestion grew by more than 200% between
August 1999 and August 2000.33 A U.S. Department of Energy (DOE) study
determined transmission congestion in four U.S. regions (California, PJM34, New
York, and New England) cost consumers $500 million annually.35 In the study, DOE
made over 50 recommendations that would improve the bulk power transmission
system to facilitate the development of competitive wholesale electric markets.
Increased coordination and tools are required to make sure numerous transactions
performed in the short term can be handled by the transmission system.
Reliability Responsibilities
Prior to Restructuring. Prior to electric utility restructuring, the
responsibilities for reliability were very clearly given to the individual utilities. As
discussed previously, NERC was formed to provide a format for utilities to join
together in developing reliability standards for the operation of the bulk power
system. The utility owners knew that reliability of the bulk power system depended
on each utility following certain standards. The standards developed were based on
a voluntary system that worked well during the last three decades of the 20th century
(See Figure 3). Quality-of-service laws were passed by most state legislatures and
enforced by the state PUCs to ensure reliability of retail supplies. When a utility
failed to meet the standards, some corrective action was taken by the utility and the

32 U.S. Department of Energy, “Maintaining Reliability in a Competitive U.S. Electric
Industry,” Final Report of the Task Force on Electric System Reliability, September 29,


33 Edison Electric Institute,”The Living Grid — Evolving to Meet the Needs of America,”
Power, Washington, D.C., July 2001 issue.
34 PJM Interconnection, L.L.C. (“PJM”) is a limited liability company which provides
electric service to customers in Pennsylvania, New Jersey, Maryland, Delaware, the District
of Columbia, and Virginia’s eastern shore.
35 U.S. Department of Energy, “National Transmission Grid Study,” May 2002,
[ h t t p : / / www.eh.doe.gov/ n t gs/ ] .

PUC to improve local reliability. Most reliability problems occurred in the local
distribution systems rather than within the bulk power system.
Transition to Restructuring. During restructuring, the electric utility
industry has initiated several changes to address new reliability responsibilities for
competitive entities. NERC has initiated a transformation from a voluntary
organization to a self-regulatory organization. DOE, FERC, and the utility industry
are all working to provide guidance and procedures that may be used by regulators
and participants in developing competitive markets.
Risk Factors. Reliability responsibilities during restructuring are much more
difficult to determine. The increased number of participants create additional risk.
A new set of participants that market electricity enter and leave the market on an
irregular basis. While separation between the market and those responsible for
reliability must be achieved to avoid market abuse, the coordination between various
participants must continue to achieve high levels of reliability. The task force
commissioned by DOE found “uncertainty regarding statutory and regulatory
authority over reliability management.”36
Customer Base
Prior to Restructuring. Prior to restructuring, the customer base for a
regulated utility was determined by the utility control area. The utility was obligated
to provide service to all retail customers in the control area. As mentioned
previously, the utility received monopoly status from the state PUC as compensation
for taking on the obligation to serve all customers. The utility estimated customer
demands based on weather, industrial activities, and projected growth. Planning
studies were normally employed to determine generation needs internal to the control
area while considering external power purchasing constraints. Economic analysis
was used to determine the least-cost overall solution to achieve the desired reliability.
In states that have not restructured their retail markets, this condition still exists.
Transition to Restructuring. During restructuring, competition or
“customer choice” is provided to retail consumers. This implies that distributors of
electricity must account for a changing customer base resulting from their choosing
different suppliers. A supplier must continue to predict loads based on all the
information used before restructuring (weather, population growth, industrial growth)
while adding the factor associated with “customer choice.”
Risk Factors. There is reliability improvement provided to the customer by
having multiple, redundant suppliers. If one supplier is not acceptable, from a price
or reliability standpoint, then a customer has an option to switch suppliers. This
ability for customers to choose suppliers is an advantage over the previous structure,
in which no choice was provided. However, the reliability of the bulk power system
could degrade if the added unknown of customers changing suppliers becomes

36 U.S. Department of Energy, “Maintaining Reliability in a Competitive U.S. Electric
Industry,” 1998, Executive Summary, page xi.

