Order Code RL32075
CRS Report for Congress
Received through the CRS Web
Electric Reliability: Options for Electric
Transmission Infrastructure Improvements
Updated June 10, 2005
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 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.
Electricity demand has been growing at 2% to 3% per year, but additions to the
transmission system have been growing by 0.7% per year. This has resulted in
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, needing approval of all states in
which the transmission line will be located. Second, some have argued that the
pricing mechanism for transmission is 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 has highlighted the need for infrastructure
improvements and greater standardization of operating rules. 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Current Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Regulatory Uncertainty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
List of Figures
Figure 1. Congested Lines in the Eastern Interconnection . . . . . . . . . . . . . . . . . . . 9
Figure 2. Congested Lines in the Western Interconnection . . . . . . . . . . . . . . . . . 10

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 (EPACT)2 created tension between the regulatory environment and existing
transmission system. EPACT 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 has
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 Twenty-two states and the District of Columbia have plans to allow for retail choice for
electricity. According to the Energy Information Administration, in 1996, 10 percent of
generating capacity was owned by non-utility generators. By 2000, 26 percent of generating
capacity was owned by non-utility generators. In addition, to encourage competition, Maine
and New Hampshire have required utilities to fully divest of either generation or
transmission assets and California and Rhode Island have partial divestiture requirements.

CRS-2
Electric reliability is addressed in comprehensive energy legislation (H.R. 6)
that passed the House on April 21, 2005. S. 10, introduced on June 9, 2005, also
includes reliability provisions. In part, Title XII of both bills would create an electric
reliability organization (ERO) that would enforce mandatory reliability standards for
the bulk-power system. All ERO standards would 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. This title also addresses transmission infrastructure
issues. The Secretary of Energy would be able to certify congestion on the
transmission lines and issue permits to transmission owners. Permit holders would
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. For
additional analysis, see CRS Report RL32936, Omnibus Energy Legislation, 109th
Congress: Assessment of H.R. 6 as passed by the House
; and CRS Issue Brief
IB10143, Energy Policy: Comprehensive Energy Legislation (H.R. 6, S. 10) in the
109th Congress
.
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 the rates for distribution charges and retail electric rates.
In states that have not restructured, the system operates as it has since enactment of
the Federal 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. The Federal Energy Regulatory Commission (FERC) regulates
all transmission, including unbundled retail transactions.4
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.
4 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. Ruling available at [http://a257.g.akamaitech.net/
7/257/2422/04mar20021030/www.supremecourtus.gov/opinions/01pdf/00-568.pdf].

CRS-3
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.5 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 (EPACT) created a new category of wholesale
electric generators called Exempt Wholesale Generators (EWGs) that are not
considered utilities.6 EWGs, also referred to as merchant generators, were intended
to create a competitive wholesale electric generation sector. In addition, EPACT
provided a means for these non-utility generators to have access to the transmission
system. As a result of EPACT, 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
wheeling authority under the Energy Policy Act of 1992 (EPACT)[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.7
In May 1994, FERC established general guidelines for comparable access to the
transmission system.8 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. 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
5 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.
6 Exempt Wholesale Generators may sell electricity only at wholesale. However, unlike
utility generators that are limited by the Public Utility Holding Company Act of 1935
(PUHCA) to operate within one state, EWGs may be located anywhere, including foreign
countries.
7 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.
8 67 FERC 61,168.

CRS-4
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.
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.9 North American
Electric Reliability Council (NERC) 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.10
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.
Electricity demand has been growing at 2% to 3% per year, but additions to the
9 Within each interconnection, all generators rotate in unison at a speed that produces a
consistent frequency of 60 cycles per second.
10 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].

