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Assessment of Demand Response and Advanced Metering 

Staff Report 

Docket AD06-2-000 

August 2006 

(Revised December 2008) 

Table of Contents 

Table of Contents ___________________________________________________________ i

Executive Summary _________________________________________________________v

Energy Policy Act of 2005 ________________________________________________________ v

Commission Staff Activities ______________________________________________________ v

Advanced Metering _____________________________________________________________vi

Existing Demand Response Programs and Time-Based Rates __________________________vi

Demand Response in Regional Transmission Planning and Operations __________________ x

Regulatory Barriers_____________________________________________________________xi

Conclusions___________________________________________________________________ xii

Chapter I. Introduction _____________________________________________________ 1

Energy Policy Act of 2005 ________________________________________________________ 1

Commission Staff Activities ______________________________________________________ 1

Demand Response and Advanced Metering Survey___________________________________ 2

Report Organization ____________________________________________________________ 2

Regional Definitions_____________________________________________________________ 3

Chapter II. Background on Demand Response __________________________________ 5

Definition of Demand Response ___________________________________________________ 5

Types of Demand Response ______________________________________________________ 6

Role of Demand Response in Retail and Wholesale Markets ___________________________ 7

Use of Demand Response in the United States _______________________________________ 8

Benefits of Demand Response____________________________________________________ 10

Participant Benefits ___________________________________________________________________10

Market and System Benefits ____________________________________________________________10

Additional Benefits Created by Demand Response ___________________________________________11

Evidence of Customer Price-Responsiveness _______________________________________ 13

Role of Enabling Technology ____________________________________________________ 14
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Table of Contents (Cont.) 

Chapter III. Advanced Metering and Market Penetration _________________________ 17

What is advanced metering? _____________________________________________________17

Overview of Advanced Metering __________________________________________________18

Building Blocks of Advanced Metering ___________________________________________________19

Estimates of Advanced Metering Market Penetration from FERC Survey _______________25

FERC Survey ________________________________________________________________________25

Advanced Metering Market Penetration Estimates ___________________________________________26

Uses of Advanced Metering_____________________________________________________________31

Recent Deployments of AMI Systems_____________________________________________________32

Costs and Benefits Associated with Advanced Metering_______________________________33

Costs of Deploying Advanced Metering ___________________________________________________33

Benefits Associated with Advanced Metering_______________________________________________35

Current Issues Associated with Advanced Metering__________________________________38

AMI specifications____________________________________________________________________38

Advanced Metering and Price Responsive Demand Response Networks __________________________39

Providing Timely Information to Customers ________________________________________________40

Interoperability and Standard Interfaces ___________________________________________________41

Security ____________________________________________________________________________42

Costs and Benefits to Include in Business Case Analyses ______________________________________43

Chapter IV. Existing Demand Response Programs and Time-Based Rates ___________ 45

Incentive-Based Demand Response Programs _______________________________________45

Direct Load Control___________________________________________________________________46

Interruptible/Curtailable Rates___________________________________________________________47

Emergency Demand Response Programs __________________________________________________48

Capacity-Market Programs _____________________________________________________________49

Demand Bidding/Buyback Programs______________________________________________________49

Ancillary Services ____________________________________________________________________51

Time-Based Rate Programs ______________________________________________________51

 Time-of-Use Rates ___________________________________________________________________53

Time-of-Use Rates____________________________________________________________________54

Critical Peak Pricing __________________________________________________________________57

Real-Time Pricing ____________________________________________________________________60

Demand Response Program Survey Results_________________________________________63

Incentive-Based Demand Response_______________________________________________________63

Time-Based Rates ____________________________________________________________________65

Motivations for the Use of Demand Response and Time-Based Rates____________________69

Current issues/challenges ________________________________________________________71

Demand Response Activities at the State, Regional and Federal Level ___________________75
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Table of Contents (Cont.) 

Chapter V. Demand Response as a Resource ___________________________________ 79

FERC Survey: Demand Response Program Information_____________________________ 79

FERC Survey Results: Demand Response Resource Estimates ________________________ 81

Potential Peak Load Reduction of Demand Response Programs and Time-Based Rates ______________81

Actual vs. Potential Peak Reductions of Demand Response Programs and Time-Based Rates__________84

Existing Demand Response Resource Contribution__________________________________ 86

Chapter VI. Role of Demand Response in Regional Planning and Operations ________ 91

Potential for Demand Response for Regional Planning _______________________________ 91

Transmission Planning and Operations and Demand Response________________________ 95

Transmission Planning Process __________________________________________________________95

Demand Response in Transmission Planning _______________________________________________97

Provision of Ancillary Services by Demand Response ________________________________________97

Regional Treatment of Demand Response ________________________________________ 101

North American Electric Reliability Council_______________________________________________101

Texas Interconnection and the Electric Reliability Council of Texas ____________________________103

Western Interconnection and the Western Electric Coordinating Council_________________________104

Eastern Interconnection _______________________________________________________________108

International Examples________________________________________________________________114

Example Demand Response Projects_____________________________________________ 114

LIPA Edge _________________________________________________________________________114

Southern California Edison Feeder Relief _________________________________________________115

BPA Olympic Peninsula ______________________________________________________________116

Consolidated Edison__________________________________________________________________116

Mad River Valley Project______________________________________________________________117

The Energy Coalition _________________________________________________________________117

Concerns And Obstacles _______________________________________________________ 117

Lack of Uniform Treatment of Demand Response. __________________________________________117

Perceived Temporary Nature of Demand Response _________________________________________118

Regulatory Treatment of Transmission and Demand Response Costs____________________________119

Reliability of Statistical Demand Response ________________________________________________119

Manual Override and Voluntary Response ________________________________________________121

Capacity Credit _____________________________________________________________________122

Co-Optimization – Response Cost Vs Duration_____________________________________________123

Steps that could be taken to ensure that, in regional transmission planning and operations, 

demand resources are provided equitable treatment________________________________ 123
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Table of Contents (Cont.) 

Chapter VII. Regulatory Barriers ___________________________________________ 125

Regulatory Barriers ___________________________________________________________125

Disconnect Between Retail Pricing and Wholesale Markets ___________________________________125

Utility Disincentives Associated with Offering Demand Response _____________________________126

Cost Recovery and Incentives for Enabling Technologies ____________________________________128

Barriers to Providing Demand-Response Services by Third Parties _____________________________129

Need for Additional Research on Cost-Effectiveness and Measurement of Reductions ______________130

Existence of Specific State-Level Barriers to Greater Demand Response_________________________131

Specific Retail and Wholesale Rules that Limit Demand Response _____________________________132

Insufficient Market Transparency and Access to Data _______________________________________132

Better Coordination of Federal-State Jurisdiction Affecting Demand Response____________________133

Recommendations_____________________________________________________________133

Appendices 

Appendix A: 

 EPAct 2005 Language on Demand Response and Smart Metering 

Appendix B: 

 Acronyms Used in the Report 

Appendix C: 

 Glossary for the Report 

Appendix D: 

 Bibliography for the Report 

Appendix E: 

 The Public Process Leading to the Report 

Appendix F: 

 The FERC Survey 

Appendix G: 

 FERC Survey Respondents 

Appendix H: 

 Demand Response (DR) Programs and Services at Responding Utilities 

Appendix I: 

 Data and Sources for Figures 

Appendix J: Acknowledgements 

Errata to the 2006 Report 
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Executive Summary 

Energy Policy Act of 2005 

Section 1252(e)(3) of the Energy Policy Act of 2005 (EPAct 2005) 1 requires the Federal Energy 

Regulatory Commission (Commission) to prepare a report by appropriate region, that assesses electric 

demand response resources, including those available from all consumer classes. Congress directed 

that this report be prepared and published not later than one year after the date of enactment of the 

EPAct 2005, and specifically to identify and review the following for the electric power industry: 

• saturation and penetration rate of advanced meters and communications technologies, devices 

and systems; 

• existing demand response programs and time-based rate programs; 

• the annual resource contribution of demand resources; 

• the potential for demand response as a quantifiable, reliable resource for regional planning 

purposes; 

• steps taken to ensure that, in regional transmission planning and operations, demand 

resources are provided equitable treatment as a quantifiable, reliable resource relative to the 

resource obligations of any load-serving entity, transmission provider, or transmitting party; 

and 

• regulatory barriers to improved customer participation in demand response, peak reduction 

and critical period pricing programs. 

Commission Staff Activities 

In preparing this report, Commission staff undertook several activities: 

• Developed and implemented a first-of-its-kind, comprehensive national survey of electric 

demand response and advanced metering. The FERC Demand Response and Advanced 

Metering Survey (FERC Survey) requested information on (a) the number and uses of 

advanced metering, and (b) existing demand response and time-based rate programs, including 

their current level of resource contribution. 

• Requested and received written comments from interested persons on a draft version of the 

FERC Survey, and on key issues and challenges that Commission staff should examine. 

Thirty-one entities provided written comments to the proposed survey. 

• Held a public technical conference on January 25, 2006 at Commission headquarters in 

Washington, D.C.; obtained comments from five panels with over 30 participants. 

• Surveyed 3,365 organizations in all 50 states representing every aspect of the electric delivery 

industry: investor-owned utilities, municipal utilities, rural electric cooperatives, power 

marketers, state and federal agencies, and unregulated demand response providers. The 

voluntary survey had a response rate of about 55 percent. 

 1

 Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(e)(3), 119 Stat. 594 (2005) (EPAct section 1252(e)(3)). 

The full text of section 1252 is attached as Appendix A. 
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• Collected information on the role of demand resources in regional transmission planning and 

operations through review of regional transmission documents, and through interviews with 

regional representatives. 

• Conducted a detailed review of the literature on and experience with advanced metering, 

demand response programs, and time-based rates. 

Advanced Metering 

By specifically designating saturation and penetrations rates of advanced meters and communication 

technologies, devices and systems as a matter to be covered in this report, Congress in section 1252 

(e)(3) of EPAct 2005 recognized that the penetration of advanced metering2

 is important for the future 

development of electric demand responsiveness in the United States. In studying this issue, 

Commission staff examined the state of the technology and the market penetration of advanced 

metering. 

One result of the FERC Survey is that advanced metering currently has a penetration of about six 

percent of total installed, electric meters in the United States. An analysis of market penetration by 

region indicates that there are differences in how much advanced metering has been adopted across the 

United States (see Figure ES-1). The parts of the United States associated with the ReliabilityFirst 

Council (RFC)3

 and Southwest Power Pool (SPP) had the highest regional overall penetration rates of 

14.7 percent and 14 percent, respectively. Advanced metering penetration for the remaining regions in 

the United States is lower than the national average. 

Commission staff also developed estimates of the penetration of advanced metering by state. These 

state-by-state estimates should provide a useful baseline in the state deliberations on smart metering 

required by EPAct 20054

 and any future state proceedings on advanced metering. Table ES-1 displays 

the penetration rate of advanced metering in the ten states with the highest penetration. The remaining 

states reported lower penetration rates. 

Market penetrations also differ by type of organization. The estimate of market penetration of 

advanced metering is highest among rural electric cooperatives at about 13 percent. Investor-owned 

utilities have the next highest penetration at close to six percent. This suggests that small, publiclyowned entities such as electric cooperatives have been actively pursuing automated and advanced 

meter reading. 

Existing Demand Response Programs and Time-Based Rates 

In this report, Commission staff adopted the definition of “demand response,” that was used by the 

U.S. Department of Energy (DOE) in its February 2006 report to Congress: 

 2

 For purposes of this report, Commission staff defined “advanced metering” as follows: “Advanced metering is a 

metering system that records customer consumption [and possibly other parameters] hourly or more frequently and that 

provides for daily or more frequent transmittal of measurements over a communication network to a central collection point.” 

3

 ReliabilityFirst Corporation (RFC) is located in the Mid-Atlantic and in portions of the Midwest. 