Most existing data indicate that few customers with the ability to choose
suppliers are exercising their option to change, and relatively small numbers of
supplier changes by residential customers will not affect electricity flows in the bulk
power system. However, larger industrial customers that move from one supplier to
another could affect the bulk power system reliability depending on the physical
location of the new wholesale supplier. To keep reliability at the same level, large
customer base changes resulting from large demand moving from one supplier to
another supplier must be accommodated without causing reliability problems in the
wholesale supply and transmission of electricity. The effect of these changes on bulk
power system reliability is difficult to predict.
Service Obligations
Prior to Restructuring. As has been mentioned, vertically integrated utilities
were given a monopoly territory in return for taking on the obligation to serve all
customers in that territory. The customers within the control area received a reliable
source of electricity as dictated by state quality-of-service legislation. The obligation
to serve accepted by the utilities translated to a well-defined reliability level for
Transition to Restructuring. In states that have authorized competitive
markets, the obligation to serve exists at the distribution level; however, suppliers no
longer have any such obligation. Generators who previously were part of a regulated
utility that did have an obligation to serve are now focusing on participation in the
competitive market. Electricity generators are no longer regulated by state quality-of-
service legislation but are driven by making a profit. An electricity service provider
may sacrifice reliability in one area to achieve an improved profit margin by lowering
existing quality-of-service or by serving a different area. Within a California statute,
the legislature noted that “[t]he proposed restructuring of the electricity industry
would transfer responsibility for ensuring short- and long-term reliability away from
electric utilities and regulatory bodies to the Independent System Operator and37
various market-based mechanisms.”
Risk Factors. In an effort to maintain reliability, several states have passed
restructuring legislation requiring a minimally acceptable level of retail service.
Some states have statutes that require service records for unplanned outages to be38
reviewed by public authorities and certain other service reliability measures. Other
states have requirements for adequate reserve margins and require reliability criteria39
to be equal to NERC standards. These laws apply only to retail service. Therefore,
if retail service outages result from a lack of bulk power system performance, it is not
clear how the state legislation will affect needed improvements in the wholesale

37 California Statute, AB1890. (334).
38 Texas, Section 36, Subchapter A, Chapter 38, Section 38.005
39 Illinois, 220 ILCS 5/16-126.

Table 1 provides a summary of all the risk factors identified in this section.
Increased risk is an indication of potential reliability problems. Reliability issues
result from situations where uncertainty or risk is not identified and eliminated. The
summation at the bottom of Table 1 is based on an observation that many of the
reliability improvements associated with restructuring have not been realized to a
large degree. No real simplification of control areas has been seen, and new capital
for transmission has not been made available (even though markets have attracted
many new generation suppliers). The major factor increasing uncertainty is the
desired use of the bulk power system to support competition, which was not
envisioned by the original power system designers. In order for the bulk power
system to reliably support competition, many argue that it must be developed into
more of a “superhighway” with higher capacities and less congestion.
Table 1. Summary of Factors from Functional Changes in
the Electric Utility Industry Resulting from Restructuring
That Can Affect Reliability
FunctionalFactors That IncreaseFactors That Lower
Changes DuringReliabilityReliability
Transition That
Affect Reliability
InstitutionalLong-term improvedAdded complexity is making
Structurecoordination could simplifystructure by decreasing thecoordination among entitiesdifficult, at least in short term.
number of control areas.
Return onNew markets encourage newNo guaranteed rate-of-return
Investmentsparticipants bringing newapproaches and new capital.given to participants;High uncertainty of transmission
i nve st me nt .
WholesaleNew market participantsMany market participants add
Competitionprovide redundancy; Concept of ancillary servicecomplexity and bring newuncertainty.
markets sets value for some
elements of reliability.
ReliabilityNERC mandatory standards;Distribution of responsibilities
ResponsibilitiesIndustry and technologyimprovements.among several entities iscomplex.
Customer BaseRetail redundancy is provided.Customer choice” may add
future uncertainty.
Service ObligationsState-sponsored reliabilityGenerators are driven by
legislation.markets and have no obligation
to serve.
SummationMany improvements are beingIncreased uncertainty is creating
developed but have not beenconditions not considered in
realized at this point.original bulk power system
d e si gns.
Source: Congressional Research Service.

