00-2

Planning 

Report

Changing Measurement and

Standards Needs in a Deregulated

Electric Utility Industry

Prepared by:

Research Triangle Institute

for

National Institute of

Standards & Technology

Program Office

Strategic Planning and

Economic Analysis Group

May 2000

U.S Department of Commerce

Technology Administration
Changing Measurement and

Standards Needs in a Deregulated

Electric Utility Industry

 May 2000

Prepared for

Gregory Tassey, Ph.D.

National Institute of Standards and Technology

Acquisition and Assistance Division

Building 101, Room A1000

Gaithersburg, MD 20899-0001

Prepared by

Michael P. Gallaher, Ph.D.

Stephen A. Johnston, Ph.D.

Research Triangle Institute

Center for Economics Research

Research Triangle Park, NC 27709

Brendan Kirby

Oak Ridge National Laboratory

P.O. Box 2008

Oak Ridge, TN 37831
ii

Contents

Executive Summary ES-1

1. Introduction 1-1

1.1 Overview of Deregulation................................................. 1-2

1.1.1 Potential Benefits of Deregulation.......................... 1-4

1.1.2 Potential Costs Associated With Deregulation........ 1-6

1.2 The Role of Standards ....................................................... 1-8

1.2.1 The Justification for Measurement and

Technology Standards in Industry .......................... 1-8

1.2.2 Measurement and Standards as

Infratechnologies ................................................... 1-9

1.3 Study Overview .............................................................. 1-11

1.4 Report Structure .............................................................. 1-13

2. Conceptual Model of Deregulation and the

Impact of Measurement and Standards 2-1

2.1 Economic Efficiency Viewed as an Optimization

Problem............................................................................ 2-1

2.2 Trade-Off Between Cost and Quality................................. 2-4

2.3 Economic Efficiency and Product Differentiation ............... 2-8

2.4 Technical and Market Information Needs to Support a

Deregulated Industry......................................................... 2-8

3. Future Implications of Deregulation for the

Electric Power Industry 3-1

3.1 Deregulation Trends and the Changing Characteristics

of the Electric Power Industry............................................ 3-1
iii

3.1.1 Separation of Resources and System

Operations ............................................................ 3-3

3.2 Enabling Technologies ...................................................... 3-4

3.2.1 Enabling Technology Advances ............................. 3-4

3.2.2 Infratechnologies Where Additional Research

is Needed.............................................................. 3-5

3.2.3 Infratechnologies that Will Enable New

Products and Services............................................ 3-6

3.3 Key Issues Related to Restructuring the Electric Power

Industry............................................................................. 3-7

3.3.1 Increased Transmission Demand............................ 3-8

3.3.2 Service Quantification ......................................... 3-10

3.3.3 Reliability Criteria................................................ 3-10

3.3.4 Real-Time Electricity Pricing................................ 3-11

3.3.5 Unbundling of Ancillary Services......................... 3-12

3.3.6 Reduced Generator and Transaction Sizes ........... 3-15

3.3.7 Power Quality ..................................................... 3-16

3.3.8 Supplier Choice................................................... 3-17

3.4 Conclusions .................................................................... 3-17

4. Measurement and Standards Needs to Support

Restructuring 4-1

4.1 Measurement Needs ......................................................... 4-1

4.1.1 Physical Measurement Requirements ..................... 4-2

4.1.2 Underlying Trends Changing Measurement

Requirements ........................................................ 4-5

4.1.3 Customer Differentiation........................................ 4-8

4.1.4 Communications ................................................... 4-9

4.1.5 Transmission ....................................................... 4-11

4.2 Areas Where Standards May Have Major Beneficial

Impacts In a Deregulated Utility Industry......................... 4-12

4.2.1 Opportunities for Standards to Support System

Operations Needs................................................ 4-13

4.2.2 Opportunities for Standards to Support Market

Transactions Needs ............................................. 4-15

4.2.3 Summary............................................................. 4-17
iv

5. Economic Impact of Measurement and

Standards 5-1

5.1 Pathways to Economic Impacts ......................................... 5-2

5.2 Economic Impact Areas..................................................... 5-3

5.2.1 System Operations................................................. 5-5

5.2.2 Market Operations............................................... 5-11

5.3 Economic Impact Estimates ............................................. 5-14

5.3.1 Impact Cost Metrics............................................. 5-17

5.3.2 Economic Impact Estimates.................................. 5-18

References R-1

Appendix

A Existing Activities and Emerging Participants in the

Electric Power Supply Chain .............................................A-1

B Deregulation Background and Trends................................ B-1

C Discussion Guide..............................................................C-1

D Interview Responses..........................................................D-1

E Calculation of Event Cost Metrics .......................................E-1
v

Figures

Figure 1-1 Typical Fluctuations in the Spot Price of Electricity..................... 1-6

Figure 2-1 Regulated Model ....................................................................... 2-2

Figure 2-2 Competitive Model .................................................................... 2-3

Figure 2-3 Trade-off between the Electric Power Price and Power

Reliability .................................................................................. 2-5

Figure 2-4 Consumer Indifference Map between Electric Power Price

and Reliability ........................................................................... 2-6

Figure 2-5 Shift in the Efficiency Frontier due to Deregulation..................... 2-7

Figure 2-6 The Role of Measurement and Standards.................................... 2-7

Figure 2-7 Product Offerings under Regulation and Deregulation................ 2-9

Figure 2-8 Information Needs for System and Market Operations.............. 2-10

Figure 3-1 Well-Behaved Generator Providing Regulation ........................ 3-14

Figure 3-2 Poorly Behaving Generator Providing Regulation ..................... 3-14

Figure 3-3 Ancillary Service Time Frames ................................................. 3-15

Figure 3-4 Average Ancillary Service Prices for December 1998

Weekdays in California............................................................ 3-15

Figure 4-1 Individual Loads Impose Different Regulation Burdens on

the Power System ...................................................................... 4-8

Figure 4-2 Individual Generators Impose Different Reliability Burdens

on the Power System ............................................................... 4-10

Figure 5-1 Potential Performance Gap Associated with Inadequate

Measurement and Standards .................................................... 5-16
vi

Tables

Table 1-1 Cost Components of Supplying Electricity .................................. 1-5

Table 1-2 Companies/Affiliations of Respondents..................................... 1-12

Table 3-1 12 Ancillary Services and their Definitions............................... 3-13

Table 4-1 Measurement Requirements Under Deregulation ....................... 4-3

Table 5-1 Benefits Associated with Measurement and Standards ................ 5-2

Table 5-2 Impact Areas Associated with Deregulation................................ 5-4

Table 5-3 Impact Areas Affected by Measurement and Standards ............. 5-19

Table 5-4 Economic Impact of Measurement and Standards..................... 5-21
ES-1

Executive Summary

The primary objective of this study is two-fold:

Z to identify areas in which measurement and standards will

be needed to capture the full benefits of wholesale and

retail deregulation of the electric power industry in the U.S.,

and

Z to identify, on a preliminary basis, the economic impacts of

not meeting those needs.

Preliminary findings were presented at NIST’s workshop on

“Challenges for Measurement and Standards in a Deregulated

Electric Power Industry” held December 6-8, 1999.

Measurement and standards can provide infrastructure

enhancements that will help facilitate deregulation, secure its

benefits, and avoid its potential pitfalls. The need for measurement

and standards in this new environment is primarily related to

Z the increased growth in the number and complexity of

transactions,

Z the increased number of market players and their

information needs, and

Z a shift from reliance on voluntary agreements among

formerly integrated utilities to explicit contracts among

many providers of different services.

We estimate that the economic impact of prospective opportunities

that may be lost by not meeting these needs ranges from $3.1 to

$6.5 billion. These estimates are more illustrative than precise

because the U.S. is in an early phase of electric industry

deregulation, and they are based on a limited number of survey

responses from a sample of electric industry experts.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

ES-2

E.1 THE ROLE OF MEASUREMENT AND

STANDARDS

Measurement and standards are technical tools that include

scientific and engineering data, measurement and test methods, and

industrial practices and techniques. They are called

“infratechnologies” because they support core technologies by

Z improving the efficiency of R&D;

Z improving production processes and product and service

characteristics; and

Z reducing market transactions costs and providing the

marketplace with reliable information on quality and other

attributes of a product, service, or process.

Measurement and standards are essential in the electric power

industry in expanding electricity use, reducing costs, maintaining or

improving system reliability, and generally enhancing the technical

and economic performance of the industry. Key areas in which

their value is increasing are

Z competitive metering of energy generation—including

distributed generation—and ancillary services at the

supplier and customer levels;

Z monitoring bulk power flows and transactions;

Z monitoring transmission and distribution system conditions;

Z communicating and controlling generation, transmission,

and distribution systems;

Z monitoring power quality along these systems and in

customer facilities; and

Z assessing system conditions and contract compliance

through the use of advanced diagnostic tools.

E.2 DEREGULATION TRENDS AND CHANGING

CHARACTERISTICS OF THE ELECTRIC

POWER INDUSTRY

Deregulation of wholesale electric markets has been moving

forward since the issuance of FERC Orders 888 and 889 in 1996

and now with the recently released FERC Order 2000.

Deregulation of retail electric markets has been moving more

slowly: approximately one-half of the states in the U.S. have now

begun to implement, or have decided to implement, retail

competition.
Executive Summary

ES-3

Deregulation in both markets is leading to several key changes in

industry structure and operation:

Z Generation, transmission, and distribution are becoming

functionally unbundled.

Z The generation segment of the investor-owned utility (IOU)

portion of the industry is becoming competitive, whereas

transmission and distribution regulation of IOUs continues

(by FERC in the first instance, and state utility commissions

in the second).

Z Transmission is now designated as a common carrier, and

transmission system operators are required to provide open

access, nondiscriminatory service to market players.

Z Ownership and control of transmission is becoming

separated in cases where groups of utilities are adopting the

nonprofit independent system operator (ISO) model,

whereas the two are remaining together in cases where

groups of utilities are adopting the for-profit transmission

company (TRANSCO) model.

Z Many types of services—generation supply and services, AS

to supplement basic transmission service, and customer

services such as energy conservation and management,

metering, and billing—are becoming “unbundled” with the

result that they are being separately priced and open to

competitive supply.

Advances in core and enabling technologies have taken place that

are coincident with these changes and, in many cases, have served

to drive or facilitate them. An example of a core technology

advance is improvements in the cost and technical (heat rate)

performance of gas turbines and combined-cycle units.

An example of an enabling technology advance is electronic data

interchange (EDI) technologies and standards that provide a

potential building block to support retail competition, although

consistency between regional EDI systems is an ongoing concern.

However, for some technologies additional research is needed. An

example is dynamic state monitoring systems that have the

potential to increase transmission system capacity and support

power system reliability, but these systems are still in development.

Some of these technology advances will enable the creation and

spread of new products and services. For example, more accurate

and widespread metering will allow loads to be more priceresponsive, enabling services that seek to manage or otherwise

affect customer usage patterns. From the suppliers’ perspective,
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

ES-4

this tool is valuable to manage generation and transmission growth.

Whereas a limited number of voluntary curtailment programs

currently exist, it is estimated that up to a 2 percent reduction in

peak demand could be obtained through widespread use of load

control programs.

E.3 MEASUREMENT AND STANDARDS NEEDS TO

SUPPORT DEREGULATION

Measurements and standards in the new environment will be of

greatest value in supporting system operations, with its traditional

concerns of system reliability and security, and market operations,

particularly the exchange of information among many market

players with different equipment.

The following examples indicate where new and enhanced

measurements and standards can contribute to system operations:

Z standardization of information availability requirements to

support competition; currently, some purchasers have a

competitive advantage because of asymmetric information;

Z expanded and more frequent measurement and

communication of system conditions to system operators;

Z measurement and communication of transmission system

dynamic performance to system operators;

Z more frequent measurement and communication of

distributed generators’ output (aggregated) to system

operators;

Z dynamic control of distributed generation to maintain

system reliability and to access potential ancillary service

benefits;

Z measurement and communication to system operators of

ancillary services provided by generators (utility and

merchant plants) and customers (through onsite generation

or load curtailment); and

Z security requirements to maintain system integrity as the

market opens up and the number of players increases.

Measurement and standards will also be needed to support market

transactions by helping ensure interoperability among equipment

and systems provided by different vendors, by providing reliable

and precise information for contracts and dispute resolution, and by

developing pricing systems that reflect proper incentives. The
Executive Summary

ES-5

following examples indicate where new and enhanced

measurements and standards can contribute to market operations:

Z creation of a seamless electronic data interchange (EDI)

between metering and communication software and

equipment, so that retail market players can obtain the

various data they need when they need it;

Z tracking of generator supply and power marketer/broker

curtailments to determine whether and when they supplied

generation/load relief or ancillary services to the system as

required by contracts;

Z tracking/tagging of power flows to assign cost responsibility

for congestion on overloaded lines and constrained

interfaces;

Z more precise measurement of standard billing parameters

(e.g., energy, demand, power factor) to support contracts;

and

Z more precise measurement of power quality, especially

harmonics, flicker, sags, and surges to support contracts.

E.4 ECONOMIC IMPACTS

We conducted a survey of a sample of industry experts to

Z identify key issues;

Z identify key impact areas; and

Z provide qualitative guidance on, and help develop

quantitative estimates of, the economic impacts of not

having adequate measurement and standards in place in a

fully deregulated environment.

Preliminary results were presented at the NIST workshop in

December 1999. We used feedback from conference participants

with additional information to refine the qualitative guidance and

the quantitative results.

Qualitative guidance provided by survey respondents includes the

following:

Z Within the system operations area, outages are a major

concern, and enhanced measurement and standards can

have a major impact in this area.

Z Within the market operations area, the cost of market

transactions is a major concern, and enhanced

measurements and standards can have a major impact in

this area.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

ES-6

We developed quantitative results for each of several important

impact areas. To develop these results, we conducted a “gap

analysis” (i.e., we estimated the performance gap between the

potential benefits under full deregulation and the constrained

benefits, that is, benefits in the absence of adequate measurements

and standards), relative to a base year cost metric. We used the

survey responses to develop each performance gap as a percentage

of its base year cost metric. Because of the variability in these

estimates, and the fact they are prospective rather than

retrospective, they are presented as ranges rather than as point

estimates.

The aggregate annual economic impacts range from $3.1 to $6.5

billion. This is a prospective annual estimate of not having

adequate measurement and standards in place to capture the full

benefits of electric deregulation.

Within this estimate, the impact of measurement and standards on

system reliability is the largest impact category, representing

35 percent of the upper-bound estimate. Power quality issues for

end users, average generation costs, and ancillary service costs

each account for approximately 20 percent of the upper-bound

estimate.

In summary, these estimates should be considered illustrative “first

cut” estimates of prospective economic impacts. They are based on

a survey of a limited number of electric industry experts early in the

industry deregulation process. Although the results are not highly

precise, the pattern of results within the system and market

operations areas are plausible and provide early guidance to

measurement and standards initiatives and investments.
1-1

1 Introduction

Deregulation of the electric power industry offers the potential of

improving the economic efficiency of the production and use of

electricity. However, achieving these gains in economic efficiency

will require developing an infrastructure that can address the

unique informational needs of an industry that is less centrally

coordinated than before and more subject to the discipline of

markets. This infrastructure includes new and improved

measurement technologies and standards for tracking economic

transactions in electricity markets and monitoring the performance

of the system for generating, transmitting, and distributing electric

power.

The industry includes a list of market players that are growing with

deregulation. An overview of the electric industry supply chain is

presented in Appendix A.

The National Institute of Standards and Technology’s (NIST’s)

mission is, in part, to provide these types of measurement and

standards technologies. Specifically, the Electricity Division of

NIST’s Electronic and Electrical Engineering Laboratory (EEEL) seeks

to “...provide the world’s most technically advanced and

fundamentally sound basis for all electrical measurements in the

United States by realizing the International System (SI) of electrical

units; developing improved measurement methods and calibration

services; and supporting the measurements and standards of

infrastructure needed by the U.S. industry to develop new products,

ensure quality, and compete economically in the world market”

(NIST, 1999).

This study examines

the broad set of

measurement and

standards needs of a

deregulated electric

power industry to

help inform NIST’s

decisions regarding

its role in meeting

these infrastructure

requirements.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-2

This study examines the broad set of measurement and standards

needs of a deregulated electric power industry to help inform

NIST’s decisions regarding its role in meeting these infrastructure

requirements. It also identifies the types of expected improvements

in the economic efficiency in the production and use of electricity

with a deregulated system facilitated by this infrastructure. The

expedient provision of the required infrastructure is a prerequisite

for obtaining the economic efficiency improvements in a timely

manner. In the context of this study, deregulation refers to the

ongoing process of restructuring (or reregulation) of the wholesale

and retail electric power markets. In addition, where appropriate,

this study investigates evolving issues and needs not directly related

to deregulation, such as the ongoing trend of generation outpacing

transmission capacity growth and introduction of commercially

competitive distributed generation, where they impinge on the

infrastructure requirements of the industry.

The study does not provide a prediction of the expected course of

deregulation or the future structure of the electric power industry.

This topic has received significant attention in professional

literature and congressional and regulatory testimonies, and the

specific course of deregulation is still highly uncertain. We find,

however, that most of the measurement and standards needs to

support deregulation are generally independent of the eventual

industry structure. Key issues and concerns, such as commodity

measurement, transmission constraints, real-time communications

needs, and information sharing requirements, are common to a

wide range of potential deregulation outcomes.

1.1 OVERVIEW OF DEREGULATION

Beginning in the latter part of the 19th century and continuing for

about 100 years, the prevailing view of policymakers and the

public was that the government should use its power to require or

prescribe the economic behavior of industry, especially those

industries characterized as the “natural monopolies” such as

electric utilities. The traditional argument is that for such industries

it does not make economic sense for there to be more than one

supplier—running two sets of wires from generating facilities to end

users is more costly than one set. The predominant form of

industry organization for electricity was (and largely still is)

The study does not

provide a prediction

of the expected

course of

deregulation or the

future structure of

the electric power

industry.
Section 1 — Introduction

1-3

characterized by vertical integration and franchise service areas.

Single companies serving a specific geographic area delineated by

government generated, transmitted, and distributed the power,

largely in isolation from the rest of the industry. However, since

monopoly supply is not generally regarded as likely to provide a

socially optimal allocation of resources, regulation of rates and

other economic variables was seen as a necessary feature of the

system.

The unwinding of economic regulation in the U.S. began in earnest

at the federal level in the 1970s. For a number of reasons, the

public policy view shifted against traditional regulatory approaches

and in favor of deregulation for many important industries including

transportation, communications, finance, and energy. The major

drivers for deregulation of electric power included the following:

Z existence of rate differentials across regions offering the

promise of benefits from more efficient use of existing

generation resources if the power can be transmitted across

larger geographic areas than was typical in the era of

industry regulation;

Z promise of new, low-cost technologies for electricity

production;

Z complexity of providing a regulated industry with the

incentives to make socially efficient investment choices;

Z difficulty of providing a responsive regulatory process that

can quickly adjust rates and conditions of service in

response to changing technological and market conditions;

and

Z complexity of monitoring utilities’ cost of service and

establishing cost-based rates for various customer classes

that promote economic efficiency while at the same time

addressing equity concerns of regulatory commissions.

The 1978 Public Utility Regulatory Policy Act (PURPA) required

that utilities purchase power from independent suppliers, opening

up production to a potentially large number of such suppliers. The

Energy Policy Act of 1992 (EPAct) further opened the door to

competition among electricity generators by giving the Federal

Energy Regulatory Commission (FERC) the right to require any

utility to transship or “wheel” power supplied by another generator

over their lines to a third supplier. Pursuant to EPAct, FERC in 1996

implemented Orders 888 “Final Rule on Open Access

Nondiscriminatory Transmission” and 889 “Open Access SameThe unwinding of

economic regulation

in the U.S. began in

earnest at the

federal level in the

1970s.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-4

Time Information System (OASIS)” to increase access to

transmission systems and to operating information on these

systems. Various forms of independent system operators (ISOs),

regional transmission organizations (RTOs), functional unbundling,

and organizational structures are being considered (and

implemented) to enhance compliance with these Orders. The

North American Electric Reliability Council (NERC) is considering

changes in its structure, powers, and standards to help ensure

reliability of the bulk power electric system in the aftermath of

these Orders.

A few states have extended deregulation to the retail level.

Customer choice of generation suppliers is now permitted in

California, Massachusetts, Pennsylvania, and Rhode Island. Over a

dozen other states have committed to retail competition in the

future, and most other states are studying the possibility. While the

specific form of the electric power industry is still evolving and the

timetable for allowing retail competition will vary from state to

state, it is clear that the future will be characterized by greater

opportunities for consumers to select a supplier and for suppliers to

make the technological and marketing choices without

governmental oversight. A review of the status of retail

deregulation is included in Appendix B.

The potential benefits of a competitive market for electricity are

large. However, securing these benefits will not be costless.

Significant investments in information infrastructures will be

necessary.

1.1.1 Potential Benefits of Deregulation

The primary promise of deregulation of electric power is that it will

promote greater economic efficiency in electricity generation,

transmission, distribution, and use than will occur under a

regulated environment. The main sources of economic efficiency

gains commonly cited by proponents of deregulation include the

potential deregulation offers to

Z lower (total) generation costs by facilitating the interregional

shipment of power (i.e., from low to high cost regions);

Z stimulate investment in new low-cost generation and

transmission resources through the removal of barriers to

entry in generation and transmission; and

Customer choice of

generation suppliers

is now permitted in

California,

Massachusetts,

Pennsylvania, and

Rhode Island.
Section 1 — Introduction

1-5

Z promote improved use of electricity by allowing rates that

more closely track the “true” cost of service and by the

development of more product differentiation, for example,

establishing markets for different levels of power reliability.

The potential benefits associated with deregulation are large

because the system is large and the economic inefficiencies are,

arguably, significant. The electric power industry represents

approximately 0.25 percent of the U.S.’s gross domestic product

(GDP). In 1998, the U.S. electric power industry had retail sales of

$217.4 billion. Thus, even small changes in economic efficiency

can lead to large economic impacts.

As shown in Table 1-1, generation accounts for approximately

75.6 percent of the retail cost of supplying electricity. Some industry

experts estimate that the average cost of generation could be reduced

by 5 percent (approximately $5 billion annually) through the more

efficient use of existing generation assets and the adoption of new

low-cost generation assets.

Cost Component Share of Cost

Generation 75.6%

Transmission 2.5%

Distribution 5.6%

Market Transactionsa 16.3%

aMarket transactions include customer accounts expenses, customer service and

information expenses, sales expenses, and administration and general expenses.

Source: Energy Information Administration (EIA). 1997. Financial Statistics of

Major Investor Owned Utilities, 1996. Washington, DC: U.S. Department of

Energy.

Managing demand on the customer’s side of the meter by

leveraging demand price elasticity is also a potential source of

benefits associated with deregulation. As shown in Figure 1-1, the

spot price for electricity varies greatly depending on the day of the

week and time of day.

Traditionally, system capacity has been designed to meet peak

demand. And under asset-based compensation, regulated utilities

have had little incentive to engage in activities to “clip” peak

Table 1-1. Cost

Components of Supplying

Electricity

Generation accounts for over

75 percent of the cost of

supplying electricity.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-6

Figure 1-1. Typical Fluctuations in the Spot Price of Electricity

The spot price of electricity varies greatly depending on the day of the week and time of day.

0

20

40

60

80

100

120

140

160

1 25 49 73 97 121 145

Monday–Sunday, Week of July 14, 1997 (hours)

PJM Spot Price ($/MWh)

demand.1 In addition, prices did not reflect the true cost of

supplying energy during peak periods. Since customers did not see

prices that reflected the high cost of consuming during times of

peak demand they too had little incentive to “clip” peak demand.

Deregulation and real-time pricing have the potential to motivate

both suppliers and demanders to initiate programs (such as

curtailable load programs) to lower peak demand.

1.1.2 Potential Costs Associated With Deregulation

As opponents of deregulation point out, the benefits of deregulation

are not free. Potential costs associated with deregulation of electric

power include the following:

 

1Demand-side management (DSM) programs were initiated in the 1980s and

1990s. These programs were mandated by regulators and primarily focused on

energy-efficient equipment. However, motivating electric utilities to pay their

customers to purchase less of their product introduced its own inefficiencies.
Section 1 — Introduction

1-7

Z increased transaction costs to support market transactions,

Z increased bulk transmission requirements,

Z increased monitoring costs to support system reliability and

power quality, and

Z potential decreased in overall system reliability and power

quality.

Transaction costs include contracting, metering, communication,

and processing of information; billing; and dispute resolution. As

shown in Table 1-1, these costs currently account for approximately

11 percent of the cost of supplying electricity. Most industry

experts believe that the increased information needs associated

with deregulation will increase total transactions costs.

Most industry experts also believe that deregulation will lead to

increased bulk transmission requirements. Over the past 10 years,

electricity sales have increased by 25 percent (in kWh) while bulk

transmission capacity has increased by only 5 percent. This trend is

likely to continue as competitive generation markets and open

access increase the average distance electricity is transported.

Expanding the transmission system will have both pecuniary and

nonpecuniary costs. New transmission corridors cost

approximately $500,000/mile 500kv line. A 1 percent increase in

the capacity of the bulk transmission system would potentially cost

$735 billion. In addition, public opposition to new transmission

lines due to health concerns and the aesthetics of power lines has

grown considerably over the decades.

System reliability and power quality are also concerns associated

with deregulation. Reliable, high-quality electric power is one of

the primary cornerstones of the U.S. economy. In fact, lack of

reliability and power quality are frequently cited as the most

important factors limiting growth in underdeveloped countries.

Because of the U.S.’s dependence on (and expectations for) reliable

power, unexpected outages can be costly. It is estimated that

power outages currently lead to $29 billion (Hoffman, 1996) in

annual losses for U.S. industries. In addition, sales of backup

generation and power cleaning equipment exceeded $5.3 billion in

1998. Any degradation in reliability or power quality (real or

perceived) could significantly increase these costs.

Over the past 10

years, electricity

sales have increased

by 25 percent (in

kWh) while bulk

transmission

capacity has

increased by only

5 percent.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-8

1.2 THE ROLE OF STANDARDS

Measurement and technology standards can play a role in helping

to realize the potential benefits of a deregulated electric utility

industry. This section presents the basic case for measurement

standards and discusses their characteristics as infratechnologies.

1.2.1 The Justification for Measurement and Technology

Standards in Industry

The basic rationale for measurement and technology standards in

industries of any type are presented by Tassey (1997). He identifies

four general areas where these standards can make a positive

contribution to the economic performance of industries:

Z Quality/Reliability. Standards are developed to specify an

acceptable level of product or service performance along

one or more dimensions such as functional levels,

performance variation, service lifetime, efficiency, safety,

and environmental impact. Thus, standards can help to

avoid “sham” products or transactions, verify performance

and delivery, and assure the credibility of offerings by new

entrants to the industry.

Z Information. Standards help provide evaluated scientific

and engineering information in the form of publications,

electronic databases, terminology, and test and

measurement methods for describing, quantifying, and

evaluating product attributes (e.g., verification of

performance claims, thereby reducing disputes and market

transactions costs and increasing market penetration).

Z Compatibility/Interoperability. Standards specify properties

that a product must have to work (physically or functionally)

with complementary products within a product or service

system. They provide a standard interface (i.e., interface

standard) between components of a larger system, and they

“open” systems technologies and allow multiple proprietary

component designs to coexist. Optimization can still occur,

but the cost of modifying physical and functional interfaces

to allow components from different vendors to work

together (i.e., to “interoperate”) can be prohibitive. Full

functionality is often not obtained by reengineering

proprietary (nonstandard) interfaces. Integrated, “turnkey”

systems offered by large companies may not be tailored for

a user’s particular needs, competitor’s components may be

superior, and there may be viable price competition for

replacement of components. Standards can lead to effective

integration of components and true compatibility of

components in open systems.
Section 1 — Introduction

1-9

Z Variety Reduction. Standards limit a product to a certain

range or number of characteristics, such as size or quality

levels, primarily to attain economies of scale. Variety

reduction goes beyond selecting certain physical

dimensions of a product for standardization and now is

commonly applied to nonphysical attributes, such as data

formats, and to combined physical and nonfunctional

attributes, such as computer architectures and peripheral

interfaces. Standardization can either enhance or inhibit

innovation. It can inhibit it when capital intensiveness

grows as economies of scale are realized, which can

exclude small, innovative firms from entry.

A standard can be specified in terms of design or performance

levels. Design-based standards are more restrictive, so

performance-based standards are generally more cost-effective.

This distinction is especially important as the electric power

industry goes through deregulation. Design-based standards that

were effective in a regulated environment may be ineffective or

overly restrictive in the new deregulated environment.

1.2.2 Measurement and Standards as Infratechnologies

Measurement and standards to support the deregulation of the

electric power industry cover a broad range of technologies,

procedures, and protocols. Measurement of commodities and

system parameters is a prerequisite to establishing competitive

markets and to ensuring reliable system operation when resources

are separated from operating control. Measurement capabilities

form the building blocks for standards, which in term support

efficient R&D, production, and market activities.

Most of the measurement and standards can be viewed as

infratechnologies. Infratechnologies are technical tools, including

scientific and engineering data, measurement and test methods, and

practices and techniques that are widely used in industry (Tassey,

1997). Infratechnologies play an important role in several stages of

the economy.

Z Infratechnologies improve the efficiency of research and

development (R&D). Infratechnologies can stimulate R&D,

improve the efficiency of R&D, and advance society’s

technological opportunities. Measurement technologies,

test methods, technical standards, and standard practices

allow researchers to conduct and discuss R&D using

terminology and measurement methods and metrics that are

understood by their colleagues and that allow for the

replication and verification of research results.

Measurement and

standards to support

the deregulation of

the electric power

industry cover a

broad range of

technologies,

procedures, and

protocols.

Most of the

measurement and

standards can be

viewed as

infratechnologies.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-10

Z Infratechnologies support the production process and can

enhance product characteristics. Infratechnologies can

improve the efficiency of the production process and the

characteristics of a product by providing tools for quality

assurance and real-time process control.

Z Infratechnologies promote technology adoption and reduce

market transactions costs. Infratechnologies can increase

the speed of market penetration by providing a language for

communicating the characteristics and quality of a new

product, process, or service. 

To varying degrees, infratechnologies have the characteristics of a

public good. Such goods, unlike private goods, are characterized

by consumption nonrivalry and by high costs of exclusion.

Rationing of such goods is undesirable because the consumption of

a public good does not impose costs on society since it does not

reduce the amount of the good available to others. Further, the

costs of excluding those who do not pay for the infratechnologies

are likely to be high because they are typically embodied in

products and processes (techniques), rather than in products that

can be sold.2 As a result of these characteristics, public goods are

typically underprovided by private markets as compared to their

socially optimal levels of provision (Stiglitz, 1988). The private

sector might also underinvest in infratechnologies because its

technology base is different from the core technology that industry

draws on to develop its product or processes (Tassey, 1997).

NIST responds to market failures in the provision of infratechnologies

by investing public funds in infratechnologies when private funding is

inadequate to meet important strategic technical goals. The

measurement technologies and standards NIST develops for the

electric utility industry benefit the entire electric power supply chain

as well as the consumers of electric power.

However, the scope of this study is not limited to NIST’s potential

roles for supporting deregulation. This study identifies the broad

range of measurement and standard needs to support deregulation

of the electric power industry, acknowledging that many private

sector, trade organizations, and other government organizations

 

2In contrast, a regulated (or publicly owned) transmission system is not a true

public good. Access to the system can be easily controlled and capacity limits

and congestion effects mean that consumption of transmission resources

imposes costs on other users.

