Electric Reliability: Options for Electric Transmission Infrastructure Improvements

Electric Reliability: Options for Electric Transmission Infrastructure Improvements

Order Code RL32075
CRS Report for Congress
Received through the CRS Web
Electric Reliability: Options for Electric
Transmission Infrastructure Improvements
Updated September 20, 2006
Amy Abel
Specialist in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

Electric Reliability: Options for Electric Transmission
Infrastructure Improvements
Summary
The electric utility industry is inherently capital intensive. At the same time, the
industry must operate under a changing and sometimes unpredictable regulatory
system at both the federal and state level. The transmission system was developed to
fit the regulatory framework established in the 1920 Federal Power Act: utilities
served local customers in a monopoly service territory. The transmission system was
not designed to handle large power transfers between utilities and regions.
Enactment of the Energy Policy Act of 1992 (P.L 102-486) created tension between
the regulatory environment and existing transmission system: the competitive
generation market encouraged wholesale, interstate power transfers across a system
that was designed to protect local reliability, not bulk power transfers.
The Energy Policy Act of 2005 (P.L. 109-58) has set in place government
activities intended to relieve congestion on the transmission system. The law creates
an electric reliability organization that is to enforce mandatory reliability standards
for the bulk-power system. In addition, processes are established to streamline the
siting of transmission facilities.
Through 1998, electricity demand recently had been growing at 2% to 3% per
year. Additions to the transmission system had been averaging about 0.7% per year.
Reversing this trend, between 1999 and 2003, transmission investment increased at
a 12% annual rate. This long period of insufficient transmission investment has led
to transmission lines that are congested in several regions of United States.
Several factors have contributed to the lack of new transmission capacity. First,
there is general consensus that siting new lines is difficult, having needed approval
of all states in which the transmission line will be located. Second, some have
argued that the pricing mechanism for transmission has been a deterrent for investors.
Third, many contend that regulatory uncertainty has added a level of risk that
investors are unwilling to assume.
The Energy Policy Act of 1992 introduced competition to wholesale electric
transactions without a comprehensive plan to address reliability issues and the
development of efficient wholesale markets. In addition, approximately half of the
states have passed legislation or had regulatory orders to introduce retail competition,
each with its own set of rules for utilities to follow. The blackout of 2003 in the
Northeast, Midwest, and Canada highlighted the need for infrastructure
improvements and greater standardization of operating rules. EPACT05 addresses
some of the transmission issues by creating an electric reliability organization,
establishing incentive-based rate-making for transmission, and allowing federal
backstop authority for transmission siting. Until the electric power industry reaches
a new equilibrium with more regulatory certainty, many observers predict,
investment in transmission infrastructure and technology will continue to be
inadequate.
This report will be updated as events warrant.

Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Historical Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Physical Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Current Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Regulatory Uncertainty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
List of Figures
Figure 1. Congested Lines in the Eastern Interconnection . . . . . . . . . . . . . . . . . . 11
Figure 2. Congested Lines in the Western Interconnection . . . . . . . . . . . . . . . . . 12

Electric Reliability: Options for Electric
Transmission Infrastructure Improvements
Introduction
The electric utility industry is inherently capital intensive. At the same time, the
industry must operate under a changing and sometimes unpredictable regulatory
system at both the federal and state level. Inconsistent rules and authorities can result
in inefficient operation of the interstate transmission system. The electric
transmission system has been affected by a combination of factors that has resulted
in insufficient investment in the physical infrastructure.
The transmission system was developed to fit the regulatory framework
established in the 1920 Federal Power Act1: Utilities served local customers in a
monopoly service territory. The transmission system was not designed to handle large
power transfers between utilities and regions. Enactment of the Energy Policy Act
of 1992 (EPACT92)2 created tension between the regulatory environment and
existing transmission system. EPACT92 effectively deregulated wholesale
generation by creating a class of generators that were able to locate beyond a typical
service territory with open access to the existing transmission system. The resulting
competitive market encouraged wholesale, interstate power transfers across a system
that was designed to protect local reliability, not bulk power transfers.
The blackout of August 2003 in the Northeast, Midwest, and Canada
highlighted the need for infrastructure and operating improvements. However, a
conflict exists between the apparent goal of increasing competition in the generation
sector and assuring adequate transmission capacity and management of the system
to move the power. Additions to generating capacity are occurring at a more rapid
pace than transmission additions. The traditional vertically integrated utility no
longer dominates the industry structure.3 In addition, demand for electric power
continues to increase. Unresolved regulatory issues that have emerged after 1992
have resulted in considerable uncertainty in the financial community. As a result of
all of these factors, investment in the transmission system has not kept pace with
demand for transmission capacity.
1 16 U.S.C. 791a et. seq.
2 P.L. 102-486.
3 Seventeen states and the District of Columbia are implementing retail choice for
electricity. According to the Energy Information Administration, in 1996, 10% of
generating capacity was owned by non-utility generators. By 2004, 37% of generating
capacity was owned by non-utility generators.