Federal and State Jurisdiction
The major industry changes identified in the previous section generally have the
potential to improve or degrade reliability. State legislators together with their public
utility commissions have jurisdiction over the retail markets within their states. State
legislators are determining if and when their state retail markets will transition to a
competitive structure.40 Under current federal law, FERC has jurisdiction over the41
wholesale markets and the bulk power system unbundled transmission system.
State restructuring legislation can have an effect on the reliability of the bulk
power system. Retail changes such as the promotion of customer choice and the lack
of an obligation to serve by merchant generators may affect reliability. Under current
laws, federal legislation does not directly affect industry changes at the retail level.
The Federal Power Act limits federal jurisdiction to unbundled transmission;
however, the bulk power system must be capable of addressing uncertainty resulting
from competitive retail markets. The goal of much federal legislation dealing with
electric utility restructuring is to supply a framework for development of a bulk
power system that will support competition at the retail level.
Public power utilities in various portions of the United States also create
jurisdictional issues for both state and federal agencies. Public power utilities own
approximately one quarter of the bulk power system’s generating capacity and
approximately 30% of the transmission system. Under current federal law, FERC
does not have jurisdiction over the transmission owned and operated by these
utilities. FERC does review cost-based rates set by public utilities. Therefore, the
present jurisdiction for FERC includes only the portion of the bulk power system
owned and operated by for-profit entities, which includes investor-owned utilities and
non-utility entities (generators, marketers, distributors). Some legislative proposals
would modify the definition of an “electric utility” in the Federal Power Act to
include federal and state sponsored utilities and municipalities.
Proposed Federal Legislative Solutions
Even though the goal of existing federal law (PURPA, EPACT) is to encourage
competition in electric markets while maintaining reliability, the complex technical
requirements associated with open access were not fully understood when the
legislation was enacted. The factors identified in the previous sections suggest the

40 For more information of the status of state restructuring plans, refer to Energy Information
Administration website, [http://www.eia.doe.gov/cneaf/electricity/chg_str/restructure.pdf].
41 Unbundled transmission services are the services that a utility provides as a separate
service. A rate or tariff for the transmission services is provided by the utility and is applied
equally to itself and others. The Supreme Court ruled that even though unbundled
transmission was purchased by retail customers, FERC still retained jurisdiction when the
unbundled transmission supported interstate commerce. Supreme Court of the United
States, No. 00-568, New York et al., v. Federal Energy Regulatory Commission et al.,
Together with No. 00-809, Enron Power Marketing, Inc. v. Federal Energy Regulatory
Commission et al., Argued October 3, 2001-Decided March 4, 2002.

level of risk that has been placed on the bulk power system. The risk comes from
attempts to implement competition at both wholesale and retail levels using a bulk
power system that was designed to service franchise control areas owned and
operated by regulated monopolies. Many of the anticipated risk improvements, which
were expected to result from restructuring efforts, have not been realized.
Various legislation has been proposed at the federal level to improve reliability
of the bulk power system during the restructuring process. These proposals have the
potential to affect reliability of the bulk power system. In the following sections, the
provisions in the legislation will be identified and potential effects on reliability will
be discussed. Table 2 provides a summary of the purposes and issues for each
legislative provision.
Participation in Regional Transmission Organizations
Some congressional proposals address participation by electric utilities in RTOs.
These include encouraging FERC to provide incentive rates for transmission for
those that do, allowing the Tennessee Valley Authority and federal power marketing
administrations to join an RTO, requiring FERC to convene discussions with state
regulatory authorities to determine whether an RTO is necessary in a region, and
prohibiting FERC from requiring a transmitting utility to transfer operational control
of its transmitting facilities to an RTO or ISO.
Purpose. FERC initiated the RTO implementation process in December 1999
by issuing Order 2000. FERC intends for the RTOs to have, in part, the following
charact eri s t i cs:
!Independence from stakeholders
!Broad scope and regional configuration
!Broad operational authority, including interconnections
!Control over short-term reliability
Therefore, the purpose of encouraging utilities to form RTOs is to create a change in
institutional structure that would promote reliability of the bulk power system within
a region. RTOs would coordinate improvements and administer reliability
requirements to distribute costs fairly among the regional participants.
Issues. As has been discussed, the implementation of RTOs holds the
potential to reduce risk through providing a central control and planning function,
reducing the number of control areas, and simplifying the institutional structure.
Many industry participants support the implementation of RTOs if constructed to
provide “fair” access to the transmission system. The difficulty has been
achievement of that goal. Originally, Order 2000 called for implementation of RTOs
across the United States by December 2001. Only one RTO, the Midwest RTO, had
been approved by FERC by the end of 2001. Other RTOs are in various stages of the
approval process; however, the implementation of these organizations has been slow.
There are several coordination issues relating to RTOs. The number of RTOs
to be implemented in the United States bulk power system is uncertain. The
coordination of the planning functions is not clear, nor how planning and capital