NIST responds to

market failures in

the provision of

infratechnologies by

investing public

funds in

infratechnologies

when private

funding is

inadequate to meet

important strategic

technical goals.
Section 1 — Introduction

1-11

will be involved in developing and implementing these

measurement technologies and standards.

1.3 STUDY OVERVIEW

This study assesses the measurement and standards infrastructure

needs of a deregulated electric power industry. It also provides

estimates of the economic impact of the failure to provide this

infrastructure. Such a failure implies that society will forego some

of the potential benefits of a deregulated electric power industry

because all of the potential gains in economic efficiency will not be

realized. The intent of this study is not to assess all of the benefits

and costs associated with deregulation. This study focuses only on

the area where measurement and standards can potentially increase

benefits or decrease costs.

Specific areas of interest include, but are not limited to,

measurement and standards to support

Z competitive metering for suppliers and consumers, energy,

and ancillary services;

Z bulk power transactions and monitoring;

Z reliable transmission and distribution of electric power;

Z communications and control technologies;

Z advanced diagnostics;

Z power quality; and

Z distributed generation.

To identify and quantify the changing measurement and standards

needs of the electric power industry, we conducted three stages of

primary data collection with approximately 40 industry experts:

Z Scoping interviews were used to investigate the evolving

structure of the U.S. electric power industry and to identify

potential areas where measurement and standards will play

important roles.

Z Detailed topic interviews were used to assess the

importance of measurement and standards on specific areas

identified during the scoping interviews. These areas

included, but were not limited to, efficient provision of

generation and ancillary services, systems operation,

wholesale market transactions, and retail market

transactions.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

1-12

Z Quantitative surveys were used to develop inputs to the

economic impact analysis. Attendees at NIST’s conference

on measurement and standards needs to support a

deregulated electric power industry were asked to provide

their estimates of the impact of measurement and standards

on several impact areas.

Appendix C contains the interview guide and survey questionnaire

used to support the primary data collection activities. Table 1-2

contains a list of the survey respondents’ company or

organizational affiliation. The identity of individual contacts has

been suppressed for confidentiality.

Table 1-2. Companies/Affiliations of Respondents

Telephone interviews with industry experts were the main source of primary data for the quantitative and qualitative

analyses.

ABB Electric Metering Northern States Power

California RTO Paradigm Consulting

Carolina Power and Light PJM Interconnection

Commonwealth Edison Radian Research

Detroit Edison Salt River Project

Duke Power Company Southern Company

Electrotek Square D/Schneider Electric

ENRON Tampa Electric

Hypertek University of Wisconsin, Electrical Engineering Department

National Regulatory Research Institute Utility Translation Systems

North American Electric Reliability Council Wisconsin Public Service

North Carolina Electric Membership Corporation

Note: The number companies/affiliations listed in the table is less than 20 because, for some companies, more than one

person was interviewed, and several respondents returned their surveys anonymously at the NIST conference on

measurement and standards.

Findings from the scoping interviews and detailed topic interviews

were used to support the discussion of measurement and standard

needs in Section 4. The quantitative surveys were used to support

the estimation of economic impacts described in Section 5.

Appendix D contains an overview of the findings from the

interviews and surveys.
Section 1 — Introduction

1-13

In addition to primary data, we also used secondary data to support

the analysis. Secondary data were collected from trade

publications, professional journals, and statistical resources.

1.4 REPORT STRUCTURE

The remainder of the report is structured as follows. Section 2

contains a conceptual overview of the economic implications of

deregulation and how the measurement and standards

infrastructure influences economic efficiency. An overview of

deregulation trends and implications is presented in Section 3.

Section 4 presents a discussion of measurement needs and

standards needs, respectively, to support deregulation. We present

the economic impacts of failing to expeditiously provide the

measurement and standards infrastructure in Section 5.

Appendix A describes existing activities and emerging participants

in the electric power supply chain. Appendix B provides

background on deregulation and notes some trends. The interview

guide and survey questionnaire used to support the primary data

collection activities and the development of quantitative results are

presented in Appendix C. Appendix D summarizes the findings

from the interviews. Appendix E describes the calculation of event

cost metrics.
2-1

Conceptual Model of

Deregulation and the

Impact of

Measurement and 2 Standards

Industry restructuring is targeted at increasing the economic

efficiency of the electric power system. In this context, economic

efficiency refers to supplying end users’ electric power needs at the

lowest cost of production (including traditional generation,

transmission, and distribution expenditures and market and system

expenditures to support competition). This section presents a

conceptual overview of the economic implications of deregulation

and illustrates how measurement and standards influence economic

efficiency and power reliability and quality.

2.1 ECONOMIC EFFICIENCY VIEWED AS AN

OPTIMIZATION PROBLEM

The problem of efficiently generating and moving electricity from a

set of producers to a set of consumers can be modeled as an

optimization problem. Figure 2-1 shows the problem as a matrix

with generators on the horizontal axis and consumers (electricity

end users) on the vertical axis.1

 

1One conceptual approach to determining the optional set of transactions is to use

a linear programming (LP) model in which the equation in the LP system would

relate producers to consumers and identify the cost of production and the cost

causality of moving electricity from producers to consumers. The equations

would also identify other system constraints, such as regulatory issues and

physical limits on the transmission system.

Economic efficiency

refers to supplying

end users’ electric

power needs at the

lowest cost of

production.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-2

Figure 2-1. Regulated Model

In a regulated scenario, regional monopolies select generation and transmission resources to optimize their individual,

constrained regional model.

Electricity Producers

Consumers of Electricity

Region A Region B Region X ...............

Region

A

Region

B

Region

X

........................

..............................................

In an unconstrained competitive model, region boundaries would

have no influence on the optimal transactions and grid structure,

except for geographic constraints and the physical considerations of

transmission costs and losses.

However, in the past, regulated regions have been viewed as

natural monopolies, and each regulated region solved its own

separate optimization problem. The boxes in Figure 2-1 reflect the

boundaries of traditional regulated utilities that limit the possible

number of power exchanges between producers and consumers.

Thus, each region in effect selected its own generation,

transmission, and distribution assets (including monitoring and

communication assets to support system operations) to minimize

the cost of supplying electricity to the consumers in its region. In

the long run, a region’s physical assets could be considered

endogenous to the optimization problem. In this report, the
Section 2 — Conceptual Model of Deregulation and the Impact of Measurement and Standards

2-3

conceptual model illustrated in Figure 2-1 is referred to as a

regulated model.

Now, with deregulation, the objective is to restructure the electric

power system to gain efficiencies from expanding transactions

beyond a series of regional optimization models to a single

(national or North American) optimization model. As shown in

Figure 2-2, with deregulation consumers in Region A can receive

power from producers outside of Region A (where the x’s represent

transactions). In effect, we have relaxed the model’s constraints by

allowing “off diagonal” transactions. In the long run, generation

and transmission assets will be selected so that the optimal grid

minimizes the cost of electricity for consumers.2 This scenario is

referred to as the competitive model.

Figure 2-2. Competitive Model

In an unconstrained competitive scenario, the optimal allocation of generation and transmission resources is different

(compared to a regulated monopoly scenario) because transactions between regions are possible.

Electricity Producers

Electricity Consumers

Region A Region B Region X ...............

Region

A

Region

B

Region

X

........................

xx x

x

x

x

x

x

x x

x

x

x

 

2An unregulated competitive scenario may also lead to competition between

generators within a region. A regulated utility’s region may have included

several control areas that may have had little interconnection.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-4

However, in the short run, generation and transmission assets are

largely fixed, and the least-cost solution is obtained relative to these

constraints. This conceptual model is referred to as the constrained

national model. Conceptually, the constrained competitive model

must be as least as efficient as the regulated (local monopoly)

model.3 In addition, the constrained competitive model will

probably be less efficient than the (unconstrained) competitive

model because of the short-run constraints on modifying generation

and transmission assets.

2.2 TRADE-OFF BETWEEN COST AND QUALITY

An important dimension missing in the simple optimization problem

described above is that electric power need not be supplied as a

homogeneous commodity. In general, electric power service can

vary with respect to its overall quality that includes all the

nonpecuniary characteristics of electricity of importance to the

consumer. Foremost among these characteristics are power reliability

and power quality.4

There is potentially a trade-off between the cost of power supply and

its reliability and power quality. For example, in the extreme,

redundant transmission systems could be built and high generation

reserve margins maintained to support power reliability. Other

examples are the choices system planners face regarding how much

to invest in real-time communications to monitor transmission

system, flexible alternating current transmission system (FACTS) to

control power flow, fault trips to limit cascading outages, and

capacitor banks to maintain power quality. Increased use of these

devices can increase the level of quality; however, they are costly.

Figure 2-3 illustrates the tradeoff between the cost of delivered power

and reliability: higher reliability costs more. All points on the curve

represent the best-practices or efficient frontier. Thus, they are all

efficient in the narrow sense that each point represents the minimum

cost at which a given level of quality can currently be achieved. Any

point above the frontier is inefficient, and points below it are

unattainable with present technology and market structure.

 

3Under the constrained national model, all consumers can still choose to purchase

power from their regional producers as before.

4The combination of the two desirable attributes is often referred to as “clean”

power.

Deregulation may lead to

the supply of electric power

at different reliability and

power quality levels.
Section 2 — Conceptual Model of Deregulation and the Impact of Measurement and Standards

2-5

Low High

Cost of

Electricity

Service

Quality of

Electricity

Service

Low

High

Efficiency

Frontier

Figure 2-4 shows the indifference map for a single consumer. It

represents the preferences of the consumer between power price

and reliability. The consumer’s economic well-being or “utility” is

constant along each curve: higher numbered curves have higher

levels of utility. The point, (A), where the consumer’s utility curve

and the efficiency frontier are tangent represents the cost/quality

combination with the highest possible utility given the present

technology and market structure embedded in the efficiency

frontier.

It has been argued that utilities compensated under a rate-based

rate of return structure may have the incentive to overinvest in

capital assets (this has been referred to as gold plating or the

Averch-Johnson effect). As a result, historically, utilities have had

incentives to invest in capital assets to maintain reliability—

potentially beyond the point that is economically efficient from a

social planner’s perspective. For example, they may be operating

at point B in Figure 2-4. With deregulation suppliers are expected

to conduct an explicit assessment of the trade-off between the cost

and quality of electricity service.

This type of evaluation between the investments to enhance

reliability or lower cost has already begun. For example, the

California regional transmission organizations (RTO) proposes to

Figure 2-3. Trade-off

between the Electric

Power Price and Power

Reliability

The efficiency frontier

represents the least-cost of

producing a given level of

power reliability.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-6

Low High

Cost/Price of

Electricity

Service

Quality of

Electricity

Service

Low

High

Efficiency

Frontier

U1 U2 U3

A

B

evaluate what would increase the utility of their customers the

most: investments targeted at lowering the cost of electricity

service or investments that are targeted at improving reliability and

power quality (CASO, White Paper #2).

As mentioned earlier, the efficiency frontier is a function of the

present state of technology and market structure. One of the

objectives of deregulation (i.e., a change in market structure) is to

shift the efficiency frontier to the lower right, thereby increasing the

possible utility of electricity consumers. As shown in Figure 2-5,

shifting the efficiency frontier to the lower right allows the provision

of a given level of quality at a lower cost (A1). Alternatively, quality

could be increased at the same cost (A2), or a combination of low

cost and increased quality could be obtained (A3). The shape of the

consumer’s utility curves would determine which cost/quality

selection would maximize consumer’s utility.

Measurement and standards have the potential to contribute to the

outward shift of the efficiency frontier. Restated, without adequate

measurement and standards, the full shift in the efficiency frontier

envisioned for deregulation may not be realized. Figure 2-6

illustrates the potential impact of measurements and standards. For

example, without adequate measurement and standards, additional

costs may be needed to maintain the reliability and power quality

Figure 2-4. Consumer

Indifference Map

between Electric Power

Price and Reliability

Each curve represents the focus

of price-reliability values that

provide a given level of

consumer welfare or “utility.”

Higher numbered curves have

higher utility levels.

Restated, without

adequate

measurement and

standards, the full

shift in the

efficiency frontier

envisioned for

deregulation may

not be realized.
Section 2 — Conceptual Model of Deregulation and the Impact of Measurement and Standards

2-7

Low High

Cost of

Electricity

Service

Quality of

Electricity

Service

Low

High

Efficiency Frontier

Shift due to Deregulation

A1

A2

A3

Low High

Cost of

Electricity

Service

Quality of

Electricity

Service

Low

High

Deregulation without

Measurements and

Standards

B1

B2

Deregulation with

Measurements and

Standards

of the system (B1). Or, without adequate measurement and

standards, the quality of electricity service may decrease given

available resources/costs (B2). Changes in system costs and

electricity service quality associated with inadequate measurement

and standards are the focus of the quantitative analysis presented in

Section 5.

Figure 2-5. Shift in the

Efficiency Frontier due to

Deregulation

One of the objectives of

deregulation is to shift the

efficiency frontier, lowering cost

and/or increasing the quality of

electricity service.

Figure 2-6. The Role of

Measurement and

Standards

Without measurement and

standards, the full benefits of

deregulation may not be

achieved.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-8

2.3 ECONOMIC EFFICIENCY AND PRODUCT

DIFFERENTIATION

An additional role of measurement and standards may be to

facilitate the differentiation of electric power by providing the

infrastructure necessary for product differentiation.5 In this context,

product differentiation refers to the ability of electricity service

providers to supply electricity with different levels of reliability or

power quality to different groups of customers.

Figure 2-7 conceptually illustrates the potential benefits associated

with product differentiation. Figure 2-7 shows two consumers:

Consumer A has a relatively low value for power electricity service

quality and Consumer B prefers a high level of quality. Under a

traditionally regulated industry, electricity service is supplied at

only one level of quality (within a service region) because the utility

does not have the incentive to differentiate its product. This

reliability level shown is “average” or Q1. Consumer A’s wellbeing is UA

1, B’s is UB1. Under deregulation, different (or the same)

suppliers may offer two levels of reliability, QA

2 and QB2, with the

result that each consumer is on a higher indifference curve. Social

welfare (the sum of the two utility levels) has risen.

2.4 TECHNICAL AND MARKET INFORMATION

NEEDS TO SUPPORT A DEREGULATED

INDUSTRY

As part of this project, we investigated the technical and market

information needs to support a deregulated electric power industry.

This distinction between technical and market information is

important because the characteristics of the information needs and

the impact on economic efficiency and clean power (of not meeting

these needs) are generally different.

 

5Measurement and standards also have the potential to increase the economic

efficiency of the unconstrained competitive model. However, the focus of this

report is on the impact of measurement and standards on a restructured industry

and implies a relatively short time horizon (10 to 20 years) where most of the

generation and transmission assets are inherited from the previous regulated

monopoly model.

Measurement and

standards are needed to

support the infrastructure

necessary for product

differentiation in the

electric power market.
Section 2 — Conceptual Model of Deregulation and the Impact of Measurement and Standards

2-9

Figure 2-7. Product Offerings under Regulation and Deregulation

With deregulation electric power suppliers may find it profitable to differentiate their product. This would raise

consumer welfare.

Price of

Electricity

Power

Reliability Q B

2 Q A2

U A

2 U A1

Q 1

U B

1

U B

2

Figure 2-8 illustrates the distinction between these two categories of

information using two separate parallel planes of operation:

systems operations and market operations. Information flows have

historically been concentrated within each plane with minimal

interchange of technical information and market information.

However, with deregulation significantly more information will

need to be exchanged between the two planes. Increasingly market

forces will drive system operations, and more technical information

will be needed to support market operations.

As an example of how information may flow between the two

planes in Figure 2-8, consider the following:

Z In the initial step, data on generating and transmission

system resources (e.g., their availability, capability,

operating levels, and incremental operating costs) and on

forecasts of load and energy from the top plane may be

shared with selected market players in the lower plane. In

the process, information from different sources and regions

will need to be aggregated, processed, and routed to

selected market players.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-10

Figure 2-8. Information Needs for System and Market Operations

Traditionally there has been limited interaction between system and market operations. However, with deregulation the

information flows between the two planes will increase substantially.

Electricity Flow

Transmission

and Ancillary

Service Data

Generation

Data

Bid and

Contract

Information

Information Flow

Data Routing

Information Processing

Market Players

Market Operations

Consumption Data

System Operations

Customers

Generation

Distribution

Transmission

Meter data

Meter data

Meter data

Curtailable 

Load 

Dispatch

Ancillary

Service 

Dispatch

Generator

 Dispatch

System

Coordination
Section 2 — Conceptual Model of Deregulation and the Impact of Measurement and Standards

2-11

Z These market players will bid generation resources,

curtailable load resources, and ancillary services into the

market. These data flow from the market players in the

lower plane to the system coordinator in the top plane (or to

a separate power exchange, as in California).

Z The system coordinator (or power exchange) in the top

plane will select the preferred resources and services. The

system coordinator will then schedule (sometimes with the

aid of scheduling subcontractors) and dispatch generation

and curtailable load resources to meet (or reduce) demand

and dispatch ancillary services to augment basic

transmission service.

Z Data on generation and curtailable load dispatched,

ancillary services used, and customer load and energy use

will flow from the top plane to market players in the lower

plane, where it will be incorporated into bills they render to

other market players. These other market players will

include the system coordinator and local distribution

companies and may include bilateral contract wholesale

market customers and bilateral contract retail market

customers.

Telephone interviews were used to investigate the technical

information needed to support deregulation. Technical information

primarily supports the physical operation of the electric power

system. It supports both economic efficiency and clean power.

The distinguishing characteristics of technical information are the

importance of real-time data transfer and communication

reliability. To maintain reliability, system coordinators need to be

able to monitor inflows and outflows from the grid, as well as

conditions throughout the system. Operating conditions must be

measured, transmitted, and processed and then responses

dispatched all in real time to maintain system stability. In the

future, real-time state information on system operations may be

used to support market functions such as estimating cost causality

of bulk transaction on the transmission system. Some of the

technical information flows to support system operations identified

during the telephone interviews are the following:

Z monitoring and control of generation and ancillary services

(standards and communications protocols are needed),

Z real-time monitoring and control of transmission system

(capacity utilization measurements/standards and dynamic

state analysis are needed), and

Z real-time communications links to end users to support

demand-side management activities (standards and

communications protocols are needed).
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

2-12

We also used the telephone interviews to investigate market

information needed to support deregulation. Market information

primarily supports the pricing and billing of the electric power

system and is used for forecasting and dispatch of generation and

ancillary services. Key characteristics are that information is

recorded at regular intervals (hourly) and communicated

periodically (daily) to central processing centers. In addition,

information reflecting the value/price for energy and ancillary

services needs to be communicated back to suppliers hourly (at

least) to get response. Because of the large number of end-user

meter reads, interoperability and processing costs are important

issues for supporting deregulation. In addition, usage data are

proprietary (and valuable); thus, security will be an important issue.

Some of the market information flows that we investigated are the

following:

Z measurement of generation and ancillary services supplied

(cannot sell what cannot be measured);

Z measurement of transmission costs (transmission causality

models are needed);

Z end-use consumption metering (standards needed to lower

cost);

Z communication, aggregation, and redistribution systems

(common protocols and standards needed to lower costs);

and

Z special information needs to support the growth in the

number of players and to lower market barriers to entry.

As part of our interviews, we developed a detailed characterization

of the technical and market information flows required to support a

deregulated electric power industry. We also qualitatively

described the measurement and standards needs required to

support the efficiency and reliability of each information flow.

Because of the large

number of end-user

meter reads,

interoperability and

processing costs are

important issues for

supporting

deregulation.
3-1

Future Implications

of Deregulation for

the Electric Power 3 Industry

This section provides an overview of the changing characteristics

and needs of the electric power industry as a result of deregulation.

We identify the emerging information, technology, and resource

needs that will be necessary to effectively manage a deregulated

power industry. From this backdrop of emerging needs, Section 4

and Section 5 discuss the roles measurement and standards may

play in meeting these needs.

3.1 DEREGULATION TRENDS AND THE

CHANGING CHARACTERISTICS OF THE

ELECTRIC POWER INDUSTRY

Restructuring of the electric power industry could result in any one

of several possible market structures. In fact, different parts of the

country will probably use different structures, as the present trend

indicates. The eventual structure may be dominated by a power

exchange, bilateral contracts, or a combination. A strong Regional

Transmission Organization (RTO) or a minimal RTO may operate in

the area, or a vertically integrated utility may continue to operate a

control area.

However, regardless of the eventual evolution of the industry

structure, most of the physical characteristics and needs of the

deregulated industry will be the same. The metering,

communications, and control requirements of a restructured

Regardless of the

eventual evolution

of the industry

structure, most of

the physical

characteristics and

needs of the

deregulated industry

will be the same.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-2

electric power industry are primarily being driven by the

fundamental change of increasing reliance on markets and

contracts and decreasing reliance on regulation and vertical

integration. These fundamental changes are common to almost all

potential restructuring scenarios. Similarly, the need to extract

more performance from the transmission system is related to the

difficulty of constructing transmission, and increasing commercial

pressure to use transmission, not necessarily to the specifics of how

industry restructuring moves forward. As a result, the general need

to advance metering and monitoring technology seems to be

broadly based on national requirements that are not sensitive to the

specific details of restructuring implementation.

In general, deregulation will lead to changes in several important

industry characteristics:

Z Commercial provision of generation-based services (e.g.,

energy, regulation, load following, voltage control,

contingency reserves, backup supply) will replace regulated

service provision. This drastically changes how the service

provider is assessed.

Z Individual transactions will replace aggregated supply

meeting aggregated demand. It will be necessary to

continuously assess each individual’s performance.

Z Services will be unbundled. It will be necessary to

separately evaluate each type of transaction.

Z Time frames will shorten. New services will be measured

over seconds and minutes instead of hours.

Z Transaction sizes will shrink. Instead of dealing only in

hundreds and thousands of MW, it will be necessary to

accommodate transactions of a few MW and less.

Z Supply flexibility will greatly increase. Instead of services

coming from a fixed fleet of generators, service provision

will change dynamically among many potential suppliers as

market conditions change.

Z Greater and greater performance will be required from

existing transmission resources. Transmission will be

increasingly difficult to build, planning transmission

enhancements will slow even further, but commercial

pressure will demand that existing resources be used to the

fullest.
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-3

All of these changes have important implications for data

collection, communications, and control requirements.

Fundamentally, they result in three basic needs:

Z faster, more accurate, and cheaper metering to

accommodate commercial transactions (revenue metering)

that are smaller in MW size; require faster services

(including dynamic response); and come from a much

larger group of resources (generators and loads)

Z real-time data acquisition, communications, and control

capabilities to support market-based systems operations

where price signals replace command-and-control

operations

Z real-time data acquisition, communications, and control

capabilities to extract as much performance as possible

from transmission and distribution facilities

If these needs cannot be met, deregulation of the electric power

industry will be severely hampered.

3.1.1 Separation of Resources and System Operations

One of the most important implications of deregulation is that it

will lead to separation of resources from system operations. With

this separation emerges the need to evaluate the performance of the

individual components of the power system.

State regulators have historically judged the overall performance of

each vertically integrated monopoly utility. In the regulated

framework, all components of the system worked together and were

compensated based on the overall performance of the system.

Regulators could reward or punish utilities by controlling the rates

the utilities were allowed to charge. While the assessment certainly

had (and has) quantitative parts and often focused on individual

areas of performance (e.g., assessing if an investment was “used

and useful”), the judgment was always on a fairly large scale and

largely subjective. Thus, in the regulated framework, the emphasis

is on the performance of the fleet of resources, and individual

performance is only important in how it affects the aggregate

objective.

With deregulation, the emphasis shifts to individual performance.

Previously suppressed (internalized) pricing systems now must be

formalized to support market transactions. In addition, formal

contracts are now needed to specify what is expected and the

Deregulation will likely

lead to a separation of

resources from system

operations. This shifts the

emphasis away from system

performance and toward

individual unit or market

participant performance.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-4

payment associated with the individual providing the agreed-upon

services, as well as payments associated with providing

unanticipated services. Under deregulation, individual units will

no longer be willing to sacrifice themselves for “the good of the

system” without compensation.

One of the main benefits of vertically integrated organizations is

that they reduce transaction costs by internalizing prices and

centralizing control. Transaction costs to support market operations

will be one of the greatest costs associated with deregulation. In

general, there are three types of transaction costs: information

costs, contracting costs, and enforcement costs. Any transaction

requires knowledge about the opportunities for exchange, the

nature of the items to be exchanged, and the willingness of the

participants to engage in a bargaining process. This information is

not costless and the lack of information can prevent certain

exchanges from ever occurring (Bromey, 1991).

The challenge for a deregulated electric power system that has

separated system control and resources will be to establish a

pricing and enforcement system that signals the correct incentives

to individual system components. This will be important both in

the efficient operation of existing assets and in attracting investment

in new generation and transmission resources.

3.2 ENABLING TECHNOLOGIES

Deregulation would not be possible without a broad range of

enabling technologies to support the increased demand for

monitoring, metering, communications, and control. Significant

technology advances have been made within and outside the

electric power industry. In addition, many technical areas were

identified during our interviews where additional research is

needed.

3.2.1 Enabling Technology Advances

Many of the technologies that make deregulation possible have

been developed outside the electric power industry and represent

spillover benefits. Examples of these technologies include the

following:
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-5

Z Advances in microprocessor performance and costs will

support the monitoring, transfer, and processing of

information.

Z Electronic data interchange (EDI) technologies and

standards provide a potential building block to support

retail competition. However, consistency between regional

EDI systems is an ongoing concern.

Z Data management and storage system technologies are

developed to support a wide range of commercial

applications and are essential to implementing retail

competition.

Z Advances in wireless technologies will support the

implementation of automated meter reading (ARM) systems.

Z Expanded Internet access and high-speed data links will

support communications needs for competitive generation

and retail competition.

3.2.2 Infratechnologies Where Additional Research is

Needed

During our interviews, industry experts indicated many areas where

technology advances will be needed to support deregulation.

Many of these areas include infratechnologies that are needed to

support system and market functions. The identified needs range

from instances where available technologies are inadequate to

instances where technologies exist but are too costly for widespread

implementation:

Z Security technologies have not yet matured in the electric

power industry. Security issues will be come increasingly

important with the increase in the number and diversity of

market participants at all levels of the supply chain.

Z Dynamic state monitoring systems have the potential to

increase transmission system capacity and support power

system reliability.

Z Improvements in cost causality models for bulk transmission

are needed for efficient pricing of transmission services.

Z Models and monitoring systems to determine thermal limits

for transmission lines have the potential to increase

transmission system capacity and support power reliability.

Z Models are needed to predict voltage instabilities and

voltage collapse. Existing real-time causality models are

inadequate.

Many of the

technologies that

make deregulation

possible have been

developed outside

the electric power

industry and

represent spillover

benefits.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-6

Z Technologies to support equipment cost reductions are

needed for widespread implementation of advanced

metering.

Z Advances to reduce the cost of flexible AC transmission

(FACTS) are needed. FACTS will potentially be an integral

tool supporting control and reliability of the bulk

transmission system. However, additional research is

needed to reduce the cost before widespread

implementation is economically feasible.

Z Technology enhancements for phase angle metering are

needed to improve accuracy and lower cost.

Z Transaction management systems are needed to reduce

operator work load and reduce mistakes.

Z Data synchronization techniques are required to eliminate

problems caused by data collected from different parts of

the system arriving at the control center at different times,

resulting in an inconsistent view of the power systems.

Z Instrumentation for early detection of cable failures is

needed along with technology and real-time control

capabilities to prevent cascading failures once cable failures

are identified.

3.2.3 Infratechnologies that Will Enable New Products and

Services

Research and development within the electric power industry is

being driven by the need for technology advances to support the

ongoing deregulation process. However, new technology advances

and the implementation of information systems will enable new

products and services not originally foreseen. As with the evolution

of the Internet where “technology push” led to development of new

applications, the technology advances and information

infrastructures driven by deregulation of the electric power industry

will lead to new, spin-off market opportunities:

Z More accurate and widespread metering will allow loads to

be price-responsive enabling services targeted at managing

demand-side usage. From the suppliers’ perspective, this

tool is valuable to manage generation and transmission

growth. Whereas a limited number of voluntary curtailment

programs currently exist, it is estimated that up to a 2

percent reduction in peak demand could be obtained

through widespread use of load control programs.

Z More accurate and widespread metering will also enable

products and services targeted for end users to more
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-7

efficiently manage electricity consumption. Detailed enduse usage profiles will become available for smaller

commercial and industrial and residential customers, along

with the technology to control individual loads.

Z ARM for electric and gas services may merge, accelerating

the development of integrated energy service providers.

Z Path-dependent models and tagging technology may help

stimulate the market for green power.

3.3 KEY ISSUES RELATED TO RESTRUCTURING

THE ELECTRIC POWER INDUSTRY

Viewed from one perspective, not much changes in the electric

industry with restructuring. The same functions are being

performed, essentially the same resources are being used, and in a

broad sense the same reliability criteria are being met. In other

ways, the very nature of restructuring, the harnessing of competitive

forces to perform a previously regulated function, changes almost

everything. Each provider and each function become separate

competitive entities that must be judged on their own.

Measurement and quantification become critical to buying and

selling power.

Several technical issues will need to be addressed as deregulation

progresses. Measurement and standards will play an important role

in developing the infratechnologies needed to meet the challenges

associated with restructuring. Areas where measurement and

standards will be important include

Z increased transmission demand,

Z service quantification,

Z reliability criteria,

Z real-time electric pricing,

Z unbundling of ancillary services,

Z reduced generator and transaction sizes,

Z power quality, and

Z supplier choice.

These issues are discussed below.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-8

3.3.1 Increased Transmission Demand

The move to market-based provision of generation services is not

matched on the transmission and distribution side. Network

interactions on AC transmission systems make it impossible to have

separate transmission paths compete.1 Hence, transmission and

distribution will remain regulated. Transmission and generation

heavily interact, however, and transmission congestion can prevent

specific generation from getting to market. Transmission expansion

planning becomes an open process with many interested parties.

This open process, coupled with frequent public opposition to

transmission expansion, slows transmission enhancement. The net

result is greatly increased pressure to extract more and more

performance from each transmission asset. For-profit RTOs may

flourish, but they will be profit-motivated organizations under

incentive-based regulation. The performance pressure on

transmission is therefore different, but no less than the pressure on

generation. More is being demanded from the transmission system

now than ever before. And this trend is expected to continue.

Transactions are going longer distances, in less predictable ways.

System operators used to be able to restrict transactions to those

that were studied ahead of time or that respected expected future

trends. Now transactions are accepted as they are presented by the

market.

Transmission is not expanding at the rate generation and load are

expanding. The North American Electric Reliability Council

(NERC) reports a 16 percent decline in the number of miles of

transmission lines per MW of summer demand from 1989 to 1997.

NERC expects an additional 13 percent decline by 2007 (NERC,

1998).

Transmission expansion is not keeping up with load and generation

for three reasons. First, it is hard (and has been for some time) to

build transmission for environmental and political reasons. Second,

the nature of AC transmission (the network interactions, lack of

control, the fact that enhancements often eliminate the locational

price signals that are needed to generate revenue) makes it difficult

to attract private investment. Consequently, transmission remains

 

1Widespread use of FACTS and DC links would make this possible, but they are

currently too expensive for widespread use.

Deregulation will lead to

increased pressure to

extract more performance

from existing transmission

assets.

Transmission expansion has

not kept pace with load

and generation growth.
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-9

regulated and cannot attract speculative capital. Third,

transmission is capital-intensive, long lived, with low operating

costs. It can be amortized over decades. It is difficult to change

the transmission system rapidly to respond to fast changes in

generation, load, and trading patterns that can result as relative fuel

costs change, populations and commercial enterprises move, or the

economy shifts.

There is also an interesting divergence in the time required to plan

and deploy transmission and generation enhancements.