4

 EPAct 2005 section 1252(b) 
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Figure ES-1. Penetration of advanced metering by region5

Source: FERC Survey 

Table ES-1. States with the highest penetration of advanced metering 

Source: FERC Survey 

 5

 Regional definitions used in this figure and subsequent figures are (See Chapter I for a NERC region map): 

• Electric Reliability Council of Texas, Inc. (ERCOT) 

• Florida Reliability Coordinating Council (FRCC) 

• Midwest Reliability Organization (MRO) 

• Northeast Power Coordinating Council (NPCC) 

• ReliabilityFirst Corporation (RFC) 

• SERC Reliability Corporation (SERC), which covers most of the Southeast. 

• Southwest Power Pool, Inc. (SPP) 

• Western Electricity Coordinating Council (WECC) 

• Other (Alaska and Hawaii) 

State Advanced Metering 

Penetration 

Pennsylvania 52.5% 

Wisconsin 40.2% 

Connecticut 21.4% 

Kansas 20.0% 

Idaho 16.2% 

Maine 14.3% 

Missouri 13.4% 

Arkansas 12.9% 

Oklahoma 7.2% 

Nebraska 6.8% 

2.8% 4.2%

0.2%

1.0%

2.5%

5.2%

14.0%

14.7%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

RFC SPP SERC MRO NPCC FRCC WECC Other

NERC Region

Advanced Metering Penetration

2.8% 4.2%

0.2%

1.0%

2.5%

5.2%

14.0%

14.7%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

RFC SPP SERC MRO NPCC FRCC WECC Other

NERC Region

Advanced Metering Penetration
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Changes in electric usage by end-use customers from their normal consumption patterns in 

response to changes in the price of electricity over time, or to incentive payments designed to 

induce lower electricity use at times of high wholesale market prices or when system 

reliability is jeopardized.6

Demand response under this definition can be categorized into two groups: incentive-based demand 

response and time-based rates. Incentive-based demand response includes direct load control, 

interruptible/curtailable rates, demand bidding/buyback programs, emergency demand response 

programs, capacity market programs, and ancillary services market programs. Time-based rates 

include time-of-use rates, critical-peak pricing, and real-time pricing. 

Based on the results of the FERC Survey, Commission staff found that the use of demand response is 

not widespread. Only approximately five percent of customers are on some form of time-based rates 

or incentive-based program. The most common demand response programs offered are direct load 

control, interruptible/curtailable programs, and time-of-use rates, but only about 200 entities reported 

that they offer these programs. Interest in time-based rates and demand response programs is growing, 

and results from recent programs and pilots are encouraging.

The FERC Survey also requested information on the potential peak reduction that existing demand 

response programs represent. Nationally, the total potential demand response resource contribution 

from existing programs is estimated to be about 37,500 MW. The vast majority of this resource 

potential is associated with incentive-based demand response. Figure ES-2 shows a breakdown of 

resource contribution by reliability region and by customer type. Because peak loads vary 

significantly among reliability regions, it is useful to characterize the existing demand response 

potential capability relative to each region’s summer peak demand. Demand response resource 

potential ranges from three to seven percent in most North American Electric Reliability Council 

(NERC) reliability regions, with the notable exception of the MRO region (20 percent). The NERC 

regions of the country with the largest demand response resource contributions (as a percent of the 

national total) are RFC (22 percent), SERC (21 percent), and MRO (16 percent). 

Demand response programs and time-based rates are offered by all forms of electric companies that 

serve customers. Publicly-owned utilities (electric cooperatives, political subdivisions, and municipal 

utilities) account for 55 percent of entities reporting that they offer time-of-use rates to residential 

customers. A similar distribution reported that they offered direct load control programs. 

Investor-owned utility programs account for 47 percent of national demand response resource 

contributions, followed by Independent System Operator/Regional Transmission Organization 

(ISO/RTO) administered demand response programs, which contribute 19 percent of national demand 

response resources (see Figure ES-3). 

 6

 U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Recommendations for 

Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of 2005, 

February 2006 (February 2006 DOE EPAct Report). 
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Figure ES-2. Existing demand response resource contribution 

by NERC region and customer type 

0

2000

4000

6000

8000

10000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

As Percent of 

Projected 

Summer 2006 

Peak Demand

3% 4% 7% 4% 20% 6% 4% 5% N/A

Source: FERC Survey 

Note: Other reliability region includes Alaska and Hawaii. 

 

Figure ES-3. Demand response resource contributions 

by entity type and customer class 

0

3000

6000

9000

12000

15000

InvestorOwned UtilityCooperative

Utility and

Political Subdivision

Municipal

Utility and

Municipal

Marketing

Authority

Curtailment

Service

Provider and

Power

Marketer

Federal and

State Utilities

ISO/RTO

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

Source: FERC Survey 
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Demand Response in Regional Transmission Planning and 

Operations 

To a degree, generation, transmission, and demand response are substitutes, depending on the location 

of generation or demand response. As a substitute for generation, demand response can serve as a 

local peaking resource and thereby assist resource adequacy. As a substitute for transmission and 

distribution infrastructure, demand response can reduce the need for new transmission or distribution 

expansion to bring generation to a local area. At minimum, demand response can provide relief for an 

overloaded transmission system, and can defer the need for infrastructure.7

 Time-based rates and 

direct-load-control can be used to target specific hours when system needs are greatest. 

Demand response is not treated in transmission planning uniformly across regions, and demand 

response is typically not directly assessed during transmission planning. It is included only indirectly 

in most transmission planning. Existing or expected demand response resources are incorporated into 

reliability assessments either as modifications to expected load or as responsive resources. New 

demand response resources are typically not included as potential solutions to transmission adequacy 

problems. System planners do not consider demand response equally when they examine options for 

dealing with transmission inadequacies. If they do consider demand response, it is as a temporary 

solution until a permanent transmission enhancement is in place. Commission staff found that many 

regional transmission organizations state that their responsibility is limited to identifying transmission 

concerns and evaluating proposed solutions, not primarily encouraging demand response. Bonneville 

Power Administration, the Midwest ISO, and the PJM Interconnection were the only large entities that 

reported having policies to consider demand response in transmission planning; however, these have 

not yet resulted in demand response projects. 

How to model demand response and how to measure demand response so it can be better included in 

electric regional planning is a challenge. In one sense, demand response is like insurance. Modeling 

its value correctly involves forecasting and uncertainty. A review of recent research suggests that 

demand response has a key role to play in regional planning. For demand response resources to be 

valued correctly in regional resource planning, resource plans must be made for a sufficiently long 

planning period. Demand response can meet peak resource needs and reduce the likelihood of lowprobability, high-consequence and potentially costly events. Adding demand response resources to 

regional plans requires modeling that address uncertainties such as fuel prices, weather, and system 

factors. Modeled properly, demand response can be an important tool for risk management. 

Demand response can also serve as operating reserves. Several demand response programs such as 

direct load control can provide the timely response necessary to provide these reserves. Load 

participating in these programs is continuously poised to respond but only has to reduce consumption 

when a reliability event occurs. Moreover, while customers providing such operating reserves do not 

normally reduce transmission loading, they can reduce the amount of transmission capacity that must 

be held in reserve to respond to contingencies. This reserve capability of demand response both 

reduces the need for new transmission and increases the utilization of existing transmission to provide 

energy from low cost generation. 

 7

 For example, ISO-New England obtained demand response in 2004 through the “Gap RFP” to address local 

reserve concerns within Southwest Connecticut. 
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The eligibility of demand response resources to provide operating reserves has been limited in most 

regions and is typically limited to providing supplemental (non-spinning) and slower reserves. 

Restrictions on demand response providing spinning reserve have eased recently in some areas. For 

example, ERCOT allows demand response as a supplier of spinning reserve. PJM allows demand 

response to supply synchronized reserves and regulation. 

Based on comments received and Commission staff review of regional transmission planning and 

operations procedures, Commission staff has identified several actions and steps that could be taken to 

enable greater use of demand resources. The merits of taking the following steps should be considered 

by appropriate transmission planners and state and federal regulators:

• Assure that regions that schedule resources to meet either energy or reserve needs properly 

recognize the capabilities and characteristics of demand resources. 

• Assure that requirements are specified in terms of functional needs rather than in terms of the 

technology that is expected to fill the need. This applies to ancillary services as well as to 

transmission enhancement. 

• Accommodate the inherent characteristics of demand response resources (just as generation 

resource characteristics are accommodated). 

• Allow appropriately designed demand response resources to provide all ancillary services 

including spinning reserve, regulation, and frequency response reserves. 

• Allow for the consideration of demand response alternatives for all transmission enhancement 

proposals at both the state and ISO/RTO level. At the minimum, transmission expansion 

planning procedures would allow demand response resources to be proposed and considered 

as solutions at congested interfaces or in load pockets, along with local generation or 

transmission enhancements. This consideration would be done early in the process, and 

include a reporting and assessment of alternatives considered. 

• When appropriate, treat demand response as a permanent solution, similar to transmission 

enhancements. 

• Develop better demand response forecasting tools for system operators, to increase the 

usefulness and acceptability of demand response. 

Regulatory Barriers 

Commission staff identified several regulatory barriers to improved customer participation in demand 

response, peak reduction and critical peak pricing programs. These barriers are based on input 

received from parties in written comments, comments filed and discussion heard at the FERC Demand 

Response Technical Conference, a review of demand-response program experience, and through a 

comprehensive literature review. Key regulatory barriers include: 

• Disconnect between retail pricing and wholesale markets. Retail rates for most customers 

are fixed, while wholesale prices fluctuate. Placing even a small percentage of customers on 

tariffs based on marginal production costs, can allocate resources more efficiently. 

• Utility disincentives associated with offering demand response. Reductions in customer 

demand reduce utility revenue. Without regulatory incentives such as rate decoupling or 

similar incentives, electric utilities lack an incentive to use or support demand response. 

• Cost recovery and incentives for enabling technologies. Utilities are reluctant to undertake 

investments in enabling technologies such as advanced metering unless the business case and 

regulatory support for deployment is sufficiently positive to justify the outlay. These 
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investments may require an increase in rates. It is uncertain whether and how would 

regulators allow these costs to be recovered. 

• The need for additional research on cost-effectiveness and measurement of reductions. 

There are deficiencies in the measurement of demand response and assessment of its costeffectiveness. Cost-effectiveness tests that have been used by regulators must be improved to 

reflect changes in the industry, especially in organized markets. 

• The existence of specific state-level barriers to greater demand response. Policies of retail 

rate regulators and state statutes in several states have created barriers to implementing greater 

levels of demand response, especially by exposing customers to time-based rates. Several 

states have laws that restrict the ability of regulators to implement critical peak pricing and 

other forms of time-based rates. 

• Specific retail and wholesale rules that limit demand response. Certain wholesale and 

retail market designs have rules and procedures that are not conducive to demand 

participation. For example, the standard lengthy wholesale settlement periods utilized in 

ISO/RTO markets delays payment to participating retail customers. 

• Barriers to providing demand response services by third parties. Shifting regulatory rules 

that allow third parties to provide demand response and potential sunset of various demand 

response programs are a disincentive to demand response providers. Because third parties 

often bear the risks of programs dependent on enabling technologies, they need long-term 

regulatory assurance or long-term contracts to raise the capital needed to invest in enabling 

technologies. 

• Insufficient market transparency and access to data. Lack of third-party access to data has 

been identified as a barrier to demand response. Greater transparency of unregulated retailer 

price offers and information on the amount of load under time-based rates or pricing would 

assist grid operation and planning. A related but more fundamental barrier related to data is 

timely access to meter data. 

• Better coordination of federal-state jurisdiction affecting demand response. While states 

have primary jurisdiction over retail demand response, demand response plays a role in 

wholesale markets under Commission jurisdiction. Greater clarity and coordination between 

wholesale and state programs is needed. 

Conclusions 

Based on the results of the FERC Survey, input from interested persons, and an extensive examination 

of regional and national trends in electric demand response programs policy, Commission staff 

concludes that demand response has an important role to play in both wholesale and retail markets. 