improvements to maintain reliability of the transmission system will be encouraged.
It is also not clear whether a reduction in the number of control areas will be
accomplished. Transmission congestion issues will be difficult to solve. Opponents
of the FERC RTO proposals argue that the cost of setting up the RTO may be too
high and will create a financial burden for some participants that is unacceptable. All
of these unknowns add to uncertainty and therefore increase risk.
FERC Jurisdiction Over Bulk Power System Reliability
At the present time, NERC has responsibility for reliability of the bulk power
system. Legislation has been proposed in every Congress since the 105th to improve
reliability and give FERC jurisdiction over an Electric Reliability Organization
Purpose. The purpose of the proposed legislation is to provide federal
jurisdiction over activities that are required to support reliability of the U.S. bulk
power system. The Federal Power Act gives FERC jurisdiction over unbundled
transmission and was intended to regulate wholesale rates; however, no authority was
provided to regulate reliability. Clarifying FERC authority to establish and regulate
an ERO is intended to improve reliability as restructuring of the U.S. bulk power
system proceeds.
Issues. Advocates of giving FERC authority over the ERO contend that
central jurisdiction would provide more accountability. FERC would be ultimately
responsible for reliability issues. If the penalties employed by the ERO were not
successful, then FERC would have the authority to enforce penalties for entities that
did not comply with reliability standards. Establishing this new relationship between
FERC and the ERO would have the potential to improve coordination between
market functions and reliability functions. Those opposed to giving FERC
jurisdiction over bulk power system reliability contend that FERC has no experience
in this area. If FERC is given this authority, it would have to rely on NERC for much
of its expertise. Placing FERC in this position may add to the uncertainty associated
with the changes in institutional structure as FERC takes on this new role.
Transmission Siting
Providing FERC with the authority to site transmission lines in regions where
interstate transmission is needed to relieve congestion has been another proposed, yet
controversial, solution to increase long term reliability of the bulk power system.
State PUCs have transmission siting authority at the present time. Some proposals
would provide for federal and state coordination of permitting for electric
transmission facilities. Others would authorize FERC to issue transmission
construction permits in areas found by DOE to be “congested.”
Purpose. The purpose of the legislation is to make sure required transmission
capacity can be constructed in situations where state PUC siting procedures do not
give adequate consideration to bulk power system reliability. Congestion on the
transmission system continues to be problematic.

Issues. Proponents of federal siting authority argue that problems with siting
interstate transmission exist and FERC authority would facilitate construction of
transmission lines. In this case, the national need for reliability of the transmission
grid, based on FERC review, would possibly override state restrictions in siting a
transmission line. Advocates believe that an interstate grid system cannot be built
without providing FERC with some siting authority. State PUCs, concerned about
environmental effects of building more transmission lines, contend that transmission
line siting should remain under local PUC control.
Public Utility Holding Company Act Repeal
Repeal of PUHCA has been proposed for many years by several within the
industry and the Securities and Exchange Commission (SEC).42 All of the legislative
proposals would provide federal access to company books and records to protect
consumers against companies that may exercise market power to control wholesale
prices, perform cross-subsidy operations, or exercise deceptive practices.
Purpose. The repeal of PUHCA has several purposes. According to the SEC,
the regulations in the act became redundant in the 1980s. State retail regulation of
utilities has been strengthened and the SEC has enhanced its regulation of securities,
including those of public utility holding companies. Advocates for PUHCA repeal
believe the act limits capital investment in the electric utility industry. More
specifically, some believe PUHCA limits the formation of companies that would43
construct transmission capacity over broad interstate regions. The purpose of the
PUHCA repeal language is to eliminate legislation that is seen as unnecessary and
as limiting industry expansion.
Issues. Those opposed to PUHCA repeal argue that the law maintains
necessary safeguards for the industry because it tends to limit formation of large
interstate companies that, by their nature, could control the marketplace. Opponents
of the repeal are primarily concerned about consumer protections. There are also
concerns about market failures resulting in a loss of confidence by investors, which
translates to a reliability problem when new transmission and generation cannot be
constructed. PUHCA repeal could have both negative and positive effects on
reliability in the long term.
Mandatory and Enforceable Reliability Standards
A task force commissioned by DOE to study reliability issues in a competitive
U.S. electricity industry provided many recommendations in a final report issued in

42 Hunt, Isaac C., “H.R. 3406, The Electric Supply and Transmission Act of 2001,”
Commissioner, Securities and Exchange Commission, Testimony before Subcommittee on
Energy and Air Quality, December 13, 2001, at [http://energycommerce.house.gov/107/
hearings /12132001Hearing449/Hunt761.htm] .
43 Edison Electric Institute,” The Living Grid — Evolving to Meet the Needs of America.”