CRS-2
The Energy Policy Act of 2005 (EPACT05) addresses electric reliability and
infrastructure investment.4 In part, Title XII creates an electric reliability
organization (ERO) that is to enforce mandatory reliability standards for the bulk-
power system. All ERO standards are to be approved by the Federal Energy
Regulatory Commission (FERC). Under this title, the ERO could impose penalties
on a user, owner, or operator of the bulk-power system that violates any FERC-
approved reliability standard. FERC approved the North American Electric
Reliability Corporation (NERC), a wholly owned subsidiary of the North American
Electric Reliability Council (NERC Council), as the ERO.5 NERC Council is a
nonprofit corporation whose membership is composed of the eight regional reliability
councils.6
Title XII also addresses transmission infrastructure issues. As required by
EPACT05, the Department of Energy issued the first National Electric Transmission
Congestion Study in August 2006. Additional studies are required every three years.
The study identified two areas of critical congestion: Southern California and the
eastern coastal area from metropolitan New York south to Northern Virginia. From
this study, the Secretary of Energy will certify congestion on the transmission lines
and issue permits to transmission owners. Permit holders will be able to petition in
U.S. district court to acquire rights-of-way for the construction of transmission lines
through the exercise of the right of eminent domain.
EPACT05 also provides for incentive rate-making for transmission investment.
FERC issued its final rule on this issue, Promoting Transmission Investment through
Pricing Reform, on July 20, 2006.7 Although the order identifies specific incentives
that FERC will allow, the burden remains on an applicant to justify the incentives.
Historical Context
There are three components to electric power delivery: generation, transmission,
and distribution. Transmission, by its nature, is generally considered an interstate
transaction whereas distribution is considered intrastate. State public utility
commissions regulate the siting of all transmission and distribution lines within each
state’s borders as well as distribution charges and retail electric rates. In states that
have not restructured, the system operates as it has since enactment of the Federal
4 P.L. 109-58.
5 Order Certifying North American Electric Reliability Corporation As the Electric
Reliability Organization in Ordering Compliance Filing. 116 FERC, 61,062. Docket No.
RR06-1-000. Issued July 20, 2006.
6 The regional reliability councils are: Electric Reliability Council of Texas, Inc. (ERCOT),
Florida Reliability Coordinating Council (FRCC), Midwest Reliability Organization (MRO),
Northeast Power Coordinating Council (NPCC), Reliability First Corporation (RFC),
Southeastern Reliability Council (SERC), Southwest Power Pool, Inc. (SPP) and Western
Electricity Coordinating Council (WECC).
7 Federal Energy Regulatory Commission Final Rule. Order Number 679. Promoting
Transmission Investment through Pricing Reform. July 20, 2006. Docket Number RM06-4-
000.