CRS-5
transmission system have been growing by 0.7% per year. So, in addition to
generation capacity shortages in certain regions of the country, transmission lines 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.11 According to NERC, the number of requests
to use the transmission system that were denied because of congestion has risen from
305 in 1998 to 1,494 in 2002.12 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.13 If this projection is accurate, further pressure on
reliability could occur in several regions.14
Siting.
One reason transmission lines have not been built in recent years is
the difficulty in siting lines. Even though the transmission of electricity is considered
interstate commerce, the siting of transmission lines is the responsibility of the states.
In addition, several federal agencies play various roles in the siting process, primarily
with regard to environmental impacts. Siting and building transmission lines have
been very difficult because of citizen opposition as well as inconsistent siting
requirements among states. While controversial, since the blackout of 2003, FERC
Commissioners are now supporting federal siting backstop authority.15 In addition,
the electric industry is in favor of giving FERC siting authority.16 States are generally
opposed to this proposal.17
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
11 CRS Report 87-289 ENR. Wheeling in the Electric Utility Industry. February 12, 1987
(available from the author).
12 NERC data on Transmission Loading Relief (TLR) requests are available at [ftp://www.
nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm].
13 Department of Energy. National Transmission Grid Study. May 2002. Available at
[http://www.eh.doe.gov/ntgs/reports.html#reports].
14 See CRS Report RL31469. Electric Utility Restructuring: Maintaining Bulk Power
System Reliability.

15 Statement of Nora Mead Brownell. FERC Reverses Position, Will Now Take Federal
Backstop Authority
. Energywashington.com. September 2, 2003.
16 Edison Electric Institute. Federal Siting Authority: Key to Expanding Electricity
Infrastructure.
Available at [http://www.eei.org/industry_issues/energy_infrastructure/
transmission/federalsiting.pdf].
17 Statement of National Governors Association available at [http://www.nga.org/nga/
legislativeUpdate/1,1169,C_LETTER%5ED_4412,00.html].

CRS-6
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.18 The study
indicated that a significant number of transmission lines operate below their thermal
limits due to equipment limitations at substations. By remediating the equipment
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.19 FERC has traditionally determined rates by using an embedded cost
method that includes recovery of capital costs, operating expenses, improvements,
accumulated depreciation, and a rate of return. Traditionally, transmission owners
have been compensated for use of their lines based on a contract path for the
movement of electricity, generally the shortest path between the generator and its
customer. However, electricity rarely follows a contract path and instead follows the
path based on least impedance.20 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.21
18 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.
19 16 U.S.C. 824(d)(a).
20 Impedance is a measure of the resistive and reactive attributes of a component in an
alternating-current circuit.
21 See, National Economic Research Associates. Transmission Pricing Arrangements and
Their Influence on New Investments
. World Bank Institute. July 6, 2000. Available at
[http://www.worldbank.org/wbi/infrafin/pdfs/samples/dc2000-weektwo/berry_trans_

CRS-7
Under Order 2000,22 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)23; (2) to compensate for perceived increases in
financial risk because of participation in a regional transmission organization, and (3)
to facilitate efficient expansion of the transmission system.
FERC uses a “license plate” rate for transmission: a single rate based on
customer location. As FERC is encouraging formation of large regional transmission
organizations, FERC may move toward a uniform access charge, sometimes called
postage stamp rates. With a postage stamp rate, users pay one charge for moving
electricity anywhere within the regional transmission organization.
Postage stamp rates eliminate so-called rate pancaking, or a series of
accumulated transmission charges as the electricity passes through adjacent
transmission systems, and increases the pool of available generation. On the other
hand, by moving to postage stamp rates, customers in low-cost transmission areas
may see a rate increase, and high-cost transmission providers in the same area may
not recover embedded costs because costs are determined on a regional basis.
In early 2003, FERC proposed to raise the rate of return as a way to reflect the
regulatory uncertainty in the industry and encourage transmission investment.24 If
adopted, this policy 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. However, in 2000, the
cost of transmission accounted for less than 10% of the final delivered cost of
electricity.25 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.26
21 (...continued)
pricing.ppt].
22 89FERC61,285.
23 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
.
24 Federal Energy Regulatory Commission. Proposed Pricing Policy for Efficient Operation
and Expansion of the Transmission Grid.
Docket No. PL03-1-000. January 15, 2003.
25 Energy Information Administration. Electric Sales and Revenue 2000.
26 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].