1998.44 One of the recommendations was the development of enforceable reliability
standards. This recommendation was also made in the energy plan developed by
Vice President Cheney and the National Energy Policy Development Group.45 As
mentioned in previous sections, the reliability standards set by NERC prior to
restructuring were voluntary. Proposed legislation and NERC have adopted the
approach of developing mandatory standards through an ERO, based on the NERC
voluntary standards, with penalties that could be imposed on violators.
Purpose. One key element that can be used to improve bulk power system
reliability is imposing economic penalties for reliability standard non-compliance.
In many cases, there is little economic benefit realized by following reliability
standards that have been developed by NERC. The purpose of the federal legislation
is to authorize the use of mandatory standards and the assessment of penalties
associated with failure to comply with the standards. The assessment of economic
penalties provides a method of attaching value to maintaining reliability. When
penalties are properly set, compliance should lower risk. The concept of mandatory
standards has received support from NERC and many representatives from the
electric utility industry.
Issues. Questions still remain about how effective mandatory standards would
be. Can enforceable standards for reliability be developed that fairly distribute
responsibilities among the participants to maintain a high level of reliability? Will
the standards be clear? These and other questions are key to the successful
implementation of mandatory standards. If the standards are perceived as high and
the non-compliance penalty is less expensive than potential profits, participants may
not give proper attention to these standards. If the standards are too low, then even
though participants comply with the standards the potential exists for outages that
could have been avoided. The process of setting standards for many different types
of owners and operators in United States, Canada, and Mexico presents a challenge.
Another area of difficulty relates to liability when outages do occur. If a market
participant does not properly schedule an outage or maintain a particular piece of
equipment, and the procedural miscue leads to a large-scale power outage, should the
market participant be liable for any or all of the costs associated with the outage,
which could be high? In the past, local power outages by utilities were analyzed by
PUCs to determine if negligence was a factor. State PUCs use legislated tools to
require a level of performance from the utility and to penalize the utility if that level
of performance is not achieved. However, liability for large-scale outages has never
systematically been assessed against participants that caused the outage.
Responsibility for Standards Development
All previously proposed reliability legislation authorizes the establishment of
an ERO to develop the reliability standards. The ERO would be certified by FERC

44 U.S. Department of Energy, “Maintaining Reliability in a Competitive U.S. Electric
45 National Energy Policy Development Group, “Reliable, Affordable, and Environmentally
Sound Energy for America’s Future,” May 17, 2001, [http://www.whitehouse.gov/energy/].

and would, most likely, be based on the present NERC organization with its 10
Regional Councils. The ERO would take primary responsibility for the validity of
the standards and would provide initial detection of non-compliance.
Purpose. The legislative proposals would direct NERC, as the ERO, to
continue in its present role as reliability standards administrator; however, FERC
would maintain jurisdiction over NERC. The regional councils in NERC would deal
with reliability issues unique to their particular portions of the power system.
Maintaining reliability must include efforts to coordinate with Canada and Mexico,
since there are many interconnections that cross those borders and allow bulk power
systems in those countries to have an effect on the U.S. system. The existing
relationship NERC has with Canadian and Mexican utilities would be a resource to
promote reliability across North American interconnections.
Issues. Many existing NERC standards have been developed based on the
principles of interconnected systems. Even though many of the basic standards can
be retained and built on, some may need to be modified and others eliminated to
account for the effects of competitive markets on the interconnect system.
Table 2. Summary of Provisions in Proposed Legislation That
Could Affect Reliability
Proposed LegislativePurposeIssues
Required RTO ParticipationCentral coordination ofImplementation is difficult and
reliability for a particularcomplex. The number of U.S.
region. RTOs has been questioned.
FERC ReliabilityResponsibility for U.S. bulkNew area of expertise for
Jurisdictionpower system reliability. FERC; special regional
concerns exist.
Transmission SitingGive FERC ability to overcomeState PUCs assert that siting
local siting issues.must remain under local control.
Repeal of PUHCAAttract new market participants.Eliminates existing industry
sa fe gua r d s.
Mandatory StandardsProvide economic penalty forSetting penalty levels and
non-compliance.standards presents new
d ifficulties.
Standards DevelopmentBuild on existing system ofSome argue FERC should
NERC standards that addressdevelop standards.
specific regions of U.S.
Source: Congressional Research Service.

