National Transmission Grid Study

U.S. Department 

of Energy

The Honorable Spencer Abraham

Secretary of Energy

May 2002
ii National Transmission Grid Study 
National Transmission Grid Study i
ii National Transmission Grid Study 
National Transmission Grid Study iii

How This Study Was Conducted

The National Energy Policy Plan directed the U.S. Department of Energy (DOE) to conduct a study

to examine the benefits of establishing a national electricity transmission grid and to identify

transmission bottlenecks and measures to address them.

DOE began by conducting an independent analysis of U.S. electricity markets and identifying

transmission system bottlenecks using DOE’s Policy Office Electricity Modeling System (POEMS).

DOE’s analysis, presented in Section 2, confirms the central role of the nation’s transmission 

system in lowering costs to consumers through increased trade. More importantly, DOE’s analysis

also confirms the results of previous studies, which show that transmission bottlenecks and 

related transmission system market practices are adding hundreds of millions of dollars to 

consumers’ electricity bills each year. A more detailed technical overview of the use of POEMS 

is provided in Appendix A.

DOE led an extensive, open, public input process and heard a wide range of comments and

recommendations that have all been considered.1 More than 150 participants registered for three

public workshops held in Detroit, MI (September 24, 2001); Atlanta, GA (September 26, 2001);

and Phoenix, AZ (September 28, 2001). In addition, more than 40 public comments were received

The National Energy Policy Development (NEPD) Group recommends that

the President direct the appropriate federal agencies to take action that will

remove constraints on the interstate transmission grid so that our nation’s

electricity supply will meet the growing needs of our economy.

NEPD directs the Secretary of Energy to examine the benefits of establishing

a national grid and to identify transmission bottlenecks and measures to

address them.

Source: Office of the President. 2001. National Energy Policy Plan. 

Download from http://www.pi.energy.gov/pilibrary.html

1Federal Register Notice for the study and public input process was published September 12, 2001.
iv National Transmission Grid Study 

by mail or through a DOE website created for the study (http://www.ntgs.doe.gov/). Appendix B

lists the organizations that offered public comment at one or more of the workshops or through

the website.

As further input to this study, DOE commissioned a series of six issue papers from teams

of nationally recognized experts. Each team of experts was asked to provide a comprehensive

survey of a topic, including review of the comments from DOE’s public hearings, and to identify

and assess options for DOE’s consideration. The six topics reviewed in the issue papers are:

● Transmission System Operation and Interconnection

● Reliability Management and Oversight 

● Alternative Business Models for Transmission Ownership and Operation

● Transmission Planning and the Need for New Capacity

● Transmission Siting and Permitting

● Advanced Transmission Technologies

The issue papers are published under a separate cover. Readers are cautioned that the

views expressed by the authors in the issue papers are not necessarily those of DOE.

In preparing its recommendations, DOE considered the analysis and options presented by 

the public comments received, DOE’s own analysis, and the issue papers. As one would expect

on such a complex subject, there were many divergent opinions on the recommendations that

DOE should include. It is not possible, or desirable, to discuss each and every position. Instead,

this study presents the results of DOE’s comprehensive review and analysis.
National Transmission Grid Study v

Acknowledgments

This report was prepared by the Secretary of Energy under the direction of Jimmy Glotfelty and

Logan Walters, Office of the Secretary, and Paul Carrier, Office of Policy and International Affairs.

The study was supported by an interagency working group that included: Tracy Terry, Office 

of Policy and International Affairs; Larry Mansueti and Philip Overholt, Office of Energy Efficiency

and Renewable Energy; Anthony Como, Office of Fossil Energy; Alison Silverstein, Federal Energy

Regulatory Commission; and Douglas Hale, Energy Information Administration. 

POEMS analysis was led by Tracy Terry, Office of Policy and International Affairs. Frances Wood

and Lessly Goudarzi, OnLocation, Inc. provided modeling support.

DOE’s public workshops were supported by Vernellia Johnson, Office of Energy Efficiency and

Renewable Energy; Peter Dreyfuss, Chicago Regional Office; James Powell, Atlanta Regional Office;

and Zead Haddad, Office of Policy and International Affairs.

Technical support was coordinated by the Consortium for Electric Reliability Technology

Solutions under the direction of Joseph Eto, Lawrence Berkeley National Laboratory. The technical

team consisted of Fernando Alvarado, University of Wisconsin, Madison; Jeff Dagle, John Hauer, and

Steve Widergren, Pacific Northwest National Laboratory; George Gross and Tom Overbye, University

of Illinois, Urbana-Champaign; Eric Hirst, Consultant; Brendan Kirby, Oak Ridge National Laboratory;

David Meyer, Consultant; Shmuel Oren, University of California, Berkeley; and Richard Sedano,

Regulatory Assistance Project. Anthony Ma, Nan Wishner, and Ted Gartner, Lawrence Berkeley

National Laboratory, provided editorial and production support.
vi National Transmission Grid Study 
National Transmission Grid Study vii

How This Study Was Conducted iii

Acknowledgments v

Acronyms ix

Executive Summary xi

Section 1: Our National Transmission System Today 1

and Tomorrow

The U.S. Electricity Transmission System is Under Stress 5

Toward the Transmission System of Tomorrow 7

Section 2: The National Interest in Relieving 9

Transmission Bottlenecks

Major Eastern Transmission Bottlenecks 11

Major Western Transmission Bottlenecks 15

The Costs of Transmission Congestion 16

The Benefits of Wholesale Electricity Markets Today 19

Next Steps Toward Relieving Transmission Bottlenecks 19

Section 3: Relieving Transmission Bottlenecks 23

By Completing the Transition to Competitive 

Regional Wholesale Electricity Markets

Establishing Regional Transmission Organizations 24

Increasing Regulatory Certainty and Focus 29

Section 4: Relieving Transmission Bottlenecks 37

Through Better Operations

Pricing Transmission Services to Reflect True Costs 39

Increasing the Role of Voluntary Customer Load Reduction, 41

and Targeted Energy Efficiency and Distributed Generation 

Using Improved Real-Time Data and Analysis of Transmission 45

System Conditions

Ensuring Mandatory Compliance with Reliability Rules 46

Table of Contents
viii National Transmission Grid Study 

Section 5: Relieving Transmission Bottlenecks 49

Through Effective Investments

Implementing Regional Transmission Planning 50

Accelerating the Siting and Permitting of Needed Transmission Facilities 53

Ensuring the Timely Introduction of Advanced Technologies 61

Enhancing the Physical and Cyber Security of the Transmission System 68

Section 6: DOE’s Commitment and Leadership 71

Consolidated List of Recommendations 75

Appendix A: Policy Office Electricity Modeling System 80

(POEMS) and Documentation for Transmission Analysis

Appendix B: List of Participants at DOE National 86

Transmission Grid Study Public Workshops and 

Written Comments Received by DOE

Appendix C: Glossary 89

Issue Papers: (under separate cover)

Transmission System Operation and Interconnection

Reliability Management and Oversight

Alternative Business Models for Transmission Ownership and Operation

Transmission Planning and the Need for New Capacity

Transmission Siting and Permitting

Advanced Transmission Technologies
National Transmission Grid Study ix

Acronyms

AC Alternating current

AEP American Electric Power

ATC Available Transfer Capability

BPA Bonneville Power Administration

CAISO California Independent System Operator

CREPC Committee for Regional Electric Power Cooperation

DC Direct current

DOE U.S. Department of Energy

EIA U.S. Energy Information Administration

ERCOT Electric Reliability Council of Texas

FACTS Flexible AC transmission system

FERC Federal Energy Regulatory Commission

HTS High-temperature superconductivity

HVDC High-voltage direct current

IEEE Institute of Electrical and Electronics Engineers

ISO Independent System Operator

kV Kilovolt

MWh Megawatt hour

NARUC National Association of Regulatory Utility Commissioners

NASEO National Association of State Energy Officials

NEPD National Energy Policy Development

NERC North American Electric Reliability Council

NGC National Grid Company

NYISO New York Independent System Operator

OASIS Open Access Same Time Information System

PBR Performance-based regulation

PCR Price-cap regulation

PJM Pennsylvania, New Jersey, Maryland Interconnection

PMA Power Marketing Administration

POEMS Policy Office Electricity Modeling System

PUC Public utility commission

R&D Research and development

RTO Regional Transmission Organization

SWPA Southwestern Power Administration

TLR Transmission Loading Relief

TTC Total Transfer Capability

TVA Tennessee Valley Authority

WAPA Western Area Power Administration

WGA Western Governors’ Association

WSCC Western Systems Coordinating Council
x National Transmission Grid Study 
National Transmission Grid Study xi

The U.S. electricity transmission system is an extensive, interconnected network of high-voltage

power lines that transport electricity from generators to consumers. The transmission system must

be flexible enough, every second of every day, to accommodate the nation’s growing demand for

reliable and affordable electricity.

The transmission system was built over the past 100 years by vertically integrated utilities

that produced and transmitted electricity locally. Small interconnections between neighboring 

utilities existed, but they were created to increase reliability and share excess generation. Over 

the past 10 years, we have introduced competition into wholesale electricity markets to lower

costs to consumers by spurring needed investments in generation and increasing the efficiency 

of operations. Today, our transmission system acts as an interstate highway system for wholesale

electricity commerce.

There is growing evidence that the U.S. transmission system is in urgent need of modernization. The system has become congested because growth in electricity demand and investment 

in new generation facilities have not been matched by investment in new transmission facilities.

Transmission problems have been compounded by the incomplete transition to fair and efficient

competitive wholesale electricity markets. Because the existing transmission system was not

designed to meet present demand, daily transmission constraints or “bottlenecks” increase electricity costs to consumers and increase the risk of blackouts.

Eliminating transmission constraints or bottlenecks is essential to ensuring reliable and

affordable electricity now and in the future. The Department of Energy (DOE) conducted an independent assessment of the U.S. electricity transmission system and found that:

● Our U.S. transmission system facilitates wholesale electricity markets that lower consumers’

electricity bills by nearly $13 billion annually.

● Despite these overall savings, interregional transmission congestion costs consumers hundreds of millions of dollars annually. Relieving bottlenecks in four U.S. regions (California,

Executive Summary
ii National Transmission Grid Study 

PJM, New York, and New England) alone could save consumers about $500 million annually. Savings could be even greater because DOE’s analysis does not capture all of the

factors, such as impacts on reliability, that result from bottlenecks.

● Introducing advanced transmission technologies and improved operating practices, 

siting generation closer to areas where electricity is needed, and reducing electricity use

through targeted energy efficiency and distributed generation could all help reduce

transmission congestion.

● Better utilizing existing facilities can help delay the need for new transmission facilities,

but it cannot avoid construction of new transmission facilities entirely. 

Much work is needed to address transmission bottlenecks and modernize our nation’s

transmission systems. As a percentage of total energy use, electricity use is growing.2 This

reflects the transformation of our economy to an increasingly sophisticated, information-based

economy, one that relies on electricity. Electricity, though, is not a commodity that can be

stored easily. Our transmission infrastructure is at the heart of our economic well-being.

Imagine an interstate highway system without storage depots or warehouses, where traffic 

congestion would mean not just a loss of time in delivering a commodity, but a loss of the

commodity itself. This is the nature of the transmission infrastructure. That is why bottlenecks

are so important to remove and why an efficient transmission infrastructure is so important to

maintain and develop.

This report outlines 51 recommendations that will help ensure a robust and reliable transmission grid for the 21st century. The following are six general recommendations:

● First, we must increase regulatory certainty by completing the transition to competitive

regional wholesale markets. 

● Second, we need to develop a process for identifying and addressing national-interest

transmission bottlenecks.

2In 1970, electricity accounted for 8 percent of total U.S. energy use. In 2000, electricity accounted for 

16 percent of total U.S. energy use. Source: Energy Information Administration. Annual Energy Outlook 2002.

Download from http://www.eia.doe.gov
National Transmission Grid Study xiii

● Third, we can avoid or delay the need for new transmission facilities by improving transmission system operations and fully utilizing our existing facilities. Regional planning

processes must consider transmission and non-transmission alternatives when trying to

eliminate bottlenecks.

● Fourth, opportunities for customers to reduce their electricity demands voluntarily, and

targeted energy-efficiency and distributed generation, should be coordinated within

regional markets.

● Fifth, ensuring mandatory compliance with reliability rules must include enforceable penalties for non-compliance that are commensurate with the risks that the violations create.

● Sixth, DOE will take an increased leadership role in transmission R&D and policy by creating a new Office of Electricity Transmission and Distribution.

Action is needed now to put this study’s recommendations in place. Private industry and federal, state, and local governments must work together to ensure that our electricity transmission

system will meet the nation’s needs for reliable and affordable electricity in the 21st century.
1
Our National Transmission System Today and Tomorrow 2

Our National Transmission System

Today and Tomorrow

Electricity is a cornerstone on which the economy and the daily lives

of our nation’s citizens depend. This essential commodity has no

substitute. Unlike most commodities, electricity cannot easily be

stored, so it must be produced at the same instant it is consumed.

The electricity delivery system must be flexible enough, every second of the day and every day of the year, to accommodate the

nation’s ever changing demand for electricity. There is growing evidence that both private and public action are urgently needed to

ensure our transmission system will continue to meet the nation’s

needs for reliable and affordable electricity in the 21st century.

Fig. 1.1

North American

Electricity

Transmission

Systems

The North American electricity transmission system consists of three interconnected systems: the

Eastern Interconnection, the Western Interconnection, and most of the state of Texas. Within these

interconnections, more than 140 control areas manage electricity operations for local areas and

coordinate reliability through 10 regional councils.

Source: NERC 2001.

construction of three major interconnected

power systems: the Eastern and Western

Interconnections, and the Electric Reliability

Council of Texas (ERCOT). Within each system,

disturbances or reliability events are felt nearly

instantaneously throughout the system. This

interdependence leads to reliance on well-coordinated actions among its users to ensure 

The electricity transmission system is one of

the greatest engineering achievements of the

20th century. It is an extensive system of 

interconnected networks in which high-voltage

power lines transport electricity from generators to customers. A critical early decision to

rely on alternating current (AC) technologies

for high-voltage transmission has led to the
In 1996, the Federal Energy Regulatory

Commission (FERC) issued its landmark Orders

888 and 889, which required utilities to allow

non-utilities, or independent power producers,

access to, and use of, utility transmission systems. Prior to these Orders, electricity production decisions were made centrally by vertically

integrated utilities relying on generators they

owned or exchanges with neighboring utilities.

Investment in new generation by utilities had

slowed and production of electricity by non-utilities was modest. FERC’s orders were fundamental shifts in electricity policy and dramatically

changed the ways that electricity production

decisions were made and, consequently, in how

the transmission system is used and operated.

3 National Transmission Grid Study 

reliability. The continued need to coordinate

actions to ensure reliability is a key institutional

challenge as the system transitions to support

competitive wholesale markets (see Section 4).

There is also renewed interest in revisiting the

decision to rely on AC transmission technologies and increasing reliance on direct current

(DC) transmission technologies, which makes

some coordination actions simpler in principle

(see Sections 3 and 5). 

The transmission system was built, over 

the past 100 years, by vertically integrated utilities that produced electricity at large generation

stations located close to fuel supplies or needed

infrastructure and then relied on transmission

facilities to transport their electricity to customers. Interconnections among neighboring

utility systems were constructed to exchange

power to increase reliability and share excess

generation during certain times of the year.

Today, over 150,000 miles of high-voltage

transmission lines link generators to load centers through interconnected transmission systems that span utility service territories, states,

regions, and the borders of Mexico and Canada

(Table 1.1).3 

Ensuring the reliability of the transmission

system has always been paramount. For years,

utilities were the system’s only users, and reliability was managed successfully through voluntary compliance with planning and operating

standards established by the North American

Electric Reliability Council (NERC). System operations depended on local utility expertise to complement these standards in recognition of the

unique design of each utility’s system and the

technical complexity of coordinating operations.

3Electricity is delivered from the high-voltage transmission system to customers through progressively lower voltage (<100 kV) distribution systems.

U.S. High-Voltage Transmission System

Voltage

AC

Total AC

Miles of Transmission Line

230 kV

345 kV

500 kV

765 kV

DC

Total DC

250-300 kV

400 kV

450 kV

500 kV

154,503

76,762

49,250

26,038

2,453

3,307

930

852

192

1,333

Table 1.1

The U.S. electricity transmission system consists of over 150,000 miles of highvoltage transmission lines.

Source: NERC. 

Total AC & DC 157,810
Our National Transmission System Today and Tomorrow 4

Centralized decision making by vertically

integrated utilities, alone, now no longer determines electricity production. Instead, competitive

market forces, involving a number of new market participants, increasingly determine who produces electricity and where it will be consumed.

Since 1996, the transmission system has been

slowly transformed into an interstate highway of

commerce upon which emerging wholesale electricity markets depend.

During the past few years, wholesale power

markets have flourished, as new market participants have undertaken the risks and rewards of

developing merchant power plants. From 1996

to 1999, wholesale power marketers increased

sales by more than six-fold. This, in addition to

both continued load growth and increased

wholesale power sales by traditional utilities, 

has resulted in the need for an expanded 

transmission system. More than half of all electricity generated is now exchanged on the 

wholesale market before being sold to ultimate

consumers.4

The creation of wholesale electricity markets

has enabled new market participants to address

the nation’s needs for new generating capacity.

After years of decline, NERC forecasts now 

indicate that generation capacity margins will

increase.5,6 Summer peak electricity demand and

generation capacity are projected to increase 

by almost 20 percent each during the next 10

years. Much of this new generation will be developed by independent power producers and

unregulated affiliates of utilities.7 (Figure 1.2)

4U.S. Energy Information Administration. 2000. The Restructuring of the Electric Power Industry: A Capsule of Issues and Events. Download from

http://www.eia.doe.gov

5Capacity margin is the ratio of generating capacity to electricity demand. Excess generating capacity is needed to ensure reliability because demand

can shift rapidly (e.g., in response to weather) and total generation capacity is not available at all times (e.g., because of planned maintenance or

unexpected equipment failure).

6North American Electric Reliability Council. 2001. Reliability Assessment, 2001-2010. Download from http://www.nerc.com

7However, the recent contraction of our capital markets, and the announced delay in the construction of many new power plants, will affect this trend.

22

20

18

16

14

12

10

8

1998 2000 2002 2004 2006 2008 2010 

1998 2000

1999 2001

Fig. 1.2

Capacity Margins

over Time

After many years of decline, the ratio of generating capacity to electricity demand has begun and, according

to NERC forecasts, will continue to increase. This increase means that there will be adequate generation

capacity to meet expected electricity demand.

Source: NERC. 2001. Reliability Assessment, 2001-2010. Download from http://www.nerc.com
5 National Transmission Grid Study 

The California Electricity Crisis

At its root, the California power crisis was caused by an imbalance in the supply and demand for

electricity. Very little new generating capacity had been built or proposed in California and the

western states during the early 1990s. Once electricity restructuring rules were put in place,

independent power producers responded quickly, beginning in 1997, to file applications to build

more than 14,000 megawatts of new capacity. Yet, almost none of this proposed new capacity

was available by summer 2000. Despite electricity demand growth rates that were lower than

the national average during the 1990s, California was short of generation capacity. The absence

of new generation capacity, along with high natural gas prices, lack of water available for hydroelectric generation, market design flaws, and little demand-side participation in the energy market all combined to drive wholesale power prices up to unprecedented levels.

The lack of adequate transmission played an important role in exacerbating the problems created by the

imbalance between California’s supply and demand for electricity. Because transmission is constrained

between the northern and southern portions of the state, the number of competitors able to provide electricity in each of these markets is effectively reduced thereby leading to higher prices.

The situation in California stabilized during the past year when wholesale power prices fell dramatically as a

result of lower natural gas prices, new generation finally coming on line, extraordinary load reduction efforts

by households and businesses, improved hydro conditions, and Federal Energy Regulatory Commission

actions. Nevertheless, transmission system upgrades remain an important element of a comprehensive,

long-term solution to California’s electricity system.

Source: U.S. Department of Energy. 2000. Horizontal Market Power in Restructured Electricity Markets. DOE/PO-0060. 

Download from http://www.policy.energy.gov/HMPReport.pdf

The U.S. Electricity Transmission System

Is Under Stress

1

Despite the success of the wholesale electricity

markets and the ability of new participants to

address the nation’s needs for new generation

capacity, there is growing evidence that the U.S.

transmission system is under stress. Growth in

electricity demand and new generation, lack of

investment in new transmission facilities, and

the incomplete transition to fully efficient and

competitive wholesale markets have allowed

transmission bottlenecks to emerge. These

bottlenecks increase electricity costs to consumers and increase the risks of blackouts.

The growth of electricity demand during

the 1990s, coupled with new generation

resulting from the emergence of competitive

wholesale electricity markets, has led to electricity flows that are greater in size and in 

different directions than those that were
Our National Transmission System Today and Tomorrow 6

anticipated when the transmission system 

was first designed. NERC reports that there 

is minimal operating experience for handling

these conditions. The increased use of the

system has led to transmission congestion

and less operating flexibility to respond to

system problems or component failures. This

lack of flexibility has increased the risk of

blackouts. Today, power failures, close calls,

and near misses are much more common than

in the past.

Transmission congestion or bottlenecks

result when there is not enough transmission

capability to accommodate all requests to ship

power over existing lines and maintain adequate safety margins for reliability. Because

electricity cannot yet be stored economically,

transmission system operators must deny

requests for transmission service when they

receive too many of them in order to prevent

lines from becoming overloaded. In other words,

transmission congestion does not refer to deliveries that are merely held up or delayed (as in

traffic congestion); it refers to transactions that

cannot be executed. 

Transmission operators manage transmission congestion through a set of NERC-approved

procedures called Available Transfer Capability

(ATC) and Transmission Loading Relief (TLR).

ATC calculations establish the maximum ability

of a system to support expected wholesale transactions reliably. When the system is in danger of

exceeding these limits, TLR procedures (known

as TLR “calls”) determine which requests for

transmission will be denied in order to prevent

lines from becoming overloaded.

In the last two years, the frequency of TLR “calls” has increased

dramatically. The frequent use of 

TLRs indicates that the system is

under greater stress because it is

being operated closer to its limits.

(Figure 1.3)

Today, the ATC and TLR procedures play a key role in ensuring

transmission reliability. Unfortunately,

the use of these procedures also

interferes with market efficiency.

Transmission congestion and the use

of TLR calls increases consumer costs

by frequently denying low-cost transactions in favor of high-cost transactions. As customer demand in an area

surpasses the import capability of the

transmission lines serving that area,

operators are forced to meet the

Actions by operators to curtail proposed transactions in order to ensure

reliability according to procedures developed by the North American

Electric Reliability Council have increased dramatically since the time

they were first adopted in 1997.

Source: NERC.