The potential immediate reduction in peak electric demand that could be achieved from existing 

demand response resources is between three and seven percent of peak electric demand in most 

regions. However, the technologies needed to support significant deployment of electric demand 

response resources, such as advanced metering, have little market penetration. 

Demand response deserves serious attention. Staff recommends that the Commission: (1) explore 

how to better accommodate demand response in wholesale markets; (2) explore how to coordinate 

with utilities, state commissions and other interested parties on demand response in wholesale and 

retail markets; and (3) consider specific proposals for compatible regulatory approaches, including 

how to eliminate regulatory barriers to improved participation in demand response, peak reduction and 

critical peak pricing programs. Staff also encourages states to continue to consider ways to actively 

encourage demand response at the retail level. In particular, staff recommends that the Commission 

and states work cooperatively in finding demand response solutions.
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Chapter I. Introduction 

Energy Policy Act of 2005 

The Energy Policy Act of 2005 (EPAct 2005) section 1252(e)(3)8

 requires the Federal Energy 

Regulatory Commission (Commission) to prepare a report, by appropriate region, that assesses electric 

demand response resources, including those available from all consumer classes. Specifically, EPAct 

2005 directs the Commission to identify and review: 

(A) saturation and penetration rates of advanced meters and communications 

technologies, devices and systems; 

(B) existing demand response programs and time-based rate programs; 

(C) the annual resource contribution of demand resources; 

(D) the potential for demand response as a quantifiable, reliable resource for 

regional planning purposes; 

(E) steps taken to ensure that, in regional transmission planning and operations, demand 

resources are provided equitable treatment as a quantifiable, reliable resource relative to the 

resource obligations of any load-serving entity, transmission provider, or transmitting party; 

and 

(F) regulatory barriers to improved customer participation in demand response, peak 

reduction and critical period pricing programs. 

Commission Staff Activities 

In preparing this report, Commission staff undertook several activities. First, Commission staff 

developed and implemented a national survey of demand response and advanced metering in the 

electric sector. Commission staff released a draft version of the survey for public comment, and over 

25 parties provided comments. 

Second, comments were solicited from interested parties on the key demand response and advanced 

metering issues and challenges that Commission staff should examine. Over 30 parties provided 

written comments. Commission staff held a technical conference on demand response and advanced 

metering (FERC Technical Conference) on January 25, 2006 at Commission headquarters in 

Washington, DC. The FERC Technical Conference allowed the Commission and staff to gain 

valuable information regarding the key issues and challenges concerning the development of demand 

response resources in wholesale and retail markets, what experiences has industry had with 

implementing demand response and time-based rate programs, how to define advanced metering, and 

 8

 Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(e)(3), 119 Stat. 594 (2005) (EPAct 2005 section 

1252(e)(3)). The full text of section 1252 is attached as Appendix A. 
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what challenges and barriers exist to greater saturation of advanced metering. The conference also 

provided a regional perspective on demand response and advanced metering issues as a result of 

participation by representatives from around the country. Thirty-one panelists participated in the 

technical conference. 

Third, commission staff reviewed the literature and experience on advanced metering, demand 

response programs, and time-based rates. As part of this review, information on the role of demand 

resources in regional transmission planning and operations were collected through review of regional 

transmission documents, and through interviews with regional representatives. 

Demand Response and Advanced Metering Survey 

Due to the lack of detailed data and information on the deployment of advanced metering, and the lack 

of data of sufficient detail on existing electric demand response and time-based rate programs, 

Commission staff developed and implemented a first-of-its-kind nation-wide survey to fill this 

information gap. The FERC Demand Response and Advanced Metering Survey (FERC Survey) 

requested information on (a) the number of advanced meters and their use, and (b) existing demand 

response and time-based rate programs, including their current level of resource contribution. 

In March 2006, the Commission received final Office of Management and Budget (OMB) approval of 

the FERC Survey. The FERC Survey was implemented as a web-based survey to expedite data 

retrieval and ensure consistency. Responses to the survey were requested from 3,365 organizations 

from all 50 states representing all aspects of the electric delivery industry: investor-owned utilities, 

municipal utilities, rural electric cooperatives, power marketers, state and federal agencies, and 

unregulated demand response providers.9

 

More than 1,850 entities responded to survey (a response rate of over 55 percent). Information 

gathered through the survey serves as the basis for the estimates of saturation of advanced metering, 

the information on existing demand response and time-based rate programs, and estimates of resource 

contribution included in this report. The results of this survey should prove useful for future policy 

discussions, particularly state-level examinations of smart metering directed by EPAct 2005.10 

Report Organization 

The report begins with an executive summary and introduction which describes the report structure. It 

then delves deeper into the issues of demand response and advanced metering, detailing the 

information that Commission staff learned regarding the six issue areas required by EPAct 2005 

section 1252(e)(3). 

Chapter 2 includes a background on demand response. This chapter includes a definition of demand 

response, a discussion of the various types of demand response programs, and examination of the 

benefits associated with demand response. 

 9

 Appendix F includes detailed information on the survey and sample design, and the OMB approval process. 

Appendix G lists the respondents to the survey. 

10 EPAct 2005 section 1252(b). 
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Chapter 3 reviews advanced metering, and estimates the saturation of advanced metering nationally, 

regionally, by type of utility, customer class, and by state based on the results of the FERC Survey. 

This chapter also summarizes the key components of advanced metering, benefits and costs of 

advanced metering, and issues associated with the deployment of advanced metering. 

Chapter 4 examines time-based rates and demand response programs. Each of the various time-based 

rates and demand response programs are discussed in detail. The number of entities offering timebased rates and demand response programs are presented by type of entity and program type. This 

chapter also reviews the motivation behind increased interest in these programs, and explores the 

issues and challenges associated with the programs. The chapter concludes with a review of recent 

developments. 

Chapter 5 considers the size of demand response as a resource. It explores the size of the existing 

demand response resource in MWs, considering results from the FERC Survey. The FERC Survey 

yielded information on the potential resource contribution as well as the actual use of resources in 

2005. 

 

Chapter 6 considers the potential and role of demand response in regional planning, with a focus on 

regional transmission planning and operations. This consideration includes a review of its current role 

along with a process for incorporating demand resources in resource plans. This chapter examines 

how demand response is utilized regionally, and provides steps that could be taken to ensure that, in 

regional transmission planning and operations, demand resources are provided equitable treatment as a 

quantifiable, reliable resource. 

Chapter 7 summarizes and analyzes the barriers identified in comments and in key reports and filings, 

and provides recommendations for future Commission deliberation. 

Regional Definitions

For the purposes of reporting the results of the assessment of demand response and advanced metering 

by region, as requested by Congress, this report will follow the regional definitions provided by the 

North American Electric Reliability Council (NERC). Eight regional reliability councils comprise the 

NERC in the lower 48 states. These regional reliability councils include: 

• Electric Reliability Council of Texas, Inc. (ERCOT) 

• Florida Reliability Coordinating Council (FRCC) 

• Midwest Reliability Organization (MRO) 

• Northeast Power Coordinating Council (NPCC) 

• ReliabilityFirst Corporation (RFC) 

• SERC Reliability Corporation (SERC) 

• Southwest Power Pool, Inc. (SPP) 

• Western Electricity Coordinating Council (WECC) 

Figure I-1 displays the configuration of these regions as of July 2006. Alaska and Hawaii are 

categorized as Other. 

Commission staff chose to use the NERC regions because they reflect the topology of the electric 

power sector, and the fact that many electric utilities cross state boundaries. Furthermore, wholesale 

market designs, resource requirements, and customer characteristics tend to vary by NERC regions. 
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Figure I-1. NERC Region Map 
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Chapter II. Background on Demand Response 

The purpose of this chapter is to provide background and context for the discussions of electric 

demand response and advanced metering that are contained in later chapters. This overview of 

demand response and advanced metering includes definitions and history of the use of these programs 

Topics discussed in this chapter include: 

• Definition of demand response 

• Types of demand response 

• Role of demand response in retail and wholesale markets 

• Benefits of demand response 

• Use of demand response in the United States 

• Customer price-responsiveness 

• Role of enabling technologies 

Definition of Demand Response 

Demand response refers to actions by customers that change their consumption (demand) of electric 

power in response to price signals, incentives, or directions from grid operators. In this report, 

Commission staff adopted the definition of “demand response” that was used by the U.S. Department 

of Energy (DOE) in its February 2006 report to Congress: 

Changes in electric usage by end-use customers from their normal consumption patterns in 

response to changes in the price of electricity over time, or to incentive payments designed to 

induce lower electricity use at times of high wholesale market prices or when system 

reliability is jeopardized.11

The crux of demand response that this definition addresses is that it is an active response to prices or 

incentive payments. The changes in electricity use are designed to be short-term in nature, centered on 

critical hours during a day or year when demand is high or when reserve margins are low. Customer 

responses to high market prices can reduce consumption; this can shave wholesale market prices on a 

regular basis and thereby dampen the severity of price spikes in wholesale markets on extreme days. 

Customer response to incentives is an important tool available to operators of the electric grid to 

address reserve shortages, or for load-serving entities (LSEs) to incorporate in their portfolios to match 

customer demand with available supply, and where available to individual customers to better manage 

their costs of doing business. 

If changes in electricity prices last for a long time or are expected to do so, a longer-term price-based 

reduction in consumption through investment in energy efficiency or change in customer behavior 

may occur. Energy efficiency and conservation are often achieved while consumers are involved in 

demand response programs through (a) actions taken by consumers to conserve their consumption of 

electricity during high price periods as they become more aware of their energy-usage patterns, or (b) 

 11 U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Recommendations for 

Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of 2005, 

February 2006 (February 2006 DOE EPAct Report), 6. 
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consumer investments in more energy-efficient lighting and appliances to lower their demand in all 

hours. Demand response programs coupled with direct feedback and specific education or advice have 

helped customers in some demand response programs reduce their consumption of electricity by up to 

10 percent.12 Energy efficiency and conservation are not directly included in the definition of demand 

response programs for purposes of our review and report.13

Demand response plays a key role in linking the retail and wholesale sectors of electric markets. Enduse customer response to prices or incentives primarily involves retail activities, and oversight of these 

activities generally is subject to retail regulation at the state or local level. Nevertheless, federal 

regulatory interests are implicated because of the importance of demand response in wholesale 

markets and its effect on wholesale market prices, the need for demand response as an emergency 

resource for grid operators. Consequently, it is important to improve coordination of state and federal 

electric policies that affect demand response, to achieve more effective regulation of electric markets. 

Types of Demand Response 

This report reviews two primary categories of demand response: incentive-based demand response 

and time-based rates. Each category includes several major options: 

• Incentive-based demand response 

o Direct load control 

o Interruptible/curtailable rates 

o Demand bidding/buyback programs 

o Emergency demand response programs 

o Capacity market programs 

o Ancillary-services market programs 

• Time-based rates 

o Time-of-use 

o Critical-peak pricing 

o Real-time pricing 

Incentive-based demand response programs offer payments for customers to reduce their electricity 

usage during periods of system need or stress. By adjusting or curtailing a production process, shifting 

load to off-peak periods, or running on-site distributed generation, customers can reduce the level of 

demand that they place on distribution networks and the electric grid. Customers who participate in 

incentive-based demand response programs either receive discounted retail rates or separate incentive 

payments. Vertically integrated electric utilities and other LSEs such as cooperatives, municipal 

utilities, or unregulated retailers offer these programs on a retail basis directly to customers. At a 

wholesale level, the impetus comes from independent system operators (ISOs) or regional 

transmission organizations (RTOs) and power marketers. These programs can be triggered either for 

reliability or economic reasons. In the wholesale demand response programs, customer load 

 12 Chris King and Dan Delurey, “Efficiency and Demand Response: Twins, Siblings, or Cousins?,” Public Utilities 

Fortnightly, 143 # 3, March 2005. 