The bulk power system in the United States has been a reliable source of
electricity for its industries and citizens. The outage during 1965 in the northeastern
United States, which left 30 million customers without electricity service, was the
largest in U.S. history until the August 2003 blackout. Since 1968, NERC has been
a vehicle for utilities to develop industry standards that promote reliability. Service
reliability by utilities during the last 30 years has been excellent in most areas of the
United States.
Beginning in 1992, the industry has undergone significant changes with the goal
of lowering rates by encouraging competition. Industry changes that have increased
uncertainty and risk have occurred in several areas, including the following: A more
complex institutional structure, no guaranteed rate-of-return for utilities, lack of
investment in the transmission system, a much more complex wholesale market,
distribution of reliability responsibilities among many participants, and retail
customers with a choice of suppliers. These changes ultimately have the potential
to adversely affect reliability of the electricity supply, and they are forcing the bulk
power system to be operated under conditions it was not designed to support.
Not all of the changes to promote competition add to risk and uncertainty.
Some of the changes tend to lower uncertainty, and they include the potential to
lower the number of control areas and improve coordination; centralized planning
improvements for larger regions; new capital from a larger number of participants;
and greater redundancy from a larger number of suppliers and providers. However,
many of the changes that would lower risk have not been realized to date. Therefore,
the electric utility industry is operating under conditions of greater risk now than it
was a decade ago. This greater risk can potentially lead to a lowering of reliability
which some feel has already been borne out in the restructuring of the California
electric utilities. Restructuring proposals may lead to less risk in the future; however,
those changes, and the benefits from those changes, have been slow to materialize.
The transmission portion of the bulk power system remains a concern. The
transmission system was designed to provide for the needs of the utility industry prior
to 1992 when utilities held monopoly status in their particular control areas.
Transmission facilities were constructed to support only transactions between those
utilities. Competition requires the bulk power system to be used in a much different
way than was envisioned by those earlier transmission system designers. Many
observers assert that methods are needed to transform the transmission system into
a “superhighway” that can support competition among multiple suppliers and
multiple consumers. In areas where congestion on the transmission system occurs,
reliability will be a problem. The responsibilities and methods that will be used to
effect this transformation of the transmission system remain unclear. Technology46
improvements may assist with these issues in the future. Distributed generation and
conservation both hold potential.

46 New technologies are being developed that will allow electric power from a large number
of smaller generators to be distributed into areas much closer to customers. This would
eliminate some needs for high voltage and long distance transmission of electricity, and
would allow for the customization of reliability needs to meet unique user requirements.

Federal legislation has been proposed that includes several provisions that could
improve reliability. Provisions that have received more support and hold potential
for reliability improvement are the jurisdictional role provided to FERC and the
establishment of an ERO to develop mandatory reliability standards. Both of these
provisions are intended to add some clarity and stability that would lower risk and
improve reliability. FERC has already started to take this role with the issuance of
Order 2000. The Supreme Court decision of March 4, 2002, which supported the
FERC definition of “unbundled transmission,” adds further clarity.47 Proposed
legislation would further provide FERC with legal authority to take on the ultimate
responsibility for bulk power system reliability. A legislative mandate for an ERO
with enforceable standards could add certainty in an area that is already being
pursued by the industry.
Whether the proposed legislation can provide the desired reliability has yet to
be seen. The details of the implementation by FERC, NERC, and the industry
participants would be the key. The answer to the question of whether reliability can
be maintained while restructuring the electric utility industry is difficult to predict.
There has been much concern about the topic; however, the proposals remain, for the
most part, untested and unproven. Proposed legislative remedies will be successful
only if and when they result in the necessary capability, flexibility, and efficiency in
the existing system required to overcome the added risks.

47 See footnote 44, which defines “unbundled transmission,” in the section titled “Federal
and State Jurisdiction.”