CRS-3
Power Act, with retail consumers paying one price that includes transmission,
distribution, and generation. This is referred to as a bundled transaction. In states
that have restructured, consumers are billed for separate transmission, distribution,
and generation charges. This is referred to as unbundled electricity service. FERC
regulates all transmission, including unbundled retail transactions.8
Generators of electricity need to move their power to their ultimate customers
through the transmission system. The current system allows for power transfers
within, but not between, three major regions of the United States: the area west of the
Rockies (Western Interconnection), Texas, and the Eastern Interconnection.
Transmission lines and distribution lines are categorized by their voltage rating. In
general, transmission lines are typically rated 230 kilovolts (kV) and higher (765 kV
is the highest installed). Subtransmission systems are 69 kV to 138 kV, and
distribution systems are rated less than 69 kV.9 Existing transmission infrastructure
was designed to accommodate the old system of central station power plants with
nearby customers. Since enactment of the Energy Policy Act of 1992, there has been
an increase in interstate bulk power transfers, a purpose for which the existing system
was not designed.
The Energy Policy Act of 1992 (EPACT92) created a new category of wholesale
electric generators called Exempt Wholesale Generators (EWGs) that are not
considered utilities.10 EWGs, also referred to as merchant generators, were intended
to create a competitive wholesale electric generation sector. In addition, EPACT92
provided a means for these non-utility generators to have access to the transmission
system. As a result of EPACT92, FERC issued a policy statement on transmission
pricing policy. It stated that:
Greater pricing flexibility is appropriate in light of the significant competitive
changes occurring in wholesale generation markets, and in light of our expanded
8 On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New York et al.
v. Federal Energy Regulatory Commission) that challenged FERC’s authority to regulate
transmission for retail sales if a utility unbundles transmission from other retail charges. In
states that have opened their generation market to competition, unbundling occurs when
customers are charged separately for generation, transmission, and distribution. Nine states,
led by New York, filed suit arguing that the Federal Power Act gives FERC jurisdiction over
wholesale sales and interstate transmission and leaves all retail issues up to the state utility
commissions. Enron in an amicus brief 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.
9 Transmission lines generally carry bulk-power transfers between utilities and move power
to load centers. Distribution lines move power to ultimate customers. Subtransmission is
sometimes considered transmission and other times considered distribution for regulatory
purposes.
10 Exempt Wholesale Generators may sell electricity only at wholesale. EWGs may be
located anywhere, including foreign countries. Before enactment of EPACT05, utility
generators were limited by the Public Utility Holding Company Act of 1935 (PUHCA) to
operate within one state.

CRS-4
wheeling authority under the Energy Policy Act of 1992 (EPACT92)[footnote
omitted]. These recent events underscore the importance of ensuring that our
transmission pricing policies promote economic efficiency, fairly compensate
utilities for providing transmission services, reflect a reasonable allocation of
transmission costs among transmission users, and maintain the reliability of the
transmission grid. The Commission also recognizes that advances in computer
modeling techniques have made possible certain transmission pricing methods
that once would have been impractical.11
In May 1994, FERC established general guidelines for comparable access to the
transmission system.12 In April 1996, FERC clarified its open-access transmission
tariff policy with Orders 888 and 889, making it easier for merchant generators to
gain access to the transmission grid and requiring utilities to “functionally unbundle”
their operations. In practice, this means that a utility’s generation and transmission
operations must be conducted separately without sharing of resources, books, and
records. Some states that have opened their retail markets to competition, including
California, have required utilities to divest of either transmission and distribution or
of generation. In these states, most utilities have divested generation assets and
maintained their transmission and distribution business. By July 9, 1996, all utilities
that own or control transmission had filed a single open-access tariff with FERC that
provides transmission service to eligible wholesale customers at comparable terms
to the service that the utilities provide themselves. Some merchant generators
asserted that they continued to be discriminated against by incumbent transmission
utilities and were denied access to the system.
Orders 888 and 889 established a pro forma open-access transmission tariff (pro
forma OATT). Many argued that this pro forma OATT allowed for opportunities for
the exercise of undue discrimination by transmission owners. On May 18, 2006,
FERC issued a Notice of Proposed Rulemaking (NOPR), Preventing Undue
Discrimination in Preference in Transmission Service, to remedy some of the
deficiencies in the pro forma OATT.13 According to FERC, the major reforms in the
NOPR include
! greater consistency and transparency in the Available Transfer
Capability (ATC) calculation;14
! open, coordinated, and transparent planning;
! reform of energy imbalance penalties;
! clarification of tariff ambiguities; and
! increased transparency and customer access to information.
11 Inquiry Concerning the Commission’s Pricing Policy for Transmission Services Provided
by Public Utilities Under the Federal Power Act; policy statement, Oct. 26, 1994, Docket
No. RM 93-19-000, 18 CFR 2, 59 FR 55031.
12 67 FERC 61,168.
13 FERC Docket Numbers RM05-25-000 and RM05-17-000.
14 ATC is the transfer capability remaining on a transmission provider’s transmission system
that is available for further commercial activity over and above already committed uses.