13 The U.S. DOE, the National Association of Regulatory Utility Commissioners (NARUC), and the National 

Association of State Energy Officials are preparing an assessment of energy efficiency in response to EPAct 2005 section 

139. 
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reductions are aggregated by retail customers, and then provided to the wholesale provider, such as an 

ISO, in exchange for an incentive. 

The second type of demand response is comprised of time-based rates. A range of time-based rates 

are currently offered directly to retail customers; not all are time-varying, but they may promote 

customer demand response based on price signals. These are different from flat rates, which are 

unvarying and offer no price signals. Flat rates are often assigned to residential customers, and are the 

only option in the absence of meters that can record time-differentiated usage (except block rates). 

Customer demand response, incentivized by time-varying price signals, is one way for electricity 

customers to move away from flat or averaged pricing and to promote more efficient markets. 

The two categories of demand response are highly interconnected and the various programs under 

each category can be designed to achieve complementary goals. For example, by adjusting customer 

load patterns or increasing price responsiveness, large-scale implementation of time-based rates can 

reduce the severity or frequency of price spikes and reserve shortages, thereby reducing the potential 

need for incentive-based programs. Care needs to be taken in their implementation to ensure that these 

programs do not work at cross-purposes. 

Chapter IV continues the examination of these demand response types and their current use in the 

United States. 

Role of Demand Response in Retail and Wholesale Markets 

A truly functioning electricity market incorporates dynamic supply and demand forces. A frequent 

criticism of current wholesale market designs is that the demand-side of the market is not active; 

thereby creating the potential for supplier market power. Enabling demand-side responses as well as 

supply-side responses increases economic efficiency in electricity markets and improves system 

reliability.14 

Not all consumers need to respond simultaneously for markets to benefit by lowered overall prices. 

One study suggested that shifting five to eight percent of consumption to off-peak hours and cutting 

another four to seven percent of peak demand could save utilities, businesses, and customers as much 

as $15 billion a year.15 Another posited, “20 percent of customers account for 80 percent of price 

response.”16 Others find that “only a fraction of all customers, perhaps as few as five percent, are 

needed to discipline electricity market prices.”17 In its comments to the Commission, the Demand 

Response and Advanced Metering Coalition (DRAM) said it “believes that demand response typically 

is capable of providing demand reductions of 3-5 percent of annual peak load for periods up to 100 

hours or so per year.”18 In California’s statewide pricing pilot, 80 percent of load reduction came from 

30 percent of customers.19

 14 See especially Chapter 4 of Sally Hunt, Making Competition Work (New York: John Wiley & Sons, 2002). 

15 Justin A. Colledge, et al., “Power by the Minute,” McKinsey Quarterly 2002 #1, 74-75. 

16 Goldman, Charles and Roger Levy, Demand Response in the U.S.: Opportunities, Issues, and Challenges. 

Presentation at the National Town Hall Meeting on Demand Response, Washington, DC, June 21, 2005, 20. 

17 Bernie Neenan, Richard N. Boisvert, and Peter A. Cappers, “What Makes a Customer Price-Responsive?” The 

Electricity Journal, 15 #3 (April 2002), 52. 

18 Demand Response and Advanced Metering Coalition (DRAM), comments filed in Docket AD06-2, December 

19, 2005, 5. 

19 Susie Sides (San Diego Gas & Electric), FERC Technical Conference on Demand Response and Advanced 

Metering, January 25, 2006 (hereinafter, “FERC Technical Conference”), transcript, 205. 
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Midwest ISO (MISO) Vice President Ron McNamara’s comments at the January 25, 2006 FERC 

Demand Response and Advanced Metering Technical Conference (FERC Technical Conference) and 

at DRAM’s January 2006 National Town Meeting on Demand Response support the need for demand 

response. He stated that industry tends to take load as a given, regardless of price, but that markets 

work best when prices are constrained by supply and demand. He added that scarcity pricing needs to 

come through as a real price signal, even while long-term bilateral contracts are the foundation of a 

market.20 Demand response programs provide markets with a second set of tools to respond to high 

prices or capacity shortages. DRAM suggests that markets without demand response tools use more 

power than they need to: demand response can mitigate market power and be a least-cost, faster-track 

solution to relieving areas of constrained supply (congestion pockets).21

ISO-New England’s president and CEO, Gordon van Welie, echoed that belief at an April 2006 

demand response summit. He said there are two ways to meet the growing demand for electricity at a 

time of high natural gas prices: reduce demand or increase supply. His staff’s analysis found that two 

demand-side actions could save New England customers. Reducing electricity use by five percent 

during peak hours (through conservation and energy efficiency) would save consumers $580 million 

annually. A 500-MW increase in demand response participation which would cut wholesale costs by 

$32 million – a total of $612 million annually. Alternatively, the supply-side solution would add 

1,000 MW of low-cost plants, saving consumers $600 million. The business-as-usual scenario, based 

on a five percent annual increase in demand, would keep electricity costs high and increase total costs 

by $700 million each year.22 Similar arguments were offered by the New York Public Service 

Commission in a recent order. The New York commission found that planners who rely solely on the 

supply-side will over-build the system for the few hours of annual system peak, rather than leveling 

that peak through conservation and demand response.23

The role that each form of time-based rates or incentive-based demand response plays in electric 

system planning and operations depends on the timeframe of the response. For example, real-time 

pricing or critical-peak pricing, which directly reflect wholesale prices, affect supply scheduling in 

day-ahead markets and during real-time dispatch. Time-of-use rates does not induce as rapid or large 

responses. Incentive-based demand resources such as direct load control, capacity, and ancillary 

services programs can be used as reserves during real-time, as reserves in day-ahead scheduling and 

dispatch, or as capacity resources in system planning. By contrast, energy efficiency can be viewed as 

a resource during system planning because of its long-term effects. 

Use of Demand Response in the United States 

Time-based rates and other forms of demand response have been used within the electric power 

industry for decades. For many utilities, demand response was a part of their portfolio of resources 

and was activated during reserve shortages or periods of high prices. Two of the oldest forms of 

demand response have been interruptible/curtailable tariffs and time-of-use (TOU) rates. Many 

utilities place large industrial consumers that have interval meters on mandatory TOU rates. In the 

 20 Ron McNamara (MISO), FERC Technical Conference, transcript, 177-180. 

21 DRAM, comments filed in Docket AD06-2, December 19, 2005, 2. 

22 Gordon van Welie, speech to 2006 “ISO-NE Demand Response Summit,” April 27, 2006; and ISO-New 

England, Staff White Paper, Controlling Electricity Costs, June 1, 2006 (the latter revised the figures slightly from the 

speech). 

23 New York State Public Service Commission, Order Denying Petitions for Rehearing and Clarification in Part 

and Adopting Mandatory Hourly Pricing Requirements, issued and effective April 24, 2006, 2. [hereinafter NYPSC Order, 

April 24, 2006] See Chapter VI for a further discussion of the incorporation of demand resources into planning. 
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past decade, these trends have reversed, and new types of participants and demand response programs 

have begun to appear. 

The use of demand response programs, also known as load management or as demand-side 

management, increased markedly in the 1980s and early 1990s. This increase was driven by a 

combination of directive in the Public Utility Regulatory Policies Act of 1978 (PURPA)24 to examine 

time-based rate standards, and by state and federal regulatory and policy focus on demand-side 

management and integrated resource planning. Regulatory support and technical advances in controls, 

communications, and metering led to a marked increase in load management, particularly direct load 

control programs and interruptible/curtailable service tariffs. 

There are regional differences in the current use of demand response and how its use has changed over 

the past decade. Data collected from regional reliability councils and electric utilities by North 

American Electric Reliability Council (NERC) in its Energy Supply & Demand database provides a 

snapshot of regional potential and historical trends. Figure II-1 illustrates that Florida Reliability 

Coordinating Council (FRCC), Electric Reliability Council of Texas, Inc. (ERCOT), and the 

MidAmerican Power Pool (MAPP) had the largest percentage of demand response capability in 1998. 

It also shows that the amount of load management included in regional forecasts declined between 

1998 and 2003. Regions with larger relative declines include ERCOT, Northeast Power Coordinating 

Council (NPCC), Mid-Atlantic Area Council (MAAC), and Western Systems Coordinating Council 

(WSCC). In 2003, due to the decline in capability in ERCOT and an increase in capability in 

Figure II-1. Load Management in NERC Forecasts

Source: Data from NERC 1998 and 2003 summer assessments. *NPCC data is for 1998 and 2002 

Mid-America Interconnected Network (MAIN), the regions with the largest percentage capability are 

FRCC, MAIN, and MAPP.25

 24 Title I of PURPA stated as its purpose (1) conservation of energy supplied by electric utilities, and (2) optimal 

efficiency of electric utility facilities and resources (section 101). PURPA section 111 directed states to consider several 

federal standards, including (1) time-of-day rates, (2) interruptible rates, and (3) load-management techniques. Public Utility 

Regulatory Policies Act of 1978, Pub. L. No. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. sections 15, 16, 26, 30, 42, and 

43). 

25 Note that since 2003, the configuration of the NERC reliability regions has changed. Portions of ECAR and 

MAIN are now in the RelibiltyFirst NERC region along with MAAC. Most of MAPP is now served by the Midwest 

Reliability Organization (MRO). SERC has expanded and now serves portions of ECAR, MAIN, and SPP. 
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According to the literature on this issue, a contributing factor behind the decline shown in Figure II-1 

has been the waning of electric utility interest and investment in demand response over the past 

decade, due to changes in industry structure and the result of state electric restructuring plans.26 State 

and utility programs were dismantled in many restructured states that had previously supported 

extensive programs. In several states, such as Texas, load management was deemed a competitive 

service and regulated distribution companies were directed to divest their holdings.27 In other states, 

utility divestiture of generation or transfer of the provider-of-last-resort (POLR) obligation removed a 

significant driver for utility investment by splitting up the benefits of demand response across multiple 

parties. Ample capacity reserves in many parts of the United States also contributed to declining 

utility interest and investment. Many states, such as Nevada, still support demand response and load 

management and operate integrated resource-planning programs that frequently include demand 

response and energy efficiency. 

Benefits of Demand Response 

Beyond the broad improvements in market efficiency and market linkages discussed above, demand 

response creates multiple, specific benefits for market participants and for the general efficiency and 

operation of electric markets. The following list of benefits encompasses many of the benefits 

referenced in the DOE report.28

Participant Benefits 

Customer adoption of demand response is based on the expectation of financial or operational 

benefits:29

• Financial benefits include cost savings on customers’ electric bills from using less energy 

when prices are high, or from shifting usage to lower-priced hours, as well as any explicit 

financial payments the customer receives for agreeing to or actually curtailing usage in a 

demand response program. The significant increases in fuel and electricity costs that have 

occurred over the last several years provide additional motivation for customers to control and 

reduce their energy consumption. 

• Reliability benefits refer to customer perceived benefits from the reduced likelihood of being 

involuntarily curtailed and incurring even higher costs, or societal, in which the customer 

derives satisfaction from helping to avoid widespread shortages. 

Market and System Benefits 

A key policy goal in implementing demand response is to create market, reliability, and social welfare 

benefits, including:30

 26 Raynolds and Cowart document this decline in Electricity Reliability White Paper: Distributed Resources and 

Electric System Reliability, 2000. 

27 More than 3,500 MW of capability from interruptible contracts no longer exist in Texas. Steven Braithwait, B. 

Kelly Eakin, Laurence D. Kirsch, “Encouraging Demand Participation In Texas’ Power Markets,” Laurits R. Christensen 

Associates Inc., prepared for the Market Oversight Division of the Public Utility Commission of Texas, August 2002. 