0

200

400

600

Total Number of Logs

Year

800

1000

1200

1997* 1998 1999 2000 2001**

*Includes only July through December

**Includes only January through October

Fig. 1.3

Transmission 

Loading

Relief Events
7 National Transmission Grid Study 

5

4

3

2

1

0

1975 1980

TRANSMISSION INVESTMENT (billion 1999-$/year)

-$117 million/year

1985 1990 1995 2000

Fig. 1.4

Transmission

System

Investment 

over Time

area’s energy demand with more expensive

local generation rather than less expensive

generation from elsewhere in the region.8

Construction of new transmission facilities would alleviate these stresses. However,

NERC also reports that investment in new

transmission facilities is lagging far behind

investment in new generation and growth 

in electricity demand. Construction of highvoltage transmission facilities is expected to

increase by only 6 percent (in line-miles) 

during the next 10 years, in contrast to the

expected 20 percent increase in electricity

demand and generation capacity (in MW).

Although we would not expect transmission

to grow as quickly as new generation capacity or demand, this projected growth is not

adequate to ensure reliability and sustain

continued growth of competitive regional

wholesale electricity markets. (Figure 1.4)

During the late 1970s, there was debate about

whether the U.S. should “nationalize” the electricity grid. Some felt the electricity system was

of such great importance that it had to be managed by the federal government; others were

wary of centralized federal decision making and

advocated industry-led solutions. During the

1990s, the nation chose to introduce competiInvestment in new transmission facilities has declined steadily for the last 25 years.

Source: E. Hirst and B. Kirby. 2001. Transmission Planning for a Restructured U.S. Electricity Industry. 

Edison Electric Institute.

8For additional background, see the Issue Paper, Transmission System Operation and Interconnection, by F. Alvarado and S. Oren.

Toward the Transmission System 

of Tomorrow

1
Our National Transmission System Today and Tomorrow 8

tion to the electricity market and has since

begun to reap the benefits of private developers’ investment in merchant generation capacity.

A key benefit to consumers is that the financial

risks of power plant construction and operation

have been shifted from consumers to private

developers whose earnings depend on their 

ability to generate power competitively.

Robust and reliable regional electricity

transmission systems are the key to sustaining

fair and efficient competition in wholesale markets that lowers costs to consumers. The national transmission grid DOE envisions is based on

the principles of free markets with clear rules,

equal access, consumer safeguards, economic

incentives, and investment opportunities rather

than federal ownership and operation.

Building new transmission facilities or

undertaking other strategies to address transmission bottlenecks should depend first and

foremost on market participants responding 

to business opportunities. Similarly, greater

electrical interconnections among existing transmissions systems should be the result of regional initiatives, not federal directives. When the

private sector and markets can do the job, the

federal role is to let regional markets work.

Discussions of regional transmission systems heighten state concerns over their regulatory responsibility to protect reliability and

ensure affordable electricity to retail consumers.

Movement toward regional transmission systems

and competitive wholesale electricity markets

must balance state, regional, and federal

responsibilities. In the end, consumers must

be assured reliable and affordable electricity.

The future provision of reliable and

affordable electricity requires modernizing the

structure and operation of the nation’s transmission systems to serve the regional needs 

of competitive wholesale electricity markets.

The transmission systems of tomorrow must

be operated in ways that take full advantage of

market forces to ensure reliability in an economically efficient manner, allow customers to

adjust their demands in response to system

needs and be compensated for these actions,

incorporate advanced hardware and software

technologies to increase utilization of existing

facilities safely, and follow strict rules for reliability with appropriate penalties for non-compliance. The transmission systems of tomorrow

must be built by relying on open regional planning processes that consider a wide range of

alternatives, accelerating the siting and permitting of needed facilities, taking full advantage

of advanced transmission technologies, and

incorporating appropriate safeguards to ensure

the physical and cyber security of the system.

The cost of transmission accounts for 

less than 10 percent of the final delivered cost

of electricity in what is today a $224 billion

electricity industry.9 We cannot afford to allow

the relatively small cost of transmission to 

prevent consumers from enjoying the reliable

and affordable electricity service that properly

managed competitive forces will deliver to 

our nation.

9Source: Energy Information Administration. Electric Sales and Revenue 2000. Download from http://www.eia.doe.gov
9 National Transmission Grid Study 

2
The National Interest in Relieving Transmission Bottlenecks 10

10DOE’s model does not consider congestion within single control areas such as ERCOT. 

Transmission bottlenecks affect national interests by increasing the

cost of electricity to consumers and the risk of transmission system

reliability problems in various regions throughout the United States.

Relieving transmission bottlenecks is a regional issue. DOE will work

in partnership with FERC, states, regions, and local communities to

designate significant bottlenecks as national-interest transmission

bottlenecks and take actions to ensure that they are addressed.

The National Interest in Relieving

Transmission Bottlenecks

tricity markets. Through the use of the POEMS

model (see text box), DOE determined the location of major bottlenecks in both the Eastern

and Western Interconnections and estimated the

costs of these constraints to consumers.10 DOE

also estimated the benefits consumers currently

receive from regional electricity markets. 

Over the past year, there have been several

national and regional studies that have highlighted congested transmission paths. DOE has

also developed a list of congested paths and

has compared it to those recently identified by

FERC. Even though the studies were conducted

using different methods, the patterns of congestion found in both studies are very similar.

DOE’s current tools have identified a number of bottlenecks that may have significant

impacts on national interests. More work and

additional public input are required to develop

a comprehensive set of tools and data needed

to capture the full range of impacts of transmission bottlenecks on national interests, including

the impacts on reliability and on the competitiveness of wholesale electricity markets.

DOE believes that identifying and eliminating

major transmission bottlenecks is vital to our

national interest. National-interest transmission

bottlenecks create congestion that significantly

decreases reliability, restricts competition, enhances opportunities for suppliers to exploit 

market power, increases prices to consumers, 

and increases infrastructure vulnerabilities.

Transmission bottlenecks and the options 

to address them are regional in nature. When 

the consequences of bottlenecks become large, 

it is in the national interest to ensure that they 

are addressed in a timely fashion. Since no state

has control or authority over regional transmission systems, the federal government has a role

to play in identifying major bottlenecks and ensuring that they are addressed. The national interest

is best served if DOE and FERC together work 

with states and regions to identify and address

the most significant bottlenecks.

To begin the process of analyzing the effects

of transmission bottlenecks on national interests,

DOE conducted an independent analysis focusing

on the impacts of transmission on regional elec-
DOE’s analysis confirms the tendency for transmission congestion to develop at many locations within the Eastern Interconnection. Out of

a total of 186 transmission paths modeled in

the East, 50 are used to their maximum capacity

at some point during the year, and 21 paths are

congested during more than 10 percent of the

hours of the year.11 The highest levels of congestion are found along transmission corridors

from Minnesota to Wisconsin, the Midwest into

11 National Transmission Grid Study 

Policy Office Electricity Modeling System (POEMS)

DOE estimated the benefits of interregional wholesale power markets using the Policy Office Electricity

Modeling System (POEMS). POEMS is a full-scale national energy model designed specifically to examine the

impacts of electricity industry restructuring. The model includes significant economic, regional, and temporal

detail that is needed to analyze the economics of interregional trade.

POEMS aggregates individual transmission lines to create a network of transmission paths that connect 

69 subregions. The model represents the transmission system as a highway system—a series of paths between

regions with a fixed amount of transmission capacity along each path. Trades are executed among the model’s

subregions based on the relative costs of generation in each subregion as well as the costs of executing each

trade. A more detailed description of the model and its use in this study is provided in Appendix A.

POEMS is an important tool for assessing the economic consequences of electricity trade and identifying

major transmission bottlenecks. However, it does not explicitly represent the physical flows of electricity over

paths in response to the combined effects of all other flows on the system. Also, because it is national in

scope, the model does not consider trade within subregions.

For the National Transmission Grid Study, POEMS was used to study:

• Transmission bottlenecks as evidenced by the costs of transmission congestion among subregions 

• The benefits of regional electricity markets today

• The benefits of regional electricity markets that would be enabled by eliminating rate pancaking.*

Results from the first two analyses are presented in this section; results from the third analysis are presented

in Section 3,“Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional

Wholesale Electricity Markets.”

*

In many regions, when electricity must be transmitted over multiple transmission systems, users must pay each owner/operator a separate

fee for use of its transmission system. This is generally referred to as rate pancaking.

Major Eastern Transmission Bottlenecks

2

11As noted previously, POEMS generally does not represent individual transmission lines. Thus, the results presented in this study do not suggest

that there is congestion on any particular transmission line but rather that there is congestion along transmission paths or corridors between

subregions.
The National Interest in Relieving Transmission Bottlenecks 12

the Mid-Atlantic, from the Mid-Atlantic to New

York, and from the Southeast into Florida.

In general, DOE’s findings are very similar

to historical data on transmission congestion,

which also indicate that there is substantial

congestion in the Midwest and upper Midwest,

and from the Mid-Atlantic to the Northeast.12

DOE also found congestion in some areas

where there have been few TLR events called,

such as in the Southeast. DOE’s analysis suggests that substantial congestion would result

in these areas if there were greater volumes of

economic wholesale electricity transactions. In

particular, all of the transmission paths 

out of the Tennessee Valley Authority (TVA)

would be congested at some point, and some

would be congested roughly 15 percent of

the time. Even more striking are the electricity flows that would take place from the

Southeast into Florida; these lines would be

congested during 40 to 80 percent of the

hours of the year. (Figure 2.1)

DOE’s findings are consistent with 

the comments of market participants who

offered input to a recent FERC staff report 

on bulk-power markets in the Southeast.13

Fig. 2.1

Map of

Congested

Paths in the

Eastern 

Interconnection

10% to

80% an

60% to

40% to

20% to

< 1

>=1

>=3

Size of Transm

Percentage of 

20

41

39

34 33

36

24

35

32

30

10

12

21

9

8

19

6

7

25

3

4

2 1

28

5

11

13

14

15

17 16

18

22

23

26

27

29

31

37

38

40

10% to 19%

80% and greater

60% to 79%

40% to 59%

20% to 39%

< 1 GW

>=1 and <3 GW

>=3 GW

Size of Transmission Paths

Percentage of Hours Congested

12This finding is based on a comparison of POEMS results and information on transmission loading relief (TLR) incidents that is routinely reported

to NERC.

13FERC. 2000. Investigation of Bulk Power Markets: Southeast Region. Staff Report. Download from http://www.ferc.gov 
13 National Transmission Grid Study 

Hours of Congestion for Twenty Most Congested Paths

EAST

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

ECAR

MAAC

SERC

MAPP

SERC

MAPP

ECAR

MAAC

ECAR

MAAC

SERC

SERC

NYPP

SERC

SPP

ECAR

MAAC

ECAR

SERC

SERC

MAAC

NYPP

FRCC

MAIN

FRCC

SERC

SERC

NYPP

ECAR

MAAC

FRCC

SERC

NYPP

SPP

SPP

MAAC

NYPP

SERC

SERC

SERC

89%

85%

78%

73%

71%

65%

58%

50%

48%

48%

44%

43%

22%

19%

19%

16%

16%

14%

14%

14%

0.176

2.605

0.536

0.202

2.837

1.178

2.175

2.797

0.765

2.866

0.581

0.408

1.143

0.866

0.398

1.643

1.191

1.500

0.552

3.468

Exporter* Importer* %Hrs Congestion

per year

Path Size (GW)

WEST

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

NWP

NWP

NWP

NWP

NWP

CNV

NWP

NWP

NWP

NWP

CNV

RA

CNV

CNV

NWP

CNV

RA

CNV

NWP

RA

NWP

NWP

CNV

CNV

CNV

NWP

NWP

NWP

NWP

RA

NWP

RA

CNV

CNV

NWP

CNV

RA

RA

NWP

NWP

59%

51%

41%

39%

38%

36%

35%

32%

26%

22%

19%

19%

17%

16%

14%

8%

6%

5%

4%

3%

0.044

0.337

1.200

3.100

0.300

0.083

0.300

1.250

0.044

0.390

3.100

0.485

0.637

3.000

0.359

3.000

0.690

1.300

1.560

0.900

*See Appendix A for acronyms.

Table 2.1
The National Interest in Relieving Transmission Bottlenecks 14

areas that contribute to congestion. Hence,

although FERC could not verify the basis for 

all of the concerns expressed, market participants perceive that these problems exist and

discourage investment and wholesale trade 

in the region.

In addition, trading into the Southeast

power market is difficult. Due to its location,

the Tennessee Valley Authority (TVA) controls

the majority of transmission access into and

out of the region. Although TVA is largely

exempt from FERC regulation, it voluntarily 

provides open access to its transmission system. However, TVA and various suppliers in 

the market continue to disagree over access 

to the transmission system.

The Southeast includes more generation owned

by vertically integrated, investor-owned utilities than any other region of the country, and

many independent power producers and marketers believe these utilities are preventing

equal and open access to the transmission 

systems in this region.

In its report, FERC identified a number 

of barriers to wholesale electricity trade in this

region, including: uncertainty in transmission

access, inconsistent posting and withholding

of available transfer capability, and the lack 

of consistency when implementing transmission loading relief protocols. Utilities in the

Southeast report that the absence of coordinated generation and transmission planning has

led to new generation that has been built in

Strengthening the Interconnection between ERCOT and the Eastern Interconnection

In 1999, the Texas Public Utility Commission completed a study evaluating the most economical, reliable,

and efficient means to interconnect the transmission facilities in the Electric Reliability Council of Texas

(ERCOT) with those in the Southwest Power Pool within the Eastern Interconnection. The study determined the costs and reliability concerns associated with a hypothetical scenario of six inter-ties. It also discussed the state and federal jurisdictional issues that would need to be addressed. The final report, while

very detailed, was not able to draw a firm conclusion regarding the desirability of greater interconnection.

The study found that total costs for the interconnection facilities alone would be between $300 and $350

million in 1997 dollars. It also identified additional costs, which are difficult to quantify, that would be

imposed upon utilities and generators based on operating characteristics of the combined grid.

Since the study was completed, between 10,000 and 20,000 megawatts of new generation have been brought

on line in Texas, new transmission lines have been completed, and the retail market has opened.

With reserve margins as high as 31 percent in ERCOT, generators may begin a renewed push for the opening of additional markets for their power. It may be time to conduct a new study that evaluates alternatives,

including additional AC interconnections, new DC interconnections, as well as expansion of existing ties.

Source: Synchronous Interconnection Committee. 1999. Feasibility Investigation for AC Interconnection between ERCOT and SPP/SERC. Report to the

76th Texas Legislature.
Electricity trading patterns and transmission

congestion are somewhat different in the West

than in the East for several reasons. First, the

transmission system in the West, unlike the one

in the East, was built primarily to carry power

over long distances. Several large power plants 

in the West were intentionally built in remote

locations; along with these plants, owners constructed high-voltage transmission lines to ship

power to densely populated load centers.14

d

50

49

53

48

56

65 61

66

59

69

47

51

52

54

55

57

58

60

62

63 64

67

68

Fig. 2.2

Map of

Congested

Paths in the

Western

Interconnection

15 National Transmission Grid Study 

Major Western Transmission Bottlenecks

2

14For example, the Palo Verde nuclear plant was built in southern Arizona in part to serve load in southern California. Similarly, the Intermountain

Power Project, a 1,640-megawatt coal plant in Utah, was built to serve a number of municipalities in Utah and in California, including Los Angeles.

A 490-mile transmission line connects the plant to southern California.

10% to 19%

40% to 49%

30% to 39%

20% to 29%

< 1 GW

>=1 and <3 GW

>=3 GW

50% and greater

Size of Transmission Paths

Percentage of Hours Congested
The National Interest in Relieving Transmission Bottlenecks 16

In addition, the Pacific Northwest is dominated by hydroelectric power. The amount 

of water available for hydropower generation

in this area is greatest during the spring and

summer when runoff from snow pack is highest; however, electricity demand in the region

is greatest during winter. During spring and

summer, the Pacific Northwest sells its excess

electricity to California and other western

states. During the winter, the Pacific Northwest purchases excess power from these

areas. For the purpose of these transactions,

a large direct current (DC) transmission line

links southern California and the Bonneville

Power Administration (BPA) in Oregon.

As a result of these patterns of supply

and demand, utilities in the West rely substantially more on transporting electricity

over long distances to meet local demand

than is commonly the case in the East.

Electricity trade as a percentage of demand

in the West reaches nearly 30 percent during some periods, compared to only 15 

percent in the East. Because the transmission system in the West was specifically

designed to support these imports and

exports, there is less interregional congestion overall in the West. Of the 106 western

transmission paths represented in POEMS,

37 are congested at some point during the

year, half of these are congested less than

10 percent of the time, and no path is congested more than 60 percent of the hours

during the year.15 (Figure 2.2)

The Costs of Transmission Congestion

2

15POEMS does not consider congestion within the subregions in the West. Consequently, congestion on California’s Path 15, which is within a subregion, is not assessed by POEMS.

16Since ISO New England is represented in POEMS as a single subregion, increased costs resulting from congestion within New England are not

reflected in the analysis. Instead, the estimates reported here include only the increased costs due to congestion into New England. For the other

three regions, the estimates reflect costs arising from congestion into and within the region. See Appendix A for additional discussion of DOE’s

analysis using POEMS.

DOE estimated in two steps the costs of 

congestion in four U.S. regions where independent system operators manage wholesale

electricity markets: California, PJM, New York,

and New England.16 In the first step, DOE

used POEMS to examine the cost reductions

that would occur if increased electricity transfers across congested paths were allowed 

in these four regions, under the assumption

that all generators bid their marginal operating cost. Under this assumption, consumer

costs for electricity decline by $157 million

per year.

In the second step, DOE calculated the

increase in congestion costs (costs to consumers) under the assumption that generators bid above their marginal operating

costs when supplies are tight and additional electricity cannot be imported, leading

to price spikes. For this calculation, price

spikes were assumed to occur during the

hours when at least one transmission link
into a subregion was congested and demand

was greater than 90 percent of peak demand.

When prices spike an additional $50 per MWh

(above the price predicted when generators

bid their marginal operating cost) during

these periods, congestion costs nearly double

to $300 million. When prices spike an additional $100 per MWh during these periods,

congestion costs nearly triple to $447 million.

This calculation is a conservative estimate of

congestion costs. Recently, FERC estimated

costs for 16 individual constraints that ranged

up to more than $700 million for a handful of

recent summer months (see text box).17, 18

It is important to note that DOE’s findings do not address transmission bottlenecks

that may exist within subregions. For example, all of New England is represented as a

single subregion within the model, so benefits

from trade within New England are not reflected in the analysis. ISO New England estimates

the costs of congestion in New England are

$125–600 million per year.19 California’s 

Path 15, which is often congested, is also 

not specifically represented in POEMS. The

California ISO (CAISO) estimates that the cost

of congestion created by a single transmission corridor, Path 15, was $222 million over

the 16 months prior to December 2000.20

17 National Transmission Grid Study 

17Federal Energy Regulatory Commission. 2001. Electric Transmission Constraint Study. Division of Market Development. Download from

http://www.ferc.gov

18Although DOE’s analysis and FERC’s analysis are not strictly comparable because of differences in the methods used, their findings are generally

consistent. FERC’s analysis is based on actual market prices and does not reflect price changes that would occur on both sides of a constrained

transmission link if additional electricity could be traded. As a result, FERC’s estimates are likely to be somewhat higher than DOE’s.

19ISO New England. 2001. 2001 Regional Transmission Expansion Plan. Download from http://www.iso-ne.com

20California Independent System Operator. 2001. Testimony of Armando J. Perez, Stephen Thomas Greenleaf, and Keith Casey. Conditional

Application of Pacific Gas and Electric Company for a Certificate of Public Convenience and Necessity Authorizing the Construction of the Los BanõsGates 500 kV Transmission Project. Application 01-04-012. California Public Utilities Commission. Download from http://www.caiso.com.

FERC Electric Transmission Constraint

Study

On December 19, 2001, FERC presented 

findings from an analysis of transmission constraints in the U.S. FERC staff identified 16

constraints (see map) across the nation characterized by either:

• A large number of Transmission Load

Relief (TLR) events (instances when market sales cannot be executed because of

transmission constraints, which forces

operators to use more expensive local

energy rather than less expensive imported energy), or 

• High price differentials across an interface

(where the delivered energy price inside 

an area is higher than the price of energy

at the same moment outside that area).

FERC estimated the economic cost of transmission congestion during the months of June

through August 2000 and 2001 using actual

data on the number of hours during which 

a specific transmission interface was constrained, the amount of energy that was redispatched in each congestion event, and the

costs of imported and replacement energy in

each of these hours.
The National Interest in Relieving Transmission Bottlenecks 18

: Constraint and constrained flow direction

MAPP

SPP

ECAR

SERC

FRCC

MAIN

Southeast West VA

West VA/PJM Interface

East KS/MO Interface

Central IA

Central MO

 Southwest MI

Central CA

WY/ID Interface

Pacific DC Intertie

Northeast AZ

NWPA

AZ/NM/SNV

CA/MX

RMPA

CA/OR Interface

East Boston

SW CT Interface

East NY

Southeast PA

ISO-NE

NYISO

PJM

Southern CA

Transmission Constraints in Contiguous U.S.

FERC found that the costs of individual constraints for these months generally ranged

from less than $5 million to more than $50

million. However, for one particular set of

conditions in the eastern portion of New York

during the summer of 2000, FERC estimated a

cost of more than $700 million.

Source: FERC. 2001. Electric Transmission Constraint Study. Division of Market Development. Download from http://www.ferc.gov

The POEMS analysis offers minimum

estimates of the benefits of vibrant wholesale markets to the consumer. However,

the trend is clear: transmission bottlenecks today compromise important national interests in efficient regional wholesale

electricity markets and reliable transmission systems.

Finally, POEMS does not analyze reliability benefits. Increased transmission

capacity will generally improve the overall

reliability of the grid and allows regions to

share capacity reserves. Although the risk

of blackouts is generally small, blackouts

usually entail very high economic costs. As

such, even a small reduction in the risk of

a blackout will have substantial benefits.
19 National Transmission Grid Study 

In addition to the costs of specific bottlenecks,

DOE found that today’s wholesale electricity

markets save consumers nearly $13 billion per

year in electricity costs. In other words, the

nation’s current $224 billion annual electricity

bill would be $13 billion higher without these

wholesale shipments of electricity. On average,

wholesale power transactions reduce generation

costs by approximately $370,000 per hour in 

the East and by more than $1,000,000 per hour

in the West. These savings translate directly to

lower prices for consumers. Average wholesale

electricity prices are roughly 12 percent lower as

a result of interregional trading.21 (Figure 2.3)

Projected Average Wholesale Electricity Prices

0

10

20

30

40

50

60

East West US Total

2000$/MWh

Without Trade

With Trade

Note: Unmet demand without trade valued at $100/MWh.

Fig. 2.3

Electricity Prices 

(by Interconnection) 

With and Without

Interregional

Electricity Trading 

Next Steps Toward Relieving

Transmission Bottlenecks

2

DOE’s analysis has confirmed the tendency 

for transmission lines to become congested 

in many locations across the U.S. The consequences of this congestion warrant additional

scrutiny to determine the extent to which

national interests are jeopardized. In particular,

The Benefits of Wholesale Electricity

Markets Today

2

21This estimate includes the savings due to all electricity trade among the 69 subregions in the model. It does not distinguish increased trade due

to wholesale competition from economy trades that routinely occurred among neighboring utilities prior to FERC Orders 888 and 889.
The National Interest in Relieving Transmission Bottlenecks 20

The Cost of Reliability—August 10, 1996, Power Outages in the Western States

The blackout in the western states on August 10, 1996, was a complex and dramatic reminder of the

importance our modern society places on reliable electricity service. Ultimately, power was interrupted

to approximately 7.5 million customers, for periods ranging from a few minutes to about nine hours.