CRS-5
Physical Limitations
Three types of constraints limit the transfer capability within the transmission
system: thermal constraints, voltage constraints, and system operating constraints.
Thermal constraints limit the capability of a transmission line or transformer to carry
power because the resistance created by the movement of electrons causes heat to be
produced. Overheating can lead to two possible problems: the transmission line loses
strength which can reduce the expected life of the line, and the transmission line
expands and sags between the supporting towers. This presents safety issues as the
lines approach the ground as well as reliability concerns. If a transmission line comes
in contact with the ground, trees, or other objects, the transmission line will go off-
line and not be able to carry power.
Voltage can be likened to the pressure inside the transmission system.
Constraints on the maximum voltage levels are set by the design of the transmission
line. If voltage levels exceed the maximum, short-circuits, radio interference, and
noise may occur. Low voltages are also a problem and can cause customers’
equipment to malfunction and can damage motors.
System operating constraints refer to reliability and security. Maintaining
synchronization among generators on the system as well as preventing the collapse
of voltages are major aspects of the role for transmission operators.15 North
American Electric Reliability Council guidelines require utilities to be able to handle
any single outage through redundancy in the system. When practical, NERC
recommends the ability to handle multiple outages within a system. Reducing the
constraints on the system through technology improvements is one way to increase
the transfer capability over existing lines.16
Current Issues
The regulatory regime has shifted the operations of the electric utility industry,
creating larger and more frequent bulk power transfers across a transmission system
largely designed for local intrastate service. However, investment and infrastructure
has not kept up with increases in the bulk power transfers and electricity demand.
Through 1998, electricity demand had been growing at 2% to 3% per year and
additions to the transmission system had been averaging about 0.7% per year. Actual
annual transmission investment had declined from $5 trillion in 1975 to about $2.25
trillion in 1998.17 Reversing this trend, between 1999 and 2003, transmission
investment increased at a 12% annual rate. During the same period, total circuit
miles of high-voltage and extra-high-voltage transmission lines owned and operated
15 Within each interconnection, all generators rotate in unison at a speed that produces a
consistent frequency of 60 cycles per second.
16 See, Energy Information Administration. Upgrading the Transmission Capacity for
Wholesale Electric Power Trade. Available at [http://www.eia.doe.gov/cneaf/pubs_html/
feat_trans_capacity/w_sale.html].
17 Real $2003. Edison Electric Institute. EEI Survey of Transmission Investment: Historical
and Planned Capital Expenditures (1999-2008). Washington, D.C. May 2005. p. 3.

CRS-6
by investor-owned utilities increased by 2.8% annually. In comparison, sales of
electricity from investor-owned electric utilities and their affiliates to end-use
customers increased by 0.7% annually between 1999 and 2003.18 So, in addition to
generation capacity shortages in certain regions of the country, this long period of
insufficient transmission investment has led to transmission lines that are congested
in several regions of United States.
As is shown in Figures 1 and 2, many lines in the Eastern Interconnection and
Western Interconnection are congested. This problem is not new. In 1987, CRS
noted that bulk power transmission lines in many parts of the country were already
operating at or near capacity and the chief capacity-related barrier to bulk-power
transfers (wheeling) was that the transmission system was not built for bulk-power
transfers.19 According to NERC, the number of requests to use the transmission
system that were denied because of congestion (TLRs) rose from 305 in 1998 to
1,494 in 2002. By 2005, there were 2,397 TLRs.20 Over the next 10 years, the line-
miles of high-voltage transmission are expected to increase 6%, in contrast to a 20%
expected increase in generation demand and capacity.21 If this projection is accurate,
further pressure on reliability could occur in several regions.22
Siting.
One reason transmission lines have not been built in recent years is
the difficulty in siting them. Even though the transmission of electricity is
considered interstate commerce, the siting of transmission lines has been the
responsibility of the states. In addition, several federal agencies play various roles
in the siting process, primarily with regard to environmental impacts. Siting and
building transmission lines have been very difficult because of citizen opposition as
well as inconsistent siting requirements among states. While controversial, since the
blackout of 2003, FERC Commissioners supported federal siting backstop
authority.23 In addition, the electric industry is in favor of giving FERC siting
authority.24 States are generally opposed to federal backstop authority.25
EPACT05 established that the Secretary of Energy is required to certify
congestion on the transmission lines. FERC may issue permits for construction of
18 Ibid. p. 4.
19 CRS Report 87-289 ENR. Wheeling in the Electric Utility Industry. February 12, 1987
(available from the author).
20 NERC data on Transmission Loading Relief (TLR) requests are available at [ftp://www.
nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm].
21 Department of Energy. National Transmission Grid Study. May 2002.
22 See CRS Report RL31469. Electric Utility Restructuring: Maintaining Bulk Power
System Reliability.
23 Statement of Nora Mead Brownell. FERC Reverses Position, Will Now Take Federal
Backstop Authority. Energywashington.com. September 2, 2003.
24 Edison Electric Institute. Federal Siting Authority: Key to Expanding Electricity
Infrastructure. Available at [http://www.eei.org/industry_issues/energy_infrastructure/
transmission/federalsiting.pdf].
25 Statement of National Governors Association.