28 February 2006 DOE EPAct Report, 26-29. 

29 February 2006 DOE EPAct Report, 26. 

30 The short-term and long-term market benefits, along with the reliability benefits description are drawn from the 

list of “Collateral Benefits” included in February 2006 DOE EPAct Report, 27-28. 
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• Short-term market impacts are savings in variable supply costs brought about by more 

efficient use of the electricity system, given available infrastructure. In particular, price 

responsiveness during periods of scarcity and high wholesale prices can temper high 

wholesale prices and price volatility. Decreases in price spikes and volatility should translate 

into lower wholesale and retail prices. Where customers are served by vertically integrated 

utilities, short-term benefits are limited to avoided variable supply costs. In areas with 

organized spot markets, demand response also reduces wholesale market prices for all energy 

traded in the applicable market. The amount of savings from lowered wholesale market prices 

depends on the amount of energy traded in spot markets. The New York Public Service 

Commission suggests that demand response can also reduce a state’s dependence on natural 

gas-fueled generation.31

• Long-term market impacts are associated with the ability of demand response to (a) reduce 

system or local peak demand, thereby displacing the need to build additional generation, 

transmission, or distribution capacity infrastructure, and (b) adjust the pattern of customer 

loads, which may result in a shift in the mix of peak versus baseload capacity. 

• Operational and capital cost savings occur as system operators, LSEs, and distribution 

utilities benefit from avoided generation costs as well as avoided or deferred transmission and 

distribution costs. Since demand response can begin to be deployed in a relatively rapid 

fashion, demand response can contribute to the resolution of problems in load pockets on a 

shorter time frame than building new generation, transmission, or distribution, which can take 

years to complete. 

• System reliability benefits. By reducing electricity demand at critical times (e.g., when a 

generator or a transmission line unexpectedly fails), demand response that is dispatched by the 

system operator on short notice can help return electric system (or localized) reserves to precontingency levels. 

Additional Benefits Created by Demand Response 

Other demand response benefits noted in studies are more difficult to quantify; their magnitude will 

likely vary by region. The importance and perceived value of each of these benefits is subject to 

debate. Additional benefits may include:32

• More robust retail markets. Demand response promotes and creates additional options in 

retail markets. For example, default-service real-time pricing can stimulate innovation (e.g., 

alternative index-based products or curtailment products) by retail suppliers.33 The 

availability of ISO/RTO-administered demand response programs can provide value-added 

opportunities for marketers and the ability of customers to monetize their demand reductions. 

• Additional tools to manage customer load. Demand response provides expanded choices 

and tools for customers in states with and without retail competition to manage their electricity 

costs. 

• Risk Management. Demand response allows customers, retailers, and utilities to hedge their 

risk exposure to system emergencies and price volatility. Retailers can hedge price risks by 

 31 NYPSC Order, April 24, 2006, 1-2. 

32 The more robust retail markets, market performance benefits, and possible environmental benefits, are drawn 

from the list of “Other Benefits” included in the February 2006 DOE EPAct Report, 29. 

33 Galen Barbose, et al., Real Time Pricing as Default or Optional Service for C&I Customers: A Comparative 

Analysis of Eight Case Studies, Lawrence Berkeley National Laboratory: LBNL-57661, August 2005. 
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creating callable quantity options (contracts for demand response) and by creating price offers 

for customers who are willing to face varying prices. Customers can explicitly incorporate 

demand response into their operations and electricity purchases on an individual facility or 

enterprise basis. Utilities can use demand response programs to hedge their portfolio. This 

form of hedging is particularly important when utilities have default service obligations under 

rate freezes or caps.34

• Market performance benefits. Demand response can also play an important role in 

mitigating the potential for generators to exert market power in wholesale electricity markets. 

In organized markets, during periods of high demand and inadequate supply, market-clearing 

prices can escalate to high levels as more expensive-to-operate generation is dispatched. 

Without price-response mechanisms to lower demand as market-clearing prices increase, the 

potential for supplier market power abuse (such as capacity withholding) is heightened. Priceresponsive demand mitigates market power potential because these reductions increase 

suppliers’ risk of being priced out of the market. Customers who lower their consumption 

increase the number of suppliers in the market, reducing concentration and making collusion 

more difficult just when competitive concerns are the most severe. Sufficient amounts of 

price-responsive demand may reduce the need to use price caps and other market mechanisms 

such as installed capacity markets. 

• Linking wholesale and retail markets. Demand response can help link retail and wholesale 

markets through greater customer price-responsiveness to wholesale price changes and by 

increased hedging opportunities. 

• Possible environmental benefits. Demand response may provide conservation effects, both 

directly from load reductions (that are not made up at another time) and indirectly from 

increased customer awareness of their energy usage and costs.35 Demand response may 

provide environmental benefits by reducing generation plants’ emissions during peak periods. 

Reductions during peak periods should be balanced against possible emissions increases 

during off-peak hours, as well as from increased use of on-site generation. If the 

implementation of demand response contributes to reduced generation facility construction, 

there may be additional environmental and aesthetic benefits. These conservation and 

environmental impacts can be either positive or negative, and will likely vary by region.36

Multiple studies have attempted to quantify these benefits. The Electric Power Research Institute 

concluded that “... a 2.5% reduction in electricity demand statewide could reduce wholesale spot 

prices in California by as much as 24%; a 10% reduction in demand might slash wholesale price 

spikes by half.”37 McKinsey estimated national benefits of time-sensitive pricing to be $15 billion.38 

An ICF Consulting study for the Commission estimated a $4 billion savings in annual system 

operating costs if customers were exposed to peak-period price signals.39 These benefits also flow to 

society as a whole, not just to participants.40 

 34 David Kathan, Policy and Technical Issues Associated with ISO Demand Response Programs, prepared for 

NARUC, July 2002. 

35 King and Delurey, 2005. 

36 Stephen P. Holland and Erin T. Mansur, “The Distributional and Environmental Effects of Time-Varying Prices 

in Competitive Electricity Markets,” CSEM Working Paper (WP-143), May 2005. 

37 Taylor Moore, “Energizing Customer Demand Response in California,” EPRI Journal, Summer 2001, 8. 

38 Colledge, 2,7. 

39 ICF Consulting, Economic Assessment of RTO Policy, prepared for FERC, February 2002. 

40 Colledge, 2. 
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The Commission has recognized the benefits of demand response in multiple orders over the last six 

years. For example, in a 2001 order addressing the California crisis, the Commission stated: 

Without a demand response mechanism, the [independent system operator] is forced to work 

under the assumption that all customers have an inelastic demand for energy and will pay any 

price for power. There is ample evidence that this is not true. Many customers, given the 

right tools, can and will manage their demand. . . . A working demand response program puts 

downward pressure on price, because suppliers have additional incentives to keep bids close to 

their marginal production costs and high supply bids are more likely to reduce the bidder's 

energy sales. Appropriate price signals to customers thus help to mitigate market power as 

high supply bids are more likely to reduce the bidders' energy sales. Suppliers thus have 

additional incentive to keep bids close to their marginal production costs. Demand-side priceresponsive bids will also help to allocate scarce supplies efficiently.41

The Commission also noted the value of incentive-based demand response in maintaining grid 

reliability in a 2002 PJM order: 

PJM is responsible for ensuring the short-term reliability of the interstate transmission system. 

When system reliability events require PJM to implement measures to protect the transmission 

system (i.e., PJM declares a Maximum Generation Emergency), encouraging load reductions 

and the use of on-site generation is an important tool in maintaining transmission reliability.42

Evidence of Customer Price-Responsiveness 

Offered time-based rates, customers choose whether to adjust their consumption or not. Their decision 

to adjust consumption is driven by the costs and benefits of taking one of the following actions: (a) 

adjusting routine business activity specifically to avoid paying higher than average prices; (b) forgoing 

discretionary usage; and (c) deploying distributed or on-site generation. The ability of customers to 

respond to prices requires the following conditions: that time-based rates are communicated to them; 

that they have load control systems that allow them to respond to price signals (e.g., by shedding load, 

automatically turning appliances down or off, or turning on an on-site generator); and that customers 

have meters that can measure consumption by at least the time of day so the utility can determine how 

much power was used at what time and bill accordingly. 

Experiences in New York, Georgia, California, and other states and pricing experiments have 

demonstrated that customers do take actions to adjust their consumption, and are responsive to price 

(i.e., they have a nonzero price elasticity of demand). Georgia Power Company’s successful real-time 

pricing tariff option has demonstrated that industrial customers who receive real-time prices based on 

an hour-ahead market are relatively price-responsive (price elasticities ranging from approximately –

0.2 at moderate price levels, to –0.28 at prices of $1/kWh or more) given the short-time period in 

which to act. Among day-ahead real-time pricing customers, price elasticities range from 

approximately –0.04 when prices are at moderate levels to –0.13 when customers are exposed to 

higher prices.43 A critical peak-pricing experiment in California in 2004 determined that small 

residential and commercial customers are price responsive and will produce significant reductions. 

 41 San Diego Gas and Electric Co., 95 FERC ¶61,148, at 62,555 (2001). 

42 PJM Interconnection, L.L.C., 99 FERC ¶ 61,139 at n. 18 (2002). 

43 Industrial Consumers, comments filed in Docket No. AD05-17-000, November 18, 2005, 39. 
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Participants reduced load 13 percent on average, and as much as 27 percent, when price signals were 

coupled with automated controls such as controllable thermostats.44 

Customer price-responsiveness varies significantly by market segment among commercial and 

industrial users (See Figure II-2). A study of Niagara Mohawk Power (now National Grid) customers 

in the real-time pricing program found nearly a third of those who were unable to curtail in the 

Niagara Mohawk program also were enrolled in a NYISO emergency demand response program 

(EDRP); nearly two-thirds had received some sort of capacity payments. These non-price-responsive 

customers may have valued perceived reliability needs more highly than perceived price needs. The 

study noted that “industrial customers who were also enrolled in the EDRP showed dramatically 

increased responses during EDRP events (0.40 on event days vs. 0.03 on non-event days); for these 

customers, the EDRP program appears to entice price response that their Niagara Mohawk tariff did 

not.”45

Figure II-2. Elasticity of substitution varies by customer market segment 

0.05

0.11

0.03

0.17

0.01

0.11

0

0.04

0.08

0.12

0.16

0.2

Commercial /

Retail

Gov't /

Education

Health Care Manufacturing Public Works All Accounts

Elasticity of Substitutio

Source: Goldman, et al., Customer Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing: LBNL-57128, August 2005.

Role of Enabling Technology 

A key requirement for most demand response programs and time-based rates is the availability of 

enabling technology. For states or utilities to implement demand response and time-based rates, 

customers would need meters that record usage on a more frequent basis, preferably hourly. 

Introducing other demand technologies such as smart thermostats (i.e., thermostats that adjust room 

temperatures automatically in response to price changes or remote signals from system operators) 

would increase the amount of load that could be reduced under a demand response program. 

Advances in integrated circuitry, control systems, and communications technologies have significantly 

increased the functionality of advanced metering and demand response technologies. These advances 

have the potential to provide more power system and societal benefits than those achievable with 

 44 Charles River Associates. Impact Evaluation of the California Statewide Pricing Pilot: Final Report. March 16, 

2005. 

45 Charles Goldman, et al., Does Real-time Pricing Deliver Demand Response? A Case Study of Niagara Mohawk's 

Large Customer RTP Tariff, Lawrence Berkeley National Laboratory: LBNL-54974, August 2004. 
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existing demand response programs. These advances make automated customer responses possible in 

more situations, allowing both greater customer receptivity and higher utility confidence that 

customers can and will respond to price-based demand response. 