Immediate costs to the region’s economy were estimated at $2 billion.

The August 10 outages were caused by multiple transmission line failures over a period of several hours.

A single transmission line failure is a contingency that is routinely considered in reliability planning.

However, the failure of several lines, combined with the day’s pattern of operation, caused the system to

become unstable (which had not been anticipated by reliability planners), causing automatic controls to

open the California-Oregon Intertie, a major link between the northern (Pacific Northwest) and southern

(California) portions of the western system. Opening the Intertie produced a power surge from the

Pacific Northwest through the eastern portion of the grid toward Arizona and southern California, causing many lines to disconnect automatically and eventually fracturing the western grid into four separate

electrical “islands.” Within each island, large blocks of customers lost power when their electricity

demands suddenly exceeded available local generation. The situation was worst in the southern island

where automatic controls disconnected over 90 generators to prevent them from being further damaged.

Some of the larger units were out of service for several days.

Source: J. Hauer and J. Dagle, 1999. Review of Recent Reliability Issues and System Events. Report PNNL-13150. 

Download from http://www.eren.doe.gov/der/transmission 

DOE has not assessed the impacts of congestion on market power and reliability.

Successfully addressing transmission 

bottlenecks requires careful analysis and consideration of their impacts on both market

operations and system reliability, as well as

analysis of the costs of transmission and nontransmission alternatives. In other words,

removing bottlenecks is not simply a matter 

of finding “congested” transmission paths and

then reinforcing existing transmission facilities

along those paths or constructing new facilities. Because the system is a network, reducing congestion in one part of the system may

shift it to another (the next-most-vulnerable)

part. Congestion also tends to move around

the system from year to year and in response

to weather and other seasonal factors.

In addition, solving the problem of 

transmission constraints within the United

States will also require cooperation with

Canada. Many scheduled power transactions

within the U.S., particularly east-to-west transactions within the Eastern Interconnection,

flow over transmission lines located in Canada

before reaching loads in the U.S. This is a

particular problem at points in the upper

Midwest where the transmission systems of

the two countries interconnect. These unintended flows (or “loop flows”) often require

transmission service curtailments in the U.S.

The benefit of increasing transmission

capability to increase economic trade depends on relative electricity prices in the

regions linked by the additional capacity and

on the additional amount of electricity that
21 National Transmission Grid Study 

Path 15—Example of Federal Leadership

Path 15 is an 84-mile stretch of electrical transmission lines in the central valley of California connecting the northern and southern portions of the state. The federal government’s recent efforts to

increase transfer capacity on this path illustrate both the role for responsible federal leadership to

address bottlenecks affecting national interests and how these bottlenecks might be addressed through

private investment.

Capacity on Path 15 is sometimes insufficient and has contributed to rolling blackouts in the state.

The California ISO has estimated that congestion on Path 15 resulted in up to $222 million in increased

electricity costs to customers in California during the 16-month period ending December 31, 2000.

In May 2001, U. S. Energy Secretary Spencer Abraham directed the Western Area Power Administration

(WAPA) to complete planning for upgrading Path 15 and to determine whether outside parties would

be interested in helping finance and co-own the new transmission line.

In June,WAPA requested Statements of Interest and 13 entities responded. In October 2001, Secretary

Abraham announced a $300 million agreement to upgrade Path 15 with WAPA and other participants

from the public and private sectors.

The proposed upgrade will add a third 500-kilovolt transmission line to the existing two lines and 

make other improvements. The upgrade will increase the capacity of Path 15 by an estimated 

1,500 MW, enough power for two million households, and could come on line as early as summer 2004.

would be traded on the new lines. If price differences are small and the added transmission

capacity would be used during only a small

percentage of the hours during the year, then

the cost of a new transmission line may not 

be justified.22

However, the benefits of increasing transmission capability to ensure reliability, even if

this insurance is used only once to prevent a

system-wide blackout, would be enormous and

could far outweigh any potential gains from

increased trade. Similarly, increasing transmission capability to reduce the ability of a competitor to exert market power could lead to

benefits far in excess of those gained from

increased trade.

Because assessing these issues will

involve tradeoffs, for example, commerce versus reliability, and local versus regional benefits, it is critical that DOE develops an open

public process to weigh the various interests.

Once it is determined that the benefits of

addressing bottlenecks outweigh the costs,

DOE must work with regions, states, and localities to ensure that these bottlenecks are

remedied appropriately.

22Building new transmission lines is not the only strategy to reduce congestion; as subsequent sections in this report discuss, many steps can be

taken to relieve transmission bottlenecks that may avoid or delay the need to construct new transmission facilities.
The National Interest in Relieving Transmission Bottlenecks 22

● DOE, through a rulemaking, will determine how to identify and designate transmission bottlenecks that significantly impact national interests. 

● DOE will further develop the analytic tools and methods needed for comprehensive analysis to

determine national-interest transmission bottlenecks. 

● In an open public process, DOE will assess the nation’s electricity system every two years to 

identify national-interest transmission bottlenecks.

RECOMMENDATIONS

DOE believes that the federal government should facilitate the process of energymarket participants seeking appropriate

solutions to transmission bottlenecks. The

recommendations in the following sections 

of this report identify actions that are needed

to address transmission bottlenecks, based

on this perspective.

DOE expects that these actions alone will

go a long way toward addressing the most

important of transmission bottlenecks—

those affecting significant national interests.

In view of the national interests at stake, the

federal government must stand ready to take

additional action if the efforts of others prove

inadequate. Toward this end, DOE has an

ongoing responsibility to assess how transmission bottlenecks affect the national interests as well as to monitor progress in

addressing bottlenecks.
3
Relieving Transmission Bottlenecks

by Completing the Transition 

to Competitive Regional Wholesale

Electricity Markets

Our nation’s transmission systems must be modernized to ensure

their continued reliability and facilitate fair and efficient regional

wholesale electricity markets that lower costs to consumers. To

achieve these goals, we must complete the transition to a restructured industry.

Core elements of the transition include

establishing regional transmission organizations

(RTOs) and increasing regulatory certainty and

focus to stimulate investment in innovative 

solutions to address transmission bottlenecks.

Completion of the transition will result in a 

stable business environment that rewards those

who take action to improve the transmission 

system. The economic rewards from improving

the transmission system must be greater than

the rewards from maintaining the status quo or

decreasing the system’s ability to reliably support

fair and efficient competitive wholesale markets.

The current upheavals and challenges facing

our nation’s electricity transmission system

result, in part, from the incomplete transition

to fair and efficient competitive regional wholesale electricity markets. In the view of many,

the incomplete transition to a restructured

industry poses the greatest challenge facing

the electricity system today. Lack of clarity in

the regulatory structure inhibits effective planning and needed investment. The transmission

system is too important to leave in an extended state of uncertainty. We must complete the

transition soon.

Establishing Regional Transmission

Organizations

3

FERC Order 2000 was a major milestone in the

movement toward fair and efficient competitive

regional wholesale electricity markets. Order

2000 calls for the formation of large RTOs to

coordinate markets and ensure the reliability of

the nation’s transmission system.

FERC outlined four characteristics that RTOs

must, at a minimum, demonstrate: 

Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 24
25 National Transmission Grid Study 

● Independence. RTOs must be independent

of market participants;

● Scope and Regional Configuration. RTOs

must serve a region of sufficient scope 

and configuration to permit each RTO to

effectively perform its functions;

● Operational Authority. The RTO must coordinate security for its region; and

● Short-term Reliability Authority. The RTO

must have exclusive authority for maintaining short-term reliability of the grid 

it operates.

FERC also identified eight functions that RTOs

must perform:

● Tariff Administration and Design. Each RTO

must be the sole provider of transmission

service in its region and the sole administrator of its own open-access tariff;

● Congestion Management. Each RTO must

ensure the development and operation of

market mechanisms to manage congestion;

● Parallel Path Flow. Each RTO must implement procedures to address parallel path

flow issues within its region and with other

regions;

● Ancillary Services. Each RTO must be the

provider of last resort of all ancillary services required by FERC Order No. 888 and

subsequent orders;

● Open Access Same Time Information

System (OASIS) Administration. The RTO

must be the single OASIS site administrator

for all transmission facilities under its control, with responsibility for independently

calculating Total Transfer Capability and

Available Transfer Capability;

● Market Monitoring. Each RTO must 

provide for objective monitoring of 

the markets it operates to identify

design flaws, market power abuses,

and opportunities for efficiency

improvements and must propose

appropriate actions;

● Planning and Expansion. Each RTO

must plan and direct necessary transmission expansions and upgrades to

enable it to provide efficient, reliable,

nondiscriminatory service and must

coordinate such efforts with the appropriate state authorities; and

● Interregional Coordination. RTOs must

develop mechanisms to coordinate

their activities with other regions.

In the summer of 2001, FERC adopted 

a more directive posture toward RTO formation and began to use existing regulatory

authorities to accelerate the process. More

recently, FERC has completed a benefit-cost

analysis of RTOs and concluded that savings

from RTO operation will save between $1–10

billion annually.23

RTOs are a means to an end. DOE supports the establishment of well-designed RTOs

as an effective way to address many of the

market and reliability coordination problems

currently facing the nation’s transmission systems. Whether RTOs represent the appropriate

end-state for the evolution of the U.S. electricity transmission system will depend on their

ability to ensure reliability and secure the benefits of fair and efficient competitive regional

wholesale electricity markets.

23FERC. 2002. Economic Assessment of RTO Policy. Download from http://www.ferc.gov
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 26

Much work remains to realize this vision.

The rules for RTO formation and operation

must be clear and rapidly adopted. They must

include stable market rules that stimulate the

supply and demand sides of markets, interconnection and reliability standards, and

transmission pricing mechanisms that reward

efficient operation and investment.24 RTOs

must be able to address transmission bottlenecks in their regions.25 

The Impacts of Transmission Fees on Trade and Congestion

Transmission fees have a substantial impact on electricity trade and congestion. In many regions, users 

must pay each utility a separate fee for use of its transmission system. This is generally referred to as “rate

pancaking.” Pancaked transmission rates create economic distortions in bulk-power markets by preventing

some trades that would be profitable if not for the multiple transmission fees involved. One of the benefits of

large RTOs would be the elimination of pancaked transmission rates.

DOE used POEMS to analyze a scenario that eliminates rate pancaking and instead uses a single access charge

to ship power anywhere within an RTO. Five RTOs were assumed for this scenario:

• Northeast (composed of PJM Interconnection, New York ISO, and ISO 

New England);

• Southeast and Florida;

• Midwest;

• Texas (ERCOT); and

• West (Western Systems Coordinating Council or WSCC).

Not surprisingly, both electricity trade and transmission congestion between

regions increase dramatically when transmission fees are structured as a single

access charge. This is a reflection of the increased business activity that would

lead to more efficient markets but also to increased loading of interregional transmission facilities. The total

volume of electricity traded across regions increases by nearly 20 percent annually, and the average number of

congested paths doubles.

The economic impacts of eliminating rate pancaking are even more dramatic. The benefits to consumers from

more efficient trade are more than $1 billion per year.*

*This analysis is not an estimate of the benefits of RTOs, nor does it represent DOE’s position on appropriate geographic boundaries for RTOs.

This analysis only illustrates the importance of transmission fees in shaping trade and congestion patterns. Eliminating pancaked rates is only

one of the expected benefits of RTOs.

24See Section 4, “Relieving Transmission Bottlenecks Through Better Operations,” for specific recommendations to improve transmission system 

operations.

25See Section 5, “Relieving Transmission Bottlenecks Through Effective Investments,” for specific recommendations on how RTOs should address

transmission bottlenecks.
27 National Transmission Grid Study 

different decision and policy makers. Each

transmission owner has its own perspective and

responds to the incentives (or mandates) created by the economic and legal environment in

which it operates. In addition, many states and

the federal government have laws that hinder

transfer of the assets or operational control of

transmission systems to RTOs. These barriers

will need to be identified and addressed. 

Effective operation of RTOs will be technically challenging. The tools and technologies

originally developed to support centrally

planned, vertically integrated operations are

inadequate to manage reliability in competitive,

region-wide electricity markets where power

flows are driven by market participants whose

behavior cannot be predicted using only traditional monitoring and dispatch concepts. DOE

will work with industry to facilitate the development of transmission enhancement and control

technologies that can help ensure reliable operations on a regional scale.26

So far, there have been several proposals

for the organization and operation of RTOs (see

Table 3.1). As expected, there are substantial

differences in these proposals, in part because

of regional differences in the electricity industry. It will be some time before the various RTO

business models can be fully evaluated and

fine-tuned. DOE can contribute to this process

by helping FERC, the states, industry, and other

stakeholders acquire appropriate tools to evaluate the performance of RTOs in meeting functional requirements. DOE can also help by

sponsoring forums to determine what economic and reliability data must be collected to conduct these evaluations, who should collect

them, and under what circumstances the information should be made publicly available.

The movement toward RTO formation has

been slow because today’s transmission facilities are owned by many different companies

and agencies. Aligning and harmonizing the

incentives of these owners to form RTOs that

support regional markets involves many 

26See Section 5, “Relieving Transmission Bottlenecks Through Effective Investments,” for additional discussion of advanced transmission technologies

and specific recommendations.

Current Status of RTO Applications

Name

Alliance RTO

California ISO

Crescent Moon RTO

West Connect RTO

ERCOT

GridFlorida Transco

GridSouth Transco

Midwest ISO/ITC

New England RTO

New York RTO

PJM / PJM West

RTO West/

TransConnect

SeTrans Grid

Southwest Power Pool

American

Transmission

Company

TRANSLink

Transmission

Denied

ISO operational

Under discussion

RTO proposed

Operational (not under FERC jurisdiction)

Provisionally approved

Provisionally approved

RTO approved 

ISO operational. RTO denied

ISO operational. RTO denied

ISO operational

Stage 1 approved

Under discussion

RTO proposed, now merging with

Midwest ISO

Operational ITC. 

Approved under Midwest RTO

Proposed ITC under Midwest RTO

Status

Source: Federal Energy Regulatory Commission, as of January 30, 2002.

Table 3.1
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 28

DOE and the Administration can play a

significant role in advancing the formation 

of effective RTOs. DOE’s Power Marketing

Administrations (PMAs) have been supportive

of RTO formation and have been key participants in RTO discussions. Bonneville Power

Administration (BPA), Western Area Power

Administration (WAPA), and the Southwestern

Power Administration (SWPA) all operate

extensive federal transmission systems.

However, some legal barriers may prevent

PMAs from shifting complete operational control over federal transmission lines to a nonfederal entity such as an RTO. PMAs also

have a unique relationship with their public

power utility customers. These issues need to

be evaluated carefully and appropriate measures must be taken to allow PMAs to become

full participants in RTOs.

The Tennessee Valley Authority (TVA) 

is a large federal utility that operates federal

transmission as well as significant generation

facilities. TVA was originally formed to facilitate unified resource development in the

Tennessee Valley. Today, among other things,

it manages the Tennessee River system 

and provides electricity to eight million customers in the southern U.S. The unique 

circumstances of its creation and its special

relationship to customers must be considered

as part of any plans for TVA to participate in

wholesale competitive markets, but should

not inhibit its full participation in an RTO.

In some cases, tax laws may be a 

barrier to the formation of RTOs both in

transferring operational control of certain

transmission assets to an RTO and in transferring ownership of the assets.27 Federal

tax law restricts the use by private firms 

of transmission facilities that are financed

with tax-exempt bonds, or that are owned

by certain cooperatives. Under existing

statutes and regulations, municipal utilities

could lose some or all of their ability to 

use tax-exempt financing, and certain cooperatives could suffer adverse tax consequences, if they turn operation of their

transmission facilities over to an RTO.

Temporary Treasury regulations, which 

are scheduled to expire in 2004, address

some of the private use issues arising from

participation by municipal utilities in open

access. For example, the temporary regulations specify certain open access transactions that do not result in private use, or

otherwise do not adversely affect the tax

exemption of outstanding bonds. Finalization of the temporary regulations by the

Treasury Department, in a manner that

enables municipal utilities to transfer operational control of their transmission assets

to an RTO in appropriate circumstances, 

will provide needed certainty in this area. In

addition, proposals to remedy this and

other tax obstacles are currently pending

before Congress.

27Greater horizontal consolidation of transmission assets through the creation of independent transmission companies is described in the next subsection.
29 National Transmission Grid Study 

Establishment of RTOs is an important step

toward a more stable business environment

for transmission system operations and

investment. In order to complete the transition to a more stable business environment,

additional efforts are necessary to increase

regulatory certainty and focus to ensure

investment in innovative solutions that will

address transmission bottlenecks.28 These

efforts require solving the problems that

emerge from:

● The current ways in which owners 

profit from existing and new transmission investments;

● RTOs should be responsible for maintaining the reliability of the grid and ensuring that transmission bottlenecks are addressed.

● DOE, with industry, will assess current system monitoring and control technologies that support efficient, reliable, and secure operation of RTOs and coordinate development of a plan

for future research and development.

● DOE will work with FERC and stakeholders to develop objective standards for evaluating the

performance of RTOs and will collect the information necessary for this assessment.

● DOE will work with the Energy Information Administration (EIA), FERC, National Governors’

Association (NGA), the National Association of Regulatory Utility Commissioners (NARUC), the

National Association of State Energy Officials (NASEO), industry, and consumer representatives

to determine what economic and reliability data related to the transmission and the electricity

system should be collected at the federal level and under what circumstances these data

should be made publicly available.

● NGA and NARUC should identify state laws that could hinder RTO development.

● DOE will review federal laws that may prevent PMAs from full participation in RTOs, direct

them to participate in the creation of RTOs, and take actions to facilitate their joining RTOs. 

● DOE will work with TVA to help it address any issues that inhibit its participation in wholesale

competitive markets, including full participation in an RTO.

Increasing Regulatory Certainty 

and Focus

3

28For additional background on this discussion, see the Issue Paper, “Alternative Business Models for Transmission System Investment and

Operations,” by S. Oren, G. Gross, and F. Alvarado.

RECOMMENDATIONS
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 30

● Coordination of the tradeoffs between

transmission investments and operation when the organizations that own

the transmission system are not the

same as those that operate it; and,

finally, 

● The interconnectedness of the AC

transmission system itself, which

means that investors in new transmission facilities cannot always charge

“rent” for unauthorized use of their

facilities because electricity flows over

all available paths.29

Ensuring Beneficial Transmission

Investments Are Profitable

New generation facilities are being built in

significant numbers in almost every region 

of the country while new transmission facilities generally are not. From a business perspective, the explanation is simple: new generation developers have figured out how to 

produce power more efficiently and to make

an attractive return on investments in the 

current market, while would-be new transmission developers have been frustrated in 

their efforts to achieve similar goals because

their returns depend on regulatory policies

and tariffs.

DOE believes that uncertainty about

recovery of transmission system investments

is a major barrier to new investments in needed transmission facilities. For investor-owned

utilities, the costs of transmission are recovered in rates authorized by federal and state

regulators. FERC authorizes rates for transmission service that are based on a target rate of

return on transmission investments. State regulators authorize rates for retail service, also

based primarily on a target rate of return that

takes the costs of transmission

into account along with all the

remaining costs of providing

electricity service, including

generation, wholesale power

purchases, and distribution

costs. Recovering the cost of

transmission becomes a local

responsibility while the benefits

of increased market efficiency

and reliability are regional. The

key to spurring new transmission investments lies in ensuring that the rewards offered by

29This phenomenon, called loop flow, is described in more detail in the subsection Loop Flow and the Emergence of Merchant Transmission, below.
31 National Transmission Grid Study 

this system of regulation are commensurate

with the risks of undertaking these investments

and finding innovative approaches to align

costs and benefits.

Industry participants have asserted that

current rates of return for transmission system

investments are not high enough. Authorizing

higher rates of return is not the only approach

to stimulating needed investments in transmission facilities over the long term. Reducing

regulatory uncertainty should also be a focus

of efforts to stimulate needed investments.

Because transmission assets are long lived,

regulatory uncertainty increases the risks to

investors and, therefore, increases the returns

they need to justify transmission system investments. Increasing regulatory certainty, therefore, should lower the returns needed to justify

these investments.

Reconciling conflicting regulatory signals

should be a core strategy for reducing regulatory uncertainty. In some states, rate freezes

may undermine the benefits that could be realized by new transmission investment because

the costs of these investments might not be

fully recovered. In fact, rate freezes can create

strong incentives not to build transmission.

That is, utilities can increase profits under a

rate freeze (as the rate base depreciates, costs

decline, and load/revenue grows) by not making significant new rate-based investments,

which would increase their net cost structure

relative to frozen assets. Hence, the utilities’

financial interest in avoiding new investment

may conflict with the benefits that new investment might provide to the region as a whole.

In these cases, state regulators should balance

the reasons for the rate freeze against the

need to stimulate adequate transmission

investment.

More closely aligning the incentives of

transmission owners with those of the public

and consumers should be another element of

eliminating regulatory uncertainty and sharpening the focus of regulatory decisions. For

example, one approach that needs to be considered is shifting some responsibility for congestion (both its costs and the benefits from

investment to reduce these costs) to transmission owners so that they have an incentive to

address transmission bottlenecks. The current

form of rate-of-return regulation is based on

investment costs. Simply passing costs of congestion through to consumers disconnects the

decision to invest from the benefit to the consumer of the investment and thus provides no
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 32

incentive to transmission owners to address

bottlenecks.

Rate-of-return regulation, therefore, may

be inconsistent with newer forms of regulation that seek to emulate the role of competitive market forces in eliciting efficient

behavior from regulated firms. A basic tenet

of competitive markets is that investors are

rewarded based on the value and innovativeness of their actions (not on the cost of their

investments, which is the basis for rewards

under rate-of-return regulation). A new class

of regulatory approaches, called performancebased regulation (PBR), offers greater promise

in offering incentives toward this end.

Examples of PBR can be found in the telecommunications industry in the U.S. and in regulated utility industries around the world, most

notably in the UK.

The Role of Performance-Based Regulation in Promoting Efficient Transmission

One of the best-known PBR mechanisms for electricity markets is found in the UK, for transmission services

provided by the National Grid Company (NGC). Though it could not be transferred directly to the U.S., this

approach also illustrates the role that incentives for enhanced transmission system operations can play in

stimulating efficient transmission operation, including investment in innovative transmission technologies.

NGC’s PBR mechanism employs a profit-sharing approach to reward NGC for reducing the charges that are

passed on to consumers for recovery of congestion relief costs incurred by NGC. The profit-sharing scheme

is based on NGC’s performance relative to a predetermined “yardstick” set by the regulator in view of historical performance and expected efficiency improvements. NGC has reduced the costs of congestion

through a combination of operational efficiency improvements, improved forecasting, investment in transmission expansion, and adoption of technologies that improve transmission grid utilization. NGC has pioneered an innovative approach in which some of these technologies, in contrast to conventional approaches,

are mobile. NGC moves them around the system in order to target areas in need of relief, which vary from

year to year in response to changing market trading patterns.