CRS-7
transmission lines to transmission owners if FERC finds that a state does not have
the authority to approve the siting of the facilities or that a state commission that has
authority to approve the siting of facilities has withheld its approval for more than
one year. Permit holders are able to petition in U.S. district court to acquire rights-
of-way for the construction of transmission lines through the exercise of the right of
eminent domain.26
Alternatives to New Rights-of-Way. Capacity of the existing transmission
system can be increased without siting new lines. In addition, new generation can be
sited closer to demand, reducing the need to use the transmission system. Additional
transmission lines could be added to existing rights-of-way or in some cases existing
towers could be restrung with higher capacity lines. However, in some cases,
reliability levels would increase with the redundancy of new transmission lines sited
on new rights-of-way; storms and other events that may cause physical damage to
one area may not affect transmission lines in another part of a state or region.
Many transmission systems could increase the capacity of the transmission
system with technology improvements. While many new technologies would require
significant capital investment, one study by the New York Independent System
Operator concluded that relatively inexpensive equipment upgrades could
significantly increase the line ratings and could reduce congestion.27 The study
indicated that a significant number of transmission lines operate below their thermal
limits due to equipment limitations at substations. By remediating those limitations
with relatively inexpensive equipment (e.g., disconnect switches, bus connectors,
relays, etc.), according to the New York study, operation at thermal capacities could
be reached with little or no risk of service interruption.
Other technological improvements to increase transmission capacity and allow
the transmission system to be operated more efficiently include upgrading
transformers, retrofitting electromechanical devices with digital devices to allow
operation of the system closer to thermal limits, and restringing existing towers with
aluminum conductor composite core cable. These would require significant capital
investment.
Pricing. Some transmission-owning utilities argue that the current pricing
mechanism for transmission discourages investment. FERC regulates all
transmission, including unbundled retail transactions. Under the Federal Power Act
(FPA), FERC is required to set “just and reasonable” rates for wholesale
transactions.28 FERC has traditionally determined rates by using an embedded cost
method that includes recovery of capital costs, operating expenses, improvements,
accumulated depreciation, and a rate of return. Traditionally, transmission owners
have been compensated for use of their lines based on a contract path for the
26 P.L. 109-58, §1221.
27 New York Independent System Operator. Investigation of Potential Low Cost
Transmission Upgrades Within the New York State Bulk Power System. Interim Report.
April 19, 2001.
28 16 U.S.C. 824(d)(a).

CRS-8
movement of electricity, generally the shortest path between the generator and its
customer. However, electricity rarely follows a contract path and instead follows the
path based on least impedance.29 Transmission lines often carry electricity that has
been contracted to move on a different path. As more bulk power transfers are
occurring on the transmission system, transmission owners not belonging to RTOs
(regional transmission organizations) are not always being compensated for use of
their lines because a contract path rarely follows the actual flow. This creates a
disincentive for transmission owners to increase capacity.30
Under Order 2000,31 FERC stated its interest in incentive ratemaking and in
particular performance-based ratemaking. Those in favor of incentive ratemaking
argue that incentives are needed: (1) to encourage participation in regional
transmission organizations (RTOs)32; (2) to compensate for perceived increases in
financial risk because of participation in a regional transmission organization, and (3)
to facilitate efficient expansion of the transmission system.
FERC has used a “license plate” rate for transmission: a single rate based on
customer location. As FERC is encouraging formation of large regional transmission
organizations, FERC may move toward a uniform access charge, sometimes called
postage stamp rates. With a postage stamp rate, users pay one charge for moving
electricity anywhere within the regional transmission organization.
Postage stamp rates eliminate so-called rate pancaking, or a series of
accumulated transmission charges as the electricity passes through adjacent
transmission systems, and increases the pool of available generation. On the other
hand, by moving to postage stamp rates, customers in low-cost transmission areas
may see a rate increase, and high-cost transmission providers in the same area may
not recover embedded costs because costs are determined on a regional basis.
In early 2003, FERC began to consider raising the rate of return as a way to
reflect the regulatory uncertainty in the industry and encourage transmission
investment.33 The proposal would give a 1% return-on-equity-incentive for new
transmission projects operating under an RTO. Transfer of transmission assets to an
RTO would also result in an incentive return on equity of between 0.5% and 2%.
This could raise return on equity to approximately 14% for some transmission
projects. Increases in the return on equity would increase consumer’s electric bills.
29 Impedance is a measure of the resistive and reactive attributes of a component in an
alternating-current circuit.
30 National Economic Research Associates. Transmission Pricing Arrangements and Their
Influence on New Investments. World Bank Institute. July 6, 2000.
31 89FERC61,285.
32 A regional transmission organization is an independent organization that does not own the
transmission lines but operates a regional transmission system on a non-discriminatory basis.
For additional discussion on RTOs see, CRS Report RL32728, Electric Utility Regulatory
Reform: Issues for the 109th Congress.
33 Federal Energy Regulatory Commission. Proposed Pricing Policy for Efficient Operation
and Expansion of the Transmission Grid. Docket No. PL03-1-000. January 15, 2003.