Technological changes (the trend to smaller, gas-fired generators)

and the privatization of the investment process are accelerating

generation deployment schedules. Simultaneously, transmission

enhancement deployment schedules are being slowed because the

processes are becoming more public and more contentious and

because of land use concerns. The problem compounds because

transmission planners are no longer simultaneously planning

generation expansion (that is now in private hands), and they now

must wait until the private generation developers make their plans

known.

The net result of these trends is that there is increasing commercial

pressure to move more transactions greater distances over a

transmission system that is shrinking relative to the size of the load

it serves. This may be accomplished by directly monitoring

parameters that indicate how equipment is being loaded (e.g., line

current, ambient temperature, wind speed) or by monitoring the

result of that loading (e.g., line tension, sag, or equipment

temperature). Sensors, communications, and control that allow the

transmission system to deliver greater response and devices that

allow system operators to drive lines, transformers, and other

transmission elements closer to their limits could increase capacity

utilization of the transmission system.

Devices that likely warrant attention include the following:

Z transformers: actual measurement of transformer hot spot or

other parameters, such as oil degradation

Z overhead lines: sag, tension, conductor temperature, air

temperature, wind, gallop

Z cables: temperature, insulation

Z circuit breakers: SF6 analysis, oil analysis
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-10

3.3.2 Service Quantification

Restructuring will likely end with deregulated generators operating

in competitive markets. RTOs will operate the power system, but

they will be independent of commercial interests. They will

facilitate commercial markets for energy and ancillary services and

will purchase ancillary services themselves from competitive

markets to support operation of the power system. The services

themselves must be quantified for these transactions to be effective.

This requires service definitions, standards, metrics, and

measurement.

3.3.3 Reliability Criteria

Changes in how reliability is maintained closely parallel changes in

commercial market development. In fact, they are the same thing

because reliability and commerce cannot be separated. In the past,

each control area (generally each utility) was responsible for

maintaining reliability within its franchise service territory. Each

was judged by its state regulator. Control areas interconnected to

increase reliability by obtaining assistance from each other when

their system was under stress. By interconnecting two control

areas, utilities could share generating reserves, for example, by

reducing the amount of reserves each has to carry while increasing

the reliability of each.

As a result of the 1968 Northeast blackout, utilities voluntarily

created regional councils and NERC. NERC and the regions helped

utilities decide what reliability actions were appropriate by

developing reliability guidelines. While each utility still had

responsibility for reliability in its control area, and performance was

still judged by the state regulator, a utility could point to the use of

NERC and regional council planning and operating guidelines to

justify that the utilities’ actions were appropriate in spite of the

inevitable power outages or to justify reliability-related expenses.

NERC is responding to restructuring by changing its name to

NAERO (the North American Electric Reliability Organization) and

by converting the voluntary guidelines to mandatory quantifiable

policies. The process is not complete; it is not clear yet where

NAERO will derive the required authority to enforce policies. Still,

it is clear that a restructured industry does require reliability rules

that are explicit, quantifiable, and enforceable (or priced).
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-11

As with unbundling of commercial functions, restructuring of

reliability responsibilities changes from primarily relying on a

judgment of the holistic system response and cost to quantification

and assessments of individual performance during individual

events.

3.3.4 Real-Time Electricity Pricing

Electricity is a unique commodity in that instantaneous production

and consumption must be balanced continuously. Consequently,

the instantaneous cost is quite volatile. Historically, loads were

shielded from this volatility and saw only average prices. Some

loads saw prices that changed seasonally; some saw prices that

reflected a predetermined time of use. Generators themselves were

shielded from price volatility and simply operated when instructed

to do so. Only the system operators were particularly aware of the

cost volatility because they dispatched generators based on the

generators’ production cost and the system’s marginal cost.

Restructuring is changing this indifference to real-time costs and

prices. One of the major differences is the switch from cost-based

transactions2 to price-based transactions.3 Clearly, prices and costs

are normally related, but the linkage is not absolute. Active spot

markets now exist for real-time pricing of bulk power transactions.

Power exchanges exist in several locations that clear transactions

based on buy and sell bid prices. The introduction of merchant

power plants and price-sensitive loads has extended the real-time

price sensitivity to individual generators and consumers, as would

be expected in a mature market. Typically, transaction prices are

held for 1 hour, but California is experimenting with transaction

periods of 10 minutes or less. Clearly, real-time markets require

faster metering and communications than are required to support

average pricing and central command-and-control generation

dispatch.

 

2Economy transactions, where power was sold from one utility to another at the

average of the two utility’s marginal production costs (allowing each utility to

capture one-half the value of the exchange) used to dominate the interchange

market.

3With price-based transactions, power is sold at whatever price the two parties

agree on.

Electricity is a

unique commodity

in that instantaneous

production and

consumption must

be balanced

continuously.

Consequently, the

instantaneous cost is

quite volatile.

Real-time markets

require faster

metering and

communications

than are required to

support average

pricing and central

command-andcontrol generation

dispatch.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-12

3.3.5 Unbundling of Ancillary Services

Restructuring has brought separation of services (unbundling) as

well as separation of suppliers. Ancillary services (FERC’s term or

Interconnected Operations Services, NERC’s term) are reasonably

well defined conceptually. These are services that are required to

assure reliability and/or to facilitate commerce. Table 3-1 provides

definitions for the 12 ancillary services. At least six of these

services require measuring specific performance from the individual

resources providing or consuming the service: regulation, load

following, voltage control, contingency reserve—spinning,

contingency reserve—supplemental, and backup supply. Most also

require communication of control signals to inform the resource of

the desired response. Dynamic scheduling also requires

measurement and communications.

Each of the services requires a metric as well as a measurement.

Regulation, for example, is the service that compensates for

fluctuations in load and unintended fluctuations in generation. The

system operator contracts for generating capacity that can

maneuver rapidly to compensate for these fluctuations and keep the

system in balance. Figure 3-1 shows the automatic generation

control (AGC) signal from the system operator requesting generator

response and the unit’s actual performance. Figure 3-2 shows a

similar plot for a unit that is not performing well. Note that even in

Figure 3-1 the generator is not performing perfectly. The degree to

which the supplier is delivering the service must be measured. This

could be related to the difference between the time series of

requests and the actual generator outputs. A metric that converts

these differences into an appropriate gauge of service provision

needs to be developed.

One common feature of each of these ancillary services is that

service provision requires controlled behavior over time frames that

are significantly shorter than the time frames over which traditional

revenue metering operates. Ancillary service time frames are shown

in Figure 3-3. The importance of measurement and quantification of

real-time service provision or consumption is heightened by the

volatility of ancillary service prices, as shown in Figure 3-4.
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-13

Table 3-1. 12 Ancillary Services and their Definitions

Time is an important factor in defining ancillary services.

Service Definition Time Scale

Services FERC requires transmission providers to offer and customers to take from the transmission provider

System control The control-area operator functions that schedule generation

and transactions before the fact and that control some

generation in real-time to maintain generation/load balance

Seconds to hours

Voltage control from

generation

The injection or absorption of reactive power from generators

to maintain transmission-system voltages within required

ranges

Seconds

Services FERC requires transmission providers to offer but which customers can take from the transmission

provider, buy from third parties, or self-provide

Regulation The use of generation equipped with AGC to maintain

minute-to-minute generation/load balance within the control

area to meet NERC control-performance standards

~1 minute

Contingency reserve—

spinning

The provision of unloaded generating capacity that is

synchronized to the grid that can begin to respond

immediately to correct for generation/load imbalances

caused by generation and transmission outages and that is

fully available within 10 minutes to meet NERC’s

disturbance-control standard

Seconds to <10

minutes

Contingency reserve—

supplemental

The provision of generating capacity and curtailable load

used to correct for generation/load imbalances caused by

generation and transmission outages and that is fully

available within 10 minutesa

<10 minutes

Energy imbalance The use of generation to correct for hourly mismatches

between actual and scheduled transactions between

suppliers and their customers

Hourly

Services FERC does not require transmission providers to offer

Load following The use of generation to meet the hour-to-hour and daily

variations in load

10 minutes to

hours

Backup supply Generating capacity that can be made fully available within

30 to 60 minutes to back up operating reserves and for

commercial purposes

30 to 60 minutes

Real-power-loss

replacement

The use of generation to compensate for the transmissionsystem losses between generators and loadsHourly

Dynamic scheduling Real-time metering, telemetering, and computer software and

hardware to electronically transfer some or all of a

generator’s output or a customer’s load from one control area

to another

Seconds

System-blackstart

capability

The ability of a generating unit to go from a shutdown

condition to an operating condition without assistance from

the electrical grid and then to energize the grid to help other

units start after a blackout occurs

When outages

occur

Network-stability

services

Maintenance and use of special equipment (e.g., powersystem stabilizers and dynamic-braking resistors) to maintain

a secure transmission system

Cycles

aUnlike spinning reserve, supplemental reserve is not required to begin responding immediately.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-14

0 15 30 45 60

Time (minutes)

Actual and Requested

Generator Output (MW)

Actual

AGC Signal

620

640

660

680

700

720

740

390

400

410

420

430

440

450

0 15 30 45 60

Time (minutes)

Actual and Requested Generator Output

(MW)

Actual

AGC Signal

31 MW

Figure 3-1. Well-Behaved

Generator Providing

Regulation

The degree to which the

supplier is delivering the service

must be measured.

Figure 3-2. Poorly

Behaving Generator

Providing Regulation

Prices and enforcement

contracts should provide the

proper incentives and penalties

when units do not perform well.
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-15

0.01 0.1 1 10 100

Time (minutes)

Energy

Imbalance Voltage Control

Regulation

Load Following

Frequency Responsive Spinning Reserve

Supplemental Reserve

Backup Supply

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hour

$/MW-Hr

Regulation Spinning

Nonspinning Replacement

3.3.6 Reduced Generator and Transaction Sizes

After nearly a century of increasing efficiency coming with

increasing central generator size, there are indications that

distributed micro sources may be the wave of the future. Fuel cells,

micro turbines, and internal combustion engines are all vying to

enter the competitive generation market. Often the primary focus is

to sell energy or backup power, but it will not be long before

Figure 3-3. Ancillary

Service Time Frames

The time frames for ancillary

services vary greatly.

Figure 3-4. Average

Ancillary Service Prices

for December 1998

Weekdays in California

Real-time measurement and

quantification of ancillary

services is needed because of

the volatility of hourly prices.

Deregulation will lead to a

larger number of small

loads and generators

participating in real-time

energy and ancillary service

markets.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-16

owners and manufacturers of these devices realize that the other

ancillary services may provide additional sources of income.

Similarly, load can and will participate actively in real-time energy

and ancillary service markets. Both trends push the size of realtime transactions down from tens to hundreds of MW to tens of

kW.

This trend to active market participation by smaller resources

(generators and loads) may be a tremendous boon. If loads

supplied all contingency reserves (certainly possible) at times of

peak usage, this would immediately free up approximately

7 percent of existing generation to serve new load. Existing

emergency backup generators could supply additional thousands of

MW of capacity.4 This, in fact, was the motivation in the fall of

1999 for the Texas PUC to accelerate developing interconnection

standards for distributed generation.

Most small resources have the added advantages of being agile,

inherently providing fast response in real time. They are generally

faster to deploy and easier to site too.

Aggregation, communications, and metering are significant

obstacles to deployment of large numbers of distributed resources

(generation and loads). System operators are used to dealing with a

relatively small number of large resources when controlling the

power system. They do not have the tools needed to communicate

with large numbers of small resources. Metering presents an

additional problem. It is not practical to outfit a 50 kW

microturbine with the same data acquisition and telemetry suite

that is typically deployed on a 500 MW steam plant.

3.3.7 Power Quality

Restructuring does not inherently change either the vulnerability to

poor power quality or the importance of maintaining high power

quality. However, the increasing use of sensitive electronic devices

and power electronics in both loads and distributed generation will

lead to power quality issues. There is an increasing need to be able

to locate sources of harmonics and flicker on the power system.

 

4There is considerable debate over the exact number.
Section 3 — Future Implications of Deregulation for the Electric Power Industry

3-17

There will probably be a need to regularly monitor large numbers

of locations on the power system.

3.3.8 Supplier Choice

Providing end users with the flexibility to choose their power

supplier may entail significant technical challenges. Generally

supplier choice is limited to the source of bulk energy. If customers

could be tied more closely to their chosen suppliers, through the

existing network, additional market efficiencies would be tapped.5

For example, a customer could choose a lower cost, lower

reliability supplier. The customer would see increased interruption

but pay a lower price for electricity. Alternatively, a customer

could pay a higher price for added reliability. This would allow

individual customers to balance reliability and price, providing

clearer market capacity expansion signals.6

3.4 CONCLUSIONS

The final form of a restructured electric power industry is far from

clear. It is likely that regional differences will persist. Several

trends appear to be well established:

Z Reliance on commercial provision of services requires

increased metering, communications, and control

capability.

Z Individual transactions will increase in importance, and

metering must accommodate smaller transactions and

smaller entities (both loads and generators).

Z Individual real-time services will be unbundled. Revenue

metering must accommodate faster transactions and

comparisons between requested and delivered responses.

Z Increased response will be required from the transmission

system, and technologies that allow the transmission system

to provide increased responses will have value.

 

5This would be the equivalent of dynamically scheduling each load to its chosen

supplier.

6This would only address generation-related reliability or adequacy issues. It would

not address distribution reliability issues, which account for most residential

outages. Still, generation adequacy and expansion are major concerns.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

3-18

The metering, communications, and control requirements of a

restructured electric power industry appear to be more related to

the fundamental change of increasing reliance on markets and

contracts and decreasing reliance on regulation and vertical

integration than they are on the specific restructuring

implementation. Similarly, the need to extract more performance

from the transmission system is related to the difficulty to construct

transmission and increasing commercial pressure to use

transmission, not to the specifics of how industry restructuring

moves forward. As a result, the need to advance metering and

monitoring technology seems to be broadly based on national

requirements that are not sensitive to the details of restructuring

implementation (i.e., different restructuring scenarios).

In addition, whether deregulation is examined from the wholesale

or retail perspective has surprisingly little impact on the type of

metering that is required. The amount of metering may be different

at the wholesale level versus the retail level. Wholesale

transactions may require metering only for large entities (generators

and large loads) and aggregations of small entities (primarily loads)

while retail transactions require metering for all entities. The type

of metering that is required, however, depends on the service being

measured, which in turn relates to physical phenomena on the

power system.

The physical laws governing the power system’s behavior do not

change with deregulation. Accomplishing the required minute-tominute generation and load balancing, for example, requires

metering that measures energy flows at least that fast. Addressing

this minute-to-minute balancing at the retail level requires more

metering, not different metering than what is required at the

wholesale level. Because of the difference in consequences to the

power system from a failure at the wholesale vs. retail level, there

may be different reliability requirements for the metering but not in

what is fundamentally being metered. Similarly, it does not matter

if metering requirements are examined from the supplier’s or the

consumer’s perspective. In both cases, the same phenomena is

being measured. Nor does it matter if metering requirements are

examined from the FERC perspective of comparability or the NERC

perspective of reliability. Again, the same underlying physical

phenomena are being measured.

The metering,

communications,

and control

requirements of a

restructured electric

power industry

appear to be more

related to the

fundamental change

of increasing

reliance on markets

and contracts and

decreasing reliance

on regulation and

vertical integration

than they are on the

specific

restructuring

implementation.
4-1

Measurement and

Standards Needs

to Support 4 Restructuring

This section discusses broad measurement and standards

requirements to support reliable operations and commercial

transactions on the electric power system in a deregulated

environment. Measurement requirements, in this context, include

the basic physical measurements as well as the associated

communications and control requirements.

Standards support requirements are related directly to the

measurement requirements. However, they are organized here into

the two categories described in Section 2: system operations and

market transactions. These standards support requirements are not

spelled out in detail—that is the appropriate role for the various

standards organizations cited in Section 4.2.

Although systems operation (e.g., reliability) and market transactions

(e.g., market development) concerns differ in many important

aspects, they are also inseparable and often complementary. We

surveyed a broad range of industry experts to capture the full range

of concerns from the supply and demand sides as well as from the

operations and planning/investment sides.

4.1 MEASUREMENT NEEDS

Measurement needs include the physical quantities that must

actually be measured and the speeds at which they must be
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-2

measured. We describe the underlying trends that are changing

measurement requirements and examine the importance of

differences among individual customers. This section also discusses

measurement and control communication requirements and how

these may change with deregulation. Finally, we discuss unique

measurement requirements for the transmission and distribution

systems.

4.1.1 Physical Measurement Requirements

In one sense, there are very few measurement requirements on an

interconnected power system. Voltage and current are the two

fundamental electrical quantities of interest. Other quantities, such

as real and reactive power and energy, are derived from

measurements of voltage, current, and the phase angle between the

two. Phase angle itself is not really a fundamental measurement but

is derived from the temporal relationship between the periodic

voltage and current fluctuations (alternating current). Measuring

harmonics, flicker, sags, surges, and dropouts involves measuring

voltage and current over different time frames.1 Similarly, even

though consensus has not yet been reached concerning the exact

definitions of the ancillary services (or the related NERC

Interconnected Operations Services) discussed in Section 3, it is

clear that they involve measuring real and reactive power delivery

and consumption over various time frames.

Table 4-1 presents the measurement requirements for a range of

services of interest under wholesale and retail power deregulation.

Note that, although the time frames presented are typical, exact

requirements vary from location to location depending on the way

each service is defined. Also note that the reporting time frame is

listed as “periodic” for all of the services because it is not strictly

necessary for the system operator to directly observe the response of

each resource supplying reliability services in real time.

The wide range of voltages involved in the electric power system

complicates the measurement of voltage and current. Transmission

line voltages are up to 765 kV (nominal line-to-line voltage), but

 

1The unique nature of power quality issues such as flicker, harmonics, sags, surges,

and dropouts may warrant individually designed meters for each. Still, they are

only measuring voltage and current.

Voltage and current are the

two fundamental electrical

quantities that need to be

measured to monitor an

interconnected power

system.
Section 4 — Measurement and Standards Needs to Support Restructuring

4-3

Table 4-1. Measurement Requirements Under Deregulation

Services are differentiated by the time frame over which the service must be deployed and measured and the response

reported.

Service or Concern Product Attributes

Measurement

Time Frame

Deployment

Time Frame Reporting Time Frame

Power Quality

Harmonics Voltage and current <1 second

Flicker, sags, surges,

dropouts

Voltage ~1 second

Periodic measurement

when problems are

reported

Ancillary Services

Regulation Watts ~1 minute ~1 minute Periodic

Stability Watts and/or vars <1 second <1 second Periodic

Contingency reserve—

spinning

Watts Seconds Seconds Periodic

Contingency reserve—

supplemental

Watts <10 minutes <10 minutes Periodic

Load following Watts ~15 minutes Minutes Periodic

Backup supply Watts ~30 minutes Minutes Periodic

even the 13 kV of typical distribution systems is too high for most

direct electronic measurement. Currents are generally too high for

direct measurement, both at the elevated and the lower voltages.

Voltage transformers, which are often referred to as PTs (for

“potential transformers”), are used to scale the voltage of interest

down to a more easily measured range. Current transformers (CTs)

are used to both scale the electric current of interest down to a more

reasonable range and to extract the electric current signal at a

voltage much closer to zero than line potential. PTs and CTs are

not to be confused with power transformers, which are very large.

PTs and CTs are expensive, and careful attention must also be paid

as to how these devices distort the measurements being made.

Measurement Synchronization

Time synchronization is very important for some measurements.

The Wide Area Measurement System (WAMS) uses precisely

synchronized measurements of voltage and current (real and

reactive power and voltage) collected from locations dispersed over

large geographic areas to observe the dynamic behavior of the
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-4

power system. This is particularly important in the Western System

Coordinating Council (WSCC).

Temporally synchronizing data is also a concern with more

conventional measurements. Many conventional system control

and data acquisition (SCADA) systems collect data by sequentially

polling the sensors on the system every few seconds. Measurements

obtained from sensors polled early in the cycle are not

synchronized with measurements obtained from sensors polled late

in the cycle. This is especially problematic if a significant event

occurs during the cycle and the system operator (or automatic

control equipment) is trying to understand what has occurred. For

example, flows might be different at two ends of a transmission line

because the line is damaged or one measurement was taken before

a generator tripped and the other was taken after it tripped. This

problem increases as additional commercial entities start to handle

data and as equipment from multiple vendors is used. Some form of

time-stamping the data may be needed.

Additional Measurements

A number of other parameters are measured to ascertain the present

capability or status of the transmission system. For example, most

electrical devices are inherently temperature-limited because the

device’s electrical resistance generates heat as current flows through

the device. Excessive heat can cause instantaneous failure or

shorten equipment life.

Equipment capacity ratings (e.g., the power flow capacity of

transmission lines or transformers) are often based on the

temperature that will result at some critical component under

specific environmental conditions such as ambient temperature and

wind speed. The device might actually have more or less capacity

under different environmental conditions. Directly measuring the

temperature of the limiting component could allow higher

utilization of transmission capacity without compromising safety.

Historically, measuring the critical temperature has been difficult

because knowing exactly which component is critical and making

measurements on energized equipment are difficult tasks. For

example, determining which span of a transmission line is the

limiting span depends on the direction of the wind and the limiting

Most electrical

devices are

inherently

temperature-limited

because the device’s

electrical resistance

generates heat as

current flows

through the device.
Section 4 — Measurement and Standards Needs to Support Restructuring

4-5

span may change with cloud cover. The electrical environment

makes determining the temperature inside a 345kV cable and

transmitting that information to the system operator much more

difficult.

Overhead transmission lines are thermally limited because heat

allows the conductor to expand. If the conductor gets too hot, it

will permanently weaken or fail. Most lines reach a sag limit (i.e.,

the conductor lengthens enough that the center of the span is too

close to the ground or to structures under the line) before the

conductor is permanently damaged by heat. Limits for current are

established for most lines based on the sag calculated to result from

that current under specific assumptions of ambient temperature and

wind. Limits could be based on direct temperature measurements

instead allowing line loadings to be raised until the line is truly at its

physical limit. Alternatively, sag could be measured directly, or line

tension could be measured to calculate sag.

Status measurements on numerous devices throughout the power

system are also required. Breaker and switch positions are

important. Generator status is important. Many system operators

require reporting generator capability regularly, either by direct

measurement or by the generator operator updating the capability.

Supplemental information, such as hydrogen pressure, is often

required to be sensed and reported directly to the system operator.

4.1.2 Underlying Trends Changing Measurement

Requirements

Three interrelated forces are driving the need for clearer definitions

of service requirements and an increased need for measurements

and communications:

Z Reliance on commercial arrangements (contracts) between

service suppliers and the system operator requires clearer

definitions of the services being provided than was needed

with vertical integration.

Z Unbundling of individual services (e.g., regulation,

contingency reserves) requires defining each service and

measuring performance.

Z The introduction of competition to replace regulated

monopolies requires more explicit and definitive service

definitions and performance measurements that can be

reflected in contracts.

Direct measurement of

ambient line conditions

would help to more

accurately estimate current

limits and increase

utilization of transmission

assets.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-6

These three interrelated forces dramatically change the

measurement requirements even when there are no physical

changes in the power system. Many more measurements at many

more locations are required to assure that specific contracted

services are being provided. A competitive commercial entity may

not deliver a service if delivery is not monitored. If an honorable

entity does deliver the unmonitored service, a less ethical

competitor may undercut the service price and win the next

contract, because its price need not cover the cost of actual

delivery.

Physical changes in the power system compound the increased

measurement requirements. Changes in the size of generators, the

inability to build new transmission, and the potential for customer

loads to enter the ancillary service markets as suppliers all

contribute to an increased need for measurements. Fortunately, the

enabling technologies of computing, communications, and

electronics are getting dramatically cheaper, so that the additional

measurement requirements will not be cost prohibitive.

Physical Changes in the Power System

Technological advances are changing the measurement,

communications, and control requirements of the power system as

well. These advances are primarily tied to the resources that are

available to provide energy and reliability services.

Z Generators are getting smaller. After a century of everincreasing efficiency coming with ever-increasing size, we

are seeing that trend reverse, perhaps dramatically. This

trend is coupled with the availability of competitively priced

natural gas as a power generation fuel. Until recently, unit

sizes were increasing above 1,000 MW to achieve greater

efficiency. Now, combined-cycle units, which use

combustion turbines and gas boiler technology in the 50 to

300 MW range, have impressive thermal efficiencies (some

claim to be near 60 percent). We are also seeing

microturbines less than 100 kW range nearing commercial

viability. Internal combustion-driven generator efficiency is

increasing dramatically as well. Especially at times of high

peak prices, we will likely see numerous generators in the

<100kW size in use at customer sites.

Z Replacing a 1,000 MW generator with multiple, smaller

(e.g., 10,000 100 kW) generators raises concerns about the

cost of metering and data communications as well as

concerns about data overload. Replacing a 1,000 MW
Section 4 — Measurement and Standards Needs to Support Restructuring

4-7

generator with multiple, smaller generators also changes the

risk assessment for failure of the resource to perform. This

changes the assessment of metering and data

communications needs related to assuring system reliability.

Z The introduction of demand-side elasticity (price-responsive

load) and load as a resource selling reliability reserves to the

power system compounds this problem because the sizes of

the individual loads that are price-responsive may be very

small.

Z Advances in electronics, computing, and communications

need to be exploited to reduce costs and increase the

opportunities for these resources to participate in electricity

and reliability service markets.

Precision and Traceability

Deregulation, corporate unbundling, and the introduction of

competition change the precision and traceability requirements of

measurements. Currently, revenue metering for energy is distinct

from operational metering. Revenue metering is generally more

precise, meets tighter standards, and has better traceability to

primary standards. Revenue metering is also more expensive and

generally does not operate as fast as operational metering. It

generally deals with energy consumption over 15 minutes or an

hour. Operational metering, on the other hand, is used by the

system operator to facilitate control of the power system. And

traditionally systems have had sufficient margins so that it is not

necessary (or economical) to precisely measure all performance

parameters. However, as safety margins shrink with the cost-cutting

pressures of deregulation, the precision of operational metering may

need to increase. Traceability and precision are not as high a

concern. Redundancy in the metering and state estimation

increases the operator’s view of the overall system without

increasing the cost of individual measurements.

With deregulation and unbundling of services, the scope of revenue

metering greatly increases. Many more activities that generators

previously performed on command by a system operator that

“owned them” will now need to be compensated for based on

measured performance. As a result, meter quality (precision, speed,

and reliability) is an important commercial issue for many more

measurements.

With deregulation

and unbundling of

services, the scope

of revenue metering

greatly increases.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-8

4.1.3 Customer Differentiation

It has long been recognized throughout the industry that different

customers impose different requirements on the power system.

Figure 4-1 shows the power consumption for a steel mill and an

aluminum plant for an hour. Clearly, the steel mill is imposing a

significantly greater regulating burden on the power system than the

aluminum mill. Historically, this difference was addressed through

the bundled rate offered to each customer by the vertically

integrated utility. That rate might, or might not, accurately reflect

the total cost to serve each customer. Deregulation is changing

how individual customers are treated.

Figure 4-1. Individual Loads Impose Different Regulation Burdens on the Power System

Under deregulation, customers will be charged for the different burdens their loads place on the system.

0 10 20 30 40 50 60

Minutes

PU Load

Steel Mill

Aluminum Smelter

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

FERC recognizes that customers use different amounts of ancillary

services as well as different amounts of energy and capacity. In a

recent Notice of Proposed Rulemaking, FERC states “The

Commission believes that, whenever it is economically feasible, it is
Section 4 — Measurement and Standards Needs to Support Restructuring

4-9

important for the RTO [Regional Transmission Organization] to

provide accurate price signals that reflect the costs of supplying

ancillary services to particular customers” (FERC, 1999). Similarly,

in Order 888 FERC states that because customers that take similar

amounts of transmission service may require different amounts of

some ancillary services, bundling these services with basic

transmission service would result in some customers having to take

and pay for more or less of an ancillary service than they use. For

these reasons, the Commission currently concludes that ancillary

services, such as system control, voltage control from generation,

regulation, contingency reserve-spinning, contingency reservesupplemental, and energy imbalance, should not be bundled with

transmission service.

Differentiation among individuals is not limited to loads or

regulation. Analysis of data from specific generators indicates that

they impose very different reliability reserve requirements on the

power system, as shown in Figure 4-2. Similarly, analysis of data

from specific generators indicates that they provide very different

regulation support to the power system.

All of this supports the need to assess each entity for the individual

support it provides or burden it places on the power system.

Metering is required to make this assessment and to respond at the

appropriate rate for each service. This change means a large

increase in metering and data processing requirements.

4.1.4 Communications

Communications requirements also need to be re-examined. Like

measurement speed requirements, communications requirements

are tied to the service being provided and the function being

performed. Communications requirements in both directions

(system operator to resource and resource to system operator) must

be addressed separately.

Historically, the system operator dealt with relatively few large

generators. SCADA systems were designed on the basis that

information was collected every few seconds by polling each data

collection point throughout the system. Techniques to reduce the

quantity of data, such as reporting only status changes, were used.

With deregulation, it will

be increasingly important

to assess each entity for the

individual support it

provides or burden it

places on the power

system.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-10

Figure 4-2. Individual Generators Impose Different Reliability Burdens on the Power System

Under deregulation, individual generators will be held responsible for the different reliability burdens they impose on

the system.

Number of Forced Outages per Year

Percentage of Units

120 Coal Units, 6 - 800 MW,1996

Average = 9 outages/year

0

2

4

6

8

10

12

14

16

18

0 2 4 6 8 10 12 14 16 18 20 >20

Commands were sent to generators and a generator’s output was

observed every 2 to 8 seconds (depending on the utility) to see if the

generator was responding. This system worked well and made

sense for large generators. It is not clear if this is the best system for

numerous small generators or for responsive load, however.

The basic requirement to get command signals from the system

operator to the resource quickly still exists. Very fast signals, based

on local conditions or system frequency, do not have to come from

the system operator; they can be locally derived. Response must

also be monitored in the same fast time frame. It may not be

necessary, however, to send the response signal back at the present

rate. It might be better to monitor performance locally and report

back at the end of the billing period. The system operator would

still be aware of the aggregated (total system) response, but the

individual composition of that response would not be immediately

available.

System operations, however, may be improved with increased

number of suppliers because the reduced size of each individual
Section 4 — Measurement and Standards Needs to Support Restructuring

4-11

supplier reduces the consequences of individual failures to respond.

It might be easier to predict the statistical behavior of a large fleet of

smaller resources than a small fleet of larger resources.

4.1.5 Transmission

Transmission (and distribution) will likely remain regulated and will

be shielded from some of the commercial pressures that generation

and load will experience. However, measurement,

communications, and control requirements for transmission will

change too.

Independent of deregulation, increasing public opposition to new

overhead transmission lines makes increasing transmission system

capacity through new construction difficult. Deregulation

compounds this problem by making it more difficult to argue that

transmission is built exclusively for reliability reasons and then to

use power of eminent domain to obtain right-of-way. Under

deregulation, transmission is built largely for economic reasons,

when it provides a better economic choice than locating additional

generation closer to the load. The shift from reliability to profit for

the justification of new transmission corridors increases the

difficulty of building new transmission capacity when public

approval is required.

Separating transmission and generation also makes solving

transmission operating problems (overloads) with traditional

generation solutions (redispatch) more difficult. With a vertically

integrated regulated monopoly, a transmission loading problem

could be solved by redispatching generation with all customers

paying the increased costs associated with off-economic dispatch

through slightly higher average rates. Now, individual generators

have a strong interest in restrictions on their operations and will

oppose curtailments in their individual operations based on

transmission loading. This problem is compounded by the increase

in the number of transactions occurring.