Source: S. Oren, G. Gross, and F. Alvarado. 2002. Alternative Business Models for Transmission System Investment and Operations, Issue Papers.

PBR is attractive because it provides targeted incentives to regulated firms to achieve

specific objectives (e.g., to increase market

efficiency, ensure reliability, and make timely

investments). In order to ensure that these

objectives are met, it is necessary to define

performance measures that directly relate to

the objectives and to ensure that firms have

adequate control over the means of meeting

the objectives. If the goal is to minimize the

cost of transmission service, a firm must be

able to balance improvements in operations

with investments in new transmission facilities,

including the deployment of advanced technologies. Similarly, if the transmission owner

bears no responsibility for costs of congestion,

there is no incentive to reduce it.30 PBR in the

UK has led to a substantial reduction in congestion costs (see text box).

30For example, one way owners might, in turn, address increased responsibility for managing congestion costs is by pricing it explicitly, thus providing an incentive to market participants to reduce these costs through adjustments to their own actions to use the transmission system. This concept is discussed further in Section 4, “Relieving Transmission Bottlenecks Through Better Operations.”
33 National Transmission Grid Study 

Finally, it may be appropriate to consider

other methods for increasing the profitability

of transmission investments, especially when

investments address important regional or

national interests. 

Coordinating Transmission

Investment and Operation

During the 1990s, many states passed

electricity industry restructuring legislation 

to introduce wholesale and sometimes retail

competition. In addressing wholesale competition, state legislation typically reinforced

FERC Orders 888 and 889 by directing utilities to accelerate the process of separating

transmission and generation functions, including divesting generation assets, or by

providing strong incentives for divestiture.

States directed utilities to ensure that operation of the transmission system would support the emergence of competitive wholesale

markets for generation. Insulating transmission and generation operations from each

other typically entailed allowing transmission

owners to retain possession of their transmission assets but transfering operational control of them to an independent entity.

Independent System Operators (ISOs),

the new institutional structures authorized by

FERC in recent years to operate transmission

assets, have led to a disconnection between

transmission investment and operational

needs. A major challenge to investment and

innovation when control and ownership of

transmission are separated is the creation of

a financial linkage between those who benefit

from the investment (the public) and those

who finance it (the owners). Today in the U.S.,

there are five ISOs operating transmission 

systems: California, New England, PJM, New

York, and Texas. Although these entities operate the systems, they cannot ensure that needed transmission is built.31 Unless managed

carefully, disconnections could lead to underinvestment and poor operations, which would

raise electricity costs and reduce reliability. As

recommended earlier, if we are to succeed in

completing the industry’s transition to a fair,

efficient, and competitive market, RTOs must

be able to address transmission bottlenecks.

Independent transmission companies that

own and operate transmission assets are a new

development and offer perhaps the greatest

potential for improving the coordination of

transmission operation and investment. These

companies achieve a complete corporate sepa31Texas is building transmission in part because the state’s utility commission regulates both the ISO and the transmission-owning utilities and supports the ISO’s transmission planning efforts with expeditious regulatory review of proposed transmission expansion.
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 34

ration between generation and transmission.

They are formed by divesting the transmission

assets from vertically integrated firms to

wholly independent firms that have no generation assets. Creation of these independent

companies is a reflection of private investors’

desire to separate and consolidate the very

different risks and rewards offered by generation and transmission businesses today.

It is imperative that private-sector initiatives such as independent transmission companies be allowed to flourish. Tax laws that

may encumber the economic transfer of transmission assets must be reviewed.

Loop Flow and the Emergence of

Merchant Transmission

A unique feature of transmission facilities is

the existence of “externalities” associated with

interconnected AC networks. Loop flow, in particular, in which electricity

passes over systems that

are not parties to its sale

and transmission, is an

unavoidable feature of

bulk-power AC transmission because electricity

takes the path of least

resistance and does not

follow prescribed routes.32

For developers of new

transmission lines, the situation is akin to building 

a new road but then having no means to effectively control (or charge for) the flow of traffic

over it.

RTOs are expected to better address loop

flow by internalizing it within the large geographic boundaries of each RTO. Greater horizontal consolidation of transmission assets, 

as reflected in the formation of independent

transmission companies that combine the

assets of many individual transmission-owning

utilities (also leading to larger geographic

boundaries), is yet another approach for internalizing loop flow, in this case within the

boundaries of a single firm.

Merchant transmission, a new entrant in

the transmission market, has relied on a technological solution to the problem of loop flow.

To date, all merchant transmission projects

have relied on DC transmission technologies

32Flexible AC transmission system (FACTS) devices can control flows over transmission lines; however, these devices are expensive and have seen

limited application to date. See Section 5, “Ensuring the Timely Introduction of Advanced Technologies,” and the Issue Paper, “Advanced

Transmission Technologies” by J. Hauer, T. Overbye, J. Dagle, and S. Widergren.
35 National Transmission Grid Study 

(e.g., Transenergie’s recently approved link

between Connecticut and Long Island, and

Neptune’s proposed Regional Electric

Transmission System in the Northeast),

which permit facility owners to directly control flows over their investments and avoid

the problem of loop flow. 

A merchant transmission project is one

that is financed by private investors with no

regulatory support (i.e., no regulator

ensures that the investor has the opportunity to earn a reasonable return on that investment). In return for lack of regulatory

protection, the owner of a merchant transmission facility can, in principle, charge market-based rates. Although merchant

transmission is a potentially powerful approach to resolving many of the difficulties

(including those related to planning, expansion, and pricing) facing traditional transmission systems, we do not know to what extent

projects financed in this manner can meet 

current and future needs for new transmission.

Nevertheless, merchant transmission projects

could introduce competition directly into an

aspect of the industry that has long been

regarded as a natural monopoly. And it seems

clear that when private investment in transmission can be undertaken in ways that avoid the

problems of loop flow, this investment may be

in the national interest.
Relieving Transmission Bottlenecks by Completing the Transition to Competitive Regional Wholesale Electricity Markets 36

● DOE will work with NGA, regional governors’ associations, NARUC, and other appropriate

state-based organizations to promote innovative methods for recovering the costs of new

transmission-related investments. These methods should consider situations where rate

freezes are in effect and also examine incentive regulation approaches that reward transmission investments in proportion to the improvements they provide to the system. 

● DOE will research and identify performance metrics and evaluate designs for performancebased regulation. 

● The Department of Treasury should evaluate tax law changes related to electricity modernization. Treasury should review its current regulations regarding the application of private use

limitations to facilities financed with tax exempt bonds in light of dynamics in the industry

and proceed to update and finalize its regulations. This will give greater certainty to public

power authorities providing open access to their transmission and distribution facilities.

● Entrepreneurial efforts to build merchant transmission lines that pose no financial risk to

ratepayers and that provide overall system benefits should be encouraged. 

● DOE and the Department of Treasury will evaluate whether tax law changes may be necessary

to provide appropriate treatment for the transfer of transmission assets to independent transmission companies. 

RECOMMENDATIONS
4
Relieving Transmission Bottlenecks Through Better Operations 38

33For additional background on this discussion, see the Issue Paper, “Transmission System Operation and Interconnection,” by F. Alvarado and S. Oren.

Ensuring the reliability of the transmission system has always been paramount. The primary

objective of reliable transmission system operation has been to minimize the risk of largescale blackouts. In extreme situations, temporary “rolling blackouts” have been imposed in

parts of the system in order to maintain the

integrity of the remainder of the system.

Current rules and operational procedures

for addressing transmission bottlenecks reflect

traditional operating practices based on experiences developed when electricity transactions

were smaller in volume, involved fewer participants, and did not routinely span multiple

regions. These rules and procedures embody 

a central-planning approach that gives little 

consideration either to the commercial value 

of electricity trade and the cost to consumers 

of lost trading opportunities, or to customers’

willingness to accept compensation voluntarily

for interruptions of electricity service.

Consistent with DOE’s vision, market

forces, not central planning, should be

relied upon to the extent feasible to ensure

reliability and to efficiently allocate transmission services when they become scarce.

Increasing reliance on market forces to

improve transmission system operations is 

a needed next step in the transition to a 

reliable transmission system that supports

fair and efficient competitive regional wholesale markets that lower the cost of electricity to consumers.

This is not to suggest that market

forces, alone, will be adequate to ensure 

reliability. In competitive wholesale markets,

there is an even greater need than in the

past for agreed-upon mandatory approaches

to reliability management and real time

operations. However, market forces should

serve as a first line of defense before turning to these approaches.33

Improving transmission system operations should be the first

element of a coordinated strategy to address transmission bottlenecks. Operational improvements can be implemented more

quickly and at lower cost than construction of new transmission

facilities. Needed improvements include: using market forces to

manage transmission congestion through better price signals;

voluntary load-reduction programs and targeted energy efficiency and distributed generation; relying on better real-time information to determine safe operating limits; and ensuring

mandatory compliance with reliability rules.

Relieving Transmission Bottlenecks

Through Better Operations
39 National Transmission Grid Study 

The first step toward increasing the role of

market forces in managing transmission 

system operations efficiently and fairly is

increasing the role of price signals to direct

the actions of market participants toward 

outcomes that improve operations. Improving

operations by relying on accurate price signals may, by itself, alleviate the need for

some construction of new transmission facilities. Moreover, when new construction is

needed, price signals will help market participants identify opportunities and assess

options to address bottlenecks.

Several aspects of transmission operations, including congestion and losses, could

be effectively addressed by pricing based on

the principle that if market participants see

the true costs of transmission services reflected in prices, they will use or procure these

services efficiently. For example, pricing principles should encourage location of new 

generation in congested areas as opposed to

location in areas with no congestion. Thus,

reliance on uplift charges, in which costs 

are recovered from all transmission users on

an equivalent basis, should be minimized.34

Here, we focus on examples where application of these principles may be especially

important for addressing transmission 

bottlenecks.35

Although curtailing some transactions is

essential to ensure reliability when transmission lines are in danger of being overloaded,

the economic losses associated with these

curtailments can be reduced by sending price

signals that will allow market participants to

choose which transactions to curtail in response to the relative value of the transactions. Congestion pricing, in which the party

that creates congestion pays for the costs of

relieving it, is a powerful example of using

Pricing Transmission Services to Reflect

True Costs

4

34Uplift charges are charges paid by all users; these charges represent costs that are difficult to apportion to particular market participants or that

regulators allocate evenly among all users in order to achieve other policy objectives. In cases where uplift charges must be used to recover costs,

however, performance-based regulations (discussed in Section 3) that provide incentives to minimize these charges and improve operational efficiency should be considered.

35For additional background on this discussion, see the Issue Paper, “Transmission System Operation and Interconnection,” by F. Alvarado and 

S. Oren.
Relieving Transmission Bottlenecks Through Better Operations 40

economic signals to relieve congestion efficiently. FERC’s Order 2000 identifies reliance on

market-based mechanisms to manage congestion as one of the eight functions of RTOs.

Transmission of electricity is not 100 percent efficient; losses, which result from the heating of lines and transformers, are inevitable, so

delivering 100 MWs of electricity to an end point

requires that more than 100 MWs be put into

the transmission system. Losses depend on a

variety of factors, including the physical properties of transmission facilities, the distance the

electricity must travel, and the current use of

transmission facilities by others. The costs of

system losses are sometimes included in uplift

charges borne equally by all transmission system users, which leads to inefficient use of the

system. More accurate pricing and allocation 

of transmission losses will lead to more efficient markets because participants can see 

and respond to the true costs of using the

transmission system.

Transmission pricing should recognize the

inherent differences between intermittent, lowcapacity-factor renewable energy sources that

are often located far from loads (such as wind

energy) and conventional generation, which is

not intermittent. Pricing should not unduly disadvantage renewable power plants. For example, wind plants must pay for their own ancillary

services. However, because of the inherent diffi-

● DOE, working with FERC, will continue to research and test market-based approaches for transmission operations, including congestion management and pricing of transmission losses and other

transmission services.

RECOMMENDATION

culty of precisely scheduling transmission

needs for wind plants on a day-ahead basis,

these plants should be allowed access to a realtime clearing market for differences, subject to 

non-punitive penalties based on cost, and/or

allowed a wider clearing band for scheduling,

as has been proposed by several states.

When we propose greater reliance on 

competitive economic forces to procure and

apportion the costs of transmission services,

we must recognize that markets for electricity

and electricity services are still maturing.

Approaches for organizing markets must minimize the risks of unintended design flaws 

that can be exploited by market participants.

There is a need to develop methods for “testing” market rules in controlled laboratory-like

settings to identify and correct design flaws

prior to implementation. While we are gaining

experience with markets, there must be safeguards—i.e., close oversight and rapid, deliberate response by FERC, including stringent

penalties—to prevent market abuses. FERC has

already initiated activities to increase its capability to monitor electricity markets more

aggressively.
41 National Transmission Grid Study 

Increasing the Role of Voluntary

Customer Load Reduction, and Targeted

Energy Efficiency and Distributed

Generation

4

Enabling customers to reduce load on the

transmission system through voluntary load

reduction or through targeted energy efficiency and reliance on distributed generation

are important but currently underutilized

approaches that could do much to address

transmission bottlenecks today and delay the

need for new transmission facilities.

Voluntary Customer Load Reduction

Allowing the “demand side” of regional wholesale electricity markets to interact with the

“supply side” is a critical missing element in

the transition to fully competitive, fair, and efficient markets. Without meaningful participation

by the demand side, today’s market is, at best,

half a market. Relaxing the current electric 

system operating principle that all customer

demand must be served at any cost is the key

to rational provision of reliable and affordable

electricity services. We can keep most of the

lights on at a lower total cost to all customers

if we allow those who are willing to turn their

lights off voluntarily (e.g., in response to economic incentives and price signals) to do so.

Voluntary load-reduction programs encompass a variety of strategies that enable 

customers to curtail or displace load from their

local utility in response to system conditions.

Providing opportunities for customers to

respond to the true costs of electricity is not

the same as enabling retail choice; voluntary

load-reduction programs can be operated in

states where there is retail choice as well as 

in states where incumbent utilities continue to

provide retail electricity service.

A full-scale effort is needed to understand

how customers would voluntarily reduce electricity loads, conduct pilot programs, assess

the impacts of these programs on wholesale

markets and system reliability, and develop

new technologies for price transparency and

customer participation in the market.

Eliciting load response from customers will

not be easy. Flexible programs will be required

in view of these key considerations:
Relieving Transmission Bottlenecks Through Better Operations 42

● Some customers may be quite willing to

view reduction of their load for economic purposes as a new source of

profit/savings, but others may only be

willing to reduce their loads in response

to circumstances such as true system

reliability emergencies. 

● Many customers will require substantial

advance notification to reduce load 

and will want to limit the duration and

frequency of interruptions in service;

others will be more flexible. 

● Real-time pricing is essential for allowing customers to determine how much

power they wish to use based on the

actual price of electricity at any point in

time. However, other programs, such 

as priority service and demand bidding,

should also be explored to accommodate customers who do not wish to

respond to real-time prices.

DOE, the states, and private industry 

can help enable widespread customer participation in voluntary load-reduction programs

by educating consumers about successful

programs. DOE can also stimulate the development and dissemination of successful

approaches and technologies. Advanced

meters must be deployed that allow customers to receive signals in real time (e.g.,

hourly prices for electricity) and new system

integration techniques must be developed

and demonstrated to automate responses 

to these signals.

Modifying transmission operation control

systems to accommodate load reduction on

New York ISO Demand-Response Programs

The New York Independent System Operator (NYISO) operated two demandresponse programs in 2001: the Emergency Demand Reduction Program and the

Day-Ahead Demand Reduction Program. Both are examples of the types of programs needed to enable voluntary customer load reduction in wholesale markets 

for the purposes of enhancing system reliability and increasing market efficiency.

The Emergency Demand Reduction Program is a “call”-type program (i.e., customers agree in advance

to curtail load when called to do so by NYISO) but is voluntary in that there are no penalties for choosing not to curtail when called, so payment is based on a participant’s performance in each hour of a curtailment event. In summer 2001, the program was operated four times because of shortages in operating

reserves. On average, the program delivered 450 MW, which is a significant share of the 1,800 MW operating reserve that NYISO maintains.

The Day-Ahead Demand Reduction Program is a “quote”-type program (i.e.. customers are given an

opportunity to offer load reductions to the wholesale market). In summer 2001, the program operated

during July and August and achieved modest load reductions. Efforts are under way to improve the

design and operation of the program for summer 2002.

Source: New York ISO. http://www.nyiso.com/services/documents/groups/bic_price_responsive_wg/demand_response_prog.html
43 National Transmission Grid Study 

an equivalent basis with electricity generation

poses a series of challenges. First and most

important, the system reliability rules and practices underlying current telemetry requirements

and control procedures must be reviewed and

redefined from a technology-neutral point of

view, without compromising system reliability.

Second, new communication and control technologies consistent with these redefinitions

must be developed and implemented. DOE can

help industry accelerate these needed changes.

Targeted Energy Efficiency and

Distributed Generation

Targeted energy efficiency and distributed 

generation are approaches through which customers can reduce electricity loads on the

transmission system, alleviate bottlenecks, and

delay the need for construction of new facilities. They are complementary strategies to voluntary customer load-reduction programs.

Utilities and government have spent more

than 25 years developing and implementing

proven energy-efficiency programs and standards that save consumers money. Today,

funding for utility-led energy-efficiency programs is significantly lower than before industry restructuring because recovering the costs

of these programs conflicted with rate reductions and freezes and the need to recover the

much larger costs of utilities’ stranded assets.

Regulators should re-evaluate and consider expanding utility support for energy efficiency programs in view of their potential benefits

to the electricity system as well as their direct

benefits to customers in the form of lower electricity bills. State regulators need to eliminate

Summer 2001 Demand Reductions in

California

California’s experiences during the electricity 

crisis in summer 2001 offer important lessons

about peak demand reduction. According to the

California Energy Commission, Californians used

8.9% less electricity during peak hours in 2001

compared to 2000 when adjusted for growth and

weather (see http://www.energy.ca.gov/).

These are very large savings compared with what

almost all observers at the time expected and 

historical behavior patterns. In other words,

demand-reducing programs performed very well,

and these reductions were of great importance

during the crisis. However, although an estimated

30 percent of these savings related to investment

in more efficient end-use devices and on-site generation will likely persist, the remaining reductions

are the result of changes in behavior and operations that may not continue now that the crisis

appears to have passed. California spent a large

sum of (one-time) funds strongly encouraging consumers to reduce energy use. Many consumers

did so for reasons including: the desire to be good

citizens, concerns about high electricity bills, and

the prospect of receiving a 20 percent electricity

bill rebate if they achieved 20 percent savings.

Thus, although demand reduction can play an

important role in relieving transmission bottlenecks, the crisis situation to which Californians

responded in summer of 2001 is not a desirable

model for future efforts. The crisis in California

was very expensive. The goal should be to avoid

such crises, in California and elsewhere. Longterm demand reduction programs, enhancement

of the transmission system, and the new supplies

are all essential to achieving this goal.
Relieving Transmission Bottlenecks Through Better Operations 44

and a combination of regulatory (e.g., loss of

sales revenues) and competitive considerations

(e.g., high charges for back-up power from 

the utility).

Current utility procedures for interconnecting distributed generation to the electricity grid are generally expensive and nontransparent. The Institute of Electrical and

Electronics Engineers (IEEE) is working to

establish technical interconnection standards

in its draft standard IEEE P 1547. This effort

must be completed soon to help promote 

distributed generation solutions. Standardized

interconnection procedures (agreements,

rules, and business procedures) are also needed to reduce costs and clarify requirements.

Current rate-making practices create disincentives for utilities to “lose” load to distributed generation (as well as to energy

efficiency) despite the benefits to the system

and the potential cost savings to customers

from these two strategies. State regulators

should examine the current regulatory disincentives to energy efficiency and distributed

generation and address them consistent with

the public interest in ensuring cost-effective

consumer investments in distributed generation and energy efficiency.

disincentives facing utilities and third-party

energy service providers who wish to lower

customer energy bills and help mitigate

transmission bottlenecks though energy efficiency programs.

Distributed generation and storage

allows customers to reduce reliance on the

transmission system by “distributing” or 

placing generation sources (such as photovoltaics; combined heat and power systems;

and small, clean generators, including microturbines and fuel cells) and energy storage

closer to the locations at which electricity is

used, e.g., at customers’ homes or businesses. For distributed generation that also 

incorporates combined heat and power 

technologies, the economics are enhanced 

by opportunities to use the heat produced 

in the conversion of fuel to electricity. Other

applications benefit from the increase in

power quality offered by certain distributed

technologies (e.g., energy storage).

There is some local utility resistance to

increasing customers’ reliance on distributed

generation. This resistance is based on technical concerns (e.g., safety of utility crews

working in the field who do not know that

current is flowing from distributed resources)
45 National Transmission Grid Study 

The maximum electrical loads allowed on the

transmission system today are estimated conservatively. Total Transfer Capability (TTC),

which is the basis for establishing Available

Transfer Capability (ATC), has traditionally been

determined by a static analysis of acceptable

system conditions—that is, system operators

assumed conservative values for ambient conditions, such as air temperature and wind speed,

that affect the safe and reliable operation of

transmission lines and other transmission facilities. This practice was acceptable in the past

because of the lack of measurement, communication, and analysis tools to determine the realtime status of the electric system. In addition, it

was easier to conduct a static analysis and overbuild the transmission system than to conduct

a dynamic analysis so that the system could be

operated more efficiently, i.e. closer to its actual safety limits, which vary over time.

The increased demand for transmission

services and the increasing difficulty in getting

new transmission lines built compel us to better understand the limits of safe and reliable

transmission system operation. As ambient conditions change, so will TTC. A dynamic system

● DOE will work with FERC, the states, and industry, and conduct research on programs and technologies to enhance voluntary customer load reduction in response to transmission system emergencies and market price signals.

● DOE will work with states and industry to educate consumers on successful voluntary load-reduction programs. DOE will disseminate information on successful approaches and technologies.

● DOE will continue to work with NGA, regional governors’ associations, and NARUC to remove 

regulatory barriers to voluntary customer load-reduction programs, and targeted energy efficiency

and distributed generation programs that address transmission bottlenecks and lower costs to

consumers.

● IEEE should expeditiously complete its technical interconnection standards for distributed 

generation.

● DOE will work with NGA and NARUC to develop and promote the adoption of standard interconnection agreements, rules, and business procedures for distributed generation.

RECOMMENDATIONS

Using Improved Real-Time Data 

and Analysis of Transmission System

Conditions

4
Relieving Transmission Bottlenecks Through Better Operations 46

Ensuring Mandatory Compliance with

Reliability Rules

4

analysis that uses real-time data instead of the

conservative proxies used in a static analysis

provides a better estimate of TTC and would

allow operators to safely move more power

across existing lines.

In addition to the corresponding increase

in ATC that would result from a more precise

assessment of TTC, dynamic analysis can further increase ATC by identifying unused transmission rights that can be made available to

the market on a nonfirm basis. The overall

result of using dynamic transmission system

analysis could be a substantial increase in ATC,

a reduction in transmission congestion, and

more efficient use of the transmission system.

Recent advancements in measurement,

communication, and analysis tools now make

dynamic analysis a possibility.36 In some cases,

a change from a static transmission system

analysis to a dynamic analysis may be the 

most cost-effective way to reduce a transmission bottleneck.