CRS-9
However, in 2000, the cost of transmission accounted for less than 10% of the final
delivered cost of electricity.34 While the industry is in favor of increasing the return
on equity as a way of providing an incentive to invest, consumer groups are opposed
to such proposals because of the potential to increase consumer rates.35
As required by §1241 of EPACT 05, FERC issued its final rule on transmission
pricing on July 20, 2006.36 Although the order identifies specific incentives that
FERC will allow, the burden remains on an applicant to justify the incentives by
showing that the new transmission capacity will reduce the cost of delivered power
by reducing transmission congestion or will ensure reliability. The applicant will
also have to show that the rate is just, reasonable, and not unduly discriminatory or
preferential.37
Regulatory Uncertainty. For many years, transmission owners and investors
expressed concern that the regulatory uncertainty for electric utilities is inhibiting
new investment in and construction of transmission facilities. For example, repeal
of the Public Utility Holding Company Act of 1935 (PUHCA) had been debated
since 1996. Without clarification on whether PUHCA would be repealed, utilities
stated that they were reluctant to invest in infrastructure. It was argued that repeal of
PUHCA could significantly expand the ability of utilities to diversify their
investment options.38 EPACT05 repealed PUHCA, and FERC and state regulatory
bodies are given access to utility books and records. Removing this uncertainty could
encourage additional investment in the transmission system.
In addition, FERC has been moving toward requiring participation in regional
transmission organizations to create a more seamless transmission system. A fully
operational regional transmission organization would operate the entire transmission
system in a region and be able to replace multiple control centers with a single
34 Energy Information Administration. Electric Sales and Revenue 2000.
35 Testimony of Gerald Norlander for the National Association of State Utility Consumer
Advocates before the House Committee on Energy and Commerce. March 14, 2003.
Hearing available at [http://energycommerce.house.gov/108/Hearings/03132003hearing818/
hearing.htm].
36 Federal Energy Regulatory Commission Final Rule. Order Number 679. Promoting
Transmission Investment through Pricing Reform. July 20, 2006. Docket Number RM06-4-
000.
37 FERC will authorize the following incentive-based rate treatments: a rate of return on
equity sufficient to attract new investment in transmission facilities; allowance of 100% of
prudently incurred Construction Work in Progress (CWIP) in the rate base; recovery of
prudently incurred pre-commercial operations costs; accelerated depreciation used for rate
recovery; recovery of 100% of prudently incurred costs of transmission facilities that are
canceled or abandoned due to factors beyond the control of the public utility, and deferred
cost recovery.
38 For discussion of PUHCA repeal issues, see CRS Report RL32728, Electric Utility
Regulatory Reform: Issues for the 109th Congress.