All of this results in increasing transmission loading, little ability to

install new capacity, and difficulty in using redispatch to alleviate

transmission congestion. Extracting increased performance from the

Independent of

deregulation,

increasing public

opposition to new

overhead

transmission lines

makes increasing

transmission system

capacity through

new construction

difficult.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-12

existing transmission system is an important alternative.2 Improved

measurement capabilities are needed to increase performance.

Z Better measurement of actual conditions is required to

provide the system operator with a more accurate picture of

how close the system is to real limits. This picture includes

a more complete picture of the electrical activity on the

power system as well as a more complete picture of the

equipment conditions. For example, real-time monitoring of

line and transformer temperatures can help provide this

more complete picture.

Z Increased ability to measure system dynamic performance

and to evaluate contingency situations is required to allow

the system operator to operate closer to the system dynamic

limits while maintaining or increasing reliability. Increased

use of WAMS and voltage security calculations could help.

Z Increased capacity to manage market transactions is needed.

Systems that relieve the system operator’s administrative

load, reduce errors, and make inputting and tracking

transactions easier are required. These systems may include

software to support user-friendly interfaces and display

systems to enhance human–machine interactions.

The benefits of these developments are not only to maintain existing

levels of system reliability. They also include increases in the

effective capacity or transfer capability of the system, increased

efficiency of operation, and reduced administrative costs of serving

a larger number of more diverse transactions.

4.2 AREAS WHERE STANDARDS MAY HAVE

MAJOR BENEFICIAL IMPACTS IN A

DEREGULATED UTILITY INDUSTRY

As described above, several issues are emerging as electric industry

deregulation proceeds. Several of these issues may benefit from the

development of standards by standards committees at the industry,

professional society, regulatory agency, or other levels.

Some examples of organizations that can and may currently be

contributing to the development of these standards are

Z Institute of Electrical and Electronic Engineers (IEEE),

Z National Electrical Manufacturers Association (NEMA),

 

2Other alternatives include placing distributed generation nears loads and

increasing use of load management programs.
Section 4 — Measurement and Standards Needs to Support Restructuring

4-13

Z American National Standards Institute (ANSI),

Z North American Electric Reliability Council (NERC) (or its

successor, North American Electric Reliability Organization

[NAERO]),

Z Edison Electric Institute (EEI),

Z Electric Power Research Institute (EPRI),

Z Federal Energy Regulatory Commission (FERC),

Z National Association of Regulated Utility Commissioners

(NARUC),

Z states (regulators and/or legislators),

Z National Regulatory Research Institute (NRRI), and

Z NIST.

This list of organizations is illustrative, not all-inclusive. Standards

committees that include representatives from one or more of these

organizations will help to integrate a diverse set of issues and

considerations into the standards development process. Such

committees may also help build a broader base of acceptance for

the standards that are developed.

We have separated opportunities for standards into those to support

system operations and those to support market transactions. This

separation is made for expositional convenience and because the

key “users” in each of the two are different. However, the two areas

are not mutually exclusive because reliability and commerce are not

mutually exclusive. Thus, some of the opportunities mentioned in

the first area may benefit the second, and vice versa.

These opportunities are a summarization of the needs for standards

cited by respondents to our survey. A copy of the survey instrument is

presented in Appendix C. A listing of these responses by type of

respondent and by response area is included as part of the full range

of notable comments provided by survey respondents in Appendix D.

4.2.1 Opportunities for Standards to Support System

Operations Needs

The contributions of standards in support of systems operations will

primarily be to help system operators maintain system reliability in

the face of expanded and more complex transactions and power

flows. Standards may also contribute to the reliability of the system

operators themselves by helping them manage and act on the

expanded flow of information. Well designed, performance based

The key driver behind the

potential value of standards

in a deregulated electric

industry is the change from

a vertically integrated

structure to one that relies

on competitive markets to

supply critical reliability

services.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-14

standards can lower costs as well as increase reliability by

encouraging innovation and allowing markets to find the most cost

effective way to provide needed reliability services.

Some key areas where technology standards may contribute to the

needs of system operators include the following:

Z standardization of information availability requirements will

be important to support competition. Currently some

purchasers have a competitive advantage because of

asymmetric information;

Z expanded and more frequent measurement and

communication of system conditions (e.g., operational status

of key equipment and components, real-time monitoring of

line and transformer temperatures, online transfer capability

evaluation) to system operators;

Z measurement and communication of transmission system

dynamic performance (e.g., system transient behavior,

WAMS, and monitoring of voltage collapse) to system

operators;

Z more frequent measurement and communication of

distributed generators’ output (aggregated) to system

operators. For example, standards are needed to increase

the amount of information returned from generation. In

particular, system operators need better information of the

timing of loads being generated;

Z dynamic control of distributed generation to maintain system

reliability and to access potential ancillary service benefits;

Z measurement and communication to system operators of

ancillary services provided by generators (utility and

merchant plants) and customers (though onsite generation or

load curtailment);

Z security requirements to maintain system integrity as the

market opens up and the number of players increases; and

Z enhanced software to help system operators manage the

increased data flows, calculate key system parameters of

interest, and present the information in a manner that avoids

information overload and facilitates quick decisions.

A central theme throughout our interviews was that industry should

move away from prescriptive standards and toward performance

based standards. In addition, particular standards should not be

built around existing system characteristics because this stifles

innovation by locking in technology-based solutions. Standards are

needed to establish a minimum set of functionality. Establishing

functionality standards will promote competition and lower barriers

to entry.
Section 4 — Measurement and Standards Needs to Support Restructuring

4-15

Interviewees also emphasized that interoperability and conformance

testing of communications protocols are essential to support the

integration of area systems. In addition, product conformance is

important because without it products might have trouble

interconnecting in a network or even fail in performing basic

operations. In some instances, regulations and standards are in

place, but there is no enforcement. For example, there are currently

standards for equipment accuracy in many states; however, state

agencies do not have the budget for compliance testing and

enforcement.

4.2.2 Opportunities for Standards to Support Market

Transactions Needs

The contributions of standards in support of market transactions will

primarily be

Z to help assure interoperability among equipment and

systems provided by different vendors and to help provide

reliable and precise information for contracts (e.g., billing,

performance measurement and verification) and dispute

resolution and

Z to help develop pricing systems that reflect proper incentives

and to support development and enforcement of

noncompliance penalties.

Growth in metering, monitoring, and communications needs within

the industry is spawning, and will continue to spawn, more vendors

and equipment. This growth can increase the risk of lost

opportunities with deregulation to the extent that the equipment and

systems cannot “cross-talk” effectively and provide the full range of

information needed by each new market player.

The contracts support function is necessary because explicit

contracts are increasingly replacing informal agreements. This trend

is a result of the change in industry structure from regulated,

integrated electric utilities who coordinate their efforts primarily

though informal agreements, to functionally unbundled electric

utilities who compete in the provision of generation, ancillary

services, and retail services. Competition requires explicit contracts

to facilitate coordination and cooperation.

Contract support here differs from system operator support

described in Section 4.2.1, not only in terms of the type of

information required and at what level, but also in terms of how

Interviewees also

emphasized that

interoperability and

conformance testing

of communications

protocols are

essential to support

the integration of

area systems.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

4-16

frequently it needs to be provided. Contract support will typically

require information on a more disaggregated level (e.g., for

individual loads rather than for entire substations), rather than

monthly readings of these values, etc., but the information is

typically communicated less frequently (e.g., monthly rather than

hourly or subhourly).

Standards will be needed to provide proper pricing signals for

transmission services. For example, new tools/procedures are

needed to help the market value power at bulk transmission

interfaces. These include new measurement and reporting

procedures to collect and distribute information on utilization of

these interfaces. Some interviewees said that the existing pricing

systems for bulk transmission provide incentives for congestion.

Some additional areas where technology standards may contribute

to the smooth functioning of wholesale and retail markets include

the following:

Z creation of a seamless electronic data interchange (EDI)

between metering and communication software and

equipment, so that retail market players (e.g., generation

suppliers, local wires utility, aggregators, billing companies)

can obtain the various data they need when they need it;

Z consideration of standards and protocols for EDI that reflect

the growing use of the Internet (and the Internet Protocol, or

IP) to link services across utility providers (the

“convergence” trend) and cover international borders (the

“globalization” trend);

Z tracking of generator supply: whether and when they

supplied generation or ancillary services to the system as

required by contracts;

Z tracking of retail customer and power marketer/broker

curtailments: whether and when they supplied load relief or

ancillary services to the system as required by contracts;

Z tracking/tagging of power flows to assign cost responsibility

for congestion on overloaded lines and constrained

interfaces;

Z more precise measurement of standard billing parameters

(e.g., energy, demand, power factor) to support contracts

that were previously not in place or that were not explicit if

they were in place;

Z more precise measurement of power quality, especially

harmonics, flicker, sags, and surges to support contracts that

were previously not in place or that were not explicit if they

were in place; and

Standards will be

needed to provide

proper pricing

signals for

transmission

services.
Section 4 — Measurement and Standards Needs to Support Restructuring

4-17

Z better definitions of what is “NIST traceable.” For example,

almost all metering equipment claims to be NIST traceable.

However, the number of steps involved in the traceability

chain influences accuracy.

4.2.3 Summary

Measurement requirements and related needs for standards

development is, or needs to be, underway in several areas to help

secure the benefits that are potentially available in a deregulated

electric industry. We have summarized some of the key areas in

this section.

The development and application of standards are not without their

own costs, however, and they may lead to some adverse side effects

as noted in Section 1.2. A decision on whether to pursue standards

in any area requires a prospective assessment of the benefits and

costs of standards for that area. Retrospective assessments of these

benefits and costs are also valuable, not so much to affirm or

withdraw the original decision, but to help refine the techniques

and areas of investigation in assessments that will be made in the

future.
5-1

Economic Impact of

Measurement and 5 Standards

Measurement and standards to support the electric power industry

will have a potentially large impact on the U.S. economy for two

main reasons:

Z Measurement and standards are becoming increasingly

important as deregulation proceeds.

Z In 1998, U.S. electric utility retail sales of $217.4 billion

represented one-quarter of 1 percent of U.S. GDP of

$8,759.9 billion. Reliable, low-cost power is a cornerstone

for almost every sector of the economy.

This section discusses the pathways through which measurement

and standards will affect the electric power industry and, hence, the

U.S. economy. The discussion is structured around 11 key

issues/benefits/concerns, referred to as impact areas, associated

with deregulation. For each impact area, we discuss the magnitude

of the potential economic impact and the importance of

measurement and standards for addressing the

issues/benefits/concerns. In addition, we discuss the level of

uncertainty associated both with the evolution of the industry

structure and future technology developments and with the future

role measurement and standards will play.

This section also presents monetary range estimates that provide

insights into the potential magnitude of the economic impact

(benefits) of measurement and standards in supporting deregulation

of the electric power industry. The underlying insights used to

develop the economic impact estimates are based on a series of

This section

discusses the

pathways through

which measurement

and standards will

affect the electric

power industry and,

hence, the U.S.

economy.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-2

scoping interviews and surveys with industry experts, and they

reflect the authors’ interpretation of information collected from

these respondents.

5.1 PATHWAYS TO ECONOMIC IMPACTS

Table 5-1 presents some of the potential impacts of measurement

and standards identified through the scoping interviews. The

impacts are presented as the benefits associated with meeting the

measurement and standards needs of the power industry (as

opposed to the costs of not meeting the industry’s needs).

Table 5-1. Benefits Associated with Measurement and Standards

Benefits are generally grouped relative to their impact on technical efficiency and/or clean power.

System Operation Market Operation

Technical Efficiency Z Alleviate transmission constraints

Z Lower the cost of generation

Z Lower the cost of ancillary services

Z Lower the cost of generation

Z Lower the cost of ancillary services

Z Lower the cost of metering, data

transfer, and data processing

Z Provide incentives for demand-side

changes (peak reduction)

Clean Power Z Reduce the duration and frequency of

power outages

Z Reduce the installation of backup and

protective equipment

Z Diagnose and verify power quality

problems at utility and customer levels

Z Support market for variable power

reliability

Z Support market for variable power

quality

Most of the categories in Table 5-1 are interrelated. For example,

efficiency gains in the form of lower-cost generation and ancillary

services will require measurement and standards to support system

operation and market operations. Enabling customers to access the

lowest-cost electricity service will require an efficient market

structure to enable transactions and the physical system to

efficiently facilitate the market transaction.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-3

As indicated in Table 5-1, measurement and standards will affect

both economic efficiency of the power supply and the level of

reliability and quality of power. In general, economic efficiency

includes achieving the lowest cost for the generation, transmission,

and distribution of electric power. Cost savings can include both

the reduction in variable inputs (e.g., by using more fuel-efficient

generation) and the avoided cost of new capital investment (e.g., by

reducing the need for new transmission assets).2

In contrast, power reliability and power quality, also referred to as

clean power (from an end user perspective rather than from an

environmental perspective), are related to factors that affect the end

users of electricity. Clean power affects end users by influencing

them to actively respond to changes in reliability and power quality

by installing backup and protective equipment or not responding

and bearing the impact of, for example, increased outages and

power surges on business activities.

5.2 ECONOMIC IMPACT AREAS

Table 5-2 lists the set of impact areas that were included in the

economic impact analysis. This table identifies key

issues/benefits/concerns associated with deregulation of the electric

power industry. For each issue/benefit/concern, the magnitude of

the potential issue is indicated along with the importance of

measurement and standards for addressing the

issue/benefit/concern.

The impacts of high/medium/low presented in Table 5-2 are based

on information obtained through telephone interviews and surveys

conducted with 40 industry experts (Table 1-2 lists the affiliations of

the respondents). The combination of “high” relative magnitude

and “high” importance of measurement and standards, such as for

 

1Gap analysis is commonly used in the strategic planning literature to compare

potential versus actual growth or efficiency gains.

2We do not trace these cost savings through to changes in price because

determining price changes involves estimating the distribution of savings

accruing to producers and consumers. And the focus of this study is on the

total change in social welfare as opposed to the proportional changes in

consumer and producer surplus. However, in the long run, all changes in

social welfare eventually accrue to consumers in the form of changes in price or

changes on the return to production assets that are owned by consumers.

Economic impacts reflect

the efficiency “gap” that

results from “inadequate”

measurement and

standards.1 Inadequate

measurement and standards

can lead to two general

categories of impacts:

Z increases in the cost of

supplying electric

power

Z costs associated with

decreases in the level

of reliability and

power quality

experienced by end

users of electricity
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-4

Table 5-2. Impact Areas Associated with Deregulation

The impacts of high/medium/low reflect opinions obtained through interviews and surveys with industry experts.

Issues/Benefits/Concerns

Associated with Deregulation

Relative

Magnitude

of Issues

Importance of

Measurement and

Standards

Variation in

Responses

System Operation

Achieving potential efficiency gains in power

generation resulting from increased competition

High Medium Low

Adequate and efficient provision of ancillary

services in a deregulated environment

Medium Medium Medium

Limited transmission capacity to support

increasing system demands resulting from

deregulation

Medium High High

Integrating distributed generation into the system

and fully using its resource potential

Medium High Medium

Increased duration and frequency of power

outages resulting from deregulation

High High Medium

Degradation in power quality resulting from

deregulation

High Medium High

Inadequate diagnostic tools capable of monitoring

system conditions and identifying problems

High Medium Medium

Market Operation

Increased cost, complexity, and vendor diversity

of metering equipment to support market

transactions

High Medium High

Increased cost of market transactions associated

with data transfer, processing, and billing

High High Medium

Development of markets for power of different

reliability levels

Medium Medium Medium

Development of markets for power of different

quality levels

Medium Medium High

increased duration and frequency of power outages resulting from

deregulation, indicate areas where measurement and standards may

have the greatest impact on social welfare. Other areas, such as

limited transmission capacity to support increasing system demands

resulting from deregulation, which have a “high” significance for

measurement and standards but a “medium” relative magnitude on

system costs, are projected to have less overall impact on social

welfare.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-5

The variation column reflects the respondents’ different opinions

and uncertainties for both the relative magnitude associated with

each issue/benefit/concern and the influence measurement and

standards may have on enhancing the benefits or mitigating the

problem. For example, most respondents agreed that measurement

and standards would have a small but positive impact on the

average cost of power generation—hence the variance is indicated

as “low.” In contrast, there was a significant difference of opinion

among respondents about the impact measurement and standards

may have on power quality to end users or on the development of

markets for differentiated power quality—hence the variance for

these impact area is “high.”

For each economic impact area presented in Table 5-2, we discuss

the relative magnitude of the issue/benefit/concern, the importance

of measurement and standards, and the variance of responses

below.

5.2.1 System Operations

Achieving Potential Efficiency Gains in Power

Generation Resulting from Increased Competition

Potential Economic Impact (High). Power generation costs exceed

$100 billion per year in the U.S. Deregulation and competitive

wholesale markets offer the potential to lower the average cost of

generation by increasing use of existing low-cost generators and

opening the market to new generation technologies with improved

energy efficiencies.

Role of Measurement and Standards (Medium). However,

competitive markets can only work if the customer has a basis to

compare the competitors. Comparisons cannot be made without

measurement and standards. For example, standards for

interconnection of new and different types of generation

technologies and customer-owned systems (including total energy

systems) to the grid are being developed, and they should help

secure generation cost savings with deregulation. In addition,

enhanced communications and information transfer systems will be

needed to support market functions.

Variation in Responses (Low). Most respondents felt that there was

little role for measurement and standards in increasing the
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-6

engineering efficiency of generation. However, they did agree that

measurement and standards were needed to support competition

and that this would lead to modest reductions in the average cost of

generation.

Adequate and Efficient Provision of Ancillary

Services in a Deregulated Environment

Potential Economic Impact (Medium). The provision of ancillary

services represents approximately $12 billion per year in the U.S.

The fundamental change that occurs with deregulation is the

reliance on competition and markets to provide the services that the

regulated, vertically integrated electric utility used to provide. The

regulator used to be able to hold the vertically integrated utility

accountable for the (qualitatively judged) final result of reliable,

affordable power. One of the goals of deregulation is that markets

will be able to provide these unbundled services more efficiently.

Role of Measurement and Standards (Medium). A common theme

associated with ancillary services is “you cannot buy or sell what

you cannot measure.” To unbundle ancillary services, each

service, each service provider, and each service consumer must be

measured. Standards to define the service and the service metrics

are essential to help the markets develop, by providing appropriate

guides to providers and useful service information to users.

Measurement to quantify service characteristics and performance

relative to these standards is essential.

Variation in Responses (Medium). Almost all respondents agreed

that improvements need to be made in the industry’s ability to

measure ancillary services. However, there was less agreement

about the potential efficiency gains that could be achieved as a

result of unbundling ancillary services in general. Some

respondents viewed measurement of ancillary services as more

important to the distribution of costs and less important to supply

efficiency or reliability.

Limited Transmission Capacity to Support Increasing

System Demands Resulting from Deregulation

Potential Economic Impact (Medium). Transmission is increasingly

difficult to build. Deregulation increases the pressure to obtain

ever-increasing performance from scarce transmission resources.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-7

Role of Measurement and Standards (High). Most transmission

limitations are based on assumed environmental conditions, such

as wind speed and temperature. Improved measurement can allow

transmission lines to be operated much closer to actual design

limits and to extract increased performance from the existing

system. For example, FACTS can help relieve constrained

interfaces through rapid reporting of power flows. However, the

incremental gain in efficiency from FACTS is likely to diminish as

their penetration grows because multiple devices in transmission

regions tend to “compete” against each other when “rerouting”

power flow.

Variation in Responses (High). Many respondents felt that limited

transmission capacity was the most significant obstacle to achieving

the potential benefits associated with deregulation. Because

bottlenecks are likely to be created at the major interconnections

and transfer points in the grid system, competition may be limited

to regional markets. In addition, many respondents felt that

straining the transmission system would affect power reliability,

leading to more frequent and larger-scale outages.

Alternatively, other respondents viewed the transmission capacity

issues as isolated, localized problems (primarily at major grid

interconnection points). They believed these issues could be

addressed through new technology and focused new transmission

capacity additions. They agreed that measurement and standards

would play an important role in resolving this issue; however, they

felt that capacity was sufficient for most of the transmission system

and that the enhancements needed to support deregulation would

not be extremely costly (relative to other issues such as metering or

communications needs).

Integrating DG into the System and Fully Using Its

Resource Potential

Potential Economic Impact (Medium). Fully integrating distributed

generation units into the power system will provide a variety of

potential benefits. Distributed generation represents many small

resources that inherently have reliability benefits when compared to

few large resources, all other things being equal. In addition,

distributed generation can be used to provide ancillary services,
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-8

such as regulation and load following services, and will help

alleviate transmission constraints.

Role of Measurement and Standards (High). Measurement and

standards will lower the cost of interconnection and hence increase

the availability of distributed generation for system support into

smaller units. Large central generators can more easily afford

expensive metering, communications, and control. They are also in

less need of standards governing interconnection and performance

requirements because they can financially support (and are in

greater need of) individual studies and negotiations. Distributed

generators cannot afford the same expenses on a unit-by-unit basis.

They require cheaper metering and standard interconnections

because there are so many more units to produce the same amount

of power. Measurement and standards for communication

protocols will also lower the cost of using distributed generation

and improve performance, hence increasing reliability.

Variation in Responses (Medium). Most respondents agreed that

the integration of smaller distributed generation units will yield

efficient improvements. However, there was disagreement about

the projected penetration of distributed generation. Beyond some

penetration level, which was not defined by the respondents,

distributed generation may create more power reliability and

quality problems than it solves. There was also disagreement on

whether distributed generation would help resolve or intensify

problems associated with power reliability and power quality.

Increased Duration and Frequency of Power Outages

Resulting from Deregulation

Potential Economic Impact (High). The greater stress placed on the

power system by the increased levels of transactions brought about

by deregulation will likely result in more frequent and longer power

outages. The costs of power outages include both decreased

productivity of labor and capital and increased expenditures on

backup equipment. The annual economic impact of power outages

is large because it affects all sectors of the economy.

Role of Measurement and Standards (High). Increased and

improved measurement and standards will help alleviate the greater

stress on transmission systems by supporting increased and more
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-9

efficient use of existing transaction assets. Appropriate standards

that define reliability services (e.g., outage frequency, duration, and

magnitude by major source) and help to commercially motivate

improved performance, coupled with measurement capability to

verify that performance, should improve reliability.

Variation in Responses (Medium). Respondents generally agreed

that the cost of power outages to industry is an important issue and

that better measurement and standards would help improve power

reliability. However, there was disagreement on whether

deregulation would significantly increase power reliability

problems and on how large an impact measurement and standards

can have on mitigating these problems. For example, measurement

and standards cannot eliminate outages caused by lightning and

other “acts of God”; however, they may be able to mitigate the

severity of such events.

Degradation in Power Quality Resulting from

Deregulation

Potential Economic Impact (High). Power quality issues will

become increasingly important with the increased use of sensitive

electrical equipment. The cost of poor power quality includes

equipment failures and lost productivity of labor and capital.

Role of Measurement and Standards (Medium). Increasing use of

power electronics (electronic ballasts and adjustable speed drives)

is increasing the injection of harmonics and flicker into the power

system and creating problems for loads susceptible to power quality

problems. Standards governing acceptable power performance and

measurements to locate the source of problems are needed to

maintain or increase power quality.

Variation in Responses (High). There was a broad range of opinion

on the subject of power quality. On one hand, many respondents

believed that power quality was an issue primarily confined to the

customer’s side of the meter and that deregulation of the electric

power industry would have little effect on power quality issues.

Also, power quality has many “dimensions” (e.g., surges, sags,

harmonics, flicker), and defining appropriate standards for any one

of these may vary with customer end uses and will raise many

issues as to what an appropriate standard in each case will be. On
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-10

the other hand, some respondents indicated that many power

quality problems could be solved with improved measurement

capabilities, which could then help move the development of

standards forward, and that the potential benefits are large.

Inadequate Diagnostic Tools Capable of Monitoring

System Conditions and Identifying Problems

Potential Economic Impact (High). Deregulation is expanding the

geographic range of transactions. FERC is encouraging

deregulation and encouraging the formation of RTOs to integrate

transmission system operations over large geographic areas.

Reliable operation of the integrated power system over these large

geographic areas requires greater observability for the system

operators. Increasingly more measurements must be coordinated.

Role of Measurement and Standards (Medium). Better tools are

required to convert raw data into meaningful information. System

operators in adjacent regions must be able to exchange data in real

time to construct a coherent picture of the entire power system.

Tools that can quickly analyze data on dynamic system

performance are needed to augment existing tools that are used to

analyze steady-state performance. Measurement and standards for

communication can increase the speed and decrease errors of data

exchange. In addition, measurement and standards can increase

interoperability of different systems and lower costs associated with

translation programs.

Variation in Responses (Medium). Almost all respondents

indicated that improved diagnostic tools to monitor system

conditions were needed and that measurement and standards could

play an important role in developing these tools. However, there

was concern regarding the cost-effectiveness of widespread

implementation of advanced monitoring systems. Several

respondents believed that the cost of such systems would limit their

implementation and, hence, their impact in the foreseeable future.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-11

5.2.2 Market Operations

Increased Cost of Metering Equipment to Support

Market Transactions

Potential Economic Impact (High). Approximately 1 percent of

electric power industry expenditures are related to purchasing,

installing, and maintaining metering equipment. Deregulation will

greatly increase these expenditures for both generators and loads as

the need for real-time metering increases.

However, increased metering will generate benefits beyond simply

supporting market transactions. Reliability and commerce are both

enhanced when markets are opened to the real-time participation

of more numerous and smaller resources. For example, on the

supply side, fundamentally it is better to spread contingency

reserves over numerous resources rather than to rely on a single

large generator. This is because there is always a danger that the

single generator will fail to respond when needed. Similarly, the

amount of contingency reserves that a utility must provide depends

on the size of the largest single contingency, usually the size of the

largest single generator. More numerous but smaller generators

result in increased reliability and reduced reserve requirements. In

addition, the statistical behavior of a larger group is easier to

predict.

On the load side, increased metering will enable the system to

leverage the benefits of variations in customer demand elasticity.

The benefits from enabling the customer as a resource are

potentially very large, and some respondents characterized them as

“hard to overestimate.” These benefits become magnified when

the power system is under stress and generation resources are

scarce.

Role of Measurement and Standards (High). Measurement and

standards can help reduce the cost of metering and

communications equipment for smaller resources. Metering costs

must be reduced for society to obtain the reliability and

commercial benefits that smaller resources offer. Fortunately,

volume also increases, so mass production benefits may be able to

be exploited once the “technical specifications” for market

participation are known and customer confidence in marketplace

offerings is enhanced by standards.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-12

Variation in Responses (Medium). Most respondents agreed that

standardizing functionality of metering and communications

equipment will support mass production and increase competition

and, hence, lower costs. However, most respondents indicated that

metering costs would increase as improved measurement and

standards broaden metering applications. And there was concern

that the high cost of advanced metering capabilities would delay

the benefits of deregulation.

Increased Cost of Market Transaction Associated

with Data Transfer, Processing, and Billing

Potential Economic Impact (High). Approximately 2 percent of

electric power industry expenditures are related to data transfer,

processing, and billing. Communications and transaction

requirements will increase greatly as many more small generators

and loads move into real-time markets.

However, similar to the issues associated with metering costs, the

economic benefits from this move to real-time response for all load

(large and small) will be large because it lowers costs through

active competitive markets and increases reliability since more

resources can respond when the system is under stress.

Potential Economic Impact (High). Measurement and standards

can help reduce market transaction costs by increasing

interoperability of the multiple networks and systems needed to

support market transactions in a deregulated environment. The

number of market participants supplying raw data to the system and

receiving processed information will increase dramatically with

deregulation. Measurement and standards will be important for

enabling the communications systems supplied by multiple vendors

to retrieve, process, and distribute information within acceptable

time intervals to multiple market players.

Variation in Responses (Medium). Most respondents thought that

measurement and standards can help reduce transaction costs so

that they do not impede the benefits to be achieved through

deregulation. However, there was disagreement on the capabilities

of existing systems. Some respondents thought that existing

communications systems and protocols would be adequate with

ongoing modifications. Other respondents thought that significant
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-13

changes in communications protocols and system interfaces needed

to be made to achieve the potential benefits from deregulation.

Development of Markets for Power of Different

Reliability Levels

Potential Economic Impact (Medium). Different industries and

customers within industries value power reliability differently. This

heterogeneity of customers’ preferences for power reliability can be

viewed as an asset that can be exploited through the development

of different product offerings (see Section 2). By offering different

levels of power reliability to customers, the system can become

more efficient by reducing reserve requirements and reducing

transmission investments. In addition, in many instances it is more

efficient for the system to “guarantee” different levels of reliability

as opposed to customers self-providing reliability through

individual investments in backup equipment (e.g., uninterruptible

power supplies, emergency generators).

Role of Measurement and Standards (Medium). Measurement and

standards will be important to ensure that reliability levels specified

in contracts have been met. In addition, for customers that do not

need the full reliability inherently offered by the power system,

communication and monitoring capabilities will be needed when

customers opt for lower reliability by “selling” load relief back to

the system. For example, standards for verifying that curtailments

have actually occurred will be required to support the increased

reliance on more, and more diverse, curtailment contracts.

Variation in Responses (Medium). Different levels of “firm” power

already exist in the wholesale market. Most respondents agreed

that this trend would continue and measurement and standards

could help expand differentiated reliability offerings into the retail

markets. However, there was disagreement about the potential size

of these markets and when it would become cost-effective to open

these markets to smaller loads.

Development of Markets for Power of Different

Quality Levels

Potential Economic Impact (Medium). As with the market for

different levels of power reliably, potential system efficiency gains

exist if customers value power quality differently. Because power
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-14

quality costs to industry and expenditures on power conditioning

equipment are large, the potential benefits from establishing

markets for power of different quality levels may be significant. In

addition, markets could address issues of individual customer’s

impact on system power quality, where customers “pay” for the

problems (e.g., harmonics) they feed back into the system.

Role of Measurement and Standards (Medium). There is an

increasing need to be able to detect power quality problems

through measurements and to define acceptable performance

through standards. Standards will be important to reduce power

quality problems from sources at the generation level (e.g., with

smaller, newer distributed generators), at the “wires” level (e.g., if

appropriate power conditioning is not provided at key points in the

system), and at the customer level (e.g., from electronic ballasts and

adjustable speed drives). Standards can also help define and match

users (or uses) who have different demands for power quality with

providers (or sources) that supply different levels of power quality.

Variation in Responses (High). There was significant disagreement

on whether markets for differentiated levels of power quality would

emerge in the near future. Some respondents cited the high cost of

providing different levels of power quality to customers on the

same distribution system as a barrier to power quality markets.

However, other respondents indicated there was a need for market

incentives/penalties to encourage customers to address their

internal power quality problems and not to feed harmonics back

into the system. They believed measurement and standards were

needed to support the development of efficient incentives.

5.3 ECONOMIC IMPACT ESTIMATES

This section presents a range of monetary benefits estimates that

reflect the social welfare gains of measurement and standards in

supporting deregulation of the electric power industry. We refer to

these as economic impact estimates. The economic impact

estimates presented in this section are based on common impact

“themes” identified during interviews with industry experts. The

empirical estimates provided below are intended to illustrate the

magnitude of the potential benefits associated with measurement

and standards. These impact estimates do not reflect projected cost
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-15

savings developed from detailed engineering analysis or results

from a statistically based survey. Instead, they should be

considered “first cut” estimates that can be refined as deregulation

progresses and as the evidence on impacts grows.

Economic impacts are evaluated relative to the performance gap

resulting from “inadequate” measurement and standards. This is

measured as a percent reduction in potential efficiency gain. These

economic impact estimates are designed to capture changes in total

social welfare. These changes in social welfare are not

desegregated into changes in consumer or producer surplus or

traced to changes in market prices.3

We used the following steps to develop the economic impact

estimates associated with measurement and standards:

Z Review the impact areas discussed in Section 5.2 and select

a subset for the empirical analysis of measurement and

standards.