● DOE will work with industry to demonstrate and document cost-effective uses of dynamic transmission system analysis.

RECOMMENDATION

Ensuring reliability has and will remain a fundamental priority for the nation’s electricity transmission systems. The procedures that have in

the past been used to set and enforce rules to

ensure reliability must change to be consistent

with and supportive of competitive wholesale

electricity markets.37

The 1990s witnessed an increase in the

number of large-scale blackouts and near 

misses. Some have expressed concern that 

this increase is evidence of the losing battle

firms now face in trying to manage reliability

while operating in competitive business environments that provide few if any economic

36A description of tools, such as the Wide Area Measurement System (WAMS), that would support more precise determinations of the dynamic state

of the transmission system can be found in Section 5, “Relieving Transmission Bottlenecks Through Effective Investments.” See also the Issue Paper,

“Advanced Transmission Technologies,” by J. Hauer, T. Overbye, J. Dagle, and S. Widergren.

37For additional background on this discussion, see the Issue Paper, “Reliability Management and Oversight,” by B. Kirby and E. Hirst.
47 National Transmission Grid Study 

rewards for continued stewardship of the public interest in electricity system reliability. 

Industry has stated clearly that it can no

longer rely on the historic system of voluntary

compliance with rules to ensure the reliability

of the nation’s interconnected transmission

systems because of the competition among

firms in today’s marketplace.38 There is widespread agreement that mandatory rules are

now required to ensure transmission system

reliability. In the West, the WSCC is creating a

mandatory system based on contractual agreements with its members. This is a significant

improvement over the historic voluntary system, however, federal legislation to create a

mandatory system remains essential.

Foremost among the issues that must be

considered in reviewing reliability rules is the

recognition that these rules directly impact

market operations (for example, TLRs curtail

certain commercial transactions, as explained

in Section 1). An open, inclusive process for

reviewing and establishing reliability rules is

required in view of their economic implications.

New reliability rules must accommodate

variations in transmission system designs 

and build upon the knowledge of local transmission system operators in open rule-setting

processes. However, it is essential that local

variations do not hinder the operation of competitive regional electricity markets and are 

not used unfairly to give a competitive advantage to one group of market participants at the

expense of others.

Although reliability has never been

ensured “at any cost,” the costs of reliability to

consumers should be explicitly accounted 

for when reviewing reliability rules. At a minimum, the penalties for violating reliability rules

should reflect the costs imposed on society 

by these violations, e.g., the cost of replacing

the reliability services that are not provided by

the violator.

Similarly, as a cornerstone of restructuring, we should allow consumers to pay for a

higher level of reliability than that provided by

the current electricity system. A critical barrier

to informed consumer choice about reliability,

which includes power quality, has been the lack

of public data on the subject. Although records

are kept by utilities, their interpretations of

reliability and power quality events vary 

Summary of Major Electricity Reliability

Events in North America

Northeast blackout: November 9–10, 1965

New York City blackout: July 13–14, 1977

Los Angeles earthquake: January 17, 1994

Western States cascading outage: December 14, 1994

Western States events in Summer 1996

- July 2, 1996—cascading outage 

- July 3, 1996—cascading outage avoided

- August 10, 1996—cascading outage

Minnesota-Wisconsin “near miss”: June 11–12, 1997

Northeast ice storm: January 5–10, 1998

Upper Midwest cascading outage: June 25, 1998

San Francisco blackout: December 8, 1998

Source: J. Hauer and J. Dagle. 1999. Review of Recent Reliability Issues and

System Events. Download from http://www.eren.doe.gov/der/transmission

Table 4.1

38North American Electric Reliability Council. 2001. Reliability Assessment, 2001-2010. Download from http://www.nerc.com
Relieving Transmission Bottlenecks Through Better Operations 48

considerably, so data from different utilities

are often not comparable. Of greater concern

is that consumers do not routinely have

access to these data. For example, when businesses experience interruptions that disrupt

their processes, it starts a long and expensive

process of data collection and analysis to

diagnose the problem before a solution 

can be prescribed. Without these data, consumers cannot make informed decisions

and cannot fully assess the significance of

electricity reliability and power quality and

thus the value of options available to

address them. 

● Federal legislation should make compliance with reliability standards mandatory.

● Current reliability standards should be reviewed in an open forum to ensure that they are technically sound, nondiscriminatory, resource neutral, and can be enforced with federal oversight.

● Penalties for noncompliance with reliability rules should be commensurate with the costs and

risks imposed on the transmission system, generators, and end users by noncompliance.

Penalties collected should be used to reduce rates for consumers.

● DOE will work with industry and NARUC to promote development and sharing of best transmission and distribution system operations and management practices.

● DOE will work with FERC, state PUCs, and industry to ensure the routine collection of consistent

data on the frequency, duration, extent (number of customers and amount of load affected),

and costs of reliability and power quality events, to better assess the value of reliability to the

nation’s consumers.

RECOMMENDATIONS
5
Relieving Transmission Bottlenecks Through Effective Investments 50

Improving transmission system operations will

go a long way toward easing transmission bottlenecks by delaying or alleviating the need 

for construction of new transmission facilities.

However, construction of new facilities cannot

be avoided entirely. We must ensure that needed facilities are identified in a timely fashion

through open processes and that, once identified, they are constructed expeditiously.

In view of its ongoing responsibilities for

public-interest energy R&D, DOE must work

closely with industry to ensure the continued

development and deployment of needed new,

transmission-enhancing technologies. This

need is especially great today to address 

gaps that have emerged during the transition

to competitive regional wholesale markets.

Finally, we must also re-double efforts to

ensure the security of new and existing facilities in the nation’s transmission infrastructure.

Relieving Transmission Bottlenecks

Through Effective Investments

Ultimately, construction of new transmission facilities will be

needed to ease transmission bottlenecks. We must implement

open, regional transmission planning processes that consider a

broad range of transmission and non-transmission alternatives,

accelerate and coordinate siting and permitting processes for

needed facilities, ensure that the transmission system can take

advantage of the latest technologies, and address physical and

cyber security issues.

Implementing Regional Transmission

Planning

5

Effective regional transmission planning

requires:

● An open, inclusive process;

● Clear planning objectives; and

● A planning entity with authority to 

conduct the process and implement

the results.39

FERC Order 2000 assigns responsibility 

for transmission planning to RTOs. Vesting this

responsibility in RTOs is an acknowledgment 

of the regional implications of transmission in

facilitating the development of regional wholesale electricity markets. RTOs are the key institutions with a regional perspective central to

39For additional background on this discussion, see the Issue Paper, “Transmission Planning and the Need for New Capacity,” by E. Hirst and B. Kirby.
their charter. As noted in Section 3, DOE

believes that a key element of RTOs’ role 

in transmission planning should be to identify and address transmission bottlenecks

It is critical that the RTOs formed in

response to FERC Order 2000 adopt planning principles and practices that facilitate

private investment in new transmission

facilities and non-transmission alternatives.

These principles and practices should advance local, state, regional, and national

interests. The goal of RTO planning should

be to identify transmission needs and the

criteria for evaluating proposed solutions,

and then to empower the market to respond

to these needs, including, if necessary, 

support for market solutions in state regulatory proceedings.

A critical challenge is to reintegrate the

generation and transmission system planning perspectives that were once a routine

element of planning by vertically integrated

utilities. Today, generators are building

power plants where permits can be obtained

with ease and there is access to fuel, water,

and other necessary infrastructure. Transmission issues are an afterthought in this

process because transmission is viewed as

the utilities’ obligation. For example, in the

Southeast, a large number of power plants

have been proposed in areas where there is

inadequate transmission. Building new generation in these areas will increase congestion on the transmission system.

Expansion of the transmission system

must be viewed as one strategy in a portfolio to address transmission bottlenecks; 

this portfolio also includes locating generation closer to loads, relying on voluntary

customer load reductions, and targeting

energy efficiency and distributed generation. Planned natural gas infrastructure

investments, which affect where new generation will be built (both large, remote 

stations as well as small, distributed generation), must also be considered.

51 National Transmission Grid Study 
Relieving Transmission Bottlenecks Through Effective Investments 52

● DOE will work with the electricity industry and state and federal regulators to identify the type

of electricity system data that should be made available in the planning process to facilitate the

development of market-based transmission solutions and devise a process for making that

information available.

RECOMMENDATION

Once transmission bottlenecks are identified, market-based approaches should be relied

upon to address them in the most efficient

way. As mentioned in the previous section, 

one way to empower market solutions is better

pricing of transmission congestion to signal

needs to private developers so that they can

capture the benefits of relieving transmission

bottlenecks. Better pricing allows generators 

to incorporate transmission considerations 

into their business decisions for locating new

power plants.

When possible, solutions to bottlenecks

should be solicited through open, competitive

processes that allow private developers to offer

proposals that might encompass new transmission facilities, non-transmission alternatives, 

or both. Access to operational data is essential

to allow market participants to formulate and

evaluate viable proposals.

Transmission plans must balance traditional reliability considerations with economic

efficiency. Taking the economic efficiency attributes of electricity markets into account requires adopting a regional perspective because

these markets span across regions. This is in

sharp contrast to most current transmission

plans, which, because of the limited geographic scope and mandate of today’s transmission

owners, focus primarily or solely on local 

considerations.

In contrast to the majority of today’s

transmission planning processes, open planning processes will be essential to ensure

meaningful public input throughout. This

input is especially needed to support the

identification and assessment of tradeoffs

among planning criteria (e.g., reliability versus economic efficiency, local impacts versus regional benefits) as well as to better

understand how parties might be affected

by different planning outcomes. Too often,

clear planning criteria and public input are

delayed until state and federal siting processes are under way. Delaying public input

until the siting process can cause substantial delays because it often introduces new

alternatives that had not previously been

evaluated. The siting process must then 

be stopped while these new possibilities 

are assessed. These delays can be avoided 

if planning criteria and public input are

incorporated early in the planning process.

Greater public access to planning data and

resources is needed to effectively inform

public input.

Meaningful public input and assessment of reasonable alternatives in the early

stages of planning will increase public acceptance of plans once they are final and will

facilitate any required siting and permitting

processes.
53 National Transmission Grid Study 

40For additional background on this discussion, see the Issue Paper, “Transmission Siting and Permitting,” by D. Meyer and R. Sedano.

Accelerating the Siting and Permitting of

Needed Transmission Facilities

5

There have been significant delays during the

siting and permitting process for many large,

interstate or regional transmission projects.40

These processes have emerged as significant

deterrents to building new regional transmission facilities. It is important that we eliminate unnecessary delays once the need for

these facilities has been established. 

State and federal regulators must work

with states and regions to ensure that transmission siting and permitting processes work

—and work together. States should retain

their present authority and play a more active

role in managing review processes for energy

infrastructure siting and permitting. As part

of their reviews, states should ensure that

regional considerations are taken into account

in assessing the costs and benefits of new

transmission. They should also coordinate

their reviews with other regional and state

planning, siting, and permitting processes. As

part of these processes, the federal government has a special responsibility to ensure

that siting and permitting on federal lands is

not needlessly delayed.

Federal regulators should actively support

and defer to these state and regional siting

and permitting processes. However, since new

regional transmission facilities will typically

span or impact multi-state areas that seldom

align with the political boundaries of states,

FERC must have appropriate backstop authority to ensure that the public interest is served

and that national interest transmission bottlenecks designated by DOE are addressed. When

state and regional processes determine that

construction of transmission facilities is needed to address national interest transmission

bottlenecks, yet are unable to site or permit

them in a timely fashion, FERC must be able to

grant designated entities the right of eminent

domain to acquire property for rights-of-way. 
Relieving Transmission Bottlenecks Through Effective Investments 54

American Electric Power’s 765-kV Project between West Virginia and Virginia

Ten years after it was first proposed, a major transmission project by American Electric Power

(AEP) in West Virginia and Virginia is still about a year from final approval. The following chronology documents the delays resulting from state regulators’ efforts to take account of local and

other concerns, and from lack of coordination among the principal parties.

1991—AEP submits a proposal for a 765-kV transmission line to Virginia,West Virginia, the U.S.

Forest Service, the National Park Service, and the U.S.Army Corps of Engineers with the goals

of maintaining reliability in southern West Virginia and southwestern Virginia and reducing the

risks of a cascading outage that could affect many states in the eastern U.S.

1992–1994—Extensive hearings are held in Virginia and West Virginia, many in potentially 

affected localities.

1996—The Forest Service issues a draft environmental impact statement which recommends

that the line not be constructed as proposed because it will cross sensitive public lands.

1997—AEP proposes, to the regulatory commissions in the two states, a longer alternate 

route that would cross less sensitive areas than the initial route.

1998—The West Virginia Public Service Commission approves its portion of the alternate

route.

Later in 1998—AEP agrees to a request from the Virginia Corporation Commission that the

utility conduct a detailed study of a second alternate route. After AEP completes its review, it

agrees that the second route is acceptable although this route would not allow as much margin

for future load growth as had been available with the first alternate route.

2001—The Virginia Corporation Commission approves the second route, chiefly because this

route would have fewer adverse environmental and social impacts than the previous routes.

Late 2001—The West Virginia Public Service Commission must review and approve the newest

route even though the West Virginia portion of that route differs very little from the one the

commission approved in June 1998. In addition, because the newest route would also cross

about 11 miles of national forest in an area not studied in the Forest Service’s 1996 draft environmental impact statement, the Forest Service must conduct a supplementary analysis before

deciding whether to grant a permit for construction.

Source: D. Meyer and R. Sedano. 2002. Transmission Siting and Permitting. Issue Papers.
55 National Transmission Grid Study 

A Coordinated Regional Approach

One way to reduce delays in siting and permitting is to foster coordinated review when 

several state or federal agencies are affected 

by a proposed facility. When proposed facilities

cross boundaries between states or cross lands

managed by one or more federal land management agencies—which is frequently the case 

for facilities whose impacts are regional in

nature—the potential for miscommunication,

poor coordination, and delay is increased 

significantly. As demonstrated by the AEP

example (see text box), failure by state and

federal agencies to coordinate their reviews

can lead to the issuance of permits that are

inconsistent with one another. This can necessitate multiple additional rounds of review 

to resolve differences and further delay an

already lengthy process. A common timetable

and coordinated process for affected agencies

is needed to reduce these delays.

The Alturas Line

Sierra Pacific’s experience in building a 163-mile transmission line is an example of the costs and delays 

that can arise when transmission projects involve multiple federal agencies with land management

responsibilities.

Sierra Pacific prepared detailed plans for the Alturas project in 1992. The Nevada Public Service

Commission approved the project in November 1993. After obtaining Nevada’s approval, Sierra Pacific

turned to the other affected agencies—the California Public Utilities Commission (CPUC) and several

Federal agencies: the U.S. Bureau of Land Management (BLM), the U.S. Forest Service, BPA, and the 

U.S. Fish and Wildlife Service. BLM had the most acreage affected by the proposal and became the lead

agency for the Federal review of the project. CPUC became the lead agency for state environmental

purposes. In spring 1994, BLM and CPUC collaborated to begin a draft environmental impact report

(EIR) for the state and a draft environmental impact statement (EIS) for the Federal agencies. Sierra

Pacific paid the cost of the studies. BLM issued the final EIS in November 1995 and approved its portion of the project in February 1996. The CPUC approved its portion of the line in January of 1996.

In February 1996, the manager of the Toiyabe National Forest issued a “no action” decision, arguing 

that the EIS was flawed because it had not addressed a sufficiently wide range of alternatives.

Eventually, Sierra Pacific decided to pursue an alternative route and withdrew the application to cross

the Toiyabe area. In April 1997, the Modoc National Forest manager denied the project a permit to

cross a three-mile portion of the Modoc National Forest. The applicant appealed this decision to the

chief of the Forest Service in May 1997; a permit was issued October 1997. However, several other parties to the proceeding appealed this permit. After review, the decision to issue the permit was upheld 

in January 1998.

Construction was begun in February 1998 and completed in December 1998. Sierra Pacific estimates

that the project was delayed by at least two years and that these delays led to additional costs of more

than $20 million.
Relieving Transmission Bottlenecks Through Effective Investments 56

Transmission systems are regional in

scope, and their benefits are generally regional

in nature, yet frequently their impacts are local.

Siting processes need to take a regional perspective, incorporating local input to fairly and

equitably assess a wide range of proposals for

transmission enhancements. Regional coordination for siting and permitting should be organized according to RTO boundaries. 

State and federal siting agencies can improve regional siting and permitting by working together in a cooperative fashion to:

● Agree on the information that is 

necessary to evaluate a transmission

proposal;

● Develop common documents (e.g., 

environmental impact statements) for

reviewing proposals;

● Set a reasonable time frame for completing review and issuing required permits;

and

● Ensure that the completed permits are

consistent.

A coordinated regional approach is

being developed by the Western Governors’

Association, which has formed the

Committee for Regional Electric Power

Cooperation (CREPC) to address regional

transmission planning and siting issues 

in the Western Interconnection. Similar

efforts for regional coordination in planning

and siting transmission should be undertaken within the Eastern Interconnection.

DOE encourages development of regional protocols to govern the siting of transmission facilities. These protocols should ensure

that states within a region follow the same

rules and that the rules are enforced. Regional transmission siting protocols should

include:

● Agreements that states concurrently

review proposals;

● Ground rules for addressing reliability

issues;

● A provision for common assessment

of market power in the region;

Regional Transmission Planning and Development of Cooperative Regional Institutions

A promising example of a regional institution that could be used to address regional transmission

siting issues on a cooperative basis is the Western States’ Committee for Regional Electric Power

Cooperation (CREPC). CREPC was created jointly in 1984 by the Western Interstate Energy

Board, which acts as the energy arm of the Western Governors’ Association, and the Western

Conference of Public Service Commissioners. CREPC has representatives from the regulatory

commissions and energy and facility-siting agencies in the 11 states and two Canadian provinces

in the Western Interconnection. Through CREPC, the western states have begun negotiations to

develop a common interstate transmission siting protocol; June 2002 is the target date for publication of their draft.

Source: Western Interstate Energy Board. http://www.westgov.org/wieb/crepnew2.htm
● A provision for consideration of the

ways that a proposed transmission facility might increase regional fuel diversity;

● Criteria for evaluating both transmission

and non-transmission alternatives; and

● Requirements for disclosure of existing

rights of way and opportunities to

increase the transmission capacity of

existing facilities.

Responsibilities of Federal Agencies

The record for siting transmission lines across

federal lands is spotty. Some efforts to build

lines across federal lands, especially in the

Western U.S., have been delayed or stopped by

an inconsistent and time-consuming process.

DOE believes that federal agencies that manage

federal lands and natural resources should 

support regional transmission siting agreements. These agreements should provide for

cooperation, timely participation, dedication 

of sufficient resources to carry out required

57 National Transmission Grid Study 

Distribution of Federal Lands in the United States

Although almost 29 percent of the land area of the United

States is federally owned, 54 percent of federally owned land

is concentrated in the 11 states of the contiguous U.S. located wholly or partially west of the Continental Divide.

State Total Area in Acres % Federal Land

Arizona 72,688 45.6

California 100,207 44.9

Colorado 66,486 36.4

Idaho 52,933 62.5

Montana 93,271 28.0

New Mexico 77,766 34.2

Nevada 70,264 83.1

Oregon 61,599 52.6

Utah 52,697 64.5

Washington 42,694 28.5

Wyoming 62,343 49.9

Source: Statistical Abstract of the United States, 2000 (U.S. Dept. of Commerce,

December, 2000), Table No. 381 (1997 data).

AR

AZ

CA

CO

ID

KS

LA

MO

MT

ND

NE

NM

NV

OK

OR SD

TVA

TX

UT

WY

WA

BPA

WAPA

SWPA

Fig. 5.1

WAPA, BPA, SWPA,

and TVA Power

Marketing Areas
Relieving Transmission Bottlenecks Through Effective Investments 58

environmental reviews, and integration of

review requirements by all parties for proposed transmission lines. These agreements

should ensure that National Environmental

Policy Act and other reviews are conducted

in a coordinated and timely manner. As

shown in the chart on the previous page, 

the federal government still manages large

sections of land in the United States. 

The present administration has worked 

to improve coordination among federal 

agencies. To help address transmission bottlenecks, the federal government should 

continue to improve coordination amongfederal agencies. A key first step should be a

jointly developed process for expedited evaluation of permits for construction or modification of transmission on federal lands.

Federal agencies should support regional planning efforts by identifying and evaluating potential transmission corridors across

federal lands. In addition, federal agencies

should reexamine existing transmission

paths across federal lands to determine the

potential to increase transmission capacity

along these paths.

Establishing a FERC Role in

Transmission Siting

Electricity transmission is a vested public

interest. As the U.S.’s demand for electricity

grows and new generation capacity is built

to meet this demand, the need for more

transmission capacity will follow. Increasing

transmission capacity will include the construction of longer, higher voltage lines.

These lines will allow delivery of the least

expensive electricity that is being produced

at the time, possibly several states away, 

to consumers.

Construction of transmission facilities

that are needed to significantly advance

national interests must not be delayed.

Rules and regulations that will improve 
59 National Transmission Grid Study 

uses eminent domain to acquire land for

radar installations.

● The General Services Administration 

has used eminent domain to acquire

property rights to provide security and

has used eminent domain to acquire

office space when other negotiations

have failed. 

● The four Department of Energy strategic

petroleum reserve sites in Louisiana 

and Texas were established by eminent

domain.

● The FERC may grant a certificate of 

public convenience and necessity to a

natural-gas company which gives the

recipient the right to exercise eminent

domain to acquire property for rightsof-way in the siting and construction of

natural gas pipeline facilities.

● Power Marketing Administrations use

procedures for the siting and permitting of

transmission lines should be implemented

immediately. The FERC should play a limited

role focused on supporting state and regional efforts, but should also possess backstop

authority to ensure that transmission facilities that eliminate national interest transmission bottlenecks are sited and constructed.

The FERC should act if state and regional

bodies are unsuccessful in siting and permitting national interest transmission lines. In

order to serve the public interest, the FERC

should enable an applicant to exercise the

right of eminent domain to acquire property

to site and permit transmission facilities in

these instances. Eminent domain is used by

many different branches of the federal government to acquire property to serve the

public interest.

● The Federal Aviation Administration
Relieving Transmission Bottlenecks Through Effective Investments 60

● FERC and DOE should work with states, pertinent federal agencies, and Native American tribes to

form cooperative regional transmission siting forums to develop regional siting protocols.

● Utilities and state utility commissions should develop an inventory of underutilized rights of way

and space on existing transmission towers. DOE will work with PMAs and TVA to conduct a comparable evaluation.

● DOE will work with NGA, regional governors’ associations, NARUC, and other appropriate statebased organizations to develop a list of "best practices" for transmission siting.

● DOE will undertake demonstration programs to support the use of innovative approaches to

transmission planning and siting (e.g., reliance on open planning processes, consideration of a

wide range of alternatives, incorporation of innovative or uncommonly employed technologies,

use of alternative mitigation measures, etc.).

● Federal agencies should be required to participate in regional siting forums and meet these

forums’ deadlines for reviews or complete reviews within 18 months, whichever occurs first.