Examples of enabling technologies include, but are not limited to,46

• interval meters with two-way communications capability that allow customer utility bills to 

reflect their actual usage pattern rather than an average load profile for that customer class 

• multiple, user-friendly communication pathways to notify customers of load curtailment 

events 

• energy-information tools that enable near-real-time access to interval load data, analyze load 

curtailment performance relative to baseline usage, and provide diagnostics to facility 

operators on potential loads to target for curtailment 

• demand-reduction strategies that are optimized to meet differing high-price or electric system 

emergency scenarios 

• load controllers and building energy management control systems that are optimized for 

demand response and which facilitate automation of load curtailment strategies at the end use 

level 

• on-site generation equipment, used either for emergency back-up or to meet primary power 

needs of a facility 

The prices for technologies to implement time-based rates and automated customer responses have 

been falling, just as their capabilities have been rising. In his seminal book, Spot Pricing of 

Electricity, Professor Fred Schweppe of Cornell University posited that demand response was an 

integral part of a market model. His analysis envisioned technology solutions that may have seemed 

futuristic in 1988, including automatic thermostat controls and customer warnings when the spot 

prices to run an appliance would exceed a pre-determined cost. He posited that as time goes by, 

“appliance manufacturers would start to produce appliances designed to be able to exploit timevarying prices.”47 

Communication technologies for notifying customers about system emergencies or price events also 

are important. Whether programs are adopted in restructured electricity markets or in traditional 

regulated markets, LSEs can adopt real-time and critical-peak pricing by notifying customers through 

pagers, cell phones, the Internet, and other means. The more communications channels used, the 

greater the likelihood of customer response. 

 46 Charles Goldman, Grayson Heffner, and Michael Kintner-Meyer, Do "Enabling Technologies" Affect Customer 

Performance in Price-Responsive Load Programs?, August 2002: LBNL-50328, 10. 

47 Fred C. Schweppe, Spot Pricing of Electricity (Boston: Kluwer Academic Publishing, 1988), chapter 4. 
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Chapter III – Advanced Metering Penetration 

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Chapter III. Advanced Metering and Market Penetration48

This chapter addresses the first area, in EPAct section 1252(e)(3), that Congress directed the 

Commission to consider: 

(A) saturation and penetration rates of advanced meters and communications technologies, 

devices and systems. 

This chapter contains a detailed analysis of the state of advanced metering, and estimates the 

saturation and penetration of advanced metering in the electric power sector across the United States. 

It also discusses the importance of advanced metering for electric demand response, describes the 

available forms of advanced metering and key technological developments in metering and 

communications equipment. 

To develop this estimate of advanced metering penetration, Commission staff conducted a 

comprehensive and first-of-its-kind survey of metering. The FERC Demand Response and Advanced 

Metering Survey49 (FERC Survey) requested information on electric industry meters in all 50 states, 

with attention to meters that measure usage in short time intervals and with meter data retrieval more 

frequent than monthly. The results of this survey suggest that advanced metering achieved almost a 

six percent penetration in the United States electric meter market by the end of 2005. 

This chapter builds on the discussion of demand response and time-based rate programs included in 

Chapter II, and is organized into five sections: 

• Definition of advanced metering 

• Description of the components and technologies associated with advanced metering 

• Presentation of the estimates of market penetration based on information received in the FERC 

Survey 

• Costs and benefits associated with the deployment of advanced metering 

• Issues associated with advanced metering 

What is advanced metering? 

Commission staff defines “advanced metering” as follows: 

Advanced metering is a metering system that records customer consumption [and possibly 

other parameters] hourly or more frequently and that provides for daily or more frequent 

transmittal of measurements over a communication network to a central collection point. 

The key concept reflected in this definition is that advanced metering involves more than a meter than 

can measure consumption in frequent intervals. Advanced metering refers to the full measurement and 

collection system, and includes customer meters, communication networks, and data management 

 48 This chapter reflects the views and the assistance of Patti Harper-Slaboszewicz of UtiliPoint International. 

49 See Appendix F for a description of the FERC Survey. 
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systems. This full measurement and collection system is commonly referred to as advanced metering 

infrastructure (AMI). 

Commission staff chose this definition based on (a) a review of the state-of-the-art of metering and 

communications technology, (b) specifications for “smart metering” or advanced metering in recent 

utility solicitations,50 (c) what type of meters and infrastructure is necessary to support demand 

response and to provide additional utility operational benefits beyond reducing metering costs,51 and 

(d) definitions of advanced metering included in the EPAct 2005.52 

Overview of Advanced Metering 

The need to bill customers for their electricity consumption has historically been the primary reason to 

read electric meters. Today, with advances in metering technology and communication systems, 

advanced meters and infrastructure can provide additional value to utilities by enhancing customer 

service, reducing theft, improving load forecasting, monitoring power quality, managing outages, and 

supporting price-responsive demand response programs. For example, if electric load serving entities 

(LSEs) read meters every day, customer service representatives can assist a customer starting or 

ending service in one phone call, or more easily handle high bill complaints. With more frequent, 

hourly reads, customer demand can be totaled across meters served by a feeder line or transformer. 

This allows electric distribution companies to properly size equipment to handle peak loads, and 

increase the reliability of service while reducing costs. Hourly reads can also improve the accuracy of 

load forecasting, allowing LSEs to sell more power into the wholesale market, or reduce spot market 

purchases.53 

Advanced metering also supports time-based rates. Monthly-only meter reads limit available rate 

options and does not support the provision of usage information in real-time to customers (see Chapter 

IV for a full description of alternative rate offerings). Hourly meter reading capabilities permit current 

and future innovative rate designs. These innovative rate designs can include retail rates designed to 

encourage customers to curtail energy use when wholesale prices are high and to make short-term or 

long-term changes to slow the growth of peak demand, and wholesale programs operated by 

Independent System Operators and Regional Transmission Organizations (ISO/RTOs) that are 

designed to curtail consumption during periods of high wholesale prices or system emergencies.54 In 

 50 Recent requests for proposals for automated meter reading have included a fixed network requirement, and the 

requirements almost always involve measuring interval data hourly and collecting the data at least once per day. Exceptions 

have included more stringent requirements, for example, CenterPoint, a large utility in Texas, issued an RFP in January 2006 

requesting 15 minute interval data. 

51 Jana Corey, Director, Advanced Metering Infrastructure (AMI) Initiative for PG&E, provided the following 

written testimony in support of PG&E’s filing for the AMI project: “Over time, the operational benefits are expected to 

cover 89 percent of the costs and PG&E continues to estimate that the additional customer demand response benefits will 

allow the total benefits to exceed the total AMI Project cost.” “Section I Advanced Metering Infrastructure Project A.05-06-

028 - Supplemental Testimony Pacific Gas and Electric Company Chapter 1 AMI Project and Project Management”, 

Application 05-06-028, filed October 13, 2005 with California Public Utilities Commission. 

52 EPAct 2005 section 1252 (included in Appendix A) references advanced metering as a “suitable meter,” a 

“device to enable demand response,” “advanced metering with communications,” and “time-based meters with 

communication devices.” The section header includes the term “Smart Metering.” EPAct 2005 section 103 offers a more 

specific definition: “advanced meters or advanced metering devices that provide data at least daily and that measure at least 

hourly consumption of electricity.” 

53 Patti Harper-Slaboszewicz, “Market Trends in AMR and Demand Response,” prepared for Automatic Meter 

Reading Association (AMRA), 2005. 

54 Roger Levy, “Meter Scoping Study,” prepared for the California Energy Commission, March 2002. 
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many time-based pricing pilots and implementations of time-based pricing, a key consideration has 

been to provide timely information to customers, and almost all time-based rate pilots or 

implementations have used advanced metering.55 Nevertheless, some electric utility representatives 

believe that the added expense of advanced metering is not needed to support time-based rates, and 

that deployment of time-of-use meters is sufficient to achieve benefits.56 

The remainder of this section presents the key building blocks of advanced metering and discusses the 

available technologies. 

Building Blocks of Advanced Metering 

Advanced metering or AMI consists of various components, including meters enabled with 

communications, a data collection network, and an AMI host system and database. Figure III-1 

provides an overview of the building blocks of advanced metering. Note that while the focus of the 

discussion in this chapter will be on electric metering, AMI can also be deployed to collect data from 

gas and water meters. 

Figure III-1. Building blocks of advanced metering 

Source: UtiliPoint International 

As is shown in Figure III-1, advanced metering has several components. Each customer meter is 

equipped with the ability to communicate with a network. A customer meter and the associated 

communication is commonly referred to as an “endpoint.” The communication system endpoints send 

 55 The following time-based pricing pilots/implementations have depended on advanced metering: Gulf Power 

GoodCents, California Statewide Pricing Pilot, PSE&G myPower Pilot Program, Anaheim Spare the Power Days program. 

56 See for example, Alan Wilcox (Sacramento Municipal Utility District), FERC Technical Conference, transcript, 

134-137. 

Data 

Collection Collection 

Network Network Advanced Metering Advanced Metering

Infrastructure Host Infrastructure Host

To Meter

Data

Management Management

neptune t

Triden 9 9 99 9 9 9

Applicable to all meter reading systems – from 

mobile to complex real-time fixed networks

Electric 

endpoint

Water 

endpoint

Gas 

endpoint

Data 

Collection Collection 

Network Network Advanced Metering Advanced Metering

Infrastructure Host Infrastructure Host

To Meter

Data

Management Management

neptune t

Triden 9 9 99 9 9 9

neptune t

Triden 9 9 99 9 9 9

neptune t

Triden 9 9 99 9 9 9

neptune t

Triden 9 9 99 9 9 9

neptune t

Triden 9 9 99 9 9 9

neptune t

Triden 9 9 99 9 9 9 9 9 99 9 9 9

Applicable to all meter reading systems – from 

mobile to complex real-time fixed networks

Electric 

endpoint

Water 

endpoint

Gas 

endpoint
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meter readings up through the data collection network to the AMI host system. The data analysis and 

storage of the meter data is managed by meter data management (MDM) systems. Each of these 

components is discussed in greater detail below. 

Metering 

Electric meters have historically been used to measure, at the minimum, consumption of electricity in 

kWh over a monthly or other similar billing period. Meters installed at larger commercial and 

industrial customers often also measured maximum demand in kW and other power quality 

parameters. Up until the last decade or so, these meters, especially for smaller customers, were based 

on electromechanical designs. Over time, electromechanical meters have become highly reliable and 

typically last for up to 40 years. 

In recent years, metering has gone through a transformation from electromechanical meters to solid 

state, electronic meters. The shift towards solid state meters is driven in part by their additional 

functionality,57 but the strongest driver for the rising market share of solid state meters is investment in 

automated meter reading (AMR) or AMI. With AMI or AMR enabled meters, the utility will plan to 

change out the meter when the AMI or AMR communications fails or is replaced. Thus, the shorter 

useful life of the solid state meter compared to electromechanical meters is less important. 

Along with the shift towards solid state meters, there also has been a gradual transition from manual 

meter reading to AMR, and onto AMI, and utilities are at various stages of adopting automation. 

Many utilities continue to employ meter readers to walk routes to read utility meters once a month. 

However, the number of utilities that use meter books and later key in the readings is dwindling. 

Hand-held electronic meter books began replacing meter books in the 1980s, which allow the meter 

reader to physically connect to the meter or key in the meter reading. Meter reads can then be 

downloaded to the utility billing system, which reduces transcription errors and speeds up the billing 

process. This system works fairly well for collecting meter reads for monthly bills but still requires 

the meter reader to get reasonably close to the meter on the customer’s property.58 AMR and AMI 

were developed to allow meter reading to be more efficient and less-costly through remote meter 

reading. In particular, deployments of AMI can also support more frequent meter reading. 

The design of the meter and the technology used does have implications for its ability to be part of an 

AMI system. To enable an electromechanical meter to communicate with an AMI system, an 

electronic meter module is installed “under-the-glass” of the meter. This module counts and records 

electronically the spinning of the disk within the meter. This retrofit solution does have limitations, 

however. The AMI measurement is performed independently of the meter measurement which may 

result in a discrepancy between the usage displayed by the electromechanical meter and what is 

reported via the AMI system. Retrofit of solid state meters to communicate with AMI systems is more 

straightforward and most meters currently being deployed have the ability to accommodate 

communication modules from multiple AMI vendors and technologies. 