Z Develop impact cost metrics for each selected area based

on professional literature, trade publications, and

government publications.

Z Use the scoping interviews and surveys with industry

experts to investigate the significance of measurement and

standards associated with each impact cost metric. From

this information, develop a percentage change impact range

for each impact cost metric.

Z Estimate economic impact range estimates by multiplying

the impact cost metric by the percentage change ranges.

Figure 5-1 illustrates how the impact cost metrics and percent

change estimates were used to estimate economic impacts. The

lower curve in Figure 5-1 represents the potential productivity gain

(reduction in the average price of generation) associated with

deregulation with adequate measurement and standards. The

upper curve reflects the gain that may be achieved without

adequate measurement and standards. The difference between the

two curves is the productivity “gap” between potential and actual

average price decreases that is not realized as a result of inadequate

measurement and standards. Information on the size of the gap

 

3Respondents had very different opinions regarding which sectors of the economy

would benefit most from deregulation. Investigating the distribution of benefits

was beyond the scope of this study.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-16

Time

$/MWh

Future

Deregulated

System

Performance

Gap

was obtained through interviews with industry experts and is

expressed as the percentage gap to simplify data collection.

The percentage gap is multiplied by an impact cost metric to obtain

the economic impact:

Economic Impact = Percentage Gap • Impact Cost Metric

Economic Impact = % Change in Average Cost of Power

Generation • Annual U.S. Expenditures on

Power Generation

Note, we are not estimating the economic impact of the potential

gains in economic performance of deregulation. The economic

impact estimates presented in this study are the reductions in the

economic performance gains resulting from inadequate

measurement and standards.

Section 5.3.1 discusses the development of the impact cost metrics,

and Section 5.3.2 presents the percentage change ranges along with

the economic impact range estimates.

Figure 5-1. Potential

Performance Gap

Associated with

Inadequate Measurement

and Standards

The potential performance gap

is the difference between the

projected and actual average

cost of power resulting from

inadequate measurement and

standards. The performance

gap is expressed as a percentage

change in per-unit power

generation costs in this

example.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-17

5.3.1 Impact Cost Metrics

A key step in estimating economic impacts is to identify and

quantify impact cost metrics that would provide a reference value

from which the impact of measurement and standards can be

measured. The impact costs metrics are the building blocks used to

estimate the economic impacts. For example, if measurement and

standards increase the capacity utilization of the transmission

system and reduce the need for new transmission capacity, we

need to know the cost of building additional transmission capacity.

Similarly, if measurement and standards can reduce the frequency

and duration of outages, then we need to know the annual cost of

outages to end users to estimate the economic impact of

measurement and standards on outage costs.

The advantage of defining impact cost metrics independent of the

role of measurement and standards is that the impact cost metrics

have less uncertainty compared to the question of “what is the

significance of measurement and standards.” By first calculating

independent impact cost metrics, we can then investigate a range of

economic impacts associated with measurement and standards

(reflecting potentially very different views of the world) based on a

common reference point.

We developed impact cost metrics for seven of the impact areas

presented in Table 5-2. The remaining four impact areas listed in

Table 5-2 were not explicitly quantified because their impacts are

either included in other impact categories or their market factors

were too uncertain to quantify. For example, the benefits of

measurement and standards to support distributed generation are

incorporated into the reduced cost of ancillary services and the

reduced demand for transmission resources. In addition,

distributed generation may also help alleviate the frequency and

severity of outages, and this would be reflected in the economic

impacts associated with measurement and standards reducing

outage costs. In general, we found that the impact of distributed

generation was too difficult for interviewees to untangle from the

other categories, such as ancillary service or transmission impact.

Similarly, the impact of measurement and standards on diagnostic

tools is indirectly reflected in the benefit associated with operating

Impact cost metrics were

developed for seven impact

areas.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-18

the transmission system and in improved power reliability and

power quality for end users.

The impact areas for differentiated levels of power reliability and

power quality were also not included in the empirical analysis. For

these areas, it was difficult to quantify the potential benefits, and

there was significant disagreement about the future evolution of

these markets and the role measurement and standards may play.

Respondents were reluctant to offer estimates of these impacts

because of the historically high levels of power reliability and

quality prevalent in U.S. electricity markets.

Table 5-3 describes the cost metrics included in the empirical

analysis and identifies the information sources used to develop

annualized expenditures or costs. Appendix E contains a detailed

description of the estimation procedures and assumptions that we

used to develop each cost metric estimate.

The cost metrics reflect U.S. impacts. When information was only

available for North America, costs were scaled by the U.S.’s share

of electricity consumption (the U.S. accounts for approximately

84 percent of electricity consumed in North America). In addition,

the impact cost metrics focus on the “end results” and estimate the

impact at the point it enters the supply chain. Specific modeling of

the physical and behavioral relationships between these categories

is beyond the scope of this study.

5.3.2 Economic Impact Estimates

We calculated economic impact estimates based on the impact cost

metrics described above and percentage change range estimates

developed through interviews and surveys with industry experts.

Most industry experts had difficulty quantifying the incremental

impact associated with measurement and standards because these

impacts needed to be measured relative to an unknown baseline

(i.e., the future course of deregulation).4 Whereas respondents

 

4In addition, quantifying the impact is also difficult because the basic structure of

how we conceptualize the industry relies on metering individual consumption.

For example, the whole structure of the restructured industry is based on

unbundling and, therefore, measuring individual provision and consumption. It

is difficult to conceive of a deregulated world without adequate measurement

and standards.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-19

Table 5-3. Impact Areas Affected by Measurement and Standards

The cost metrics form the “building blocks” for estimating economic impacts associated with measurement and standards.

Impact Area Cost Metric Sources

System Operations

1) Achieving potential

efficiency gains in

power generation

resulting from increased

competition

Annual U.S. expenditures on

power generation

Energy Information Administration. 1998b.

Electric Power Annual. Volume 2.

Washington, DC: U.S. Department of

Energy.

2) Adequate and efficient

provision of ancillary

services in a

deregulated

environment

Annual U.S. expenditures on

ancillary services

Hirst, Eric and Brendan Kirby. 1998.

“Unbundling Generation and Transmission

Services for Competitive Electricity Markets:

Examining Ancillary Services.” Prepared for

the National Regulatory Research Institute,

Columbus, OH.

3) Limited transmission

capacity to support

increasing system

demands resulting from

deregulation

Avoided cost of new

transmission resources:

Z building new corridors

Z restraining existing

corridors

Fuldner, Arthur. 1996. Upgrading

Transmission Capacity for Wholesale

Electric Trade. Washington, DC: Energy

Information Administration.

Edison Electric Institute. 1998. Statistical

Yearbook of the Electric Utility Industry

1997. Washington, DC: Edison Electric

Institute.

4) Increased duration and

frequency of power

outages resulting from

deregulation

Annual power outage costs

to U.S. industries, and

Expenditures on backup

equipment to support

reliability

Hoffman, Steve. 1996. “Enhancing Power

Grid Reliability.” EPRI Journal 21(6):6-16.

Power Quality Assurance. 1999. “The Top

50 Equipment Suppliers and Service

Providers.” <http://www.powerquality.

com/art0055/art1.html>. As obtained on

October, 13 1999.

5) Degradation of power

quality resulting from

deregulation

Expenditures on protective

equipment to mitigate

power quality problemsa

Power Quality Assurance. 1999. “The Top

50 Equipment Suppliers and Service

Providers.” <http://www.powerquality.com/

art0055/art1.html>. As obtained on

October, 13 1999.

Market Operations

6) Increased cost of

market transactions

associated with data

transfer, processing,

and billing

Annual U.S. industry

expenditures on contract

writing, legal disputes, and

bill reconciliation

Energy Information Administration. 1997.

Financial Statistics of Major Investor Owned

Utilities, 1996. Washington, DC: U.S.

Department of Energy.

7) Increased cost,

complexity, and vendor

diversity of metering

equipment to support

market transactions

Annualized cost of metering

equipment

Annualized cost of operating

metering systems

(installation, calibration,

service calls, wireless

communications equipment)

Electrical World. 1998. “Meter Market

Measures.” <http://www.gepin.com/

tombew/08009813.htm>. As obtained on

November 22, 1999.

Energy Information Administration. 1997.

Financial Statistics of Major Investor Owned

Utilities, 1996. Washington, DC: U.S.

Department of Energy.

aNote: Information was not available on annual power quality costs to U.S. industries.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-20

indicated that measurement and standards would be important

regardless of the eventual course of deregulation, asking

respondents to quantify the impact of measurement and standards

in the presence of such great future uncertainty made it difficult to

elicit comparable impact metrics that could be aggregated using

statistical methods. As a result, our approach for assessing the

range of the percentage change impact associated with

measurement and standards was to

Z review each survey response separately,

Z assess the baseline from which each respondent was

developing his impact estimates,

Z identify common measurement and standards impact

themes, and

Z develop ranges of measurement and standards impact

estimates based on assimilating input from all responses.

Based on this approach, we developed impact metrics that were

used to estimate ranges of potential economic impacts associated

with measurement and standards. We want to emphasize that the

economic impact estimates presented in this section reflect the

authors’ interpretation of information collected through a series of

telephone interviews and survey questionnaires and are not the

result of a statistically based survey.

Table 5-4 presents the range of percentage change impacts for each

cost metric category that was developed based on discussions with

industry experts. The economic impact estimates reflect the

potential efficiency gains (gains associated with deregulation) that

are not realized as a result of inadequate measurement and

standards. Upper and lower bounds of the performance “gap” are

estimated in terms of the percentage change relative to the cost

metric. For example, for Impact Area 2, respondents indicated that

deregulation could significantly reduce the average cost of

providing ancillary services. However, the eventual deregulated

cost of ancillary services will be 8 to 12 percent higher without

adequate measurement and standards. The economic impact is

then calculated by multiplying the percentage performance gap by

the annual expenditures on ancillary services (the impact cost

metric).

Most industry

experts felt that

measurement and

standards can have

the greatest

percentage change

(or relative) impact

on the cost of

providing ancillary

services, the level of

power reliability,

and power quality

experienced by end

users.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-21

Table 5-4. Economic Impact of Measurement and Standards

The economic impact estimates reflect the potential performance gains (gains associated with deregulation) that are not

realized as a result of inadequate measurement and standards. An upper and lower bounds of the performance “gap”

are estimated in terms of the percentage change relative to the cost metric. For example, for Impact Area 2, respondents

indicated that deregulation could significantly reduce the average cost of providing ancillary services. However, the

eventual deregulated cost of ancillary services will be 8 to 12 percent higher without adequate measurement and

standards. The economic impact is then calculated by multiplying the percentage performance gap by the annual

expenditures on ancillary services (the impact cost metric).

Percentage Reduction

in Potential Efficiency

Gain

Economic Impactb

($ millions)

Impact Area

Cost

Metrica

($ millions) Lower Upper Lower Upper

System Operations

1) Achieving potential efficiency gains

in power generation resulting from

increased competition

100,000 0.5% 1.5% 500 1,500

2) Adequate and efficient provision of

ancillary services in a deregulated

environment

12,000 8% 12% 960 1,440

3) Limited transmission capacity to

support increasing system demands

resulting from deregulation

7,700 0% 6% 0 462

4) Increased duration and frequency of

power outages resulting from

deregulation

30,000 5% 9% 1,500 2,700

5) Degradation in power quality

resulting from deregulation

4,300 6% 12% 258 516

Market Operations

6) Increased cost of market transactions

associated with data transfer,

processing, and billing

800 1% 5% 8 40

7) Increased cost, complexity, and

vendor diversity of metering

equipment to support market

transactions

2,200 –4% –6% –88 –132

Total 3,138 6,526

aAll costs and economic impacts are presented in 1999 dollars.

bThe economic impacts are presented as benefits of measurement and standards. Thus, a positive percentage change

typically reflects a decrease in expenditures (such as for power generation or new transmission capacity) or a

decreased burden on end users associated with a “bad” outcome (such as power outages).
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

5-22

Most industry experts felt that measurement and standards can have

the greatest percentage change (or relative) impact on the cost of

providing ancillary services, the level of power reliability, and

power quality experienced by end users.

Measurement and standards was thought to have a smaller relative

impact on the cost of generation, ranging from 1 to 2 percent.

However, because generation costs represent over $100 billion

annually, this category still represents a significant economic

impact.

Measurement and standards’ impact on transmission system costs

had the largest range, reflecting varying opinions on the net

economic impact. Many interviewees cited increased capacity

utilization of the transmission system and avoided costs of new

transmission capacity as large benefits resulting from measurement

and standards. However, other interviewees felt that these benefits

would be offset by increased monitoring and diagnostic costs that

would accompany increased measurement capabilities. As a result,

this category ranges from 0 to 6 percent change.

It should be noted that many of the benefits of measurement and

standards as applied to the transmission system will be captured in

reduced outage costs and power quality costs to end users. Several

respondents may have allocated the costs of measurement and

standards to Impact Area 2 in Table 5-4 and implicitly included the

associated benefits in Impact Areas 4 and 5.

As shown in the last two columns of Table 5-4, the sum of the

annual economic impacts quantified as part of this study ranges

from $3.1 to $6.5 billion. Measurement and standards’ impact on

power reliability is the largest impact category, representing

35 percent of the upper-bound estimate. Power quality issues for

end users, average generation costs, and ancillary service costs

each account for approximately 20 percent of the upper-bound

estimate.

The percentage change in equipment costs ranges from –4 to

–6 percent. The impact is negative because respondents indicated

that metering equipment costs throughout the system would

increase as a result of more refined and more frequent

measurements at more locations. Thus, this appears as a negative

economic impact in Table 5-4. However, the respondents

The sum of the

annual economic

impacts quantified

as part of this study

ranges from $3.1 to

$6.5 billion.
Section 5 — Estimating the Economic Impact of Measurement and Standards

5-23

indicated that benefits would be associated with these increased

metering activities, and they are captured in the other categories in

Table 5-4, such as decreased ancillary service costs. Also,

enhanced metering may generate additional benefits through

support of markets for differentiated power reliability and power

quality (not included in Table 5-4).

As noted previously, these estimates are illustrative “first cut”

estimates of economic impacts based on a survey of a limited

number of electric industry experts early in the industry

deregulation process. Although the results are not highly precise,

the pattern of results within the system and market operations

categories are plausible and provide early guidance to

measurement and standards development initiatives and

investments. Examples of groups that are involved in the

measurement and standards development process are provided in

Section 4.
R-1

References

American Public Power Association (APPA). 2000. “Status of State

Electric Utility Deregulation.” <http://www.appanet.org>.

Bromey, D.W. 1991. Environment and Economy: Property Rights

and Public Policy. Cambridge: Blackwell.

CASO. White Paper #2.

Cavanagh, Ralph. 1999. “Congress and Electric Industry

Restructuring: Enviornmental Imperatives.” The Electricity

Journal 12(6):11-20.

Douglas, John. 1992. “The Delivery System of the Future.” EPRI

Journal 17(3).

Edison Electric Institute (EEI). 1992. Statistical Yearbook of the

Electric Utility Industry 1991. November. Washington,

DC.

Edison Electric Institute (EEI). 1998. Statistical Yearbook of the

Electric Utility Industry 1997. Washington, DC: Edison

Electric Institute.

Edison Electric Institute (EEI). 1999a. “The Number of Electricity

Suppliers in Today’s Market.”

<http://www.eei.org/issues/comp_reg/3electri.htm>. As

obtained on August 11, 1999.

Edison Electric Institute (EEI). 1999b. “The Rise of the Power

Marketer.” <http://www.eei.org/issues/compreg/6riseofp.htm>. As obtained on August 11, 1999.

Electrical World. 1998. “Meter Market Measures.”

<http://www.gepin.com/tombew/08009813.htm>. As

obtained on November 22, 1999.
Changing Measurement and Standards Need in a Deregulated Electric Utility Industry

R-2

Energy Information Administration (EIA). 1995a. “Annual Electric

Utility Report.” Form EIA-861. Washington, DC: U.S.

Department of Energy.

Energy Information Administration (EIA). 1995b. “Annual

Nonutility Power Producer Report.” Form EIA-867.

Washington, DC: U.S. Department of Energy.

Energy Information Administration (EIA). 1996a. The Changing

Structure of the Electric Power Industry: An Update.

DOE/EIA-0562(96). Washington, DC: U.S. Department of

Energy.

Energy Information Administration (EIA). 1996b. Electric Power

Annual 1995. Volume I. DOE/EIA-0348(95)/1.

Washington, DC: U.S. Department of Energy.

Energy Information Administration (EIA). 1997. Financial Statistics

of Major Investor Owned Utilities, 1996. Washington, DC:

U.S. Department of Energy.

Energy Information Administration (EIA). 1998a. The Changing

Structure of the Electric Power Industry: Selected Issues,

1998. DOE/EIA-0562(98). Washington, DC: U.S.

Department of Energy.

Energy Information Administration (EIA). 1998b. Electric Power

Annual. Volume 2. Washington, DC: U.S. Department of

Energy.

Federal Energy Regulatory Commission (FERC). 1996. “Open

Access Same-Time Information System and Standards of

Conduct.” Order No. 889, Final Rule.

Federal Energy Regulatory Commission (FERC). 1999. “Notice of

Proposed Rulemaking.”

Fuldner, Arthur. 1996. Upgrading Transmission Capacity for

Wholesale Electric Trade. Washington, DC: Energy

Information Administration.

Haltmaier, Susan. 1998. “Electricity Production and Sales.” In

U.S. Industry & Trade Outlook ’98, DRI/McGraw-Hill,

Standard & Poor’s, and U.S. Department of

Commerce/international Trade Administration. New York:

McGraw-Hill.
References

R-3

Hirst, Eric, and Brendan Kirby. 1998. Unbundling Generation and

Transmission Services for Competitive Electricity Markets:

Examining Ancillary Services. Prepared for the National

Regulatory Research Institute, Columbus, OH. NRRI 98-05.

Hoffman, Steve. 1996. “Enhancing Power Grid Reliability.” EPRI

Journal 21(6):6-16.

National Association of Regulatory Utility Commissioners

(NARUC). 1998. “Direct Access Metering & Data

Communication Requirements.” Acton, MA: Plexus

Research, Inc.

National Institute of Standards and Technology (NIST). 1999. An

Assessment of the National Institute of Standards and

Technology Measurement and Standards Laboratories—

Fiscal Year 1999. Washington, DC: National Academy

Press.

North American Electric Reliability Council (NERC). 1998.

Electricity Supply & Demand Database and Software.

Princeton, NJ, October.

Power Quality Assurance (PQA). 1999. “The Top 50 Equipment

Suppliers and Service Providers.”

<http://www.powerquality.com/art0055/art1.html>. As

obtained on October 13, 1999.

Progress & Freedom Foundation. The Replacement Cost of the U.S.

Investor Owned Utilities’ Transmission System.

<http://pff.org/energy/appendix.html>. As obtained on

November 10, 1999.

Resource Data International. 1999. “PMA Online Top 25 Power

Marketer Rankings.” Power Marketers Online Magazine.

<http://www.powermarketers.com/top25a.htm.> As

obtained on August 11, 1999.

Shepherd, Dennis. 1998. “Direct Access Settlement.” Working

paper.

Stiglitz, J.E. 1988. Economics of the Public Sector. New York:

W.W. Norton & Company.

Tassey, G. 1997. The Economics of R&D Policy. Westport, CT:

Quorum Books.
Appendix A:

Existing Activities

and Emerging

Participants in the

Electric Power

Supply Chain
A-1

This appendix provides background on existing activities and

emerging participants in the electric power supply chain. Because

the restructuring plans and time tables are made at the state level,

the issues of asset ownership and control throughout the present

supply chain in the electric power industry vary from state to state.

However, the activities conducted throughout the supply chain are

generally the same.1

Section A.1 presents a brief history of the development of the

electric supply industry. Figure A-1 provides an overview of the

present state of the electric power supply chain, highlighting a

combination of activities and service providers. The

activities/members of the electric power supply chain are typically

grouped into generation, transmission, and distribution. These

three segments are described in Sections A.2 through A.4.

Equipment manufacturers supply all three segments and are

described in Section A.5.

A.1 EVOLUTION OF THE ELECTRIC POWER

INDUSTRY

The electric utility industry began as isolated local service systems

with the first electric companies evolving in densely populated

metropolitan areas like New York and Chicago. Prior to World

War I, rural electrification was a piecemeal process. Only small,

isolated systems existed, typically serving a single town. The first

high-voltage transmission network was built in the Chicago area in

1911 (the Lake County experiment). This new network connected

the smaller systems surrounding Chicago and resulted in substantial

production economies, lower customer prices, and increased

company profits.

In light of the success of the Lake County experiment, the 1910s

and 1920s saw increased consolidation and rapid growth in

electricity usage. During this period, efficiency gains and demand

growth provided the financing for system expansions. Even though

 

1Of course, asset ownership and control are at the heart of deregulation and are an

important factor driving the need for measurement and standard technologies,

and these issues are discussed in detail in Section 3.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-2

the capacity costs (fixed costs per peak kW demanded) were

typically twice as large with the consolidated/interconnected supply

Figure A-1. Electric Utility Industry

Electricity

Waste Heat

Intersystem

Private Exchange

Lines

▲

▼

▲ Surplus

Electricity

▼ Purchased

Fuel Source: Coal, Natural Gas, Water, etc.

 Surplus

Electricity

 Purchased

Self-Generation

Large C/I

Customers

Small C/I

Customers

Residential

Customers

Local Distribution

System Reliability

and Control

Bulk Transmission

IPP Generation Local Utility

Generation Competing Utility

Generation

(outside service

territory)

systems, the fixed costs per unit of energy production (kWh) were

comparable to those of the old single-city system. This was the
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-3

case because of load factor improvements, which resulted from

aggregating customer demand.

Whereas the average fixed cost per customer was relatively

unchanged as a result of the move from single-city to consolidated

supply systems, large savings were realized from decreases in

operating costs. In particular, fuel costs per kWh decreased

70 percent because of the improved combustion efficiency of larger

plants and lower fuel prices for purchases of large quantities. In

addition, operating and maintenance costs decreased 85 percent,

primarily as a result of decreased labor intensity.

During the 1920s, only a small part of the efficiency gains were

passed on to customers, in the form of lower prices. Producers

retained the bulk of the productivity increases as profits. These

profits provided the internal capital to finance system expansions

and to buy out smaller suppliers. Industry expansion and

consolidation led to the development of large utility holding

companies whose assets were shares of common stock in many

different operating utilities.

The speculative fever of the 1920s led to holding companies’

purchasing one another, creating financial pyramids based on

inflated estimates of company assets. With the stock market crash

in 1929, shareholders who had realized both real economic profits

and speculative gains lost large amounts of money. The financial

collapse of the utility holding companies led to new levels of utility

regulation.

From the 1930s through the 1960s, the regulated mandate of

electric utilities was basically unchanged: to provide safe,

adequate, and reliable service to all users of electricity. The

majority of the state and federal laws regulating utilities in place

during this era had been written shortly after the Depression. The

laws were primarily designed to prevent “ruinous competition”

through costly duplication of utility functions and to protect

customers against exploitation from a monopoly supplier.

During this period, most utilities were vertically integrated,

controlling everything from generation to distribution. Economies

of scale in generation and the inefficiency of duplicating

transmission and distribution systems made the electric utility

industry a textbook example of a natural monopoly. Electricity was
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-4

viewed as a homogeneous good from which there were no product

unbundling opportunities or unique product offerings on which

competition could get a foothold. In addition, the industry was

extremely capital-intensive, providing a sizable barrier to entry

even if the monopoly status of the utilities had not been protected.

From the 1930s to the 1960s, the electric industry experienced

almost continuous growth in demand. In addition, there was a

steady stream of technological innovations in generation,

transmission, and distribution operations. The increased economies

of scale, technological advances, and fast demand growth led to

steadily declining unit costs. However, in an environment of

decreasing unit costs, there were few rate cases and almost no

pressure from customers to change the system. This period is often

referred to as the golden era for the electric utility industry.

A.2 GENERATION

The transmission and distribution of electricity are being separated

from the business of generating electricity, and a new competitive

market in electricity generation is evolving. As power generators

prepare for the competitive market, the share of electricity

generation attributed to nonutilities and utilities is shifting.

More than 7,000 electricity suppliers currently operate in the U.S.

market. As shown in Table A-1, approximately 42 percent of

suppliers are utilities and 58 percent are nonutilities. Utilities

include investor-owned, cooperatives, and municipal systems. Of

the approximately 3,100 utilities operating in the U.S., only

approximately 700 generate electric power. The majority of

utilities distribute electricity that they have purchased from power

generators via their own distribution systems.

Utility and nonutility generators produced a total of 3,369 billion

kWh in 1995. Although utilities generate the vast majority of

electricity produced in the U.S., nonutility generators are quickly

eroding utilities’ shares of the market. Nonutility generators

include private entities that generate power for their own use or to

sell to utilities or other end users. Between 1985 and 1995,

nonutility generation increased from 98 billion kWh (3.8 percent of

total generation) to 374 billion kWh (11.1 percent). Figure A-2

illustrates this shift in the share of utility and nonutility generation.
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-5

Electricity Suppliers Number

Utilities 3,124

Investor-Owned Utilities 222

Cooperatives 875

Municipal Systems 1,885

Public Power Districts 73

State Projects 55

Federal Agencies 14

Nonutilities 4,247

Nonutilities (excluding EWGs) 4,103

Exempt Wholesale Generators 144

Total 7,371

Source: Edison Electric Institute. 1999a. “The Number of Electricity Suppliers in

Today’s Market.” <http://www.eei.org/issues/comp_reg/3electri.htm>. As

obtained on August 11, 1999.

Utilities

There are four categories of utilities: IOUs, federal utilities,

publicly owned utilities, and cooperative utilities. Of the four, only

IOUs always generate electricity.

IOUs are increasingly selling off generation assets to nonutilities or

converting those assets into nonutilities (Haltmaier, 1998). To

prepare for the competitive market, IOUs have been lowering their

operating costs, merging, and diversifying into nonutility business.

In 1995, utilities generated 89 percent of electricity, a decrease

from 96 percent in 1985. IOUs generate the majority of the

electricity produced in the U.S. IOUs are either individual

corporations or a holding company, in which a parent company

operates one or more utilities integrated with one another. IOUs

account for approximately three-quarters of utility generation, a

percentage that held constant between 1985 and 1995.

Table A-1. Number of

Electricity Suppliers in

1999
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-6

Figure A-2. Utility and Nonutility Generation and Shares by Class, 1985 and 1995

12% Other Non-QF

25% Cogen Non-QF

SPP QF

EWG 0%

EWG

7%

 Cogen QF

 Any Combinationa

1985

55%

Federal

1985

10%

9% Other Public

5% Cooperative

InvestorOwned 76%

Federal

1985

9%

Other Public 11%

Cooperative 6%

InvestorOwned 74%

Shares of Total

Nonutility Generation

1%

Other Non-QF 6%

Cogen Non-QF 9%

2%

SPP QF 13%

 Cogen QF

1995 Utility Total

1995 Utility Total 2,995 Billion kWh

2,470 Billion kWh

1995

67%

4%

1985 Nonutility Total

98 Billion kWh

1985 Generation

Utility 96%

Nonutility 4%

Shares of Total

Nonutility Generation

Shares of Total

Utility Generation

Shares of Total

Utility Generation

NONUTILITIES

UTILITIES

1995 Nonutility Total

374 Billion kWh

1995 Generation

Utility 89%

Nonutility 11%

aIncludes facilities classified in more than one of the following FERC designated categories: cogenerator QF, small

power producer QF, or exempt wholesale generator.

Cogen = Cogenerator.

EWG = Exempt wholesale generator.

Other Non-QF = Nocogenerator Non-QF.

QF = Qualifying facility.

SPP = Small power producer.

Note: Sum of components may not equal total due to independent rounding. Classes for nonutility generation are

determined by the class of each generating unit.

Sources: Utility data: Energy Information Administration (EIA). 1995a. “Annual Electric Utility Report.” Form EIA-861.

Washington, DC: U.S. Department of Energy; and Energy Information Administration (EIA). 1996b. Electric Power

Annual 1995. Volume I. DOE/EIA-0348(95)/1. Washington, DC: U.S. Department of Energy; Table 8 (and previous

issues); 1985 nonutility data: Shares of generation estimated by EIA; total generation from Edison Electric Institute

(EEI). 1992. Statistical Yearbook of the Electric Utility Industry 1991. November. Washington, DC; 1995 nonutility

data: Energy Information Administration (EIA). 1995b. “Annual Nonutility Power Producer Report” Form EIA-867.

Washington, DC: U.S. Department of Energy.

Utilities owned by the federal government accounted for about

one-tenth of generation in both 1985 and 1995. The federal

government operated a small number of large utilities in 1995 that

supplied power to large industrial consumers or federal

installations. The Tennessee Valley Authority is an example of a

federal utility. Most of the remaining energy is sold on the

wholesale market to IOUs and cooperatives (EIA, 1996a). Very

little energy is sold to retail customers.
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-7

Many states, municipalities, and other government organizations

also own and operate utilities, although the majority do not

generate electricity. Those that do generate electricity operate

capacity to supply some or all of their customers’ needs. They tend

to be small, localized outfits and can be found in 47 states. These

publicly owned utilities accounted for about one-tenth of utility

generation in 1985 and 1995. In a deregulated market, these

generators may be in direct competition with other utilities to

service their market.

Rural electric cooperatives are the fourth category of utilities. They

are formed and owned by groups of residents in rural areas to

supply power to those areas. Cooperatives generally purchase from

other utilities the energy that they sell to customers, but some

generate their own power. Cooperatives only produced 5 percent

of utility generation in 1985 and only 6 percent in 1995.

Nonutilities

Nonutilities are private entities that generate power for their own

use or to sell to utilities or other establishments. Nonutilities are

usually operated at mines and manufacturing facilities, such as

chemical plants and paper mills, or are operated by electric and gas

service companies (EIA, 1998a). More than 4,200 nonutilities

operate in the U.S.

Between 1985 and 1995, nonutility generators increased their share

of electricity generation from 4 percent to 11 percent (see Figure A2). In 1978, the Public Utilities Regulatory Policies Act (PURPA)

stipulated that electric utilities must interconnect with and purchase

capacity and energy offered by any qualifying nonutility. In 1996,

FERC issued Orders 888 and 889 that opened transmission access

to nonutilities and required utilities to share information about

available transmission capacity. These moves established

wholesale competition, spurring nonutilities to increase generation

and firms to invest in nonutility generation.

Nonutilities are frequently categorized by their FERC classification

and the type of technology they employ. There are three categories

of nonutilities: cogenerators, small power producers (SPPs), and

exempt wholesale generators (EWGs).
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-8

Cogenerators are nonutilities that sequentially or simultaneously

produce electricity and another form of energy (such as heat or

steam) using the same fuel source. At cogeneration facilities, steam

is used to drive a turbine to generate electricity. The waste heat

and steam from driving the turbine is then used as an input in an

industrial or commercial process. For a cogenerator to qualify or

interconnect with utilities, it must meet certain ownership,

operating, and efficiency criteria specified by FERC. In 1985, about

55 percent of nonutility generation was produced by cogenerators

that qualified or met FERC’s specifications and sold power to

utilities. By 1995, the percentage increased to 67 percent as the

push for deregulation gathered momentum. At the same time, the

percentage that was produced by nonqualifying cogenerators

decreased from 25 percent to 9 percent.

SPPs generate power using renewable resources, such as biomass,

solar energy, wind, or water. As with cogenerators, SPPs must

fulfill a series of FERC requirements to interconnect with utilities.