CRS-8
Regulatory Uncertainty. Transmission owners and investors have expressed
concern that the regulatory uncertainty for electric utilities is inhibiting new
investment in and construction of transmission facilities. For example, repeal of the
Public Utility Holding Company Act of 1935 (PUHCA) has been debated since 1996
without resolution. Without clarification on whether PUHCA will be repealed,
utilities state that they are reluctant to invest in infrastructure. Repeal could
significantly expand the ability of utilities to diversify their investment options.27
In addition, FERC has been moving toward requiring participation in regional
transmission organizations to create a more seamless transmission system. A fully
operational regional transmission organization would operate the entire transmission
system in a region and be able to replace multiple control centers with a single
control center.28 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).29 FERC’s stated goal of SMD requirements in
conjunction with a standardized transmission service is to create “seamless”
wholesale power markets that allow sellers to transact easily across transmission grid
boundaries. The proposed rulemaking would create a new tariff under which each
transmission owner would be required to turn over operation of its transmission
system to an unaffiliated independent transmission provider (ITP). The ITP, which
could be an RTO, would provide service to all customers and run energy markets.
Under the NOPR, congestion would be managed with locational marginal pricing.
27 For discussion of PUHCA repeal issues, see CRS Report RL32728, Electric Utility
Regulatory Reform: Issues for the 109th Congress
.
28 PJM operates with a single control center.
29 FERC, Docket No. RM01-12-000.


CRS-9
Figure 1. Congested Lines in the Eastern Interconnection
Source: U.S. Department of Energy. National Transmission Grid Study. May 2002.
On April 28, 2003, FERC staff issued Wholesale Power Market Platform, a
White Paper that intended to clarify FERC’s SMD proposal.30 The White Paper
responds to approximately 1,000 sets of formal comments submitted to FERC. In the
White Paper, FERC states its intention to eliminate a proposed requirement that
utilities join an Independent Transmission Provider (ITP). Instead, the final rule will
require utilities to join an RTO or Independent System Operator (ISO). In the NOPR,
FERC proposed to assert jurisdiction over the transmission component of bundled
retail service. The White Paper reverses this position and states that the final rule will
not assert new FERC jurisdiction over bundled retail sales.
30 The FERC White Paper is available at [http://www.ferc.gov/industries/electric/indus-act/
smd/white_paper.pdf].


CRS-10
Figure 2. Congested Lines in the Western Interconnection
Source: U.S. Department of Energy. National Transmission Grid Study. May 2002.
Some state officials have expressed concern that the proposed rule infringes on
state authority. FERC responded to this in the White Paper by clarifying that the
final rule will not include a requirement for a minimum level of resource adequacy.
In addition, the final rule will eliminate the NOPR’s requirement that Firm
Transmission Rights be auctioned. The White Paper noted that each RTO or ISO will
need to have a cost recovery policy outlined in its tariff, but each region may differ
on how participant funding will be used.31 In addition, FERC stated that the final rule
will allow for phased implementation to address regional differences.
This NOPR has been very controversial, with many arguing that the “one-size-
fits-all” approach does not reflect regional differences. It is unlikely that FERC will
31 Participant Funding would additional transmission infrastructure that would be required
to connect new generators to the grid to be paid for by the beneficiaries of the new
transmission (ultimate consumers or new generators) rather than the traditional method of
cost recovery through the entire rate-base.

CRS-11
issue a final SMD rule in the near future. House-passed comprehensive energy
policy legislation (H.R. 6) would prohibit FERC from implementing its SMD
proposal for five years. This adds to uncertainty for transmission owners who may
be considering transmission additions as well as for investors.
Investment. Some contend that obtaining funding is the major impediment
to transmission expansion.32 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 withdrawn from heavily
investing in utility stock. According to Standard & Poor’s, utility bonds are also
unattractive to investors.33 Since 2000, 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 has significantly slowed
transmission capacity additions.
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.34
32 Roseman, Elliot and Paul De Martini. In Search of....Transmission Capitalists. Public
Utilities Fortnightly. April 1, 2003.
33 Standard & Poor’s, U.S. Power Industry Experiences Precipitous Credit Decline in 2002;
Negative Slope Likely to Continue,
Jan. 15, 2003.
34 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
(continued...)

CRS-12
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, approximately half
of the states have passed legislation or issued regulatory orders to introduce retail
competition, each with its own set of rules for utilities to follow. Without greater
regulatory certainty, and a clearer vision of the role of competition in the electric
power industry, investment in transmission infrastructure and technology will likely
continue to be inadequate.
34 (...continued)
Representatives. Committee Print 102-F. June, 1991.