Utilities tend to meter medium-sized customers with demand meters. However, these customers are 

not large enough to be metered with the more sophisticated metering used for the largest customers of 

utilities. Demand meters measure the maximum demand during the billing period along with the 

 57 Solid state meters provide the ability to measure loads at lower levels, increased measurement frequency, 

increased accuracy, data storage capability, measurement of additional parameters, and ease of upgrading meter functionality 

or integrating communication technology. 

58 Roger Levy, 2002. 
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energy measurement. The difficulty has been with how to reset the demand measurement once the 

maximum demand has been recorded for the current billing period without actually physically visiting 

the meter site. With AMI, if the utility retrieves the maximum demand daily, it is no longer necessary 

to manually reset the demand measurement. 

The transition to solid state metering occurred some time ago for larger customers. Conversion to a 

new AMI system for larger customers is typically driven by the need to change communications 

technologies. For example, many electric utilities are converting from using analog cellular to other 

communication technologies as cellular companies drop support for analog cellular. 

For all customers, there are a variety of choices for meters, solid state or electromechanical, and most 

AMI vendors have developed AMI modules for more than one meter vendor. Large purchases of 

meters today are usually related to a rollout of AMI, and purchase is guided by the selection of the 

AMI technology rather than by the selection of a particular meter. AMI has thus contributed to the 

treatment of meters as commodities by utilities. 

AMI Data Collection 

AMI data collection involves the collection and retrieval of meter data without physically visiting the 

meter site, and is typically done by means of a fixed network.59 Today, electric utilities use various 

types of AMI systems. The different types of AMI systems available on the market today are: 

• Broadband over power line 

• Power line communications 

• Fixed radio frequency (RF) networks 

• Systems utilizing public networks (landline, cellular, or paging) 

Each of these different AMI system types are examined in more detail below. 

Broadband Over Power Line (BPL)60

BPL works by modulating high-frequency radio waves with the digital signals from the Internet. 

These high frequency radio waves are fed into the utility grid at specific points, often at substations. 

They travel along medium voltage circuits and pass through or around the utility transformers to 

subscribers' homes and businesses. Sometimes the last leg of the journey, from the transformer to the 

home, is handled by other communication technologies, such as Wi-Fi. 

As seen in Figure III-2 below, substations receive power from power plants over high voltage lines, 

and then step down the voltage to transmit power to distribution transformers over medium voltage 

circuits. Each medium voltage circuit services 20-25 distribution transformers which convert the 

medium voltage down to the voltage level used within most homes and businesses (110v/220v). 

Between one and six homes are connected to each distribution transformer which translates to about 

100 homes passed per medium voltage circuit. 

 

 59 A fixed network refers to either a private or public communication infrastructure which allows the utility to 

communicate with meters without visiting or driving by the meter location. 

60 The information in this section relies heavily on facts provided in a seminar presented in 2005 by UtiliPoint: 

Ethan Cohen, UtiliPoint, “BPL Hope, Hyperbole, and Reality,” April 2005. 
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Figure III-2. Stylized Grid diagram 

Source: Bruce Bahlmann, Birds-Eye.Net and UtiliPoint® International 

To implement BPL, a utility must interconnect substations (many of which are already interconnected 

using fiber). The BPL signal is then injected onto the medium voltage circuits at the substations. Due 

to the tendency of transformers to filter the high-frequency BPL signal, at each distribution 

transformer one of three things can happen: the signal is pushed through the transformer, the 

transformer is bypassed, or the signal is provided to the customers using a Wi-Fi device physically 

located near the distribution transformer. 

In Europe, there are typically 100 customers served on a distribution line with transformers at each 

end of the span. In contrast, the United States distribution system has one transformer serving six to 

ten customers, which increases the relative cost in the United States.61 

Major vendors of broadband over powerlines include Ambient, Amperion, Current Technologies, 

Main.net, and PowerComm Systems. 

Power Line Communications (PLC) 

PLC systems send data through powerlines by injecting information into either the current, voltage or 

a new signal. This can be accomplished by slightly perturbing the voltage or current signal as it 

crosses the zero point or adding a new signal onto the power line. The system normally has equipment 

installed in utility substations to collect the meter readings provided by the endpoint, and then the 

information is transmitted using utility communications or public networks to the utility host center for 

the PLC system. The low frequency signals used in PLC communications in the United States are not 

filtered out by distribution transformers. 

PLC systems are particularly well suited to rural environments, but have also been successfully used in 

urban environments.62 For utilities with both rural and suburban areas in their service territory, PLC 

provides an option for using one AMI technology for the entire service territory for electric meters. 

PLC systems initially targeted residential and small commercial metering, but are now able to read for 

larger customers as well. 

 61 “Is the Ambient system compatible with all distribution systems?” Frequently asked questions on Ambient 

Corporation website, http://www.ambientcorp.com/pages/faqs-UTILITY.htm, “For all practical purposes, yes. In the US and 

Canada, all systems are essentially the same from a BPL perspective. In other countries, differences in voltage, frequency and 

configuration (specifically, the number of customers on each distribution transformer) can impact equipment and system 

design. In general, the higher density of customers per transformer in Europe and other countries works in favor of BPL.” 

62 PPL Electric Utilities has used PLC in Pennsylvania and, more recently, Pacific Gas & Electric selected a PLC 

system for its electric AMI system for both rural and suburban areas. 
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Major vendors of power line communications include Cannon Technologies, DCSI, and Hunt 

Technologies. 

Fixed RF Systems 

In basic fixed radio frequency (RF) systems, meters communicate over a private network using RF 

signals. Each meter communicates via the network directly to a data collector or a repeater. Repeaters 

may forward information from numerous endpoints to the more sophisticated devices called data 

collectors. 

Data collectors often store the meter readings from meters within range. The data collectors then 

upload the meter readings to the AMI host system at preset times using the best communication 

method available, ranging from public networks to microwave to Ethernet connections. The 

communications between the data collector and the network controller are usually two-way, and allow 

the network controller to query for a recent meter reading and the status of one or a group of meters. 

From 1994 to 1999, this type of automated meter reading system was selected for every large fixed 

network deployment in the United States. 63 Since 1999, fixed RF has been selected in seven of the 12 

large fixed network deployments. 

More advanced RF networks have also been developed and implemented. Within these more 

advanced systems, the meters themselves may form part of the network, and meters are not required to 

communicate directly or indirectly with a repeater or the data collector. One example of an advanced 

RF AMI network is shown below in Figure III-3. In this system, endpoints can communicate directly 

with towers (similar to super data collectors) or via a ‘buddy” meter. Other advanced systems are 

designed with endpoints that form a mesh network, and where some of the endpoints within the mesh 

may function as data collectors and meters. The flexibility provided by advanced RF AMI systems is 

generally thought to offer advantages in terms of better coverage and more robust communications. 

One of the key features of the more advanced RF networks that appeal to utilities is the ability of the 

network to “self heal.”64 If the endpoints have more than one communication path to the main hub of 

the system, and the best path is no longer available, endpoints can change their communication path. 

This is very important to utilities because changes in the service territory are ongoing. New buildings 

are constructed, trees or other shrubbery are planted or grow, and other changes occur which affect RF 

communications. 

Major vendors of fixed RF systems include Cellnet, Elster, Hexagram, Itron, Sensus/AMDS, Silver 

Spring Networks, Tantalus, and Trilliant. 

 63 See Table III-3 later in this chapter for a list of recent deployments. 

64 Bruce Carpenter, Portland General Electric, “PGE Mesh Metering Tests”, September 2005 
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Figure III-3. Advanced RF Network system overview

Source: Sensus/AMDS

Systems Utilizing Public Networks 

These systems utilize existing public networks such as paging, satellite, internet and/or telephony 

(cellular or landline) networks to provide for communications between meters and utilities. One key 

advantage of these systems is the ability to deploy AMI across a wide area with low densities, and the 

possible lower upfront cost of deployment since the utility does not need to build a private 

infrastructure. Some systems rely on paging networks while others rely on cellular or landline 

telephone networks. Some have used satellite communications. Three key limitations include: being 

subject to the coverage provided by the public networks; changing protocols (this is especially true in 

the cellular segment); and operational costs. 

With AMI systems based on public networks, if there is coverage at the customer location, installation 

costs are limited to installing the new endpoint, and setting up the service. Utilities are not required to 

install any communication infrastructure, which can speed up the deployment process. 

All of these systems have been used for larger customers and small rollouts of AMI, but recently these 

systems are being considered for much larger rollouts for smaller customers.65 

 65 Hydro One in Ontario announced in April 2005 it had selected Rogers Wireless Inc./SmartSynch to provide 

25,000 "Smart Meters" as part of a pilot program. The Smart Synch system relies on a selection of various public networks 

for communications. 

Phone Line

ISDN

Satellite

TGB

Tower Gateway

Basestation

'

UTILITY 

OFFICE

RNI

Regional 

Network 

Interface

Map TGB Channel Noise

TGB Channel Noise

Correlation

System Health 

Management 

Data Warehouse

60 Day History

XML File

Itron MV 90, MV 90 HHF

Itron Enterprise Edition

SIMS

Custom Interface

Utility Interface Web Functions

Two-way & One-way

Meter endpoints 

(Electric, Gas, Water)

75 to 300 Sq. Miles

Per tower range 

Phone Line

ISDN

Satellite

TGB

Tower Gateway

Basestation

'

UTILITY 

OFFICE

RNI

Regional 

Network 

Interface

Map TGB Channel Noise

TGB Channel Noise

Correlation

System Health 

Management 

Data Warehouse

60 Day History

XML File

Itron MV 90, MV 90 HHF

Itron Enterprise Edition

SIMS

Custom Interface

Utility Interface Web Functions

Two-way & One-way

Meter endpoints 

(Electric, Gas, Water)

75 to 300 Sq. Miles

Per tower range 
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Meter Data Management 

Meter data management provides utilities a place to store meter data collected from the field. Utilities 

that install AMI usually invest in meter data management to provide storage for the large number of 

meter readings that will be collected each year per meter. If utilities opt for hourly interval data, this 

results in 8,760 meter readings per meter year, compared to 12 each year for a meter that is read once 

per month. For a utility of even modest size, the storage requirements and data processing can become 

substantial. 

Meter data management can also be configured to meet the specific requirements of other utility 

applications. For example, with meter data management, meter data can be provided in the same 

manner to all applications, or it can provide data in the exact form that each application requires. If 

the utility bills residential customers on the total usage for the billing period, the meter data 

management can total all of the daily reads to provide the billing system the total usage for each 

customer. 

Estimates of Advanced Metering Market Penetration from FERC 

Survey 

In order to respond to the direction from Congress to assess market penetration of advanced metering 

by region, Commission staff undertook a comprehensive survey of electric delivery companies and 

other entities that might own or operate retail electric meters to learn how they use their advanced 

metering systems, and for how many meters utilities they have deployed to collect information that 

could be used to support demand response. This section reports on the results of this survey. 

FERC Survey 

Commission staff asked respondents to provide information on how often customer usage data is 

collected, and the frequency of the data measurement. This allowed the survey to provide meaningful 

benchmarks for advanced metering, showing statistics for a range of metering sophistication. 

In the FERC Survey, Commission staff requested respondents that own or operate customer meters to 

provide information by customer class on the number of customer meters they own and/or operate, and 

how energy usage is measured and retrieved. Electric utilities and other entities divide energy 

measurement into several categories based on how often the data is collected, and the frequency of the 

data intervals. 

Commission staff also asked entities to distinguish between whether the installed metering and/or 

advanced metering system in place is capable of meeting the stated requirements or is being used in 

accordance with the stated standards. Collection of data on whether meters are capable covers 

situations where electric utilities are not using the AMI system to the fullest extent, but could in the 

future without a separate physical trip to retrofit or replace the customer meter. 

Entities were asked to divide the number of meters in the following categories for each customer class 

that are being used or capable of being used: 

1. For those meters where meter reads are collected at least daily, how many are collecting 

interval data where: 
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Intervals <= 15 minutes. 

Interval is > 15 minutes and <= hourly. 