CRS-10
control center.39 This type of control can increase efficiencies in the operation of the
transmission system. RTO participants are required to adhere to certain rules, but
these are not currently enforceable in court.
Uncertainty over the form of an RTO, its operational characteristics, and the
transmission rates for a specific region have apparently made utilities wary of
investing in transmission. FERC has granted RTO status to several entities and
conditionally approved others. If RTOs are able to operate successfully and develop
a track record, some regulatory uncertainty will diminish.
On July 31, 2002, FERC issued a Notice of Proposed Rulemaking (NOPR) on
standard market design (SMD).40 This NOPR was highly controversial. FERC’s
stated goal of SMD requirements in conjunction with a standardized transmission
service was to create “seamless” wholesale power markets that allow sellers to
transact easily across transmission grid boundaries. The proposed rulemaking would
have created 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 have been an RTO, would have
provided service to all customers and would have run energy markets. Under the
NOPR, congestion would have been managed with locational marginal pricing.
FERC withdrew its SMD proposal shortly before passage of EPACT05.
39 PJM operates with a single control center.
40 FERC, Docket No. RM01-12-000.

CRS-11
Figure 1. Congested Lines in the Eastern Interconnection
Source: U.S. Department of Energy. National Transmission Grid Study. May 2002.

CRS-12
Figure 2. Congested Lines in the Western Interconnection
Source: U.S. Department of Energy. National Transmission Grid Study. May 2002.
Investment. Some contend that obtaining funding is the major impediment
to transmission expansion.41 Utilities have traditionally raised capital from three
sources: equity investors, internal cash flow, and bondholders. Up through 1978,
utility stocks were seen as safe investments for investors. The Three Mile Island
nuclear accident and other cost overruns of nuclear facilities made utility investment
less attractive. Following enactment of the Energy Policy Act of 1992, many found
investing in non-traditional utilities (Enron, Mirant, etc.) to once again be an
attractive option. Following the California energy crises and the bankruptcy of
several energy-related companies, investors have once again withdrew from heavily
investing in utility stock. Since 2000, utility bonds had been unattractive to
41 Roseman, Elliot and Paul De Martini. In Search of Transmission Capitalists. Public
Utilities Fortnightly. April 1, 2003.

CRS-13
investors, according to Standard & Poor’s.42 Since then, many utilities have had their
bond ratings reduced. In 2002, there were 182 bond rating downgrades of utility
holding and operating companies and only 15 upgrades. A majority of electric
utilities (62%) have a bond rating of BBB or below while the number of those rated
A- or better fell from 51% to 38% in one year. Also, according to Standard & Poor’s,
debt and preferred securities financing activity fell from $86 billion in 2001 to $74
billion in 2002. Additionally, internal investment has declined. The lack of
investment options for utilities for transmission improvements had significantly
slowed transmission capacity additions. According to Standard & Poor’s, the power
sector has begun to experience an upward trend in bond ratings. During the first half
of 2006, the U.S. power sector showed positive ratings gains, with company bond
ratings being upgraded more often than downgraded.43
Conclusion
For the transmission system to operate efficiently and reliably, many observers
argue that the tensions between economic, regulatory, and technology issues must be
balanced. Currently, the transmission industry is widely viewed as being in a state
of disequilibrium with significant regulatory and economic uncertainty. In addition,
regional differences complicate regulatory solutions. A large component of
regulatory uncertainty originates with a piece-meal approach to electric utility
restructuring on both the federal and state level. In 1991, CRS stated that
comprehensive regulatory reform of the electric power industry is neither
desirable nor practical without a clearer vision of what form the industry should
take. Too many uncertainties leave the future nature of the electric power
industry such that a major overhaul of regulation would involve significant risks
to the present stability of available and reliable electric power with little
guarantee of improved service or lower costs.44
The Energy Policy Act of 1992 introduced competition to wholesale electric
transactions without provisions for a comprehensive plan to address reliability issues
and the development of efficient wholesale markets. In addition, many states have
passed legislation or issued regulatory orders to introduce retail competition, each
with its own set of rules for utilities to follow. Provisions in EPACT05 are intended
to address many issues left outstanding by EPACT02. Although regulatory certainty
may improve as a result of EPACT05, a clearer vision of the role of competition in
the electric power industry, and additional investment in transmission infrastructure
and technology, continues to be necessary to support an adequate and reliable
transmission system.
42 Standard & Poor’s, U.S. Power Industry Experiences Precipitous Credit Decline in 2002;
Negative Slope Likely to Continue, Jan. 15, 2003.
43 Standard & Poor’s, Industry Report Card: U.S. Utility Second-Quarter Upgrade Surge
Is Strongest in Years, July 10, 2006.
44 Electricity: A New Regulatory Order? A Report Prepared by the Congressional Research
Service for the Use of the Committee on Energy and Commerce, U.S. House of
Representatives. Committee Print 102-F. June, 1991.