● All federal agencies with land management responsibilities or responsibilities for oversight of

non-federal lands should assist FERC-approved RTOs in the development of transmission plans.

● Congress should grant FERC limited federal siting authority that could only be used when nationalinterest transmission bottlenecks are in jeopardy of not being addressed and where regional bodies have determined that a transmission facility is preferred among all possible alternatives.

● The Council on Environmental Quality should continue to coordinate efforts with the Secretary of

the Interior, Secretary of Energy, Secretary of Agriculture, Secretary of Defense, and Administrator

of the EPA to ensure that federal permits to construct or modify facilities on federal lands are

acted upon according to timelines agreed to in any FERC-approved regional protocol. The agencies should work together to re-evaluate the development of transmission corridors across federal lands and identify the current and potential future use of existing transmission corridors on

federal lands.

RECOMMENDATIONS

eminent domain to site transmission

facilities in much of Midwest and

Western United States

DOE believes that Congress should

grant limited federal siting authority to

FERC to be conveyed only when a transmission facility that would significantly advance

national interests is in jeopardy of not being

built and only after regional bodies have determined that this facility is preferred among all

possible alternatives. 
61 National Transmission Grid Study 

High-Temperature 

Superconducting 

Cables

Underground Cables

Advanced Composite 

Conductors

More Compact

Transmission Line

Configurations

Six or Twelve Phase

Transmission Line

Configurations

Modular Equipment

Wireless Power

Transmission

Superconducting ceramic cables can carry much more current

than standard wires of the same size, with extremely low resistance, allowing more power to flow in existing right-of-ways. But

the required refrigeration results in higher initial and ongoing

costs.

Underground cables transmit power with very low electromagnetic fields in areas where overhead lines are impractical or unpopular. Costs are 5 to 10 times that of overhead lines, and electrical

characteristics limit AC lines to about 25 miles.

New transmission conductors with composite cores, as opposed

to steel cores, are both lighter and have greater current carrying

capacity, allowing more power to flow in existing right-of-ways.

New computer-optimized transmission line tower designs allow

for more power to flow in existing right-of-ways.

Practically all AC high voltage power transmission is performed

using three phases. The use of six or even twelve phases allows

for greater power transfer in a particular right-of-way with

reduced electromagnetic fields due to greater phase cancellation.

Modular equipment designs provide greater transmission system

flexibility, allowing the grid to quickly adapt to changing usage.

They could also facilitate emergency deployment from a “strategic reserve” of critical devices, such as transformers. 

High power, wireless transmission using either microwave or

laser radiation is being explored. Application includes power

transmission from earth to orbiting satellites.

Demonstration project underway

with cables up to 400 ft. Self-contained current limiters are close 

to commercial availability.

Widely used when overhead is not

practical, mostly in urban areas and

underwater. Research is ongoing to

reduce costs.

Just entering commercial testing.

More experience is needed to lower

total life cycle costs.

Commercially available, with

increasing use.

Demonstration lines have been

built. Key challenge is cost and

complexity of integrating with

existing three phase systems.

Many standards already exist, but

further work is needed. 

Not expected to be competitive for

at least 20 years except in very

specialized niche markets such as

space power.

Ensuring the Timely Introduction of

Advanced Technologies

5

Table 5.1

Advanced Transmission Technologies

Technology Overview Commercial Status

41For additional background on this discussion, see the Issue Paper, “Advanced Transmission Technologies,” by J. Hauer, T. Overbye,

J. Dagle, and S. Widergren.

Continued on next page

The electricity system is one of the greatest

engineering achievements of the 20th century.

The system has benefited from countless technological innovations that have lowered costs

and increased reliability. Today, many more

innovations are not being utilized because their

pathway to the market is blocked by the business uncertainties resulting from the incomplete transition to a fully restructured electricity

industry. A large number of advanced transmission technologies are available that could

enhance reliability and dramatically increase

electricity flows through existing transmission

corridors (Table 5.1).41
Relieving Transmission Bottlenecks Through Effective Investments 62

Advanced Transmission Technologies (continued)

Technology

Ultra High Voltage

Lines

High-Voltage DC

(HVDC) 

Flexible AC

Transmission System 

(FACTS) devices 

Energy Storage

Devices

Controllable Load

Distributed Generation

Enhanced Power

Device Monitoring

Direct System State

Sensors 

Higher voltage lines can carry more power than lower voltage

lines. The highest transmission voltage line in North America

is 765 kV. Higher voltages are possible, but require much

larger right-of-ways, increase need for reactive power reserves,

and generate stronger electromagnetic fields.

HVDC provides an economic and controllable alternative to AC

for long distance power transmission. DC can also be used to

link asynchronous systems and for long distance transmission

under ground/water. Conversion costs from AC to DC and

then back to AC have limited usage. Currently there are several thousand miles of HVDC in North America. 

FACTS devices use power electronics to improve power system

control, helping to increase power transfer levels without new

transmission lines. But currently they are expensive, making

FACTS uneconomic for most transmission owners. 

Energy storage devices permit use of lower cost, off-peak

energy during higher-cost peak-consumption periods. Some

specialized energy storage devices can be used to improve

power system control. Technologies include pumped hydro,

compressed air, superconducting magnetic energy storage

(SMES), flywheels, and batteries. 

Fast-acting load control has the potential to become an important part of transmission system control. Flexible load allows

higher normal-power transfer levels since during system emergencies the load can be rapidly curtailed.

Small, distributed generators, including conventional (e.g.,

diesel generators) and newer (e.g., PV, fuel cells and microturbines) technologies, allow generation to be located close to

the load, decreasing the need for reliance on the transmission

system. 

The operation of many power system devices, such as transmission lines, cables, and transformers is limited by the

device’s thermal characteristics. The high operating voltages

of these devices make direct temperature measurement difficult. Lack of direct measurements required conservative operation, resulting in less power transmission capacity. Newer

dynamic sensors have the potential to increase transmission

system capacity. 

In some situations the capability of the transmission system is

limited by region-wide dynamic constraints. Direct system

voltage and flow sensors can be used to rapidly measure the

system operating conditions, allowing for enhanced system

control. 

Overview Commercial Status

Voltage levels of 1000 kV are

currently used in Japan. Electromagnetic fields, right-of-way, and

technical concerns limit use in

the U.S.

Converter costs are decreasing

making DC an increasingly attractive alternative. Most merchant

transmission lines propose utilizing HVDC.

Several large demonstrations

projects are operating. New

power electronics advances may

result in costs reductions. 

Demonstrations are underway for

many advanced storage technologies. The economics of the others is still elusive except in small

markets.

Commercially available with

increasing use.

Commercially available with the

economics dependent upon the

price of natural gas and utility

interconnection policies. Ongoing

maintenance costs are also an

issue.

Commercial units are available to

measure conductor sag allowing

for dynamic transmission line

limits. Dynamic transformer and

cable measurement units are also

commercially available.

High speed power system measurement units are commercially

available and are being used by

several utilities. Research has

only begun to examine use of

these measurements for real time

control of the power system.

Source: J. Hauer, T. Overbye, J. Dagle, and S. Widergren. 2002. Advanced Transmission Technologies. Issue Papers.
One class of technologies that could

be used seeks to improve throughput of

electricity over existing transmission corridors by using advanced composite materials for new overhead conductors and

high-temperature superconducting (HTS)

cables that can carry five times as much

electricity as copper wires of the same

63 National Transmission Grid Study 

High-Temperature Superconductivity

During the past decade, DOE and industry have pursued research on a promising technology called high-temperature

superconductivity. Superconductivity

refers to a physical state of materials at

which electricity can pass with no loss 

of energy. Formerly thought to occur

only at very low temperatures, which

would not be practical in commercial

applications, superconductivity has been

de-monstrated with newer materials at

higher temperatures. Commercial applications of superconductivity that are

now being explored include more efficient motors, generators, transformers,

and other electric equipment.

For electricity transmission, superconductivity offers the promise of dramatically lowering the losses

associated with long distance transmission of electricity. Electricity losses in transmission and distribution systems exceed 10 percent of total electricity generated. Reducing these losses would represent

hundred of millions of dollars in annual savings to the nation’s electricity bill.

DOE supports industry efforts to commercialize superconducting technologies through basic research

and testing that will speed its acceptance and use. In partnership with industry, DOE expects to assist

industry in rapidly moving these technologies into the marketplace.

Several states, including Michigan, New York, and Ohio, will soon see first-of-a-kind operational testing

of superconducting generators, power lines, and transformers. These real-world experiences will lay the

foundation for widespread use across the grid of this next-generation technology that provides higher

capacity, greater reliability, and improved efficiency.

Source: U.S. Department of Energy. http://www.eren.doe.gov/superconductivity/

At the beginning of 2002, the Southwire Company, in a 50/50 cost share with

DOE, completed two years of the first operational test of superconducting cables

in an industrial application.

size. DOE has been a leader in developing

HTS (see text box). Another approach to

better utilization of existing corridors is

improvement in the configuration of 

transmission lines or placement of conductors underground, which also minimizes

some environmental impacts of electricity

transmission.
Relieving Transmission Bottlenecks Through Effective Investments 64

42It is also appropriate to consider non-transmission alternatives, such as controllable load and distributed generation, as technologies that enable

greater control of electricity flows. See Section 4, “Relieving Transmission Bottlenecks Through Better Operations.”

Another class of technologies enables 

better control of the flow of electricity over

existing lines. Flexible AC transmission system

(FACTS) devices are high-voltage power electronics devices that allow precise and rapid

control of power. They can help eliminate loop

flow in AC networks. High-voltage direct current (HVDC) lines and more recently HVDC

“light” can completely avoid the problems of

loop flow. Superconducting magnetic energy

storage can be located strategically throughout

the grid to damp out disturbances.42

Another class of technologies would

increase the accuracy with which the limits of

safe operation could be determined. These

technologies take precise measurements of 

the system in real time. Real-time monitoring

of the actual status of the power system would

permit the introduction of sophisticated automatic controls to prevent blackouts. The Wide

Area Measurement System was an early DOEsupported demonstration of the improvements

in reliability management made possible by

advanced measurements (see text box). Realtime monitoring of conductor temperatures

would replace reliance on conservative, predetermined ratings for conductors, safely permitting increased flows over transmission lines.

These hardware technologies can provide

the muscle for improved transmission system

capabilities, but software technologies are

also needed to provide the intelligence to 

use these hardware technologies effectively.

Advanced visualization techniques can dramatically enhance the ability of system operators to identify emerging grid problems in 

real time, assess options to address them, 

and take rapid corrective actions. New models

and modeling techniques have improved 

our understanding of how the system behaves in response to region-wide transfers of

electricity.

Encouraging the use of these new technologies is essential to make better use of

existing transmission facilities and reduce the

number of new facilities that are needed.
65 National Transmission Grid Study 

Wide Area Measurement Systems

Wide Area Measurement Systems

(WAMS) technology is based on

obtaining high-resolution powersystem measurements (e.g., voltage) from sensors that are dispersed over wide areas of the 

grid, and synchronizing the data

with timing signals from Global

Positioning System (GPS) satellites.

System operators currently retrieve

archived data to analyze grid disturbances and improve system models;

in the future, they will be able to

use these data in real time to assess

the health of the grid.

In 1995, DOE launched the WAMS

project, in cooperation with Federal

utilities and the private sector, to

determine the information needs of

the emerging power system and to

develop technologies to meet these

needs. A prototype WAMS network

was installed, and software was

developed to record, archive, and

retrieve data.

The real-time information available from WAMS may allow operators to detect and mitigate a disturbance before it can spread and enable greater utilization of the grid by operating it closer to its limits

while maintaining reliability. The capacity that is freed up is available to move larger amounts of

power over the grid in response to competitive market transactions.

WAMS demonstrated its value following the massive Western system blackouts on August 10, 1996.

Engineers began analyzing WAMS data within minutes of the blackout to reconstruct the sequence of

events that led to it and to initiate corrective actions to restore service. DOE is working with Federal

and private utilities to transfer this technology to system operators nationwide. Additional hardware

and software enhancements using state-of-the-art technologies are needed to allow WAMS to realize

its full potential.

Source: U.S. Department of Energy. http://www.eren.doe.gov/der/transmission
Relieving Transmission Bottlenecks Through Effective Investments 66

Continued development of these technologies

is also expected to lead to a smart, switchable

grid that can anticipate impending emergencies and automatically take preventive actions.

Technologies such as these can protect the

grid not only against traditional threats to 

reliability (such as storms and other natural

events) but also against deliberate disruptions. (Transmission system security is discussed in more detail in the next subsection.)

Despite the obvious advantages of advanced transmission technologies, their development and deployment has been waning

during the past 10 years. The uncertainties

created by the anticipation of and the incomplete transition to a restructured electricity

industry has led to a decline in traditional utility support for advanced technologies. 

Before restructuring, funding for utility

R&D was recovered in rates paid by all electricity consumers. In the vertically integrated

industry of the past, collaborative, publicinterest transmission-system R&D supported

by all utilities (which did not compete with

each other) was a logical complement to

longer-range, higher-risk R&D, which was supported by the federal government.

Today, new institutions in the restructured industry, such as RTOs and ISOs, should

be responsible for ensuring that adequate

research and development is undertaken to

support a reliable and efficient transmission

system. However, these institutions have

either not yet formed or have not been given

an explicit charter to ensure adequate support

for these activities. Once the transition to a

restructured industry is complete, the private

sector should once again be able to ensure

adequate R&D investments. However, there is

a critical need for the federal government 

to increase efforts to monitor and address

emerging gaps in public-interest R&D for

transmission technologies.

The areas appropriate for increased federal scrutiny and focus are defined by the

technology requirements of reliable electric

transmission systems that support regional

competitive wholesale electricity markets. As

noted in Section 3, there is a need for technologies to help manage the operations of

large regional transmission systems reliably.

As noted in Section 4, expanded efforts are

also needed in the areas of improved real-time

measurements, analysis of competitive market

rules and their impacts on (and the opportunities they offer for enhancing) reliability, programs and technologies to enhance voluntary

customer load reduction, and interconnection

and integration of distributed generation.

Federal PMAs, such as BPA and WAPA,

remain important, unique elements of the U.S.

R&D infrastructure. TVA has been a leader in

development and demonstration of advanced

transmission technologies. These entities have

a long tradition of multi-institutional R&D conducted in the public interest. Today, they are

functioning, proven, and immediately available

resources for joint public-private technology

development efforts.

One of the gaps on the pathway to market is demonstration of advanced technologies

in utility systems using utility procedures and

independent evaluation of the performance of

these technologies. One way to fill this gap

would be to combine the expertise of DOE’s

national laboratories, TVA, and the PMAs to

develop flexible field test facilities that can 

create realistic demonstrations of advanced
67 National Transmission Grid Study 

technologies under a wide range of electrical

conditions without jeopardizing normal

operations. Overhead and underground

transmission, composite conductors, hightemperature superconducting equipment,

high-voltage power electronics, energy storage systems, and combinations of these

technologies and other equipment would

benefit from this type of test facility. Publicprivate partnerships should guide the evaluation of these technologies.

It is worth nothing that a crisis may be

brewing upstream in power system engineering education as talented young engineers

seek out careers in other, more lucrative

professions. Some argue that the dearth of

RECOMMENDATIONS

● DOE will work with NARUC to develop guidance for state regulators and utilities on evaluating

the risks of investment in innovative new technologies that advance public interests. These

guidelines will help determine when a technology is a reasonable performance risk and how to

weigh the costs and benefits of using a new versus an established technology.

● The PMAs and TVA should maintain their leadership of demonstration efforts to evaluate

advanced transmission-related technologies that enhance reliability and lower costs to 

consumers.

● DOE will develop national transmission-technology testing facilities that encourage partnering

with industry to demonstrate advanced technologies in controlled environments. Working with

TVA, DOE will create an industry cost-shared transmission line testing center at DOE’s Oak

Ridge National Laboratory (with at least a 50 percent industry cost share).

● DOE will accelerate development and demonstration of its technologies, including high-temperature superconductivity, advanced conductors, energy storage, real-time system monitoring and

control, voluntary load-reduction technologies and programs, and interconnection and integration of distributed energy resources.

● DOE will work with industry to develop innovative programs that fund transmission-related R&D,

with special attention to technologies that are critical to addressing transmission bottlenecks.

talented engineers is simply a reflection of a

supply and demand system that has not valued power engineers sufficiently to attract

young new recruits to the profession. The

solution to the problem, these observers

argue, is not to artificially increase the numbers of poorly paid engineers but instead to

create a reward structure to attract the necessary talent. Regardless of the reason or the

best solution, there is no question that there

is at the moment an apparent shortage of

qualified operating staff for the electricity

power systems just at the time when many

senior engineers—the collective engineering

institutional memory of the industry—are

about to retire.
Relieving Transmission Bottlenecks Through Effective Investments 68

Enhancing the Physical and Cyber

Security of the Transmission System

5

Recent concern about national security

issues has focused attention on the basic

design of the interconnected transmission

system and the reliability management

philosophies that guide its operation. While

DOE has included a limited discussion of

transmission-related energy security issues

in this subsection, this study is not intended as a comprehensive discussion of electricity infrastructure security issues.

Reliability has always taken into

account the impacts of weather and random equipment failure. Extensions of existing practices, as well as new technologies

and operating practices are now needed to

protect the transmission system against

deliberate, coordinated attacks. For example, increased reliance on distributed generation—electricity generation closer to 

the point of use (which would result in less

reliance on the transmission system)—leads

to a more robust electricity system.

As the U.S. moves forward with the

modernization of its transmission systems,

it is critical that infrastructure protection be

built into these decisionmaking processes.

Hardware and software technologies that

are available in the market today can protect facilities, improve recovery and restoration speed, and reduce the effectiveness of

deliberate attacks. The smart, switchable

grid discussed in the previous subsection

should be an important element in this

portfolio; R&D on this concept must extend

its capabilities to address multiple contingencies in the case of deliberate attack. 
69 National Transmission Grid Study 

The Northeast Ice Storm of 1998—Lessons for Power System Recovery

No reasonable set of precautions can entirely prevent widespread disruptions of electrical services.

However, when such disruptions do occur, their impact can be greatly reduced if advance preparations have been made.

Between January 5 and 10, 1998, a series of exceptionally severe ice storms struck large areas within New York, New England, Ontario, Quebec, and the Maritime Provinces. The worst freezing rains

ever recorded in the region deposited ice up to three inches thick. Damage to transmission and

distribution facilities was severe—more than 770 transmission towers collapsed.

The Northeast ice storm showed that the following types of resources should be part of advance

preparation for emergencies:

• Comprehensive procedures for emergency management;

• Stockpiles of reserve equipment for emergency management and repair of facilities; and

• Procedures to ensure that adequate numbers of trained personnel can be mobilized.

Source: Northeast Power Coordinating Council. 1998. January 1998 Ice Storm—Final Report. http://www.npcc.org

It should be designed to prevent, detect, and

mitigate threats to reliability.

Unlike operational failures of the grid,

which can usually be corrected within several

hours, attacks on the grid are likely to result 

in the type of physical damage to equipment

that is experienced in severe storms. The costs

of service disruption to individual customers

and to society rise sharply the longer an outage lasts. Emergency preparedness can greatly

mitigate the impact of widespread disruptions

whether they are natural events or the result 

of malicious attack. Recent experiences with

natural disasters may be used as a roadmap for

advance planning to minimize disruptions. 

There is great diversity of electricity system and equipment designs and parts. Our

electricity systems were designed by hundreds

of local utilities with little consideration for standardization. Discussions within the industry

should identify key hardware and software items

that link our transmission system and evaluate

the costs and benefits associated with standardizing equipment, where possible, and maintaining a reserve supply of transmission equipment.

Reserve equipment is shared among utilities

today; now is the time to ensure that adequate

reserves of equipment are also available in a

restructured market tomorrow. 

We have an unprecedented opportunity to

address these issues. As RTOs begin the process

of building the software and hardware needed to

operate our regional transmission systems, energy security issues should be factored into decisions on how we can best protect the reliability

of our transmission system. 
Relieving Transmission Bottlenecks Through Effective Investments 70

● DOE will work with industry to evaluate the feasibility of adopting modular designs and standards

for substation and other transmission equipment to facilitate rapid replacement.

● DOE and the national laboratories will continue to develop cost-effective technologies that

improve the security of, protect against, mitigate the impacts of, and improve the ability to recover from disruptive incidents within the energy infrastructure.

● DOE will continue to develop energy infrastructure assurance best practices through vulnerability

and risk assessments.

● DOE will work with industry to evaluate the costs and benefits associated with maintaining a

reserve supply of transmission equipment that is funded by transmission rates. This reserve would

be a resource in case of major outages resulting from terrorism or natural disasters.

● DOE will continue to work with industry to promote education and awareness in the industry

about critical transmission infrastructure issues.

● DOE will continue to work closely with industry and state and local officials on implementation

plans that respond to attacks on our transmission infrastructure.

● DOE will continue to provide training in critical infrastructure protection matters and energy emergency operations to state government agencies and to private industry.

● DOE will study the Eastern and Western AC Interconnections to assess the costs and benefits,

including impacts on national security, of a series of smaller interconnections that are electrically

independent of one another with DC links between them.

● DOE will work with industry and the states to develop standardized security guidelines to help

reduce the cost of facility protection and facilitate consequence management.

RECOMMENDATIONS

Critical Infrastructure Protection

DOE works closely in partnership with industry to address critical infrastructure protection challenges. DOE has led assessments to help industry

understand the vulnerability of its systems to cyber or physical disruptions

and identify ways to mitigate these vulnerabilities. DOE also works with

industry to provide security alerts, contain and divert attacks, plan a system that can respond effectively to energy-sector attacks, and identify ways

to facilitate rapid restoration of the system.

http://www.energy.gov/
6
The importance of the interstate commerce that is conducted

through our electricity transmission system dictates that there will

be a federal role in ensuring reliable transmission systems that

support fair and efficient competitive regional wholesale electricity markets. DOE is committed to taking a leadership role in

addressing emerging transmission bottlenecks that threaten our

national interests. Furthermore, DOE will develop the state-of-theart tools needed to evaluate the system’s operation and efficiency,

and will continue to work with industry and Congress to ensure

that basic transmission research and development continues.

DOE’s Commitment and Leadership 72

DOE is the lead federal agency responsible for

developing sound and secure national energy

policy. DOE funds and promotes new transmission technologies, oversees the federal Power

Marketing Administrations, issues permits for

cross-border transmission lines, and addresses

national energy security.

DOE must also take responsibility for 

identifying and helping eliminate transmission

bottlenecks of national importance, and for

developing the tools needed to ensure efficient

regional markets.

DOE’s objective is simple: to provide our

citizens with a reliable supply of electricity 

at the lowest possible cost. During the early

1990s, the department worked closely with 

the Administration and Congress to support

this objective through the Energy Policy Act of

1992, which moved the nation toward competitive electricity markets.

Opening the electricity industry to competitive wholesale markets has resulted in newer,

cleaner power plants that cost less and are

more efficient than older power plants. Where

less than 200 heavily-regulated, vertically-inteDOE’s Commitment and Leadership

grated electric utilities used to control more

than 80 percent of the industry, non-regulated

power producers now account for the majority

of new power plant additions. Consumers 

have benefited from lower electricity bills. But,

we cannot stop here; there are many more

economies to be gained by completing the

transition to competitive electricity markets.