PURPA revisions enabled nonutility renewable electricity to grow

significantly, and SPPs have responded by improving technologies,

decreasing costs, and increasing efficiency and reliability (EIA,

1998a). Between 1985 and 1995, the percentage of SPP nonutility

generation nearly doubled to 13 percent.

EWGs produce electricity for the wholesale market. Also known as

independent power producers, EWGs generate for large bulk

customers, such as large industrial and commercial facilities and

utilities. They do not operate any transmission or distribution

facilities but pay tariffs to use facilities owned and operated by

utilities. Unlike with qualifying cogenerators and SPPs, utilities are

not required to purchase energy produced by EWGs, but they may

do so at market-based prices. EWGs did not exist until the Energy

Policy Act created them in 1992, and by 1995 they generated about

2 percent of nonutility electricity.

In 1995, about 4 percent of nonutility generation was produced by

facilities that were classified as any combination of cogenerator,

SPP, and EWG. An additional 6 percent was produced by facilities

that generate electricity for their own consumption.
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-9

A.3 TRANSMISSION

Whereas the market for electricity generation is moving toward a

competitive structure, the transmission of electricity is currently

(and will likely remain) a regulated, monopoly operation. In areas

where power markets are developing, generators pay tariffs to

distribute their electricity over established lines owned and

maintained by independent organizations. Independent system

operators (ISOs) will most likely coordinate transmission operations

and generation dispatch over the bulk power system.

The bulk power transmission system consists of three large regional

networks, which also encompass smaller groups. The three

networks are geographically defined: the Eastern Interconnect in

the eastern two-thirds of the nation, the Western Interconnect in the

western portion, and the Texas Interconnect, which encompasses

the majority of Texas. The western and eastern networks are each

fully integrated with Canada. The western is also integrated with

Mexico. Within each network, the electricity producers are

connected by extra high-voltage connections that allow them to

transfer electrical energy from one part of the network to the other.

The networks themselves are only loosely connected to one

another; therefore, transferring electricity between one another is

difficult.

RTOs are entrusted with coordinating electricity transmission and

assuring reliability of the system. The RTO’s operations and the

tracking, monitoring, and information activities to support the RTO

are common costs. All of the users of the system are required to

contribute to support these activities that ensure efficient system

operation and reliability. Although California is the only state that

has completed the deregulatory process, there are four RTOs in

operation: the California RTO, RTO New England, the

Pennsylvania-New Jersey-Maryland RTO, and the Electric

Reliability Council of Texas-Texas RTO. Seven others are planned.

The bulk power system makes it possible for electric power

producers to engage in wholesale trade. In 1995, utilities sold

1,283 billion kWh to other utilities. The amount of energy sold by

nonutilities has increased dramatically from 40 billion kWh in 1986

to 222 billion kWh in 1995, an average annual increase of

21 percent (EIA, 1996a). Distribution utilities and large industrial
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-10

and commercial customers also have the option of purchasing

electricity in bulk at market prices from their local utility, a

nonutility, or another utility. The process of transmitting electricity

between suppliers via a third party is known as wholesale

wheeling.

The wholesale trade for electricity is increasingly handled by power

marketers (brokers). Power marketers act as independent

middlemen that buy and sell wholesale electricity at market prices

(EEI, 1999b). Customers include large commercial and industrial

facilities in addition to utilities. Power marketers emerged in

response to increased competition. Brokers do not own generation

facilities, transmissions systems, or distribution assets, but they may

be affiliated with a holding company that operates generation

facilities. Currently, 570 power marketers operate in the U.S. The

amount of power sold by marketers increased from 3 million MWh

to 2.3 billion MWh between 1995 and 1998. This is the equivalent

of going from powering 1 million homes to powering 240 million

homes (EEI, 1999b). Table A-2 lists the top ten power marketers by

sales for the first quarter of 1999.

Table A-2. Top Power Marketing Companies, First Quarter 1999

Company Total MWh Sold

Enron Power Marketing, Inc. 78,002,931

Southern Company Energy Marketing, L.P. 38,367,107

Aquila Power Corp. 29,083,612

PG&E Energy Trading-Power, L.P. 28,463,487

Duke Energy Trading & Marketing, L.L.C. 22,276,608

LG&E Energy Marketing, Inc. 15,468,749

Entergy Power Marketing Corp. 12,670,520

PacifiCorp Power Marketing, Inc. 11,800,263

Tractebel Energy Marketing, Inc. 10,041,039

NorAm Energy Services, Inc. 9,817,306

Source: Resource Data International. 1999. “PMA Online Top 25 Power Marketer Rankings.” Power Marketers Online

Magazine. <http://www.powermarketers.com/top25a.htm.> As obtained on August 11, 1999.
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-11

A.4 DISTRIBUTION

The local distribution system for electricity is expected to remain a

regulated monopoly operation. But power producers will soon be

able to compete for retail customers, by paying tariffs to entities that

distribute the power. Utilities may designate an RTO to operate the

distribution system or continue to operate it themselves. If the

utility operates its own system, it is required by law to charge the

same tariff to other power producers that it charges producers

within its own corporate umbrella. The sale of electricity by a

utility or other supplier to a customer in another utility’s retail

service territory is known as retail wheeling.

Supporters of retail wheeling claim that it will help lower the

average price paid for electricity. The states with the highest

average prices for electricity are expected to be the first to permit

retail wheeling; wholesale wheeling is already permitted

nationwide. In 1996, California, New England, and the MidAtlantic states had the highest average prices for electricity, paying

3 cents or more per kilowatt-hour than the national average of

6.9 cents (EIA, 1998a). Open access to the electricity supply,

coupled with a proliferation of electricity suppliers, should

combine to create falling electricity prices and increasing usage.

By 2002, the nationwide average price for electricity is projected be

11 percent lower than in 1995, an average annual decline of

roughly 2 percent (Haltmaier, 1998).

The explosion in computer and other information technology usage

in the commercial sector is expected to offset energy-efficiency

gains in the residential and industrial sectors and lead to a net

increase in the demand for electricity. Retail wheeling has the

potential to allow customers to lower their costs per kilowatt-hour

by purchasing electricity from suppliers that best fit their usage

profiles. Large commercial and industrial customers engaged in

self-generation or cogeneration will also be able to sell surplus

electricity in the wholesale market.

A.5 METERING AND DATA COMMUNICATIONS

Metering and data communications activities are an integral part of

the electric power industry supply chain. Advances in metering

and data communications technologies have been essential in
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-12

supporting emerging electric power markets. Hourly meter

readings, communicated daily, are currently considered the ideal

data to support the transactions associated with a restructured

electric market. This information is primarily needed to support

transactions between wholesale providers and the retail sellers of

energy, and to a lesser extent this information is needed to support

transactions between customers and their retail suppliers (NARUC,

1998).

Hourly metering is currently in place at most large commercial and

industrial facilities. However, the costs of hourly metering

equipment and the communication logistics have limited the

penetration of hourly metering equipment into the small

commercial and industrial and residential sectors. For these

smaller energy users, profiling is typically used to develop proxies

for actual hourly metering.

Profiling estimates an end user’s hourly consumption by assuming

that the end user’s monthly energy use follows a pattern that is

similar to others in the end-user’s class. Hourly usage profiling is

then estimated based on the class’ usage pattern and the end-user’s

monthly meter reading. The disadvantage of profiling is that it

provides no incentive or mechanism for end users to respond to

short-term market forces. In addition, profiling introduces

inaccuracies by “averaging” end-users’ usage, which leads to issues

of equity and fairness in billing.

In addition to the cost of installing the metering equipment,

communications and processing of metering data present barriers to

the penetration of hourly meter reading for smaller end users.

Manual methods for meter reading are in the process of being

replaced by automated meter reading (ARM) systems. However,

the technologies to support ARM are still evolving.

The technology for automated communications of meter data is

generally grouped in to two categories:

Z dedicated ARM networks and

Z multipurpose networks that are “transparent” to the function

they are supporting (NARUC, 1998).

Dedicated ARM networks have the advantage that the majority of

electric customers can be equipped to fully benefit from open

access in a relatively short time, and these networks can provide a
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-13

wide range of new energy services and a few nonenergy services.

The disadvantages of ARM networks are that regionally dominate

suppliers of meter communication services may limit competition

once they are established, and reliability is an issue because of the

cost associated with dedicated backup systems.

Transparent networks, such as the Internet, have the advantage that

diverse applications will promote competition and provide the

resource to support continued technical evolution, stimulating

innovation and ensuring that capabilities expand to meet many

market needs. In addition, the “cloud” structure of transparent

networks such as the Internet increases reliability because of the

availability of multiple communication paths.

The California Model

California has initiated one of the most comprehensive and largest

applications of direct access metering and data communications

(Shepherd, 1998). The California RTO is responsible for balancing

generation supply and demand. The RTO is also responsible for

settling imbalance deviations for market participants when dayahead scheduling and actual generation and usage deviate (this is

referred to as setting or direct access settlement). The RTO

settlement process relies on scheduling coordinators to make daily

reports of actual usage of each of their loads, aggregated to each

grid supply point on an hourly basis. Hourly meter data are also

required for all generating units.

Figure A-3 illustrates California’s metering, data communication,

and settlement system to support their electric market. Utility

Translation System, Inc.’s Meter Data Acquisition System (MDAS) is

configured to read approximately 3,000 meters on an hourly basis

to measure the total power supplied to the transmission grid from

power plants and interchange points (state boundaries and for all

grid supply points where power is taken from the transmission grid).

The system retrieves data from meters through a dedicated ATM

network using frame relay and ISDN lines. The system is designed

to collect the meter information within 2 minutes and have it

available in the data management system within 8 minutes.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-14

Figure A-3. Information Flow to Support Billing and Market Settlements

Meter Data

Acquisition

Data

Aggregation

Data

Management

Data Delivery

to Market

Participants

Billing and

Market

Settlements

End

User

Bills

·

·

·

Local Profile

and Data

Warehousing

The aggregation of meter data is a key function that must be

performed before information can be dispatched for load profiling

or settlement processes. Both load data and financial settlement

use aggregation of load profiles from individual meters to generate

virtual meters that represent loads by end use, class, multimeter

accounts, delivery points, energy marketers, and utilities (Shepherd,

1998). Data compatibility is essential because of the large amounts

of data being processed and the reliance on system automation.

Data delivery to market participants is complicated by the large

number and the diversity of entities using the processed metering

information. The potential number and variations of systems,

architectures, and data formats that must be interfaced are huge.

The delivery system must be able to support delivery of data in

multiple file formats and to use various techniques for data

delivery, including physical media (disk, CD), telephone, e-mail,

and the Internet. There have been regional efforts in California to

establish standard formats for data delivery, but none has been
Appendix A — Existing Activities and Emerging Participants in the Electric Power Supply Chain

A-15

accepted on a broad basis. In addition, efforts are underway to

establish standard electronic data interchange (EDI) formats to

support transferring data between systems. The Internet has been

targeted as a likely de facto standard for data transfer, but several

issues are of concern, such as security and reliable transfer time.

The final step is the overall settlement process that compares

aggregated day-ahead schedules with aggregated estimates/actual

loads to calculate energy imbalances. The pricing components are

input from a combination of sources such as spot market purchase

prices, approved index pricing sources, and transmission control

area charges. California uses metering data to support the pricing

of the products and services, such as

Z ancillary services,

Z congestion management costs (re-dispatch and must-run),

Z transmission services,

Z RTO control area implementation and operating charges,

and

Z competitive transition charges (stranded access recovery).

Metering Equipment Manufacturers

The initial automatic meter reading projects began in the 1970s.

Westinghouse R&D designed the first nonvolatile solid state

memory chip for automated reading. It took readings from electric,

gas, and water meters and sorted them in memory that did not

require continuous power or battery back up to retain memory

through a power outage. Darco (name later changed to Darcom)

was a major contributor to the development of ARMs, designing

and programming a Texas Instruments-built customer

microprocessor chip for the Electric Power Research Institute’s

automatic meter reading functions.

Major manufacturers of meters today are listed in Table A-3. All of

these companies mass produce both monthly meters and hourly

meters.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

A-16

Table A-3. Meter Manufacturers

ABB OSC/Intelimeter

Computerized Manufacturing Corporation Process Systems, Inc. (Siemens)

General Electric Quadlogic Controls

Hiaweh Meter Company Schlumberger

Itron Genesis Teldata

Leach Industries—Amron Transdata, Inc.

National Meter Company

Currently, more than 30 companies provide or support advanced

metering products or automatic meter reading systems capable of

supporting hourly metering. These companies include

Z CallNet Data Systems,

Z ITRON,

Z Landis & Gyr Utility Services,

Z Polymeters Response International,

Z Schlumberger Industries,

Z UNITIL, and

Z Utility Translation System.
Appendix B:

Deregulation

Background and

Trends
B-1

Deregulation of the electric utility industry is an ongoing process.

In particular, deregulation of wholesale markets is well underway.

Wholesale market deregulation was initiated by the Energy Policy

Act (EPAct) of 1992, and implementing rules were issued by the

Federal Energy Regulatory Commission (FERC) in Orders 888 and

889. FERC Order 888 requires open access to the electricity grid

and nondiscriminatory pricing of wholesale transactions. FERC

Order 889 contains rules establishing and governing utility OpenAccess Same-Time Information Systems (OASIS) and prescribing

codes of conduct.

Deregulation of retail electricity markets is occurring at the state

level. But states are moving at different rates. Some states have

forged ahead and either allow, or will soon allow, electricity

customers to choose among generation suppliers. Most of the other

states have begun to address the issue of retail deregulation, but no

formal plans are in place yet. States that have deregulated tend to

be in regions with high electricity prices, but not exclusively so.

The overall trend is clearly toward deregulation of retail electric

markets, and the movement is gaining momentum.

This appendix provides a brief overview of the technology issues

that have led to deregulation of electricity markets, and a

discussion of the history of restructuring. The final section contains

two tables that present the status (Table B-1) and progress (Table B2) of retail electric deregulation across the United States as of

January 2000.

B.1 TECHNOLOGY ISSUES LEADING UP TO

DEREGULATION

The push for deregulation in the electric utility industry has not

been the result of rapid technology advances, as has been the case

in other industries, such as telecommunications. In fact, in many

ways, it is the lack of technology advances and the tapering off of

increased production efficiencies in large-scale generation that

have fueled the deregulation movement in the electric utility

industry. Since the birth of the electric utility industry up through

the early 1970s, the cost of generation had continually decreased

(usually in nominal, but always in real, terms). Over this period,
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-2

consumers became accustomed to reliable and inexpensive

electricity.

In the early 1970s, however, several factors combined to bring

about the first real increases in the price of electricity. The two

main components that had historically held prices in check—

increased generating efficiency and rapid demand growth—no

longer held true in the 1970s. The costs of generation could no

longer be reduced by building larger plants as economies of scale

in fossil fuel generation leveled off. In addition, the oil embargo

and the push for national energy self-sufficiency in the 1970s

spurred improvements in electric end-use equipment efficiency and

led to the first decrease in kWh sales since 1946 (the transition from

wartime to peacetime economy).

The sheer size of the construction projects for larger generation

plants contributed to the reduction of economies of scale in

generation. The magnitude of the projects strained the

management and organizational limits and often led to construction

delays and cost overruns. The combination of 10- to 15-year

construction projects with the high inflation and high cost of capital

of the 1970s also made constructing large-scale power plants

uneconomical.

In the mid-1980s, regulatory commissions began reviewing the

“prudence” of utilities’ decisions to proceed with the construction

of new large-scale generating plants. These reviews resulted in the

disallowance of billions of construction dollars and signaled the

end of large-scale construction projects. Environmental concerns of

the late 1970s and early 1980s also led to increases in the cost of

large-scale generation. Costly pollution abatement equipment for

fossil fuel plants was phased in during this period. Sharply

increased nuclear safety concerns in the aftermath of the Three Mile

Island incident led the Nuclear Regulatory Commission (NRC) to

require extensive and costly design modifications to planned

nuclear units and to nuclear plants under construction.

While efficiency gains in large-scale generation were leveling off,

advances in transmission technology enabled the transportation of

large blocks of power over long distances with improved reliability

and lower cost. Traditionally, transmission lines had a voltage

capacity of less than 200 kilovolts and could transmit power
Appendix B — Deregulation Background and Trends

B-3

effectively only over a short distance. With the introduction of

high-capacity lines of close to 1,000 kilovolts, line loss was greatly

reduced.

Innovations in the natural gas industry also played a major role in

the move toward deregulation in the electric industry. With new

seismic and drilling technologies, supply at the wellhead became

more reliable. Bottlenecks in the gas delivery system were worked

out, and natural gas markets evolved, enabling electricity

generators to contract for gas over long time periods. These factors

contributed to the cost competitiveness of small-scale combustion

turbine engines.

Also in the mid-1980s, new capacity construction costs for gas

turbine engines decreased because of a combination of advances in

turbine technology and economies of scale in engine production.

Technological progress in combustion turbines led to higher firing

temperatures, which resulted in increased efficiency for small-scale

generation. In addition, when combustion turbines are coupled

with heat recovery boilers to capture the exhaust heat, steam can

be generated. This steam can be used for process use

(cogeneration) or for generation of additional electricity with steam

turbines.

In conclusion, the main technology issue leading to the push for

deregulation in the electric utility industry has been the leveling off

of efficiency gains from large-scale generation and the increased

competitiveness of small-scale generation due to technology

advances and low gas prices.

B.2 BRIEF HISTORY OF RESTRUCTURING

The vision behind the restructuring of the electric power industry is

the creation of a competitive generation sector that would replace

the historic generation monopolies. The Public Utility Regulatory

Act of 1978 and the National Energy Act of 1992 encouraged the

introduction of independent power producers (IPPs) and began

building the diverse generation base needed to support a

competitive generation sector. However, in the 1980s and early

1990s the IPPs were still primarily limited to selling their power to

local utilities at prices set by regulatory agencies.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-4

In 1993, Alberta was the first region in North America to establish a

competitive wholesale spot market for electric generation. At about

the same time, British Columbia was also developing plans for

short-term markets. In April 1994, California followed with a

proposal to phase out its retail electric monopolies and offer

customers direct access to competitive generation markets.

However, the growth of regional spot markets was hampered by the

lack of an “open grid” that would support the large-scale

interregional market transactions associated with a truly

competitive generation sector.

FERC 888 was issued in April 1996 with the intent to provide open

access to transmission for all generators. It orders that private

owners of transmission assets offer competitors access to their grids

on the same terms afforded their own generation units. As part of

the order, public utilities that own, operate, or controll transmission

facilities are required to file open access nondiscriminatory

transmission tariffs. Tariffs are specified to provide service on both

a network basis and a flexible point-to-point basis: the network

service is a load-based service, and the point-to-point service is

based on transmission capacity reservations (FERC, 1996).

At the same time FERC issued Order 889 containing rules for

establishing and governing an OASIS and prescribing standards of

conduct. FERC 889 orders public utilities that own, operate, or

control transmission facilities to create or participate in an OASIS

that would provide open access transmission customers with

information, provided by electronic means, about available

transmission capacity, prices, and other information that would

enable them to obtain open access to nondiscriminatory

transmission service (FERC, 889). Section J of FERC 889 document

specific standards and communications protocols to support the

electronic transfer of information.

B.3 PRESENT STATE ACTIVITY

The present pace and details of restructuring vary greatly from state

to state. By mid-1999, 20 states and the District of Columbia, an

area containing over half of the U.S. population, had formally

decided to restructure and move toward some form of market-based

generation (Cavanagh, 1999). Another ten states are actively
Appendix B — Deregulation Background and Trends

B-5

engaged in some form of legislative or regulatory activity with the

goal of bringing retail electricity competition. Seventeen states

have established legislative study committees, and only three states

were not actively pursuing any reform (APPA, 2000). Table B-1

indicates where all 50 states and the District of Columbia fall on

this spectrum.

Table B-2 provides more detail and information on all of the states

that have enacted legislation and some of the states that have seen

significant activity towards enacting legislation. This table is based

on data from the Energy Information Administration and is current

as of January 2000.

Among the states that have moved to a competitive retail electricity

market, California has been a leader. In March 1998, some

Californians had the opportunity to select their electric supplier

over a transmission system operated with complete independence

from all generation owners. By 2002, all Californians will be able

to choose their supplier. In addition, the California independent

system operator (ISO) has established an Internet-based system of

communicating and monitoring generation units to support market

transactions. Other states, like Maryland, have followed similar

actions. A retail access bill was signed in April 1999, allowing

one-third of residential customers to choose their supplier by July

2000 and the remaining two-thirds of retail customers to choose

their supplier by July 2001. States that have enacted legislation are

predominately located in the Northeast (Maine, Rhode Island,

Pennsylvania) and the Southwest and West Coast (Texas, California,

New Mexico).

States that have engaged in some legislative or regulatory activity

have focused on achieving similar goals for retail customers as the

states that have already enacted retail competition. For example, a

bill was introduced into the Michigan legislature in January 2000

that is designed to give customers free choice over their electricity

suppliers by January 2002. Other states, like Louisiana, have

decided to move towards competition and will enact policy

changes by 2001. States that have seen major regulatory or

legislative activity are located in the Midwest (Indiana, Wisconsin)

and the Deep South (Alabama, Mississippi).
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-6

A third group of states has not made a decision to pursue retail

competition; they are maintaining vertically integrated monopoly

power systems while they are deciding if they should pursue

competition. For example, Utah passed legislation in 1997 to form

a study committee to determine the impacts of competition in Utah.

The main outcome of their study has been to adopt a “go slow”

approach and wait until the impacts from other states are better

understood. South Carolina also passed legislation in 1997 that has

been renewed each year since then to continue the study process.

States that are currently using legislative study committees are

located in the Southeast (Georgia, North Carolina) and the Rocky

Mountain area (Colorado, Nebraska).

Florida, Hawaii and South Dakota are not currently engaged in any

form of restructuring. These states are not pursuing any form of

deregulation nor have they created study committees to determine

if they should. However, these states have pursued deregulation in

the past. For example, Florida has introduced bills calling for

competition and for study committees; however, they have never

passed. South Dakota, on the other hand, has no desire to pursue

deregulation. South Dakota is one of cheapest power states in the

country, and deregulation would provide little, if any, benefit to the

predominantly rural population.
Appendix B — Deregulation Background and Trends

B-7

Table B-1. Status of Present State Activity, January 2000

Enacted Legislation

Legislative or

Regulatory Activity Study Committee No Present Activity

Arkansas Alabama Alaska Florida

California Arizona Colorado Hawaii

Connecticut Indiana Georgia South Dakota

Delaware Iowa Idaho

District of Columbia Louisiana Kansas

Illinois Michigan Kentucky

Maine Mississippi Minnesota

Maryland New Hampshire Missouri

Massachusetts New York Nebraska

Montana Wisconsin North Carolina

Nevada North Dakota

New Jersey South Carolina

New Mexico Tennessee

Ohio Utah

Oklahoma Washington

Oregon West Virginia

Pennsylvania Wyoming

Rhode Island

Texas

Vermont

Virginia

Source: American Public Power Association (APPA). 2000. “Status of State Electric Utility Deregulation.”

<http://www.appanet.org>.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-8

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

State Status of Restructuring Activity

Alaska

Additional

Information

1/99: Chugach rejected Matanuska’s offer and contended that the savings projected by the merger

could easily be achieved through competition; Chugach will continue to push for statewide

competition.

10:98: Matanuska Electric Association, Chugach’s largest wholesale customer, offered to buy out

Chugach. Chugach’s assets are valued at $486 million. Chugach officials were surprised by the offer

and are withholding judgment.

6/98: PUC rejected Chugach’s argument and affirmed the Public Utility Commission’s (PUC’s)

authority to regulate retail wheeling.

1/98: Chugach Electric Association, the state’s largest utility, urged PUC and legislators to allow retail

competition in Anchorage and surrounding areas. House Bill 235 primarily failed because Chugach

would not support it unless it was amended to allow retail wheeling in Anchorage and surrounding

areas.

Arizona

Schedule 1/00: APS and TEP have opened 20 percent of their retail load to competition, APS in 10/99 and TEP

in 1/00. Salt River Project began phasing-in retail access in 12/98. All customers in the state will have

retail access by 1/01.

11/99: The ACC approved Tucson Electric Power’s restructuring settlement. TEP will open 20 percent

of its load to retail competition by 1/00

9/99: APS will open 20 percent of its territory to competition on 10/1/99, and all of it by 1/01.

7/99: The first customers to take advantage of retail choice began receiving power from APS Energy

Services in July. The two industrial customers are in the Salt River Project’s service territory. Salt River

Project opened 20 percent of its territory to retail competition in 12/98, and will open the rest by

12/00.

1/99: The Salt River Project opened about 20 percent of its market to retail competition in 12/98.

Rates 11/99: TEP’s settlement agreement was approved and requires a 1 percent rate reduction and a rate

freeze through 2008.

9/99: APS’s settlement agreement was approved. Residential rates will be reduced 7.5 percent over 4

years, and large users’ rates 5 percent over 3 years.

5/99: In the proposed APS settlement agreement, rates will be reduced 7.5 percent for residential and

small business customers and 5 percent for industrial customers over the next 4 and 3 years,

respectively. If approved, the residential and small business reductions would total 16 percent over

10 years, including the rate reductions from 1994. TEP’s settlement includes a more modest rate

reduction of 1 percent in 7/99 and in 7/00 with rates frozen at the 7/00 level until 2008.

1/99: The Salt River Project’s restructuring plan includes a 5.4 percent residential rate reduction.

Utility Plans 11/99: The ACC approved TEP’s restructuring agreement. The agreement will allow recovery of $450

million in stranded costs collected from ratepayers through 2008; rate reductions of 1 percent and

frozen from 7/00 to 2008; and retail access beginning with 20 percent of TEP’s retail load 60 days

after ACC approval (1/00), and all customers by 1/01. TEP’s generation assets will be transferred to an

affiliate company by the end of 2002.

(continued)
Appendix B — Deregulation Background and Trends

B-9

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Arkansas

Schedule 5/99: Legislation sets retail competition to begin by 1/1/02. Implementation of retail competition can

be delayed by the Public Service Commission (PSC), but no later than 6/30/03.

Rates 5/99: Rates for consumers of utilities seeking to recover stranded costs will be frozen for 3 years, and

for those not seeking to recover any stranded costs, 1 year.

Utility Plans 12/97: Arkansas PSC agreed to Entergy’s restructuring plan. The plan includes rate reductions of

about $217 million over 2 years; debt reduction of $165 million over 5 years on the Grand Gulf

Nuclear Station; and creation of a special transition cost account to collect funds for stranded costs

recovery.

California

Schedule 1/00: As of 1/15/00, the PUC reports 209,752 direct access customers (2.1 percent) out of 10,157,716

possible utility distribution customers. The direct access customers represent 13.8 percent of the total

load. Almost one-third of the demand by large industrial customers is being served by competitive

companies, whereas only about 2.1 percent of residential load is on direct access.

6/99: As of 5/31/99, the PUC reports that 135,493 California consumers (about 1.3 percent) have

switched electricity providers. The breakdown by customer class is: 92,904 residential consumers or

about 1.1 percent; 26,942 small commercial (2.8 percent); 11,652 large commercial (5.9 percent);

1,002 large industrial (20.6 percent); 2,977 agricultural (2.5 percent); and 16 unknown. About half of

the consumers who have switched suppliers have opted for “green” power, electricity generated from

environmentally acceptable methods, such as wind, solar, and geothermal.

10/98: Based on California Public Utilities Commission (CPUC) data, New Energy Ventures, a retail

electricity marketer, calculated it has won about 40 percent of the 13,648 GWh load being served by

nonutility energy service providers.

4/98: The CPUC issued the final order to open the retail market on 3/31/98; all consumers in investorowned territories could choose alternative electricity suppliers.

Rates 6/99: The CPUC ended the mandatory 10 percent rate reduction for San Diego Gas & Electric

(SDG&E) since the transition period for SDG&E ended with recovery of all stranded costs and the end

of the competitive transition change (CTC) for consumers. Rates in SDG&E’s territory are now

unregulated and likely could be more volatile. The utility expects rates may rise during the summer

months.

5/99: SDG&E’s consumers may see lower bills as the transition period for SDG&E ends in July when

their stranded costs will have been completely recovered. The accelerated pay-off of stranded costs

has left most of the monies raised through securitization to finance the 10 percent rate reduction with

bonds unneeded. SDG&E plans to return some of the funds to small consumers. SDG&E also asked

the PUC to end the rate cap, which should allow a more competitive market to develop.

4/98: California’s restructuring legislation included a 10 percent rate reduction for residential

consumers.

Utility Plans 6/99: Los Angles Department of Water and Power is offering a “green power” option to its customers.

5/99: Sacramento Municipal Utility District approved a direct access program to replace their pilot

program. The program will offer 300 MW of load to competitive suppliers and is less expensive and

simpler for suppliers than the pilot program.

Additional

Information

7/99: To date, over 90 percent of customers who switch their electricity providers are receiving green

power. The CPUC reports show customer requests for green power are up 90 percent from earlier in

the year. A statewide credit for renewable energy purchases allows green power providers to offer

renewable-based electricity at a price below that offered by the three major IOUs.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-10

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Connecticut

Schedule 6/99: The Department of Public Utility Control (DPUC) is concerned that no suppliers have yet

applied for licensing to serve the market when it opens 1/00. Part of the lack of interest may be

because the rules for standard offer service and estimated stranded cost recovery are not yet finalized

by the Attorney General and the state General Assembly.

4/99: The DPUC ordered generation charges to be shown as a separate charge beginning 7/99. Bills

will be completely unbundled as of 1/00. Suppliers will begin licensing as early as 7/99 and soliciting

of customers will begin.

4/98: Restructuring legislation requires retail competition for 35 percent of consumers by 1/00, and all

consumers by 7/00.

Rates 4/98: Restructuring legislation requires a 10 percent rate reduction beginning 1/00.

Utility Plans 8/99: The DPUC gave a preliminary order for stranded cost recovery of $726 million instead of the

requested $916 million to United Illuminating (UI).

6/99: UI’s plan for unbundling its generation assets was approved by the DPUC. UI plans to place its

nuclear assets in a separate division from 10/99 until they are divested through public auction.

10/98: UI filed its divestiture plan with the PUC to sell its nonnuclear generating assets. Plants being

sold include the 590 MW Bridgeport Harbor and the 466 MW New Haven Harbor plants. Also in

filing are plans on how to unbundle the generation business from the wires or distribution business.

UI will become a “wires” company responsible for power delivery.

Delaware

Schedule 9/99: The PUC issued final orders for restructuring in Delaware. Start date for competition is 10/1/00

for residential customers, 10/1/99 for large customers, and 1/15/00 for medium-sized customers.

Conectiv (DP&L)—Phase-in of retail access for consumers in Conectiv’s territory is for large industrial

consumers on 10/1/99; other consumers with over 300 kW demand by 2/00; and small consumers by

8/00. DP&L will be the default supplier during the 4-year transition period.

Delaware Electric Cooperative—Consumers in Delaware Electric Cooperative territory will have a

similar schedule with a 6-month delay. Municipals in Delaware may choose whether to allow retail

access.

Rates 4/99: Conectiv (DP&L) residential consumers will receive a 7.5 percent rate reduction and a 4-year

rate freeze from 10/1/99 to 9/30/02. Nonresidential consumers also will receive a rate freeze for the

same period.

DE Electric Cooperative—Consumers will receive no further rate reduction (having received a recent

5 percent cut) but will have rates frozen for 5 years.

Utility Plans 5/99: Conectiv announced its restructuring plan to prepare the company for competition. It will sell

its three fossil-fuel plants and interest in five nuclear plants used for baseline generation and retain

peaking gas units. It plans to expand its telecommunications business.

4/99: Restructuring plans for Conectiv and DE Electric Cooperative will be filed by 4/15 and 9/15,

respectively.

(continued)
Appendix B — Deregulation Background and Trends

B-11

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

District of

Columbia

Rates 3/99: Potomac Electric Power Company’s (PEPCO’s) restructuring plan proposes a 5-year rate freeze.

Utility Plans 3/99: PEPCO plans to sell its power plants and purchase power contracts. PEPCO intends to become

a “wires” company, concentrating on power delivery, retailing power, cable TV, and Internet services.

Georgia

Utility Plans 6/98: Georgia Power submitted a 3-year plan to reduce rates by about $300 million. Georgia Power

advocates a slow approach to restructuring.

Additional

Information

New customers with loads greater or equal to 900kW have had the option to pursue private contracts

for power since1973 under the Georgia Territorial Electric Service Act.

Illinois

Schedule 11/99: Direct access began in 10/99 for many commercial and industrial consumers. Loads over

4MW and multisite (at least ten sites) customers with aggregate loads over 9.5MW are automatically

included in this first phase to implement retail access. A lottery was held at each utility to choose

consumers to allow about one-third of the remainder of commercial and industrial load to participate

in the first phase. Media sources report that customers in Commonwealth Edison’s service territory are

realizing 5 to 15 percent savings from competitive companies.

7/99: The General Assembly amended the 1997 restructuring law, accelerating the schedule for retail

access: certain nonresidential consumers will begin retail access by 10/99. Government customers

will have direct access by 10/1/00; all remaining nonresidential customers by 12/31/00; and all

residential customers by 5/1/02.

4/99: The sign-up process for eligibility to choose is under way at each utility. Loads over 4MW and

multisite (at least ten sites) customers with aggregate loads over 9.5MW are automatically included.

Interested consumers will sign up and a lottery will be held to determine the one-third of

nonresidential load (excluding the 4MW and 9.5MW aggregated loads) that will have retail choice by

10/99. The remainder of commercial and industrial consumers not chosen in this lottery will get retail

choice on 12/31/00, and residential consumers will have retail access by 5/1/02.

12/97: The restructuring legislation in Illinois will allow retail access for some commercial and

industrial consumers by 10/99 and all consumers by 5/02. Transition charges will be collected from

consumers who choose alternative suppliers until 2006.

Rates 3/99: ComEd’s residential customers have saved approximately $170 million as a result of the

15 percent rate reduction on 8/1/98.

10/98: As required by the restructuring law in Illinois, a 15 percent rate reduction went into effect in

8/98. To date, Illinois Power customers have saved about $12.5 million.

8/98: The phase-in of rate cuts took effect. The state’s largest utilities, Illinova and Commonwealth

Edison, cut rates 15 percent; another 5 percent reduction is due 5/02. Smaller utilities will phase-in

5 percent reductions by 5/02.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-12

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Illinois (continued)

Utility Plans 8/99: Ameren and Cilco both held lotteries to choose the one-third of eligible customers that will

receive retail access. All customers over 4 MW are automatically eligible, and one-third on the load

for nonresidential customers will be available to competitive suppliers beginning 10/1/99. Lotteries

were held because more than a third of the customers expressed the desire to be included in this first

phase of retail access in Illinois. Those customers not selected in these lotteries will have retail choice

in 2000. Residential customers will have retail choice in 5/02.

7/99: ComEd held three lotteries (one for single-site consumers, one for commercial consumers with

at least ten sites and an aggregated demand of at least 9.5 MW, and one for nonresidential consumers

with two or more sites; customers with loads 4 MW and more are automatically included) to choose

the one-third of consumers to have retail access by 10/99. Over half of the commercial and industrial

consumers in ComEd’s territory are registered for retail choice. ComEd announced the resultant

energy freed for competition will be over 30 billion kWh. In Illinois Power’s service territory, all

commercial and industrial customers who registered will begin retail access 10/1/99. Only about

75 percent of those eligible in Illinois’s territory registered.

Indiana

Utility Plans 7/98: Consumers of Indianapolis Power & Light were offered three billing options. Consumers can

choose a fixed rate, a fixed monthly bill based on last year’s average bill, or a “green power” rate

under an alternative pricing plan approved in 3/98 by the Indiana Utilities Regulatory Commission.

Maine

Schedule 1/99: Maine consumers will begin seeing itemized bills in 1/99 that separate the costs of power

generation from delivery. The restructuring law requires unbundled billing by 1/1/99.

5/97: Restructuring legislation requires retail competition by 3/00. IOUs are limited to 33 percent of

the market in their territories.

Utility Plans 5/98: PUC approved Central Maine Power’s corporate reorganization into a holding company, CMP

Group, Inc., and distribution and transmission services. A new unit, Maine Power, will market

electricity.

Maryland

Schedule 4/99: Restructuring legislation allows retail access over a 3-year phase-in period beginning 7/00 with

a third of consumers, another third by 7/01, and all by 7/02.

Rates 9/99: PEPCO is seeking approval of its deregulation plan that will include a 3 percent rate reduction

over 4 years beginning in 7/00, and another 4 percent reduction by eliminating a surcharge that has

funded energy conservation programs over the last decade.

4/99: Restructuring legislation requires at least a 3 percent rate reduction for residential consumers.

Utility Plans 01/00: Allegheny Energy Inc.’s settlement plan for restructuring was approved by the PSC in 12/99.

Highlights of the plan include retail direct access for almost all Maryland customers by 7/1/00; a

7 percent residential rate reduction, effective 1/1/02 through 12/31/08; a cap on residential generation

rates from 1/1/02 through 1/1/08; a cap on nonresidential rates through 1/1/04; a cap on transmission

and distribution rates for all customers from 1/1/02 through 1/1/04; authorization to transfer all

generation assets to Allegheny’s unregulated affiliate company, Allegheny Energy Supply Company,

LLC, at book value; the recovery of purchased power costs incurred as the result of contracts with

PURPA qualifying facilities; and establishment of a fund for the development and use of energyefficient technologies.

(continued)
Appendix B — Deregulation Background and Trends

B-13

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Maryland (continued)

Utility Plans

(continued)

1/00: PEPCO’s restructuring plan was approved by the PSC. The plan will allow retail direct access

by 7/00; the sale of PEPCO’s power plants; a 7 percent residential rate reduction; and a 4 percent

nonresidential rate reduction.

12/99: PEPCO began a consumer education program, PEPCO Answers, to provide information to

Maryland consumers on electricity competition. Consumers were told that they may begin “shopping”

for power in the spring of 2000 and begin receiving power from competitive companies by 7/00.

PEPCO has filed proposals with the Maryland and District of Columbia PSCs to sell its power plants.

9/99: Under its pending restructuring plan, BG&E’s shopping credit for residential consumers would

be 4.224 cents per kilowatt-hour and rise to 5.02 cents in 6 years, too low according to competitive

companies seeking to enter the retail electricity market in Maryland. The Mid-Atlantic Power Supply

Association suggests the credit be set at 5.7 cents; BG&E says the low credit reflects its low prices.

6/99: The restructuring legislation prompted Maryland utilities to revise their restructuring proposals.

BG&E submitted its new plan to the PSC: all customers will have retail access beginning 7/00;

residential rates will be decreased 6.5 percent beginning 7/00; $528 million in transition costs will be

recovered over 6 years from customers; rates will be unbundled and generation assets transferred to an

affiliate company; and BG&E will provide the initial funding of a low-income assistance fund and act

as default supplier for customers deciding not to switch suppliers.

4/99: PEPCO reached an agreement for restructuring. It will open retail competition to all of its

consumers on 7/1/00. PEPCO is selling its generation assets and will use the profits to offset stranded

costs. Remaining stranded costs will be collected from consumers paying a transition charge. Rates

will be capped for 3 years at the 7/1/00 level.

2/99: PEPCO signed an agreement with the Maryland PUC for a plan to bring retail choice to its

Maryland consumers as early as next year. The plan requires Maryland legislation and concurrence

with the District of Columbia PUC for the sale of PEPCO’s power plants.

Additional

Information

4/99: The restructuring legislation gives municipalities the option to implement retail direct access.

Massachusetts

Schedule 2/99: Standard offer service (SOS), set for 1998 at 2.8 cents/kWh, rose to 3.5 cents/kWh for 1999,

which should enable some suppliers to offer electricity competitively. SOS will gradually increase to

5.1 cents/kWh in 2004. By 3/05, SOS will end and all customers are expected to take competitive

generation service.

6/98: Customers in Massachusetts are beginning to sign up to purchase power from competitive

suppliers.

11/97: Restructuring legislation requires retail access by 3/98.

Rates 10/98: NEES subsidiaries, Massachusetts Electric and Nantucket Electric Company, report savings for

their consumers of $67.5 million due to rate reductions. The state’s restructuring law reduced rates by

10 percent. The sale allowed additional rate reductions prior to the law’s further requirements in 1

year.

11/97: Restructuring legislation requires rate reductions of 10 percent by 3/98 and another 5 percent

18 months later.

Additional

Information

10/99: By the first quarter of 1999, about 1.3 percent of retail sales were supplied by competitive

suppliers, representing about 0.13 percent of customers, most of which are large industrial consumers.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-14

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Massachusetts (continued)

Additional

Information

(continued)

9/98: PG&E Corporation’s subsidiary, PG&E Energy Services has secured a multiyear contract with the

Massachusetts High Technology Council (with over 200 members) to provide electricity to its

members. This is the largest aggregation of customers in the U.S., representing about 1.2 million

MWh annually.

6/98: Massachusetts’ utilities received no bids for SOS or default power supply. Western

Massachusetts Electric has asked the Department of Telecommunications and Energy (DTE) to remove

the price cap on SOS, hoping to attract suppliers. SOS is set at 2.8 cents/kWh for consumers this year;

bids were sought for no higher than 3.2 cents/kWh.

Michigan

Schedule 1/00: The second phase in Consumers Power’s plan to gradually implement retail direct access now

allows 300 MW of load to be served by alternative suppliers. As in the first round of bids for 150

MW, the second set of bids exceeded the 150 MW of allotted capacity. Three more blocks of 150

MW each are scheduled to be offered for direct access on 12/27/99, 2/28/00, and 10/30/00. By 1/02,

all consumers will have direct access to retail electric power.

1/00: Detroit Edison customers participating in Phase I of the customer choice program began taking

power from alternative suppliers in 12/99.

12/99: The first phase of retail access was implemented in 9/99 with full participation in Detroit

Edison’s territory. The second phase began in 11/99. Each of five phases will make 225 MW of

capacity available for all classes of consumers, until beginning in 1/02, when all consumers will have

retail direct access to competitive generation provider companies.

5/99: Seven large consumers of Detroit Edison can begin buying power from competitive suppliers on

6/1/99. Choice will be phased in for all Detroit Edison consumers by 1/02.

3/99: The PSC plan is for 2.5 percent of consumers of Detroit Edison and Consumers Energy to

choose electric suppliers beginning 9/99, and adding an incremental 2.5 percent every 6 months until

1/1/02, when all consumers of Detroit Edison and Consumers Energy will gain retail access.

Utility Plans 3/99: The PSC gave final approval to the retail choice implementation plans for Detroit Edison and

Consumers Energy. A phase-in period for retail access will begin on 9/20/99.

6/98: Detroit Edison and Consumers Energy filed revisions of draft plans that address comments from

the MPSC staff, customers, suppliers, and other interested parties. Both plans will phase-in retail

competition over the next 4 years beginning with large industrial consumers by 11/98 and full retail

access by 1/1/02.

Montana

Schedule 3/98: Montana Power accelerated its schedule for residential and commercial customers’ pilot

program. All customers will have retail access by 4/00, 2 years earlier than the law requires.

4/97: Senate Bill 390, the Electric Utility Industry Restructuring and Customer Choice Act, was

enacted allowing large industrial consumers retail access by 7/98 and all consumers by 7/02.

Rates 4/97: The restructuring law includes a 2-year rate freeze beginning 7/98.

Utility Plans 11/98: The PSC reached an agreement with Pacificorp to proceed with the sale of its service territory

in the state to Flathead Electric Cooperative. Pacific Power (Pacificorp’s Montana division) has about

34,500 customers.

(continued)
Appendix B — Deregulation Background and Trends

B-15

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Nevada

Schedule 6/99: AB 366 delays the opening of the retail market by 3/00 and gives the governor, rather than the

PUC, the authority to select another date if he deems it in the best interest of consumers.

4/99: The Senate committee approved a bill that would delay retail access until 3/00 and freeze rates

until 3/03.

7/97: Restructuring legislation directs the PUC of Nevada (formally the PSC) to establish a market in

which customers have access to potentially competitive electric services from alternative suppliers no

later than 12/31/99.

Rates 6/99: AB 366 freezes rates from 3/00 through 3/03.

New Hampshire

Schedule 10/98: Granite State will begin retail choice in its service territory upon the closing of the sale of

NEP’s nonnuclear generation assets or by 7/1/98, whichever occurred first.

4/98: Legislators are discussing a delay until 1/31/99 for beginning retail choice in the state or

authorizing the PUC to postpone the date indefinitely, due to the delay until November of the

stranded costs case brought by PSNH.

5/96: House Bill 1392 was enacted, requiring the PUC to implement retail choice for all customers of

electric utilities under its jurisdiction by 1/1/98, or at the earliest date that the Commission determines

to be in the public interest, but no later than 1/1/98.

Utility Plans 8/99: Public Service of New Hampshire (PSNH) filed a settlement plan with the PUC that will give

consumers an 18 percent rate cut and allow retail competition to finally begin. Under the agreement,

customers would pay $1.9 billion in stranded costs (PSNH would write off about $225 million in

stranded costs, the largest disallowance of stranded cost recovery at a U.S. utility to date).

9/98: Unitil (subsidiaries include Concord Electric, Exeter & Hampton Electric, and Fitchburg Gas &

Electric) filed its restructuring settlement agreement with the PUC. In the agreement, Unitil will sell its

New Hampshire power supply portfolio and be allowed to recover 100 percent of stranded costs over

12 years. Customer choice will be phased-in beginning 3/1/99.

8/98: PUC ruled that New Hampshire Electric Cooperative can offer customers choice if FERC

approves the “interpretation of its contract” for power purchases with PSNH.

6/98: The PUC gave approval to a settlement, the first in the state, with Granite State Electric to bring

retail competition to the electricity market. Under the settlement, Granite State customers could see a

17 percent rate cut and choose their generation supplier as early as July.

4/98: Granite State restructuring plan is approved by PUC and the governor. Retail choice will begin

7/98 regardless of other utilities in the state. A 10 percent rate reduction will go into effect and, after

divestiture of generation assets, a 17 percent reduction. Stranded cost recovery is set at 2.8

cents/kWh, decreasing by 50 percent once divestiture is completed.

Additional

Information

4/99: Restructuring is at a standstill due to federal court rulings concerning the PUC’s efforts to set

stranded costs and rates for PSNH. The continuing federal court cases could delay restructuring efforts

in the state for years.

12/98: U.S. Circuit Court of Appeals ruled in favor of a lower court ruling, preventing the NH PUC

from implementing deregulation, advancing PSNH’s lawsuit over the plan to trial. The trial is set for

2/99.

6/98: U.S. District Court issued an order enjoining the PUC from implementing any restructuring

plans until the court holds trial for the suit filed by PSNH, scheduled in November.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-16

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

New Hampshire (continued)

5/98: The New Hampshire Supreme Court heard arguments in the PSNH rate agreement case. A

ruling is expected early in June.

Additional

Information

(continued) 1/98: The PUC formally delayed the 1/98 start of retail competition to 7/98 due to the continuing

litigation between the PUC and PSNH.

3/97: PSNH filed a complaint with federal district court requesting the court enjoin the PUC

restructuring plan, due to basing stranded cost recovery on market forces rather than utility costs. The

court issued a stay on the plan as it applies to PSNH.

New Jersey

Schedule 12/99: Customers in New Jersey began receiving power from their suppliers of choice on 11/14/99.

8/99: As a result of legislation passed 2/99, retail choice for all consumers became a reality on 8/1/99

in New Jersey.

3/99: New Jersey plans to launch its consumer education for electricity restructuring and retail choice

program on 6/1/99.

Rates 8/99: Retail rates were reduced 5 percent on 8/1/99 as required by restructuring legislation. Further

rate reductions will increase to 10 percent. The reductions must be sustained for 48 months from the

start of direct access.

Utility Plans 7/99: Conectiv has received final approval from the BPU for its restructuring plan. The plan will give

consumers retail choice by 11/14/99, as the BPU has extended the date for delivery of power from

alternative suppliers to allow utilities more time to get their computer systems ready for the change.

Rates will be cut by 5 percent on 8/1/99, increase to 7 percent on 1/1/01, and increase to 10.2 percent

on 8/1/02. Conectiv’s distribution rate will be 2.1384 cents/kWh. The company is allowed $800

million in stranded costs recovery. Shopping credits, the rates which outside suppliers must compete,

are set: residential credits will be 5.65 cents/kWh in 1999, 5.7 in 2000, 5.75 in 2001, 5.8 in 2002,

and increase to 5.85 in 2003; commercial rates will begin at 5.18 cents/kWh and eventually increase

to 5.7 cents; industrial rates range from 4.95 cents/kWh and go up to 5.65, depending on voltage and

time-of-day usage.

6/99: GPU’s restructuring plan for offering customers retail choice as of 8/1/99, was accepted by the

BPU. The settlement includes rate reductions in addition to the 5 percent due August 1 as required by

the restructuring legislation. Customers of GPU subsidiary Jersey Central Power & Light will also

receive another 1 percent reduction in 2000, 2 percent in 2001, and 3 percent in 2002. Average

shopping credits (actual credits depend on consumer class) were increased to 5.13 cents/kWh for

August 1999, 5.27 cents in 2000, 5.31 cents in 2001, 5.36 cents in 2002, and 5.40 cents in 2003.

GPU will be allowed to recover $400 million in stranded costs. Originally they asked for $525

million.

3/99: Public Service Electric & Gas proposed a deregulation plan to the BPU that would determine

how PSE&G would operate in a deregulated environment, which is scheduled to begin in New Jersey

on 8/1/99.

8/98: BPU is reviewing PSE&G’s and Atlantic City’s Conectiv) restructuring plans.

9/97: An Initial decision on the four investor-owned utilities’ restructuring filings is set for May 1998.

PSE&G’s plan would provide full retail competition by 1/99, and Rockland Electric’s by 5/99. GPU’s

(Jersey Central P&L) and Atlantic Energy’s adhere to the BPU schedule

7/97: The four investor-owned electric utilities in the state submitted three filings each to the BPU

consisting of a rate unbundling filing, a stranded cost filing, and a restructuring filing.

(continued)
Appendix B — Deregulation Background and Trends

B-17

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

New Mexico

Schedule Legislation passed in 4/99 that will allow direct access to be phased-in over the next 3 to 4 years.

New York

Schedule Central Hudson Gas & Electric

Phase I—9/1/98 includes 8 percent of load by 12/31/98.

Phase II—1/1/99 includes 8 percent additional load by 12/31/99.

Phase III—1/1/00 includes 8 percent additional load each year.

Full Retail Access—7/1/01.

Consolidated Edison

Phase I—6/1/98 includes 1,042 MW (116 MW small loads and 926MW large loads).

Phase II—4/1/99 includes an additional 1,000 MW from all customer classes.

Phase II was reopened in August to fill the program to its targeted enrollment of 2,000 MW.

Phase III—4/1/00 includes an additional 1,000 MW each year from all customer classes.

Full Retail Access—12/31/01 or 18 months after RTO fully operational, whichever is sooner.

Long Island Power Authority

8/99: Numerous large business customers in LIPA’s Choice Program began receiving power in

August from an alternative supplier, ConEdison Solutions. ConEd Solutions is supplying about 20

MW of power to over 100 facilities on Long Island.

New York State Electric & Gas

Phase I—8/1/98 includes all customers in Norwich and Lockport Division and all small industrial

 customers throughout service territory.

Full Retail Access—8/1/99.

Niagara Mohawk Power

Phase I—9/1/98 includes transmission level customers >60KV.

Phase II—9/1/98 includes all remaining customers with peak demands >2MW.

Phase III—5/1/99 includes all remaining transmission and subtransmission customers >22KV.

Phase IV—4/2/99 includes all residential customers.

Phase V—8/1/99 includes all remaining nonresidential customers.

Full Retail Access—8/1/99.

Orange and Rockland Utilities

Phase I—5/1/98 includes expanding the pilot program, PowerPick, to all customers (energy only).

Full Retail Access—5/1/99 includes energy and capacity.

Rochester Gas & Electric

Phase I—7/1/98 includes all customer classes, energy only, limited to 670 GWH annual

 energy total.

Phase II—7/1/99 includes all classes, energy and capacity, limited to 1,300 GWH annual

 energy total.

7/99: RG&E is making an additional 10 percent of their system available to competitors.

Phase III—7/1/00 includes all classes, energy and capacity, limited to 2,000 GWH annual

 energy total.

Full Retail Access—7/1/01 includes all customers, energy, and capacity.

Rates 8/99: Niagara Mohawk received approval to reduce prices for the second consecutive year, beginning

9/1/99. The price reductions are part of NIMO’s PowerChoice Plan. Average reductions for

residential and small commercial consumers should be about 1 percent in addition to the approximate

0.8 percent effected last year. Another reduction scheduled for 9/1/00 will achieve overall reductions

of about 3.2 percent. Industrial customers will receive larger reductions. Total savings for all

customer classes under the 3-year Power Choice Plan will be about $600 million.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-18

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

New York (continued)

Utility Plans Consolidated Edison

4/99: Phase II of ConEd’s retail choice program began in April. Nearly 22,000 new customers are

now enrolled, bringing the total customers in the programs to more that 68,000.

12/98: ConEd began Phase II of its customer choice program. Enrollment of customers to exercise

retail choice begins 1/99. The program will continue phasing in customers until all ConEd’s

customers have retail access in 2001.

5/98: Because of oversubscription of ConEd’s Phase I for retail competition, the load for residential

and small commercial customers was doubled to 1,000 MW; a lottery will be conducted for large

customers. Customers will begin receiving power from their suppliers of choice among more than

20 registered ESCOs on June 1.

9/97: PSC approved ConEd’s restructuring plan. The plan calls for rate cuts, retail competition to

phase-in beginning 6/98, and full retail access by 12/01. In addition, ConEd will file by 1/98

unbundled tariffs for all classes of customers, to become effective 4/98. The plan calls for

divestiture of at least 50 percent of ConEd’s New York City fossil-fueled generation by the end of

2002.

Central Hudson Gas & Electric

2/98: PSC approved restructuring plan for Central Hudson Gas & Electric. The plan requires

divestiture of fossil-fueled plants, a rate freeze until 6/30/01, rate reductions, and transition to full

retail competition by 7/01.

Long Island Power Authority

11/98: Long Island Power Authority began retail access for 400 MW of load in 1/99 with a target

of August for delivery of power from competitive providers. The first phase of direct access is split

between residential (180MW), commercial, and government consumers. Phase II will open

another 800 MW in 5/00. All customers of LIPA will have retail choice by 1/03.

New York State Electric and Gas

1/98: PSC approved New York State Electric & Gas’s restructuring plan. The plan includes phasein of retail competition for small industrials beginning 8/98, full retail competition by 8/99, a rate

freeze and rate cuts, and divestiture of its coal plants by 8/99.

Niagara Mohawk

12/99: A competitive supplier, NYSEG Solutions, is offering NIMO residential customers a choice

in generation supplier.

2/98: PSC approved Niagara Mohawk’s plan for rate restructuring, a nonbypassable CTC to fund

$3.6 billion in debt for settlement with 16 IPPs to restructure uneconomic contracts, and divestiture

of fossil-fueled and hydroelectric plants. Retail competition will begin in 1998 for large customers

and be available to all customers by 1/1/00.

(continued)
Appendix B — Deregulation Background and Trends

B-19

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

New York (continued)

Utility Plans Orange and Rockland

(continued) 12/97: PSC settled Orange and Rockland’s proposal for restructuring. O&R will phase-in retail

competition beginning

5/98: Allow full retail competitive by 5/99, provide rate cuts, and require divestiture of generation

assets by 5/99.

5/98: Orange and Rockland became the first utility in New York to offer retail choice through its

Power Pick program as customers began to receive power from their suppliers of choice on 5/1/98.

Rochester Gas & Electric

1/98: PUC approved Rochester Gas & Electric’s restructuring plan. RG&E will begin in 7/98 with

open access for 10 percent of its customers and phase-in full retail access by 7/01. Divestiture of

fossil-fueled and hydro plants and rate cuts is included in the plan.

Ohio

Schedule 6/99: The restructuring legislation will allow retail customers to choose their energy suppliers

beginning with a phase-in by 1/01 and completion by 12/05.

Rates 6/99: The restructuring legislation requires 5 percent residential rate reductions and a rate freeze for 5

years.

Utility Plans 1/00: First Energy filed a transition plan with the PUCO in 12/99. The plan includes unbundling the

price of electricity into the components (generation, transmission, distribution, and transition).

Additional

Information

6/98: The PUC approved Monongahela’s tariff for conjunctive electric service, the first tariff approved

that will allow groups of consumers to aggregate and negotiate the price for electricity.

Oklahoma

Schedule 6/98: New restructuring legislation speeds up the time line for restructuring the industry and requires

that all studies by completed by 10/99. Some retail competition should begin as early as 1999.

4/97: The Electric Restructuring Act of 1997 allows retail competition by 7/02. The OCC is directed

to study the issues and develop a framework to implement retail competition.

Oregon

Schedule 7/99: The restructuring legislation will allow direct access for industrial and large commercial

consumers beginning 10/00. Residential consumers will not have direct access to suppliers under

restructuring, but will be provided a portfolio of pricing options, including a “green” rate, a marketbased rate, and a traditional regulated rate.

Utility Plans 2/98: Portland General Electric’s deregulation plan, which could become a model for the state, faces

opposition from the Oregon Intervenor Coalition that includes Pacificorp, Washington Water Power,

and consumer groups. Portland’s plan calls for selling all its generation and allowing all customers to

choose competitive generation suppliers. The coalition prefers a “portfolio model” for customer

choice. The portfolio model would allow large industrial customers to shop for power suppliers, but

small customers would continue to be served by the incumbent utilities and be offered a menu of

plans to choose from. Options would include existing, market, or “green” rates.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-20

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Pennsylvania

Schedule 1/99: About 475,000 customers (9.5 percent of eligible customers) have submitted paperwork to

switch their generation supplier. Retail access will be available for two-thirds of the state’s customers

on 1/1/99.

9/98: About 1.8 million customers have registered to choose their electric generation supplier. The

customers have received a “How to Shop” guide and a list of competitive suppliers and are now in the

process of making choices. All residential customers will receive an 8 percent rate reduction, and so

far competitive suppliers will provide customers about 14 percent savings. Also, four “Green-e”

products (a product with the Green-e logo is certified to be produced with 50 percent or 100 percent

generation from renewables; see California) are being offered to Pennsylvania customers.

8/98: The Electric Choice Program has enrolled 1.75 million customers and 70 electric service

providers as of 8/1/98. In September, consumers will receive information on shopping for an electric

service provider and the “shopping phase” will begin. Retail access is set to begin on 1/1/99.

7/98: Pennsylvania consumers began signing up to participate in the first phase-in of competition. In

the first week, over 1.1 million consumers signed up for the Electric Choice Program.

Rates 8/99: Rates for PP&L customers will drop by about 1 percent. The rate reduction is the result of

PP&L’s securitization of a portion of its competition-related transition costs.

1/99: The 8 percent rate reduction in PECO’s restructuring plan took effect for the 1.5 million

residential customers in PECO’s service territory.

Utility Plans Allegheny Power

11/98: The PUC and Allegheny reached a compromise agreement. Allegheny will have a 3.16

cents shopping credit, retail choice will follow the schedule consistent with the rest of the state

(two-thirds by 1/99 and all consumers by 1/00), and $670 million can be recovered in stranded

costs over 10 years.

5/98: The PUC approved Allegheny’s West Penn to recover $524 million in stranded costs.

Consumers will be phased-in beginning 1/99 and going to full retail choice by 1/00.

Duquesne Light

5/98: PUC approved Duquesne Light’s restructuring plan. Stranded cost recovery is set at $1.331

billion over 7 years beginning 1/99. Consumers should expect to save about 12 percent. Retail

competition will be phased-in beginning 1/99 and be complete by 1/00.

Pennsylvania Power & Light

10/98: The PUC and PP&L reached an agreement on capacity prices; PP&L agreed to sell installed

capacity at $19.72/kw-year through 1999.

5/98: PP&L’s restructuring plan was tentatively approved by the PUC. In the plan, PP&L will

provide a 10 percent rate reduction and phase-in retail competition in thirds, beginning with twothirds in 1/99 and all by 1/00. The amount of recoverable stranded costs allowed is $2.864 billion.

Customers should see savings of about 10 percent.

(continued)
Appendix B — Deregulation Background and Trends

B-21

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Pennsylvania (continued)

Utility Plans GPU Energy

(continued) 10/98: The PUC and GPU reached a settlement in GPU’s restructuring cases, clearing the way for

GPU customers to choose their electric generation suppliers on schedule beginning 1/99.

9/98: The PUC capped installed capacity (guaranteed access to a supply of electricity) prices at

$19.72 per kilowatt-year. PP&L has argued that federal law allows capacity sale at “whatever the

traffic will bear.” Higher prices are keeping competitive power marketers out of PP&L’s retail

market where no competitor has been able to quote a price to beat PP&L’s “price to compare” at

4.26 cents/kWh.

8/98: PP&L reached a settlement on its restructuring case. Under it, all consumers will get a

4 percent rate reduction. PP&L will be allowed $297 billion in stranded cost recovery over 11

years. Consumer choice will follow the same phase-in schedule.

PECO

5/98: The PUC gave final approval to PECO’s restructuring plan in a compromise agreement.

Under the plan, PECO customers will receive an 8 percent rate reduction next year, 6 percent in

2000, with 20 percent savings expected for those willing to shop for power. PECO will be allowed

to recover $5.26 billion in stranded costs over a period of 12 years. Two-thirds of customers will

be phased in to retail competition by 1/99 and all customers by 1/00.

UGI Utilities

6/98: The PUC approved restructuring plans for UGI Utilities, allowing $32.5 million of the

requested $58.5 million in stranded cost recovery.

6/98: The PUC gave final approval to Pennsylvania Power & Light, Pennsylvania Power Co.

(approved recovery of $234 million out of $273 million in stranded costs), and GPU’s subsidiaries,

Metropolitan Edison and Pennsylvania Electric. Also, the PUC authorized the Philadelphia Gas

Works to sell retail electricity to its customers.

Additional

Information

9/99: Restructuring in Pennsylvania is the most successful in the nation, in terms of the number of

customers who have chosen alternative generation suppliers. About 450,000 customers in

Pennsylvania have switched suppliers, a majority of them in the Philadelphia area, PECO’s service

territory. PECO had some of the highest prices in the state prior to deregulation.

4/99: Pennsylvania leads the nation in power shoppers. However, the Philadelphia City Council will

examine why only 14 percent of eligible PECO consumers are taking advantage of up to 9 percent

savings, above the guaranteed 8 percent savings given by PECO, and buying less expensive power that

is available from competitive suppliers.

Rhode Island

Schedule 9/99: As of 6/99, roughly about 2,000 customers out of the state’s 456,000 have chosen alternative

generation suppliers.

1/98: Retail access was implemented with 25 registered generation suppliers, but the standard offer

interim rates (3.2 cents/kWh) offered by the state’s IOUs are low enough that no real competition has

occurred.

Rates 1/99: The standard offer rate increased from 3.2 cents/kWh to 3.5 cents. The increase should spur

some competition in the state’s retail electricity market. The standard offer rate will increase again to

3.8 cents in 1/00

8/98: Narragansett is proposing to cut rates 12.4 percent as a result of selling its power plants for $1.6

billion to U.S. Generating.