Differences in electricity prices prompted

the push for competition. Under monopoly 

regulation, some consumers used to pay many

times more than others for wholesale electricity. Competitive markets give firms incentives 

to lower costs, improve efficiency, innovate,

and provide new services to consumers. The

electricity industry is still undergoing substantial change. Although industry participants do

not agree on how best to achieve the ultimate

objective of reliable supplies at the lowest cost,

they do agree that, in order to obtain the full

benefits of competitive electricity markets, we

need to dramatically improve our electricity

delivery system.

Developing and implementing policies that

will lead to needed beneficial investments in
73 National Transmission Grid Study 

the nation’s electricity transmission system

and support fair and efficient regional wholesale electricity markets will be challenging. 

The public interest is foremost and the views

of consumers, states and industry must be

heard and considered. Accommodating diverse

interests is imperative because federal transmission policies will only work if they can be

supported politically and implemented; the 

recommendations contained in this study will

help guide us.

Some of the recommendations included in

this report are not new. Similar recommendations have been made in other DOE reports in

recent years.

For example, the Secretary of Energy

Advisory Board’s 1998 report “Maintaining

Reliability in a Competitive U.S. Electricity

Industry” recommended that DOE:43

● Develop methods for sharing generation- and transmission-planning data;

● Study and recommend performancebased rates and other transmission 

pricing methods;

● Help modify reliability rules to reduce

congestion;

● Adopt open standards for control 

centers; and 

● Further promote reliability technologies.

In addition, DOE’s Power Outage Study

Team “Findings and Recommendations to

Enhance Reliability from the Summer of 1999”

proposed:44

● An increased federal leadership role in

electricity reliability issues;

● Support for market rules for customer

demand response;

● Support for interconnection standards for

distributed generation;

● Support for mandatory reliability 

standards;

● Sharing of “best practices” for distribution;

● Use of uniform definitions and measurements for reliability information;

● Development of real-time system monitoring and control equipment; and

● Improvement of analytic models for load

forecasts and power-system simulation.

DOE has acted on some of these recommendations, but it has not followed through on all of

them due to limited resources, a lack of focus,

and a lack of accountability. DOE will improve 

on this record in two steps. First, DOE commits

to addressing administratively the concerns of

43Download from http://vm1.hqadmin.doe.gov/seab/esrfinal.pdf

44Download from http://www.pi.energy.gov/pilibrary.html
DOE’s Commitment and Leadership 74

focus and accountability. Second, DOE will work

with the Administration and Congress to identify

and allocate appropriate resources.

The department is committed to implementing the recommendations of the National

Transmission Grid Study to ensure needed, beneficial investments in the nation’s transmission

system. To accomplish this task, the department

will reorganize itself to combine its divergent

electricity delivery system resources into a single, focused Office of Electric Transmission and

Distribution.

This new program office will:

● Fund transmission- and distributionsystem R&D;

● Promote and foster the deployment of

new transmission- and distributionsystem technologies;

● Develop the data and analytical tools 

necessary to assess the reliability and

performance of the transmission and 

distribution system;

● Conduct research on electricity market

designs and evaluation of market 

performance;

● Designate national-interest transmission

bottlenecks;

● Approve cross-border transmission lines;

and

● Support the Power Marketing Administrations’ efforts to eliminate transmission

bottlenecks, introduce new technologies

that increase the reliability and efficiency

of the transmission system, and help

ensure that best practices are shared.

For DOE to become a leader in shaping

electricity policy, this new Office of Electric

Transmission and Distribution must be responsible and accountable for our efforts to

improve the system.

DOE has many tools at its disposal to

carry out these responsibilities. In the fall 

of 2001, DOE executed two memoranda of

understanding to address electricity issues

that affect both state and federal interests.

These partnerships, with the National

Governors Association and the Western

Governors’ Association, respectively, should

provide a solid basis for implementing many

of this study’s recommendations.

In addition, DOE has the authority to 

propose rules and forward them to the FERC

for debate. Although not often used in the

past, DOE will actively review and pursue

appropriate opportunities to use this authority

in the future.

DOE, in its leadership role for the development of electricity policies, must change its

organizational structure, become proactive in

FERC rulemakings, encourage the use of new

technologies as a solution to transmission system problems, and identify and help eliminate

the nation’s most significant bottlenecks. DOE

must work with regions, states, and localities

to ensure that national-interest transmission

bottlenecks are remedied appropriately.

● DOE will create an Office of Electric Transmission and Distribution.

RECOMMENDATION
75 National Transmission Grid Study 

Section 2—The National Interest in Relieving Transmission

Bottlenecks

Next Steps Toward Relieving Transmission Bottlenecks

● DOE, through a rulemaking, will determine how to identify and designate transmission bottlenecks

that significantly impact national interests.

● DOE will further develop the analytic tools and methods needed for comprehensive analysis to 

determine national-interest transmission bottlenecks.

● In an open public process, DOE will assess the nation’s electricity system every two years to identify

national-interest transmission bottlenecks.

Section 3—Relieving Transmission Bottlenecks By Completing the

Transition to Competitive Regional Wholesale Electricity Markets

Establishing Regional Transmission Organizations

● RTOs should be responsible for maintaining the reliability of the grid and ensuring that transmission

bottlenecks are addressed.

● DOE, with industry, will assess current system monitoring and control technologies that support 

efficient, reliable, and secure operation of RTOs and coordinate development of a plan for future

research and development.

● DOE will work with FERC and stakeholders to develop objective standards for evaluating the performance of RTOs and will collect the information necessary for this assessment. 

● DOE will work with the Energy Information Administration (EIA), FERC, National Governors Association

(NGA), the National Association of Regulatory Utility Commissioners (NARUC), the National

Association of State Energy Officials (NASEO), industry, and consumer representatives to determine

what economic and reliability data related to the transmission and the electricity system should be

collected at the federal level and under what circumstances these data should be made publicly available.

● NGA and NARUC should identify state laws that could hinder RTO development.

● DOE will review federal laws that may prevent PMAs from full participation in RTOs, direct them to

participate in the creation of RTOs, and take actions to facilitate their joining RTOs.

● DOE will work with TVA to help it address any issues that inhibit its participation in wholesale competitive markets, including full participation in an RTO.

Consolidated List of Recommendations
Consolidated List of Recommendations 76

Increasing Regulatory Certainty and Focus

● DOE will work with NGA, regional governors’ associations, NARUC, and other appropriate statebased organizations to promote innovative methods for recovering the costs of new transmissionrelated investments. These methods should consider situations where rate freezes are in effect

and also examine incentive regulation approaches that reward transmission investments in proportion to the improvements they provide to the system. 

● DOE will research and identify performance metrics and evaluate designs for performance-based

regulation. 

● The Department of Treasury should evaluate tax law changes related to electricity modernization.

Treasury should review its current regulations regarding the application of private use limitations

to facilities financed with tax exempt bonds in light of dynamics in the industry and proceed to

update and finalize its regulations. This will give greater certainty to public power authorities

providing open access to their transmission and distribution facilities. 

● Entrepreneurial efforts to build merchant transmission lines that pose no financial risk to ratepayers and that provide overall system benefits should be encouraged. 

● DOE and the Department of Treasury will evaluate whether tax law changes may be necessary to

provide appropriate treatment for the transfer of transmission assets to independent transmission companies. 

Section 4—Relieving Transmission Bottlenecks Through Better

Operations

Pricing Transmission Services to Reflect True Costs

● DOE, working with FERC, will continue to research and test market-based approaches for transmission operations, including congestion management and pricing of transmission losses and

other transmission services.

Increasing the Role of Voluntary Customer Load Reduction, and Targeted Energy

Efficiency and Distributed Generation

● DOE will work with FERC, the states, and industry and conduct research on programs and technologies to enhance voluntary customer load reduction in response to transmission system emergencies and market price signals.

● DOE will work with states and industry to educate consumers on successful voluntary load-reduction programs. DOE will disseminate information on successful approaches and technologies.

● DOE will continue to work with NGA, regional governors’ associations, and NARUC to remove regulatory barriers to voluntary customer load-reduction programs, and targeted energy-efficiency

and distributed-generation programs that address transmission bottlenecks and lower costs to

consumers.
77 National Transmission Grid Study 

● IEEE should expeditiously complete its technical interconnection standards for distributed 

generation.

● DOE will work with NGA and NARUC to develop and promote the adoption of standard interconnection agreements, rules, and business procedures for distributed generation.

Using Improved Real-Time Data and Analysis of Transmission System

Conditions

● DOE will work with industry to demonstrate and document cost-effective uses of dynamic transmission system analysis.

Ensuring Mandatory Compliance with Reliability Rules

● Federal legislation should make compliance with reliability standards mandatory.

● Current reliability standards should be reviewed in an open forum to ensure that they are technically sound, nondiscriminatory, resource neutral, and can be enforced with federal oversight.

● Penalties for noncompliance with reliability rules should be commensurate with the costs and

risks imposed on the transmission system, generators, and end users by noncompliance.

Penalties collected should be used to reduce rates for consumers.

● DOE will work with industry and NARUC to promote development and sharing of best transmission and distribution system operations and management practices.

● DOE will work with FERC, state PUCs, and industry to ensure the routine collection of consistent

data on the frequency, duration, extent (number of customers and amount of load affected),

and costs of reliability and power quality events, to better assess the value of reliability to the

nation’s consumers.

Section 5—Relieving Transmission Bottlenecks Through Effective

Investments

Implementing Regional Transmission Planning

● DOE will work with the electricity industry and state and federal regulators to identify the type

of electricity system data that should be made available in the planning process to facilitate the

development of market-based transmission solutions and devise a process for making that

information available.

Accelerating the Siting and Permitting of Needed Transmission Facilities

● FERC and DOE should work with states, pertinent federal agencies, and Native American tribes

to form cooperative regional transmission siting forums to develop regional siting protocols.
Consolidated List of Recommendations 78

● Utilities and state utility commissions should develop an inventory of underutilized rights of way

and space on existing transmission towers. DOE will work with PMAs and TVA to conduct a comparable evaluation.

● DOE will work with NGA, regional governors’ associations, NARUC, and other appropriate statebased organizations to develop a list of “best practices” for transmission siting.

● DOE will undertake demonstration programs to support the use of innovative approaches to

transmission planning and siting (e.g., open planning processes, consideration of a wide range

of alternatives, incorporation of innovative or uncommonly employed technologies, use of alternative mitigation measures, etc.).

● Federal agencies should be required to participate in regional siting forums and meet these

forums’ deadlines for reviews or complete reviews within 18 months, whichever occurs first.

● All federal agencies with land management responsibilities or responsibilities for oversight of

non-federal lands should assist FERC-approved RTOs in the development of transmission plans.

● Congress should grant FERC limited federal siting authority that could only be used when

national-interest transmission bottlenecks are in jeopardy of not being addressed and where

regional bodies have determined that a transmission facility is preferred among all possible

alternatives.

● The Council on Environmental Quality should continue to coordinate efforts with the Secretary

of the Interior, Secretary of Energy, Secretary of Agriculture, Secretary of Defense, and

Administrator of the EPA to ensure that federal permits to construct or modify facilities on 

federal lands are acted upon according to timelines agreed to in any FERC-approved regional

protocol. The agencies should work together to re-evaluate the development of transmission

corridors across federal lands and identify the current and potential future use of existing transmission corridors on federal lands.

Ensuring the Timely Introduction of Advanced Technologies

● DOE will work with NARUC to develop guidance for state regulators and utilities on evaluating

the risks of investment in innovative new technologies that advance public interests. These

guidelines will help determine when a technology is a reasonable performance risk and how to

weigh the costs and benefits of using a new versus an established technology.

● The PMAs and TVA should maintain their leadership of demonstration efforts to evaluate

advanced transmission-related technologies that enhance reliability and lower costs to 

consumers

● DOE will develop national transmission-technology testing facilities that encourage partnering

with industry to demonstrate advanced technologies in controlled environments. Working with

TVA, DOE will create an industry cost-shared transmission line testing center at DOE’s Oak

Ridge National Laboratory (with at least a 50% industry cost share). 
79 National Transmission Grid Study 

● DOE will accelerate development and demonstration of its technologies, including high-temperature superconductivity, advanced conductors, energy storage, real-time system monitoring and

control, voluntary load reduction technologies and programs, and interconnection and integration of distributed energy resources.

● DOE will work with industry to develop innovative programs that fund transmission-related R&D,

with special attention to technologies that are critical to addressing transmission bottlenecks.

Enhancing the Physical and Cyber Security of the Transmission System

● DOE will work with industry to evaluate the feasibility of adopting modular designs and standards for substation and other transmission equipment to facilitate rapid replacement.

● DOE and the national laboratories will continue to develop cost-effective technologies that

improve the security of, protect against, mitigate the impacts of, and improve the ability to

recover from disruptive incidents within the energy infrastructure.

● DOE will continue to develop energy infrastructure assurance best practices through vulnerability and risk assessments.

● DOE will work with industry to evaluate the costs and benefits associated with maintaining a

reserve supply of transmission equipment that is funded by transmission rates. This reserve

would be a resource in case of major outages resulting from terrorism or natural disasters.

● DOE will continue to work with industry to promote education and awareness in the industry

about critical transmission infrastructure issues.

● DOE will continue to work closely with industry on implementation plans that respond to attacks

on our transmission infrastructure.

● DOE will continue to provide training in critical infrastructure protection matters and energy

emergency operations to state government agencies and to private industry.

● DOE will study the Eastern and Western AC Interconnections to assess the costs and benefits,

including impacts on national security, of a series of smaller interconnections that are electrically independent of one another with DC links between them. 

● DOE will work with industry and the states to develop standardized security guidelines to help

reduce the cost of facility protection and facilitate consequence management. 

Section 6—DOE’s Commitment and Leadership

● DOE will create an Office of Electric Transmission and Distribution. 
National Transmission Grid Study 80

Overview of POEMS

The Policy Office Electricity Modeling System (POEMS) integrates

the Energy Information Administration (EIA) National Energy

Modeling System (NEMS) with the detailed electricity market

model TRADELECTM, developed by OnLocation, Inc. NEMS is an

integrated energy model with supply and demand modules 

representing the U.S. energy system. In POEMS, TRADELECTM

replaces the Electricity Market Module of NEMS to add detail

and disaggregation. TRADELECTM was designed specifically for

analyzing competitive electricity markets and the transition

from regulated markets. TRADELECTM incorporates the features

necessary to analyze key policy questions: stranded costs, 

consumer prices, mix of new construction, impact of increased

electricity trading, and interaction with environmental policies.

POEMS has been used to support DOE’s analysis of the

Comprehensive Electricity Competition Act proposed by the

Clinton Administration. For various participants in electricity

markets, POEMS has been used to assess regional markets,

forecasting electricity prices, supply, and demand under alternative economic and fuel price scenarios. The model has 

also been used to assess the impact of alternative environmental policies on utility industry capital turnover and inter-fuel

substitution. 

For the National Transmission Grid Study, the dispatch and

trade portion of TRADELECTM was used as a stand-alone model

with generating capacity, fuel prices, and electricity demands

held constant. In other words, the other fuel supply and

demand modules were not used, and the capacity expansion

module was turned off. The analysis focused on a single year

(2002). Hence, the impacts of changes in these other variables

is small and detract from the focus on transmission and trade

flows. Therefore, documentation included in this appendix

focuses on the dispatch and trade portions of TRADELECTM and

does not describe its other modules and features, (e.g., capacity expansion, retail pricing, and demand response.) 

TRADELECTM Electricity Model

The heart of the TRADELECTM model is market-driven electricity

trade over the existing electricity transmission system. Electricity trade is solved as a function of relative prices, transmission

availability, and a hurdle rate that is designed to reflect the

additional costs of handling market trading. TRADELECTM represents transmission inter-ties at existing transfer interfaces.

Current and future transmission bottlenecks may limit trade

flows among certain buyers and sellers when transmission

capacity is reached. This would result in final regional price differences that exceed the cost of transmission and trading. 

The trading function is critical in determining competitive

prices for electric power and in measuring efficiency gains from

restructuring the electricity industry. By explicitly solving trade

relationships, TRADELECTM offers insights into pricing patterns

and motivations for interregional trading.

In the absence of transmission constraints, electricity

prices nationwide would converge to a single value with local

delivery prices varying only by differences in the cost of transmission (including line losses) and distribution services.

However, the tendency in competitive markets toward a single

price does not mean that there will be no market separation.

Because transmission is neither unconstrained nor without

cost, separable regional electricity markets are likely to be

observed as model solutions evolve. Additional regional constraints, such as region-specific pollution abatement measures,

could further increase regional price differences even in fully

competitive power markets.

Appendix A

Policy Office Electricity Modeling System (POEMS) and Documentation for

Transmission Analysis
81 National Transmission Grid Study

Model Description and Structural Assumptions

Electricity Demands and Load Shapes

A unique aspect of POEMS is its representation of the 

load-duration curves with vertical rather than horizontal time

blocks. This approach ensures that trades among regions are

fulfilling the same requirements and that power generated at

one time (such as during night hours) is not being used to satisfy power demands at another time (such as during peak daytime hours). The definition of the time blocks is flexible. For

this transmission study, the annual load in each region is represented by total of 864 load slices: 24 hours for three typical 

day types (weekday, weekend day, and peak day) within each 

of the 12 months.

Dispatch and Trade

TRADELECTM is a network model of electricity dispatch,

trade, capacity expansion, and pricing, as shown in Figure 1.

The model operates using POEMS’ 69 regions or power centers,

illustrated in Figure 2. These regions are combinations of the

roughly 150 power control areas in the

U.S. although some power pools are disaggregated to reflect transmission constraints between zones. POEMS regions

are represented as a series of nodes, connected by transmission inter-ties with specific transfer capabilities. There are more

than 300 transmission paths in POEMS.

Supply resources within each POEMS

region, consisting of utility plants, exempt

wholesale generators, traditional and nontraditional cogenerators, and firm power

contracts, are represented in considerable

detail. Plant characteristics, such as capacity, heat rate, and forced and maintenance

outage rates, are represented based on

data in EIA filings and the North American

Electric Reliability Council Generating

Availability Data System data. TRADELECTM incorporates financial, operational, and physical data representing virtually every

significant operating electric utility in the U.S. and the transmission inter-ties among them.

Representation of Generation Plants

The plant input file to POEMS consists of virtually all existing units in the U.S. Plants currently under construction that are

expected to be on-line during the year 2002 are included as

well. Each unit in the plant input file is combined with like units

to form dispatchable groups. The process of combining units is

flexible, but, at a minimum, combined units serve the same

demand region and are physically located in the same supply

region, use the same fuels with the same type of prime mover,

and have the same in-service period. Dispatchable capacity

groups also have similar heat rates, and renewable groups have

similar utilization patterns. Currently, there are more than

7,000 plant groupings in the model. There are over 100 dispatchable plant groupings per POEMS region on average, with

Figure 1: Components of the TRADELECTM Model
National Transmission Grid Study 82

the largest POEMS regions having 300 to 500 plant groups. 

A merit order dispatch algorithm is initially employed to determine generation in each time segment prior to trade.

Trade

Network interregional trade is solved to maximize the economic gains from trade by ordering trades in descending order,

starting with the trade that contributes the largest efficiency

gains first. Succeeding trades continue until available transmission opportunities or all possible gains are exhausted. The primary economic and physical limits to trade are imposed by

means of alternative scenarios for transmission fees, losses,

transmission capacity, and hurdle rates. Thus, integrated interregional trade is modeled to operate in much the same fashion

as a full-fledged, time-block power auction. 

Transmission Costs and Capacity

POEMS transmission path and nodal

trading limits were derived from a number

of sources, including the Western States

Coordinating Council (WSCC) 2001 Path

Rating Catalog and various power flow cases

filed with the Federal Energy Regulatory

Commission (FERC) and evaluated using the

Power Technologies Inc. PSS/E power-flow

modeling system.

Transmission costs are reflected

through representation of transmission 

tariffs that can be implemented on a 

POEMS region or Regional Transmission

Organization (RTO) level. RTO definitions are flexible and 

can be changed for each scenario. The model uses pancaked

transmission fees, in which a trade is assessed a fee for each

region that it passes through, or regional postage stamp fees,

where one tariff is established for each RTO that is composed 

of several POEMS regions. (The use of these fee structures is

described in the section below on transmission study scenarios.)

Transmission is treated as cost of service, and any revenue 

collected through wholesale trade is used to offset the transmission costs borne by retail customers. The wholesale transmission fees are set to a percentage (generally in the range of 50

to 80 percent) of the average FERC Order 888 stage one, pro

forma, point-to-point tariff. 

Transmission losses are modeled as a nonlinear, distance

sensitive measure. In addition, a user-specified “hurdle level” is

input to limit transactions to those that provide a specified minimum level of economic gain. The hurdle rate can be adjusted

to reflect reductions in potential inefficiencies and transactions

costs as markets provide greater incentives to exploit profitable

trades. The market simulation is conducted within each of the

time and season load slices that are modeled, and chronological

simultaneity is maintained. 

Pricing

Wholesale generation prices are established for each POEMS

region for each time and season load slice. The market-clearing

price equals the marginal cost or bid price of the most expensive generating unit that is operating. This next marginal unit

could be native to the POEMS region or determined through

trade with other POEMS regions. 

Figure 2: Current TRADELECTM Regions.
83 National Transmission Grid Study

The competitive bid price for each unit is assumed to be

its marginal cost in accord with the standard characterization

of competitive markets. Marginal costs are the sum of fuel

costs and the variable portion of operating and maintenance

(O&M) costs. 

Fixed and Variable O&M Costs

POEMS initially puts all O&M costs into a fixed O&M

account and allows the user to determine how much of the

fixed costs should be considered variable. For this transmission study, one-half of O&M cost is assumed to be included 

in generator bid prices. In addition, historical levels of O&M

costs are expected to decrease over time because of the pressures of competition. POEMS includes a feature that allows 

the user to specify O&M cost targets by plant type along with

a specification of a percentage progress towards that target

by plant type and year. Competitive pressures are also expected to spill over into the regulated segment of the industry.

POEMS allows the user to specify transmission and distribution productivity improvements. Competition is also expected

to result in heat rate improvements, which affect the generation price. POEMS includes a feature that allows the user to

specify target heat rates by plant type along with a specification of a percentage improvement towards that target by plant

type and year. 

Transmission Scenarios

All the POEMS scenarios are projections based on expected

electricity demand, capacity, and fuel prices for the year 2002. 

Current Markets

The Current Markets case is an approximation of the current status of transmission policy. Several regions are represented as RTOs with postage-stamp transmission fees. Under

postage stamp fees, transmission assets within an RTO are

pooled on a fixed-cost basis. Each member of the RTO pays a

single charge for access to the transmission grid; there are no

additional charges for each transaction. A fee is only paid for

transactions that cross RTO borders. The remaining regions

are assumed to have pancaked rates, in which a separate fee

is assessed for movement across each power center. The

transmission fees are established based on 50 percent of calculated FERC pro forma tariffs. In addition, the gain from all

trades must exceed a hurdle rate of $3.00 per MWh, which

represents the transaction costs and barriers associated with

arranging transmission paths and finding trading partners. 