(continued)
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

B-22

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Rhode Island

(continued)

Rates

(continued)

5/98: PUC reluctantly approved a rate increase for Narragarsett Electric Company for its standard offer

rate from the existing 3.2 cents/kWh to 7.1 cents/kWh by 2009. Similar increase were approved for

Blackstone Valley and Newport Electric.

Texas

Schedule 6/99: Restructuring legislation enacted in June will open the retail market for electricity by 1/02,

except for customers of cooperatives and municipals that do not opt for direct access.

Rates Utilities can freeze rates through 12/31/01. All customer classes will receive a 5 percent rate

reduction on 1/1/02.

Utility Plans 12/97: Houston Light and Power (HL&P), Texas Utilities Electric Co., and Texas-New Mexico Power

Co. announced agreements with the PUC on proposed competition plans, although final approval by

the PUC is still needed. All three contain rate reduction measures. Texas-New Mexico’s plan offers a

guaranteed date, 2003, for full retail choice beginning with a phase-in of customers as early as 1/98

and a plan for stranded cost recovery.

Texas Utilities

3/98: PUC approved Texas Utilities’ restructuring plan.

Houston Light & Power

10/97: HL&P presented its transition proposal for restructuring. Included is a 4-percent rate

decrease over 2 years for residential customers.

3/98: HL&P’s restructuring plan was approved. The HP&L plan provides a 4 percent rate cut in

1998 and another 2 percent in 1999.

Texas-New Mexico

12/98: As part of Texas-New Mexico’s transition to competition, the PUC approved a price

reduction for their customers retroactive to 1/98, resulting in a credit on bills for customers. The

price reduction is part of Texas-New Mexico’s plan to reduce residential rates by 9 percent and

commercial rates by 3 percent over a 5-year transition period.

7/98: PUC approved Texas-New Mexico’s 5-year transition plan. Along with the rate reductions

(described below) are a provision for a pilot program and plans to allow retail choice of generation

providers to all retail consumers by 2003.

5/98: An administrative law judge recommended the PUC reject Texas-New Mexico’s restructuring

plan. The plan would provide residential customers an immediate 3 percent rate reduction and

another 3 percent in 1/00 and 1/01, totaling 9 percent over 3 years. Also, the plan provided for full

recovery of stranded costs through a CTC. A final decision by the PUC is expected by July.

Vermont

Utility Plans 3/99: Central Vermont Public Service and Green Mountain Power filed a joint restructuring plan with

the Public Service Board (PSB) of Vermont. The plan would consolidate the two companies into one

distribution company and would have both companies sell their generating assets and focus on

distribution and retail sales.

(continued)
Appendix B — Deregulation Background and Trends

B-23

Table B-2. Status of State Electric Industry Restructuring Activity as of February 1, 2000

(continued)

State Status of Restructuring Activity

Virginia

Schedule 3/99: Senate Bill 1269, The Virginia Electric Utility Restructuring Act, will allow retail direct access

beginning on and after 1/1/02. The State Corporation Commission (SCC) will establish a phase-in

schedule for customers by class. All customers will have direct access by 1/1/04.

Rates 8/98: The SCC approved more than $700 million in refunds and rate reductions. A total of $150

million in refunds will be provided by 11/2/98. In return for the refund/rate cuts, Virginia Power will

use $220 million in revenue to reduce debt on generation assets.

6/98: In an agreement between regulators, government, and business and Virginia Power, Virginia

Power will refund $920 million, the biggest rate adjustment in Virginia history, in rate cuts and refunds

over the next 5 years. The rate reduction refund agreement is subject to approval by the SCC. A

public hearing is scheduled for 7/21/98 on the proposed settlement.

Wisconsin

Rates 9/99: Wisconsin Electric Power Company requested that the PSC establish criteria for performancebased ratemaking. WEPC also submitted a request for a 3.1-percent rate increase.
Appendix C:

Discussion Guide
C-1

Measurement and Standards Important to

Deregulating the Electricity Industry

Thank you for agreeing to speak with us about measurement and standards issues important to the

electric power industry. Below is a brief background on the study and its objectives. We have

also included a discussion outline containing an overview of the issues we would like to cover

during our conversation on October X at XX:00 a.m./p.m. Please feel free to share this with

colleagues and solicit any insights they may have.

Background

The National Institute of Standards and Technology (NIST) recently commissioned Research

Triangle Institute (RTI) to study technology trends in the generation, transmission, and distribution

sectors of the electric power industry. As part of this analysis, RTI is assessing measurement and

standards needs identified by power industry experts. The results of this study will be made

available in a NIST publication and will be presented during a NIST-sponsored national

conference on “New Challenges for Measurements and Standards in a Deregulated Electric Power

Industry,” which will be held December 6-8, 1999.

In general, we are interested in two topics: 1) analyzing the changing measurement and

standards needs of the electric power industry as a result of deregulation, and 2) estimating the

economic impact of meeting (or not meeting) these needs. Specific areas of interest include, but

are not limited to, measurement and standards to support

Z competitive metering,

Z bulk power transactions and monitoring,

Z reliable transmission and distribution of electric power,

Z communications and control technologies,

Z advanced diagnostics,

Z power quality, and

Z distributed generation.

Discussion Topics

To conduct our study, we are partitioning our discussion into three broad (admittedly interrelated)

categories:

Z Efficiency Benefits of Restructuring: measurement and standards needs to

support/enhance projected increased system efficiency.

Z Issues Related to System Planning and Operation: measurement and standards needs to

support the planning and operation of power generation, transmission, and distribution.

Z Issues Related to Market Functions: measurement and standards needs to support

wholesale and retail customer billing and metering

For each topic, we would like to begin with a general discussion of restructuring issues and then

ask what role measurement and standards may have in solving problems or enhancing benefits.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-2

Efficiency Benefits of Restructuring

In general, what are the anticipated benefits associated with restructuring the electric power

industry?

For example, will restructuring effect the overall economic efficiency of the

electric power system? If so, how

Z will restructuring decrease the average cost of generation?

Z will restructuring decrease the average cost of ancillary services? Which ancillary

services will be most affected? Will low cost suppliers enter the market. Will the

unbundling change the available supply of certain ancillary services?

What are other benefits do you foresee associated with restructuring?

What do you foresee will be the additional costs that somewhat offset the economic

benefits. For example,

Z will restructuring affect total system monitoring and control costs?

Z Will there be additional metering costs to support market functions?

Can measurement and standards play a role in enhancing system efficiency? If so, how?

For example,

Z can measurement and standards reduce average generation or ancillary service

costs? Approximately what percentage change in cost do you expect?

Z can measurement and standards reduce total system monitoring and control costs?

Approximately what percentage change in cost do you expect?

What are other areas where measurement and standards can enhance benefits or

reduce costs from restructuring?
Appendix C — Discussion Guide

C-3

System Planning and Operations

What are the major difficulties facing system planning and operation associated with restructuring

the electric power industry?

Transmission Capacity

Do you think restructuring will increase the demand for transmission services?

If so, what are the potential problems associated with the demand for transmission services

outpacing the growth of new transmission capacity?

Z Do you think transmission constraints will affect reliability?

Z Do you think transmission constraints will affect power quality?

Z What other specific areas will be affected?

How do you think the electric power system will respond to the increased transmission demand?

For example, will system planner and operators respond by

Z building new transmission corridors?

Z restringing existing towers to increase capacity?

Z increasing capacity utilization of existing transmission system through better

monitoring and control (introducing dynamic state control)?

Z increasing the use of distributed generation?

Z increasing the use of curtailable load programs?

Z limiting whole sale transaction activities?

Z other responses

What is the relative importance of each area in alleviating transmission

constraints?

What role can measurement and standards play in alleviating the transmission shortages?

Which response areas identified above are the most dependent on measurement and standards?

Can you roughly estimate the total magnitude of the potential effect measurement and standards

can have on transmission resources (e.g., measurement and standards may increase existing

system capacity by X percent or by Z GW-miles)?
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-4

System Planning and Operations (continued)

Increased Number of Market Players and the Impact on Power

Reliability and Quality Issues

Will the increased number of power generation and ancillary service providers affect system

reliability?

If so, how will reliability potentially be affected?

Z increased frequency of outage?

Z increased scope (number of customers) of outages?

Z increased duration of outages?

Z other impact metrics?

What will be the primary source of reliability problems?

Z For example, will distributed generation be the main source of reliability

problems?

Z Other restructuring factors?

What role can measurement and standards play in maintaining reliability?

Will the increased number of power generation and ancillary service providers affect power

quality?

If so, how will power quality be affected?

Z Increase in the frequency of power disturbances such as transients, overvoltage

(swell), undervoltage (sag), noise harmonics, or outages

Z Will power quality problems effect both end users and power generators?

What role can measurement and standards play in maintaining power quality?
Appendix C — Discussion Guide

C-5

Market Functions

In general, what are the major technological issues that need to be addressed to implement

wholesale and retail markets for electric power?

What are the potential impacts of inefficient markets?

For example,

Z could the inability to measure the “cost causality” of the bulk power transmission

systems limit the potential efficiency gains from restructuring?

Z could market price structures that do not send proper incentives affect the

efficiency, reliability, or power quality of the system?

Wholesale Market Transactions—Bulk Transmission

What measurements and standards are needed to support efficient pricing of bulk transmission?

In which areas will these measurement and standards have the greatest potential impact?

For example,

Z supporting measurement and data transmission for tracking transmission use?

Z supporting cost causality models of bulk power transmission?

Z supporting other needs for efficient pricing of bulk power transmission?

What are the economic benefits of meeting these needs?

For example,

Z could efficient transmission pricing lead to decreased demand (GW miles) of

transmission services for the same level of end-use power consumption?

Z could efficient transmission pricing lead to an increase level of market

transactions?

Wholesale Market Transactions—Generation

What measurement and standards are needed to measure the value of service provided by

generator and ancillary service providers? In which areas will these measurement and standards

have the greatest potential impact?

For example,

Z verifying that generators meet contractual obligations?

Z measuring generators’ impact on system reliability and power quality?

Z measuring value of services supplied by ancillary service providers?
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-6

Market Functions (continued)

What are the economic benefits of meeting these needs?

For example,

Z improved quality services provided by generators and ancillary service providers?

Z decreased transactions costs, such as less expensive meters or fewer legal disputes?

Retail Market Transactions

What measurement and standards are needed to support metering and billing for retail services?

In which areas will these measurement and standards have the greatest potential impact?

For example,

Z facilitating electronic data interfaces (EDI) between meters and systems of different

equipment manufacturers?

Z developing protocols for EDI to distribute customer and system information to the

increasing number of market players involved in account reconciliation?

What are the economic benefits of meeting these needs?

For example,

Z decreased cost of metering and billing activities?

Z improved accurate billing?

Z availability of pricing incentives for demand-side management?

Z fewer billing errors

Z identifying and decreasing cross-subsidization between customer groups?

We thank you in advance for participating in this study.
Appendix C — Discussion Guide

C-7

Measurement Technologies and Standards Important to

Deregulating the Electricity Industry

Thank you for agreeing to participate in The National Institute of Standards and Technology’s

(NIST’s) study on measurement and standards issues important to the electric power industry.

Below is a brief introduction to the study and its objectives, followed by a short questionnaire.

Background

NIST recently commissioned Research Triangle Institute (RTI) to study technology trends in the

generation, transmission, and distribution sectors. As part of this analysis, RTI is assessing

measurement and standards needs identified by power industry experts and investigating the

economic impact of meeting (or not meeting) these needs.

The results of this study will be made available in a NIST publication and will be presented during

a NIST-sponsored national conference on “New Challenges for Measurements and Standards in a

Deregulated Electric Power Industry,” which will be held December 6-8, 1999.

Questionnaire

The purpose of this questionnaire is to obtain information to assist, in quantifying the economic

impact of meeting (or not meeting) measurement and standards needs of a restructured electric

power industry.

I’m sure you will agree that this is an ambitious task and that any impact estimates that are

developed as part of this study will be the subject of great scrutiny and debate. It is not our intent

to develop a definitive estimate of the value of measurement and standards. In contrast, we are

hoping to develop a range of potential impacts associated with measurement and standards that

reflect the large uncertainty in the evolution of the industry structure and in future technology

developments.

We understand that providing a numerical approximation (guess) of the impacts of measurement

and standards is very difficult. For this reason, we encourage you to provide ranges as shown in

the examples. In addition, in many cases your first response will probably be “it depends” on

how the future of the industry unfolds. At the end of the questionnaire there is space for you to

provide specific caveats or assumptions associated with your responses.

The impact categories listed on the next few pages were identified during interviews with utility

system planners, regulators, equipment manufacturers, academics, and organizations such as

EPRI, FERC, and regional ISOs. We encourage you to include additional categories for which you

feel measurement and standards will be important.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-8

We view this questionnaire as eliciting individual opinions of industry experts. Responses will

not be interpreted as representing official positions of your company or organization. In addition,

any information provided will be aggregated, and only average responses will be included in the

presentation and report. All individual responses will remain strictly confidential, and no

individuals will be identified in the report.

Once again, we thank you for your assistance. If you have any questions or comments, please

feel free to call Steve Johnston at 919 541-5935

Please return your questionnaire to Ryan Avent by fax at 919-541-6683 or by e-mail to

avent@rti.org.

Once again, thank you for your participation.
Appendix C — Discussion Guide

C-9

IMPACT OF DEREGULATION

Wholesale and retail deregulation has the potential to affect both the economic efficiency of the

electric power system and the reliability and power quality of electric power to end users.

Several examples are shown in the tree diagram below.

Deregulation

∆ Reliability and Power Quality

(Impact on End Users)

∆ Economic Efficiency

(Impact on Supply Chain)

Installation of

Backup

Equipment

Efficient

Generation and

Ancillary

Services

Equipment

Costs

Outage Costs

Equipment

Damage

Outages

Power

Quality

Enhance

System

Operations

Enhance

Market

Communications

Lower Costs of

Transmission

and Distribution

Reduced Need

for New

Transmission

Capacity

Lower

Transactions

Costs

Technical

Impacts:

Economic

Impacts:

Please fill in the blanks below to indicate which areas you think will be affected by deregulation

and provide your best guess (or range) of the potential size of the impact. For example,

Z Deregulation may lead to a –X1 to –X2% change in the average cost of generation, and/or

Z Deregulation may lead to a +Z1 to +Z2% change in transmission system monitoring

expenditures, and/or

Z Deregulation may lead to 0% change in the frequency of outages.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-10

Impact of Deregulation (continued)

Reliability and Power Quality Economic Efficiency

Deregulation may lead to a: Deregulation may lead to a:

____ % change in the frequency of outages (greater

than one second)

____ % change in the average cost of generation

____ % change in the average duration of outages ____ % change in the average cost of ancillary

services

____ % change in the average number of end users

affected during an outage event

____ % change in required transmission capacity,

or the need for an additional _____ GW

miles in transmission assets

____ % change in power quality events, such as

transients, swells, sags, noise, harmonics

____ % change in system monitoring and

communications costs

____ % change in equipment expenditures to

provide backup for outages

____ % change in metering equipment

expenditures

____ % change in equipment expenditures to

compensate for power quality problems

____ % change in market transaction costs (such

as billing, writing contracts, dispute

resolution)

____ % change in operating metering systems,

such as installation, calibration service calls

____ % change in the cost of usage data transfer,

aggregation, and analysis to support market

transaction

____ % change peak demand reductions from

demand-side programs, or ____ MW change

in curtailment load programs

Other changes

__________________________________________

__________________________________________

__________________________________________

__________________________________________

Other changes

__________________________________________

__________________________________________

__________________________________________

__________________________________________

Comments/qualifiers/caveats for impacts provided above:

____________________________________________________________________________________

____________________________________________________________________________________

____________________________________________________________________________________

____________________________________________________________________________________
Appendix C — Discussion Guide

C-11

IMPACT OF MEASUREMENT AND STANDARDS

Measurement and standards will play an important role in determining the eventual impact

wholesale and retail deregulation has on economic efficiency, power reliability, and power

quality. Several examples are shown in the tree diagram below.

Measurement and

Standards

∆ Reliability and Power Quality

(Impact on End Users)

∆ Economic Efficiency

(Impact on Supply Chain)

∆ Installation

of Backup

Equipment

∆ Efficient

Generation and

Ancillary

Services

∆ Equipment

Costs

∆ Outage Costs

Equipment

Damage

∆ Outages

Power

Quality

∆ Enhance

System

Operations

∆ Enhance

Market

Communications

∆ Lower Costs

of Transmission

and Distribution

∆ Reduced

Need for New

Transmission

Capacity

∆ Lower

Transactions

Costs

Technical

Impacts:

Economic

Impacts:

Please use the blanks below to indicate the areas where you think measurement and standards

will have the greatest impact by indicating how your impact estimates provided above would

change if proper measurement and standards were not available in the future.

For example,

Z Without proper measurement and standards, the change in the average cost of generation

would not be –X1 to –X2% (as indicated above), but would only be –Y1 to –Y2% (Y to be

filled in on next page) and/or

Z Without proper measurement and standards, the change in transmission system

monitoring expenditures would not be +Z1 to +Z2% (as indicated above), but would only

be +W1 to +W2% (W to be filled in on next page) and/or

Z Without proper measurement and standards, the change in outages would not be 0% (as

indicated above), but would actually be V % (V to be filled in on next page).
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

C-12

Impact of Measurement and Standards (continued)

Reliability and Power Quality Economic Efficiency

Without proper measurement and standards

deregulation may instead lead to a:

Without proper measurement and standards

deregulation may instead lead to a:

____ % change in the frequency of outages (greater

than one second)

____ % change in the average cost of generation

____ % change in the average duration of outages ____ % change in the average cost of ancillary

services

____ % change in the average number of end users

affected during an outage event

____ % change in required transmission capacity,

or the need for an additional _____ GW

miles in transmission assets

____ % change in power quality events, such as

transients, swells, sags, noise, harmonics

____ % change in system monitoring and

communications costs

____ % change in equipment expenditures to

provide backup for outages

____ % change in metering equipment

expenditures

____ % change in equipment expenditures to

compensate for power quality problems

____ % change in market transaction costs (such

as billing, writing contracts, dispute

resolution)

____ % change in operating metering systems,

such as installation, calibration service calls

____ % change in the cost of usage data transfer,

aggregation, and analysis to support market

transaction

____ % change peak demand reductions from

demand-side programs, or ____ MW change

in curtailment load programs

Other changes

__________________________________________

__________________________________________

__________________________________________

__________________________________________

Other changes

__________________________________________

__________________________________________

__________________________________________

__________________________________________

Comments/qualifiers/caveats for impacts provided above:

____________________________________________________________________________________

____________________________________________________________________________________

____________________________________________________________________________________

____________________________________________________________________________________

Thank you for your participation.
Appendix D:

Interview Responses
D-1

D.1 IOU SYSTEM PLANNERS

Potential Benefits Associated with Deregulation

Z Systems will operate closer to their capacity.

Z Introduction of a market will optimize energy supply.

Z Price signals will become clearer.

Z Restructuring will bring improved consumer choice.

Z Good technologies will be incorporated sooner, while bad

technologies will be ignored or phased out faster.

Z Prices should fall.

Z Power will be able to flow from surplus areas to shortage

areas.

Z Reserve sharing may lower the cost of ancillary services.

Potential Costs Associated with Deregulation

Z Engineering efficiency will fall, at least in the short run, due

to subjecting systems, especially those involved with

transmission, to strains for which they were not intended.

Z Ancillary services costs will increase, but this will mainly

result from the need to install improved metering

instruments.

Z Costs will increase due to increased metering requirements

associated with determining energy imbalances.

Z Data management systems will have to be greatly improved,

which will increase costs.

Z New transmission will not be built, because no one will

invest in lines they will have to share.

Measurement and Standards Needs Associated with

System Planning and Operations

Z Standards will be needed to determine thermal limits for

transmission lines.

Z Standards will be needed not just for design issues but also

for system performance.

Z Measurement is needed to determine how close to capacity

transmission systems are running.

Z Standards need to be set for a measure of system reliability.

Z Standards are needed for communication protocols and

technology/methods for data collection.

Z The industry needs a standard number for loading state to

alert operators to approaching limits.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

D-2

Z Communication and measurement need to improve to help

facilitate interaction between newly separated gencos and

transcos.

Z Measurement will have to increase dramatically to get away

from load-profiling.

Z Thermal monitoring systems need to be installed crosscountry.

Z Better measurement and monitoring systems will be

required to protect investments from damage due to

improper use.

Z Measurement will need to be improved at stations and

substations to allow incorporation of dispersed generation

assets.

Z Standards may be needed to determine an appropriate level

of meter accuracy and voltmeter accuracy.

Z Standards may be needed for power quality.

Z Distributed generation will require standards to be set for

frequency.

Measurement and Standards Needs with Wholesale

Market Transactions

Z Ancillary services need to be defined.

Z Faster/cheaper metering and communications are needed to

bring smaller energy providers into the fold.

Z Standards need to be established to ensure contractual

compliance.

Z Standards need to be established for performance of

generation equipment and for providers of metering

services.

Z Standards will be needed anywhere different systems

interact.

Z Standards will be needed to ensure system security.

Z Standards will be needed across the board, from

compliance/enforcement mechanisms to communication

systems.

Z There should be standard interface requirements.

Z Increased transactions will necessitate improved

communication systems.

Z Standards will be needed to determine the value of an

interface relative to congestion.

Measurement and Standards Needs with Retail

Market Functions

Z Metering will ultimately have to improve at a retail level.
Appendix D — Interview Responses

D-3

D.2 RTO/POOL OPERATORS

Potential Benefits Associated with Deregulation

Z Separated ancillary services may lead to more efficient

service pricing and, thus, lower ancillary costs.

Z Deregulation-fueled competition may lead to a reduction in

high-cost generation.

Z Open access will cause more energy to be readily available

and transferable, reducing shortages and emergencies.

Z Restructuring should reduce the average cost of generation.

Z Low-cost suppliers of power will enter the market.

Z Improved price signals after restructuring will improve the

efficiency of consumer usage.

Potential Costs Associated with Deregulation

Z Original set-up costs of ISOs or equivalent could be quite

high.

Z Running an efficient power market will require real-time

metering and billing, which will be very expensive to

develop.

Z More complex transmission systems will require improved

monitoring, metering, and data management technologies,

which will all add to cost.

Measurement and Standards Needs Associated with

System Planning and Operations

Z Interface numbers will increase, which will require

increased measurement to manage transmission.

Z Measurement improvements will be needed to squeeze

more capacity out of existing lines.

Z Communication systems will have to be improved, and

systems will have to be able to read more than one

protocol, which may require standards to be set.

Z Measurement will need to see improvements to deal with

shifts in generation and transmission locations.

Z Measurement and standards are vital to alleviating

transmission constraints.

Z Diffused generation will require standards to be set to

maintain reliability.

Z ISOs and RTOs can help deal with transmission constraints

but require metering and monitoring improvements.

Z Improved metering will improve consumer decisionmaking,

which will help alleviate system congestion.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

D-4

D.3 EQUIPMENT MANUFACTURERS

Potential Benefits Associated with Deregulation

Z Larger users will obtain lower prices through their ability to

negotiate.

Z Smaller users will have more energy options.

Z Outsourcing of certain tasks (metering) will lower costs.

Z Metering will improve.

Z More accurate metering will affect demand-side behavior in

a positive way.

Z Improved metering will assign system-threatening loads the

appropriate costs.

Potential Costs Associated with Deregulation

Z Efficiency costs could be a long time coming as they will

originally be offset by necessary measurement and

monitoring improvements.

Measurement and Standards Needs Associated with

System Planning and Operations

Z Monitoring of the transmission system must increase.

Z Generation and transmission need to be metered more

heavily.

Z Interconnection requirements need to be established.

Z IT standards will need to be developed for system operation

and maintenance.

Z Monitoring will need to improve as ancillary services are

unbundled.

Measurement and Standards Needs with Wholesale

Market Transactions

Z Measurement will need to improve to capture benefits of

long-distance transactions.

Z Measurement or standards or both need to improve to

improve accountability for power generation and reliability.

Measurement and Standards Need with Retail Market

Functions

Z Metering will need to be vastly improved to take advantage

of choice offerings.

Z Standard meter protocols should be developed and soon to

facilitate manufacture of appropriate meters.
Appendix D — Interview Responses

D-5

Z Without standard meters, customers may have to change

meters when they change providers.

Z Standards may be important in establishing what security is

needed in each stage of the distribution process.

Z A standard modular meter model could greatly improve

efficiency and customer choice.

D.4 REGULATORS

Potential Benefits Associated with Deregulation

Z Competition will increase under deregulation.

Z Electricity prices will fall.

Z Inefficient generators will be forced to shut down.

Z Ancillary service costs will decrease; this will be monitored

by regulators to ensure fairness.

Measurement and Standards Needs Associated with

System Planning and Operations

Z The industry must develop improved data collection

systems and improved tagging systems.

Z Monitoring will need to improve from both producers and

regulators to guarantee power quality and reliability.

Measurement and Standards Needs with Wholesale

Market Transactions

Z Standards need to be developed on compliance

mechanisms.

Z Measurements need to be uniform.

Z Communication will need to improve greatly.

Z Standard security measures will need to be examined.

D.5 ACADEMIC

Potential Benefits Associated with Deregulation

Z Large consumers will experience considerable benefits.

Z In the long run, all consumers should see price reductions.

Z Real-time-pricing will bring efficiency benefits.

Z Customers can modify their behavior to reduce costs.

Z Efficient businesses will succeed while inefficient businesses

will go out of business.

Z Consumers will enjoy choice between service, price, etc.

Z Better measurement will lower transaction costs.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

D-6

Potential Costs Associated with Deregulation

Z Equipment/power quality may fall as utilities attempt to

keep prices low.

Z Tendency to gravitate toward cheaper instruments may lock

in cheap technology.

Z With real-time-pricing, retailers will be able to more easily

price-discriminate.

Measurement and Standards Needs Associated with

System Planning and Operations

Z ISOs will require vast amounts of information and, thus,

great IT improvements.

Z Large increases in the distance power must travel will

require investments in measurement and monitoring

technologies.

Measurement and Standards Needs with Wholesale

Market Transactions

Z Standards will become vital at points of system

interconnection and between unrelated communication

systems.

Z Measurement and standards must improve to confirm

compliance with contractual obligations.
Appendix E:

Calculation of Event

Cost Metrics
E-1

This appendix contains a description of the estimation procedures

and assumptions we used to develop the event cost estimates

presented in Table 5-4.

E.1 SYSTEM OPERATIONS

E.1.1 Generation Production Costs

In 1997, the total estimated cost of electricity generation was

approximately $100 billion. This estimate includes fuel and other

generating costs incurred by both publicly owned (POUs) and

investor-owned utilities (IOUs) and the cost of purchases from

nonutility generators. These numbers do not include non-utility

electricity sales directly to customers, which will likely remain

unaffected by deregulation. These data were obtained from the

Energy Information Administration’s (EIA’s) Electric Power Annual

1997.

E.1.2 Ancillary Services

The provision of ancillary services is estimated to cost industry $12

billion a year (Hirst and Kirby, 1998). This estimate includes

services such as regulation, spinning reserve, supplemental reserve,

load following, and backup supply.

E.1.3 Transmission Assets

New Transmission Lines

The weighted average cost per mile of new overhead bulk

transmission lines (voltage greater than 138 kV) used in this study is

approximately $0.4 million per mile (see Table E-1). Arthur

Fuldner (1996) of the EIA and the Progress and Freedom Foundation

(PFF) developed typical construction costs per mile for lines ranging

between 138 kV and 765 kV. The costs were weighted by the

number of miles nationally for each line voltage and then averaged

to determine a typical replacement cost. This estimate is likely to

be conservative because it does not include expenditures for right

of way or legal costs.
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

E-2

Table E-1. Cost of Adding New Transmission Lines and Restringing Existing Corridors

The replacement value of the U.S. bulk power transmission system is more than $100 billion.

Voltage

(kV)

Circuit

Miles in

U.S.

Replacement

Cost per Circuit

Mile

Weighted

Replacement Cost

per Circuit Mile

Replacement Value of

Existing Transmission

System

Restringing

Cost per

Circuit Mile

Weighted

Restringing Cost

per Circuit Mile

138 73,186 281,287 20,586,270,382 132,742

161 25,227 329,483 8,311,867,641 155,486

230 69,598 477,500 33,233,045,000 193,333

345 54,593 477,500 26,068,157,500 193,333

500 27,960 477,500 13,350,900,000 193,333

765 3,142 477,500 1,500,305,000 193,333

Totals 253,706 406,181 103,050,545,523 172,091

Sources: Fuldner, Arthur. 1996. Upgrading Transmission Capacity for Wholesale Electric Trade. Washington, DC:

Energy Information Administration.

Progress & Freedom Foundation. 1999. The Replacement Cost of the U.S. Investor Owned Utilities’ Transmission

System. <http://pff.org/energy/appendix.html>. As obtained on November 10, 1999.

Edison Electric Institute. 1998. Statistical Yearbook of the Electric Utility Industry, 1997. Washington, DC: Edison

Electric Institute.

Other estimates for new bulk transmission lines are also in the

neighborhood of half a million dollars per mile. Douglas (1992)

estimated the cost of new bulk transmission lines to be

approximately $477,500 per mile.

Restringing Transmission Lines

The weighted average cost of restringing existing corridors is

$172,091 per mile (see Table E-1). The same weights and

methodology were used to determine the weighted average costs of

new corridors were also used to determine those for restringing.

The Cost of Increased Transmission Capacity

The exisitng power system has approximately 250,000 miles of bulk

transmission lines. Thus, a 1 percent increase represents

approximately 2,500 line-miles. Assuming that upgrades to the

system would be achieved by a combination of new corridors and

restringing (50-50 weight), the average cost of new capacity would

be approximately $324,800 per mile. Thus, a 1 percent increase in

the bulk transmission system is estimated to cost over $812 million.
Appendix E — Calculation of Event Cost Metrics

E-3

Discounting over 20 years using a 7 percent discount rate yields an

annualized cost of $76.6 million to increase the system by

1 percent, or restated, $7,660 million to expand the system by

100 percent.

E.1.4 Outage Costs

According to the Electric Power Research Institute (1996),

unplanned power outages cost U.S. businesses an estimated $29

billion each year. This figure accounts for the losses in commercial

and industrial productivity that occur during transmission and

distribution power outages. In addition, according to Power

Quality Assurance (PQA), a bimonthly journal for power quality

professionals, U.S. industry expenditures on back-up generation

equipment are approximately $1 billion a year.

E.1.5 Expenditures on Power Cleaning Equipment

Expenditures on protective power cleaning equipment are

approximately $4.3 billion (PQA, 1999). Information was not

available on the cost of power quality problems in terms of

equipment damage and lost productivity. Thus, the estimate of

$4.3 billion per year is likely to significantly underestimate the

annual cost of power quality problems in the U.S.

E.2 MARKET OPERATIONS

E.2.1 Metering Costs

The U.S. power industry spends approximately $280 million dollars

on metering equipment annually (Electrical World, 1998). IOUs

spend an additional $613 million per year on meter operations and

maintenance. Metering operations and maintenance costs include

installation, calibration, service calls, and wireless communications

systems (EIA, 1997). Data for POUs were not available at this level

of detail; therefore, $613 million per year is a conservative estimate

of metering operations.

E.2.2 Data Management and Transactions Costs

Data management costs for IOUs are approximately $2 billion a

year (EIA, 1997). Utilities collect, process, and maintain large

quantities of data. The $2 billion per year estimate includes
Changing Measurement and Standards Needs in a Deregulated Electric Utility Industry

E-4

management and maintenance costs and transactions costs, such as

contracts, billing, and dispute settlement. Data for POUs were not

readily available at this level of detail.