POEMS tracks electricity generation and prices for each 

of the 69-regions both before and after any trade among the

region occurs. The current markets case was used to estimate

the benefits of wholesale electricity trade given the current

physical and institutional operation of the transmission grid

by comparing electricity production costs and prices before

and after trade. It does not distinguish increased trade due to

wholesale competition from economy trades that routinely

occurred among neighboring utilities prior to FERC Orders

888 and 889.

No Congestion For Four ISOs

A No Congestion case was constructed in which the

transmission paths within four major ISOs were increased so

that no economic flows were prevented. The four ISOs are

PJM, New York, New England, and California.

Transmission Fee

In the Transmission Fee case, there are five large RTOs,

and each is assumed to have a postage-stamp rate structure.

The hurdle rate is reduced to $1.50 per MWh to reflect

reduced transaction costs expected from large RTOs. 

This analysis is not a complete estimate of the benefits 

of RTOs, nor does it represent DOE’s position on appropriate

geographic boundaries for RTOs. This analysis only illustrates

the importance of transmission fees in shaping trade and congestion patterns. Eliminating pancaked rates is only one of the

expected benefits of RTOs.
National Transmission Grid Study 84

Calculation of Economic Benefits of Trade

There are several ways to measure the economic benefits of

trade. Two measures have been adopted in this study. The first

is the reduction in net generation costs that results from trade.

Exporters will have an increase in fuel and operating costs

because they are producing more power while importers will

have reduced costs. Assuming competitive markets in which

power plant owners bid their marginal operating costs, trading

will always result in a net reduction in generation costs. Some

regions rely heavily on imports and do not maintain sufficient,

even expensive, capacity to meet their native loads. For these

regions, we assessed a $100-per-MWh generation cost for

unmet demand and used this value to calculate reductions in

generation costs. For example, if a region is unable to meet its

own demand and imports power for $70 per MWh, the generation cost savings is $30 ($100-$70), multiplied by the amount

of the imports.

A second measure of benefit is the impact on consumer

prices. The change in wholesale prices can affect consumer

prices in one of two ways. If the area remains under traditional

cost-of-service regulation, wholesale costs and revenues are

treated as utility expenses that flow through to consumer

rates. We have assumed that 75 percent of the gain, either the

additional margin made by exporters or the reduced net costs

of the importers, is passed through to the consumer. The

other 25 percent would be allowed to go to the shareholders

as an incentive for utilities to maximize the benefits of trade.

For regions that have moved to full retail competition, 

consumer prices will, on average, follow wholesale prices. The

consumer savings from trade are computed as the change in

prices before and after trade, multiplied by total demand. In

general, the impact will be larger than in regulated regions

where only the amount of electricity that is traded is used in 

the computation of benefits. The regions that are considered

to have competitive pricing at the retail level are the same as

those that have RTOs in the Base Case: PJM, New York, New

England, ERCOT, and California.

The change in production costs and consumer costs for

each of the scenarios modeled in POEMS are given in Table 1. 

POEMS underestimates the savings to consumers from

wholesale electricity trade and the costs of congestion for

three reasons. First, POEMS does not capture the effects of

Region

PJM—Pennsylvania, 

New Jersey, Maryland

NEPX—New England

NYPP—New York

ECAR—East Central Area

Reliability Coordination

Agreement

MAIN—Mid-America

Interconnected Network

MAPP—Mid-Continent

Area Power Pool

SPP—Southwest Power

Pool

ERCOT—Electric

Reliability Council of

Texas

FRCC—Florida

SERC—Southeastern

Electric Reliability

Council (excluding

Florida)

WSCC/AZN—Arizona/

New Mexico

WSCC/CNV—California

WSCC/NWP—Northwest

Power Pool

WSCC/RA—Rocky

Mountain Area

Base Case

Transmission

Fee Type

postage stamp

postage stamp

postage stamp

pancaked

pancaked

pancaked

pancaked

postage stamp

pancaked

pancaked

pancaked

postage stamp

pancaked

pancaked

Transmission

Fee Region

Northeast

Northeast

Northeast

Midwest

Midwest

Midwest

Midwest

ERCOT

Southeast

Southeast

West

West

West

West

Table 1
85 National Transmission Grid Study

price spikes. POEMS assumes that prices are determined by the

marginal costs of the last generator needed to meet load in

each subregion. In reality, however, price spikes often occur

when supplies become tight and additional electricity cannot be

imported. Prices might also rise in constrained regions if generators are able to exercise market power. Within competitive

markets, transmission investment to reduce congestion might

sometimes lead to only small changes in generation costs, but

the mere presence of additional transmission capacity creates

contestability in each of the local markets that will curb potential market power and reduce prices to consumers. These benefits are not captured by POEMS.

DOE calculated the increase in congestion costs resulting

from prices spikes for four regions in the U.S.: California ISO,

PJM, New York ISO, and ISO New England. Price spikes are

assumed to occur during the hours when at least one transmission link into the region was congested and demand was

greater than 90 percent of peak demand. Total congestion

costs (cost to consumers) for these four regions combined are

initially estimated to be $157 million annually (without price

spikes). When prices spike an additional $50 per MWh during

these periods, congestion costs nearly double to $300 million.

When prices spike an additional $100 per MWh during these

periods, congestion costs nearly triple to $447 million.

Second, POEMS captures only the benefits of trade between

regions and does not address trade within regions. For example, all of New England is represented as a single region within

the model, so benefits from trade within New England are 

not reflected in the analysis. Accordingly, the model does not

represent transmission constraints within regions and does not

account for these congestion costs in the analysis. California’s

Path 15, which is often congested, is not specifically represented in POEMS.

Finally, POEMS is not designed to analyze reliability benefits. Increased transmission capacity will generally improve 

the overall reliability of the grid and allows regions to share

capacity reserves. Although the risk of blackouts is generally

small, blackouts usually entail very high economic costs. As

such, even a small reductions in the risk of a blackout will 

have substantial benefits.

Current Trade*

No Congestion Within Four

ISOs

Transmission Fee

Generation Cost

(change from

base)

-$3,254

NA

-$375

Consumer Costs

(change from

base)

-$4,248

NA

-$726

Generation Cost

(change from

base)

-$8,944

NA

-$35

Consumer Costs

(change from

base)

-$8,351

NA

-$307

Generation Cost

(change from

base)

$-12,198

-$89

-$410

Consumer Costs

(change from

base)

-$12,599

-$157

-$1,033

Table 2: Annual Economic Costs (Millions)

East West Total

Scenario

*For the current trade case, the change in generation costs and consumer costs represents the decrease in costs that results from the base case level of wholesale electricity trade among the model’s 69 subregions compared to a case in which no wholesale trading is allowed. For the remaining cases, the reported savings are the change from the current trade case.
National Transmission Grid Study 86

American Electric Power*

American Electric Power*

Consumers Energy Group*

Detroit Edison Company*

Ecostar Power

Enron

EPRI

First Energy Corp

International Transmission Company*

Michigan Electric Transmission Company

Michigan Public Service Commission*

National Grid USA*

Northeast Power Coordinating Council

Public Service Electric and Gas

Public Utilities Commission of Ohio*

US Department of Agriculture, Rural Utilities

Service

Xcel Energy Services

* Offered public comment at workshop

Appendix B

List of Participants at DOE National Transmission Grid Study Public Workshops and 

Written Comments Received by DOE

Detroit, MI Public Workshop ● September 24, 2001

Atlanta, GA Public Workshop ● September 26, 2001

2M Design Consultants

ABB

Alabama Public Service Commission*

American Electric Power

Army Environmental Policy Institute

Balch & Binghem

Central Electric Power Cooperative*

Central Maine Power*

Certified Living

City of Griffin

Dalton Utilities

Dynegy

EnerVision

Enron

Florida Public Service Commission

Georgia Public Service Commission

Georgia Transmission Corporation

Kentucky Public Service Commission

Large Public Power Council*

Municipal Electric Power of Georgia*

MidAmerican Energy

Midwest ISO*

Mirant Corporation*

Northeast Power Coordinating Council*

PG&E National Energy Group

PJM Interconnection*

Reliant Resources

RETX*

Rural Electric Service*

Santee Cooper
87 National Transmission Grid Study

South Carolina Public Service Commission*

Southeastern Electric Reliability Council

Southern States Energy Board

Southern Company*

Southwire Corporation

Troutman Sanders

Tennessee Valley Authority

US Department of Agriculture/Rural Utilities

Service

* Offered public comment at workshop

ABB

Arizona Public Service

Arizona Residential Utility Consumer Office

Arizona Corporation Commission*

Arizona Department of Interior

Arizona Governor’s Office*

Arizona House of Representatives

Arizona Municipal Power Users

Arizona State Senate

Bonneville Power Administration

California Independent System Operator

Chelan Public Utility District

City Public Service, San Antonio

Colorado River Energy Distributors

Association*

Delaney Power Consultants

Dow Jones News

Electricity Consumers’ Alliance*

Enron

EPRI*

KR Saline & Associates

Kansas Corporation Commission

Navaho Tribal Utility Authority

Navigant Consulting

Oregon Office of Energy*

PG&E National Energy Group

Pinnacle West Capital Corp

Pinnacle West Energy

Public Service Company of New Mexico

Power Up Corp*

R.W. Beck

Reliant Resources

RTO West

Salt River Project

San Carlos Irrigation Project

State Senate

Southwest Power Pool

Southwest Transmission Cooperative*

Tucson Electric Power

Tri-States Generation and Transmission

Association

US Bureau of Reclamation

Western Area Power Administration*

Valmont Industries

Wellton Mohawk Irrigation & Drainage

District

Western Governor’s Association*

Williams Energy

Wyoming Business Council

* Offered public comment at workshop.

Phoenix, AZ Public Workshop ● September 28, 2001
National Transmission Grid Study 88

ABB

American Electric Power

American Public Power Association

American Superconductor

American Transmission Company

Arizona Public Service Company

Bandag

Carolina Power & Light

City of Griffin Electric Department

Dynegy

EPRI

Elucem

Georgia Public Service Commission

International Transmission Company

Kentucky Public Service Commission

Mid-Area Continent Power Pool

Midwest Independent Support Operations

Municipal Electric Authority of Georgia

National Association of Regulatory Utility

Commissioners

National Electrical Manufacturers

Association

National Grid USA

National Rural Electric Cooperatives

Association

New Jersey Division of the Ratepayer

Advocates

New York Independent System Operator

Northeast Power Coordinating Council

Northern Carolina Utilities Commission

Oregon Office of Energy

Power Up Corporation

Public Service Company of New Mexico

Public Service Enterprises Group

Retail Energy Transaction Exchange 

Rick Cleckler

South Florida Regional Planning Council

Salt River Project

Southern California Edison

Southern Company Services

Southwest Transmission Cooperative

Thrust Power Systems

Xcel Energy

Written Comments Received by DOE
89 National Transmission Grid Study

Appendix C: Glossary

This glossary provides definitions of terms used throughout the report and some

others that are related to the field but not expressly mentioned.

Adequacy—Ability of the electric system to supply the aggregate electrical demand and energy requirements of customers at all

times, taking into account scheduled and reasonably expected unscheduled outages of system elements. 

Ancillary Services—Interconnected Operations Services identified by the U.S. Federal Energy Regulatory Commission (Order No. 888

issued April 24, 1996) as necessary to effect a transfer of electricity between purchasing and selling entities and which a transmission

provider must include in an open-access transmission tariff. See also Interconnected Operations Services. 

Apparent Power—Product of the volts and amperes. It comprises both real and reactive power, usually expressed in kilovolt-amperes

(kVA) or megavolt-amperes (MVA). 

Automatic Generation Control (AGC)—Equipment that automatically adjusts a control area’s generation to maintain its interchange

schedule plus its share of frequency regulation. 

Availability—Measure of time that a generating unit, transmission line, or other facility is capable of providing service, whether or not

it actually is in service. Typically, this measure is expressed as a percent available for the period under consideration. 

Bulk Power System—The portion of an electric power system that encompasses the generation resources, system control, and highvoltage transmission system. 

Capability—see Installed Capability and Operable Capability.

Capacity—The rated continuous load-carrying ability, expressed in megawatts (MW), megavolt-amperes (MVA), or megavolt-amperesreactive (MVAR) of generation, transmission, or other electrical equipment. 

Cascading—Uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread

service interruption, which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies. 

Clearing Price—see Energy Clearing Price.

Contingency—Unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch, or

other electrical element. A contingency also may include multiple components, which are related by situations leading to simultaneous

component outages. 

Contract Path—Specific contiguous electrical path from a point of receipt to a point of delivery for which transfer rights have been

contracted. 

Control Area—Electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to

maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnection. 

Current Limiter—Device that, when added to an electric system, is designed to limit damaging levels of current in the system. In the

Consolidated Edison distribution system, current limiters (in the form of fusible links) are used to protect low-voltage conductors in

the underground distribution system.

Curtailment—Reduction in the scheduled capacity or energy delivery. 

Demand Elasticity—Measure of how the quantity of a good (e.g., electricity) demanded responds to a change in its price.

Demand-Side Management—Programs that affect customer use of electricity, both the timing (sometimes referred to as load management) and the amount (sometimes referred to as energy efficiency).
National Transmission Grid Study 90

Dispatch—Operating control of an integrated electric system involving operations such as assignment of levels of output to specific

generating stations and other sources of supply; control of transmission lines, substations, and equipment; operation of principal

interties and switching; and scheduling of energy transactions.

Distribution Network—A network of electrical lines from a substation (which is the terminus of the transmission network) to a series

of transformers (and eventually to the ultimate customer).

Distribution System—Portion of an electric system that “transports” electricity from the bulk-power system to retail customers, consisting primarily of low-voltage lines and transformers. 

Disturbance—Unplanned event that produces an abnormal system condition. 

Electrical Energy—The generation or use of electric power by a device over a period of time, expressed in kilowatt-hour (kWh),

megawatt-hour (MWh), or gigawatt-hour (GWh). 

Electric System or Electric Power System—An interconnected combination of generation, transmission, and distribution components that make up an electric utility, an electric utility and one or more independent power producers (IPPs), or group of utilities and

one or more IPPs.

Electric Utility—Corporation, person, agency, authority, or other legal entity or instrumentality that owns or operates facilities for the

generation, transmission, distribution, or sale of electric energy primarily for use by the public and is defined as a utility under the

statutes and rules by which it is regulated. An electric utility can be investor-owned, cooperatively owned, or government-owned

(owned by a federal agency, crown corporation, state, provincial government, municipal government, and public power district). 

Emergency—Any abnormal system condition that requires automatic or immediate manual action to prevent or limit loss of transmission facilities or generation supply that could adversely affect the reliability of the electric system. 

Energy Clearing Price—The price at which the market is able to match the last unit of energy a specific seller is willing to sell with

the last unit of energy a specific purchaser is willing to buy.

Federal Energy Regulatory Commission (FERC)—Independent federal agency within the U.S. Department of Energy that, among

other responsibilities, regulates the transmission and wholesale sales of electricity in interstate commerce. 

Firm Power or Purchase—Power or power-producing capacity intended to be available at all times during the period covered by a

guaranteed commitment to deliver, even under adverse conditions.

Forced Outage—Removal from service availability of a generating unit, transmission line, or other facility for emergency reasons or a

condition in which the equipment is unavailable because of unanticipated failure.

Frequency—Rate, in cycles per second (or Hertz, Hz), at which voltage and current oscillate in electric power systems. The reference

frequency in North American Interconnections is 60 Hz. 

Generating Reserve—see Reserve.

Generating Unit—An electric generator together with its prime mover (e.g., steam from boiler).

Grid—System of interconnected power lines and generators that is managed so that the generators are dispatched as needed to meet

the requirements of the customers connected to the grid at various points. Gridco is sometimes used to identify an independent company responsible for the operation of the grid. 

Independent System Operator (ISO)—A neutral operator responsible for maintaining the generation-load balance of the system in

real time. The ISO performs its function by monitoring and controlling the transmission system and some generating units to ensure

that generation matches loads. 

Installed Capability—Seasonal (i.e., winter and summer) maximum load-carrying ability of a generating unit, excluding capacity

required for station use.
91 National Transmission Grid Study

Interconnected Operations Services (IOS)—Services that transmission providers may offer voluntarily to a transmission customer

under Federal Energy Regulatory Commission Order No. 888 in addition to ancillary services.

Interconnection—When capitalized, any one of the major electric system networks in North America. When not capitalized, the facilities that connect two systems or control areas. In addition, an interconnection refers to the facilities that connect a nonutility generator to a control area or system. 

Interface—Specific set of transmission elements between two areas or between two areas that make up one or more electric systems. 

Interruptible Rate—Electricity rate that, in accordance with contractual arrangements, allows interruption of consumer load by direct

control of the utility system operator or by action of the consumer at the direct request of the system operator. It usually involves

commercial and industrial consumers. In some instances, the load reduction may be affected by direct action of the system operator

(remote tripping) after notice to the consumer in accordance with contractual provisions.

Load—A consumer of electric energy; also the amount of power (sometimes called demand) consumed by a utility system, individual

customer, or electrical device. 

Load Pocket—Geographical area in which electricity demand sometimes exceeds local generation capability and in which there is an

electricity import limitation as a result of transmission constraints.

Load Shedding—The process of deliberately removing (either manually or automatically) preselected customer demand from a power

system in response to an abnormal condition in order to maintain the integrity of the system and minimize overall customer outages. 

Market Clearing Price of Electricity—see Energy Clearing Price.

Marketers—Commercial entities that buy and sell electricity. 

Must-Run Resources—Generation designated to operate at a specific level and not available for dispatch.

Network Distribution—Method of distributing electric power to a densely populated area, where a network or grid of low-voltage

conductors covers an area of several city blocks to a few square miles. The grid is solidly connected and is fed from multiple distribution feeders.

Nonfirm Power or Purchase—Power or power-producing capacity supplied or available under a commitment having limited or no

assured availability.

Nonspinning Reserve—Generation capacity that is not being utilized but that can be activated and used to provide assistance with little notification.

North American Electric Reliability Council (NERC)—A not-for-profit company formed by the electric utility industry in 1968 to promote the reliability of the electricity supply in North America. NERC consists of 10 Regional Reliability Councils and one Affiliate

whose members account for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California Norte,

Mexico. The members of these Councils are from all segments of the electricity supply industry—investor-owned, federal, rural electric

cooperative, state/municipal, and provincial utilities, independent power producers, and power marketers. The 10 NERC Regional

Reliability Councils are East Central Area Reliability Coordination Agreement (ECAR), Electric Reliability Council of Texas (ERCOT),

Florida Reliability Coordinating Council (FRCC), Mid-Atlantic Area Council (MAAC), Mid-America Interconnected Network (MAIN), MidContinent Area Power Pool (MAPP), Northeast Power Coordinating Council (NPCC), Southeastern Electric Reliability Council (SERC),

Southwest Power Pool (SPP), and Western Systems Coordinating Council (WSCC). The Affiliate is the Alaskan Systems Coordination

Council (ASCC). 

Open-Access Same-Time Information System (OASIS)—An electronic posting system for transmission access data that allows all

transmission customers to view the data simultaneously. 

Operable Capability—The portion of installed capability of a generating unit that is in operation or available to operate in the hour.

Operating Reserve—That capability above firm system demand required to provide for regulation, load forecasting error, equipment

forced and scheduled outages, and local area protection. It includes both spinning and nonspinning reserve.
National Transmission Grid Study 92

Peak Demand or Load—The greatest demand that occurs during a specified period of time.

Power Pool—Entity established to coordinate short-term operations to maintain system stability and achieve least-cost dispatch. The

dispatch provides backup supplies, short-term excess sales, reactive power support, and spinning reserve. Historically, some of these

services were provided on an unpriced basis as part of the power pool members’ utility franchise obligations. Coordinating short-term

operations includes the aggregation and firming of power from various generators, arranging exchanges between generators, and

establishing (or enforcing) the rules of conduct for wholesale transactions. The pool may own, manage, and/or operate the transmission lines (i.e., wires) or be an independent entity that manages the transactions between entities. Often, the power pool is not meant

to provide transmission access and pricing or to provide settlement mechanisms if differences between contracted volumes among

buyers and sellers exist. 

Reactive Power—Portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment.

Reactive power must be supplied to most types of magnetic equipment, such as motors and transformers. It also must supply the

reactive losses on transmission facilities. Reactive power is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors and directly influences electric system voltage. It is usually expressed in kilovars (kVAR) or megavars (MVAR). 

Real Power—Rate of producing, transferring, or using electrical energy, usually expressed in kilowatts (kW) or megawatts (MW). 

Reliability—Degree of performance of the elements of the bulk power system that results in electricity being delivered to customers

within accepted standards and in the amount desired. Reliability may be measured by the frequency, duration, and magnitude of

adverse effects on the electric supply. Electric system reliability can be addressed by considering two basic and functional aspects of

the electric system—adequacy and security. 

Reserve—Electric power generating capacity in excess of the system load projected for a given time period. It consists of two sources:

spinning reserve and supplemental reserve.

Retail Sales—With regard to the electric industry, electrical energy supplied for residential, commercial, and industrial end-use 

purposes. Other small end-use classes, such as agriculture and street lighting, also are included.

Schedule—Agreed-upon transaction size (megawatts), start and end time, beginning and ending ramp times and rate, and type

required for delivery and receipt of power and energy between the contracting parties and the control area(s) involved in the transaction. 

Security—Ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of system elements. 

Security Coordinator—One of 23 entities established by NERC with the responsibility and authority to direct actions aimed at maintaining real-time security for a control area, group of control areas, NERC subregion, or NERC region. 

Short-Notice or Short-Term Transaction—Transaction for the transfer of net energy from one region to another, made with little

time between the transaction and the transfer (typically, less than one hour).

Spinning Reserve—Ancillary service that provides additional capacity from electricity generators that are on line, loaded to less than

their maximum output, and available to serve customer demand immediately should a contingency occur. 

Stability—Ability of an electric system to maintain a state of equilibrium during normal and abnormal system conditions or disturbances. 

Supplemental Reserve—Ancillary service that provides additional capacity from electricity generators that can be used to respond to

a contingency within a short period, usually 10 minutes. 

System—see Electric System.

System Operator—Individual at an electric system control center whose responsibility it is to monitor and control that electric system

in real time. 
93 National Transmission Grid Study

Tariff—Schedule detailing the terms, conditions, and rate information applicable to various types of electric service.

Topology—Structure and layout of a system.

Transmission—Interconnected group of lines and associated equipment for the movement or transfer of electric energy between

points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems. 

Unit—see Generating Unit.

Unit Commitment—Process of determining which generators should be operated each day to meet the daily demand of the system. 

Utility—see Electric Utility.

Volt-Ampere-Reactive (VAR)—Unit of measure of the power that maintains the constantly varying electric and magnetic fields associated with alternating-current circuits. See Reactive Power. 

Voltage—The unit of measure of electric potential. 

Voltage Collapse—An event that occurs when an electric system does not have adequate reactive support to maintain voltage stability. Voltage collapse may result in outage of system elements and may include interruption in service to customers. 

Wholesale Electricity Market—Purchase and sale of power, according to agreements with varying lengths and lead times, among

power marketers, power producers, and other wholesale entities.