2. For those meters where meter reads are collected at least monthly but not as often as daily, 

how many are collecting interval data where: 

Intervals <= 15 minutes. 

Intervals are > 15 minutes and <= hourly. 

3. For those meters where measurement is collected for two to four peak periods (on, shoulder, 

off, etc.) per day, how many are: 

Collecting for intervals greater than hourly but less than daily (two hour intervals, 

three hour intervals, etc.). 

Providing daily peak period totals. 

Providing monthly totals for each peak period 

. 

Consistent with our earlier definition of advanced metering, the penetration estimates presented below 

reflect meters that are currently used to collect measurements with data intervals of an hour or less, 

and a data retrieval frequency of at least daily. 

It is still unclear how demand response requirements will be incorporated into advanced metering or 

whether it will be common practice to use the AMI systems to send demand response signals to 

customers or to load control equipment. Therefore, Commission staff elected to ask respondents about 

other features of AMI, besides measurement and data retrieval. 

Advanced Metering Market Penetration Estimates 

The results of the FERC Survey indicates that advanced metering or AMI currently has a low market 

penetration of less than six percent in the United States (See Figure III-4).66 This result is lower than 

past estimates, which had suggested the penetration rate was closer to 10 percent.67

The following discussion breaks down the advanced metering penetration results by customer class, 

region, customer class and region, and by state. 

Figure III-4. United States penetration of advanced metering 

Source: FERC Survey 

 66 UtiliPoint International, under contract with the Commission for the purposes of this Report, performed analysis 

and tabulation of results 

67 Chris King, eMeter “Advanced Metering Infrastructure (AMI) Overview of System Features and Capabilities,” 

prepared for presentation at a joint meeting of the CPUC, CEC, and the Governor’s Cabinet of California, September 30, 

2004. 

NonAdvanced 

Metering, 

94.1%

Advanced 

Metering, 

5.9%

Advanced Metering

Non-Advanced Metering

NonAdvanced 

Metering, 

94.1%

Advanced 

Metering, 

5.9%

Advanced Metering

Non-Advanced Metering
Chapter III – Advanced Metering Penetration 

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27

A breakdown of the national results by customer class (Figure III-5) suggests that the market 

penetration estimates of advanced metering for the primary customer classes (residential, commercial, 

and industrial) are relatively close to the national penetration estimate. The highest penetration rate 

(eight percent) is associated with transportation customers. 

Figure III-5. Penetration of advanced metering by customer class 

Source: FERC Survey 

Examination of market penetration by type of entity and ownership (see Figure III-6) indicates that 

electric cooperatives have deployed the greatest level of advanced metering, with overall penetration 

of 12.9 percent. Investor-owned utilities have the next highest level of penetration at 5.7 percent, 

close to the national average. 

Figure III-6. Penetration of advanced metering by ownership 

Source: FERC Survey 

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

Other Transportation Industrial Commercial Residential

Customer Class

Advanced Metering Penetration

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

Other Transportation Industrial Commercial Residential

Customer Class

Advanced Metering Penetration

0.3% 0.1% 0.0% 0.4%

5.7%

12.9%

2.0% 1.3%

0.5%

1.3%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

Cooperative Investor

Owned

Municipal

Marketing

Authority

Municipal Political

Subdivision

Power

Marketer

Federal CSP State ISO

Ownership

Advanced Metering Penetration

0.3% 0.1% 0.0% 0.4%

5.7%

12.9%

2.0% 1.3%

0.5%

1.3%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

Cooperative Investor

Owned

Municipal

Marketing

Authority

Municipal Political

Subdivision

Power

Marketer

Federal CSP State ISO

Ownership

Advanced Metering Penetration
Chapter III – Advanced Metering Penetration 

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An analysis of market penetration by region indicates that there are differences in how much advanced 

metering has been adopted across the United States (see Figure III-7) in the footprints of the various 

NERC regional reliability councils. The ReliabilityFirst Council (RFC), which covers the MidAtlantic and portions of the Midwest, and the Southwest Power Pool (SPP), with overall penetration 

rates of 14.7 percent and 14.0 percent respectively, show the highest regional penetration. 

Figure III-7. Penetration of advanced metering by NERC region68

Source: FERC Survey 

Table III-1 further breakdown of the regional market penetration estimates by customer class.69 The 

penetration of advanced metering for the residential and commercial classes is the highest in the RFC 

and SPP regions. All other NERC regions have lower than average penetrations of AMI for 

residential and commercial classes. For the industrial class, the MRO, RFC and NPCC regions enjoy 

a penetration rate higher than average, and all of the other regions are below average. 

Table III-2 includes estimates of the penetration of advanced metering by state. These state-by-state 

estimates may prove a useful baseline in the state deliberations on smart metering required by EPAct 

200570 and any future state proceedings on advanced metering. 

There is wide variation in the number of advanced meters that have been installed across the states. 

The five states with the highest penetration of advanced meters are Pennsylvania, Wisconsin, 

Connecticut, Kansas, and Idaho. Most states have reported much lower penetration of advanced 

meters. 71

 68 Regional definitions used in this figure and subsequent figures and tables are based on NERC regions. See 

Chapter I for a map of these regions. 

69 Examples of transportation customers are rapid transit customers. Other customers include wholesale customers, 

street lights, and customers that do not fit into the other categories. 

70 EPAct 2005 section 1252(b). 

71 The penetration estimates for several states such as Louisiana and Mississippi do not reflect complete 

information. Electric utilities serving these states were unable to provide a full inventory of meters due to the impacts of 

Hurricanes Katrina and Rita in 2005. 

2.8% 4.2%

0.2%

1.0%

2.5%

5.2%

14.0%

14.7%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

RFC SPP SERC MRO NPCC FRCC WECC Other

NERC Region

Advanced Metering Penetration

2.8% 4.2%

0.2%

1.0%

2.5%

5.2%

14.0%

14.7%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

RFC SPP SERC MRO NPCC FRCC WECC Other

NERC Region

Advanced Metering Penetration
Chapter III – Advanced Metering Penetration 

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Table III-1. Penetration of AMI by region and customer class 

Region Residential Commercial Industrial Transportation Other 

RFC 15.0% 13.6% 11.1% 68.4% 0.4%

SPP 15.2% 8.9% 2.6% 15.7% 5.8%

SERC 5.4% 2.6% 2.9% 50.3% 4.6%

ERCOT 4.6% 2.0% 3.4% 0.0% 0.1%

MRO 4.1% 5.3% 7.2% 0.4% 0.6%

NPCC 2.8% 2.9% 9.2% 1.3% 6.3%

FRCC 2.8% 0.6% 2.8% 0.0% 0.0%

WECC 0.9% 1.4% 5.2% 0.5% 2.9%

Other 0.3% 0.0% 0.6% 0.0% 0.0%

Total 6.0% 5.0% 5.7% 8.0% 2.6%

Source: FERC Survey 

In order to provide a complete picture of meter reading, estimates for the market penetration of meter 

reading with measurement intervals and collection frequencies other than at least once an hour and 

read at least once daily. The penetrations for various combinations of measurement intervals and 

collection frequencies are included in Figure III-8. Analysis of these results suggests that even with 

the most expansive definition of advanced metering (which includes time-of-use measurement 

intervals and monthly meter reads), the penetration of meters capable of supporting time-based rates is 

still only seven percent. 

Figure III-8. Advanced metering data interval and collection frequency 

penetration estimates 

2.1%

5.0%

5.9%

2.3%

5.9%

7.0%

4.5%

2.8%

2.7%

2.4%

1.2%

0% 1% 2% 3% 4% 5% 6% 7% 8%

Daily Collection, Interval < 15 minutes

Daily Collection, 15 minutes < Interval <= Hourly

Advanced Metering

Daily Collection, TOU

Daily Collection, Interval <= Hourly or TOU

Daily or Monthly Collection, Interval <= Hourly or TOU

Monthly Collection, Interval <= Hourly or TOU

Monthly Collection, TOU

Monthly Collection, Interval <= Hourly

Monthly Collection, 15 minutes < Interval <= Hourly

Monthly Collection, Interval <= 15 minutes

Source: FERC Survey 
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Table III-2. Penetration of advanced metering by state 

Source: FERC Survey 

State Advanced Meters Non-Advanced 

Meters Total Meters Penetration

Alaska 1,358 303,565 304,922 0.4%

Alabama 75,861 2,332,450 2,408,311 3.1%

Arizona 34,342 2,638,468 2,672,810 1.3%

Arkansas 183,449 1,234,925 1,418,374 12.9%

California 41,728 14,206,721 14,248,449 0.3%

Colorado 95,582 2,237,762 2,333,344 4.1%

Connecticut 592,147 2,174,220 2,766,367 21.4%

Delaware 12 416,518 416,530 0.0%

District of Columbia 245 231,470 231,715 0.1%

Florida 243,591 9,429,060 9,672,651 2.5%

Georgia 118,239 4,221,386 4,339,625 2.7%

Hawaii 10 465,304 465,314 0.0%

Idabho 119,024 614,525 733,549 16.2%

Illinois 83,903 5,557,111 5,641,014 1.5%

Indiana 22,103 3,311,080 3,333,183 0.7%

Iowa 21,590 1,072,588 1,094,178 2.0%

Kansas 259,739 1,038,977 1,298,716 20.0%

Kentucky 119,221 2,207,524 2,326,745 5.1%

Lousiana 112 1,359,878 1,359,990 0.0%

Maine 112,104 673,197 785,301 14.3%

Maryland 641 2,573,546 2,574,187 0.0%

Massachusetts 6,613 3,644,426 3,651,039 0.2%

Michigan 29,065 4,665,504 4,694,569 0.6%

Minnesota 15,019 2,482,308 2,497,327 0.6%

Mississippi 101 985,411 985,512 0.0%

Missouri 400,310 2,596,411 2,996,721 13.4%

Montana 739 531,930 532,669 0.1%

North Carolina 7,208 4,521,491 4,528,699 0.2%

North Dakota 10,201 413,665 423,866 2.4%

Nebraska 64,442 885,019 949,461 6.8%

Nevada 17 1,194,001 1,194,018 0.0%

New Hampshire 19,070 755,259 774,329 2.5%

New Jersey 15,502 3,851,148 3,866,650 0.4%

New Mexico 4,708 887,354 892,062 0.5%

New York 6,933 7,988,548 7,995,481 0.1%

Ohio 2,199 6,079,222 6,081,421 0.0%

Oklahoma 138,602 1,788,326 1,926,928 7.2%

Oregon 5,284 1,820,389 1,825,673 0.3%

Pennsylvania 3,176,455 2,879,274 6,055,729 52.5%

Rhode Island 402 484,196 484,598 0.1%

South Carolina 65,726 1,987,174 2,052,900 3.2%

South Dakota 18,192 544,768 562,960 3.2%

Tennessee 110 3,044,306 3,044,416 0.0%

Texas 572,836 12,514,011 13,086,847 4.4%

Utah 239 1,051,350 1,051,589 0.0%

Vermont 1 329,966 329,967 0.0%

Virginia 139,601 3,189,764 3,329,365 4.2%

Washington 41,366 2,967,267 3,008,633 1.4%

West Virginia 30 668,972 669,002 0.0%

Wisconsin 1,199,432 1,782,717 2,982,149 40.2%

Wyoming 89 1,384,782 1,384,871 0.0%
Chapter III – Advanced Metering Penetration 

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31

Uses of Advanced Metering 

Commission staff also asked respondents to the FERC Survey how they used their systems and which 

functions the AMI systems provides them. Specifically, the FERC Survey asked organizations who 

have installed AMI systems to identify which of the following possible AMI features they used: 

• Remotely change metering parameters 

• Outage management 

• Pre-pay metering 

• Remote connect/disconnect 

• Load forecasting 

• Reduce line losses 

• Price responsive demand response 

• Enhanced customer service 

• Asset management, including transformer sizing 

• Premise device/load control interface or capability 

• Interface with water or gas meters 

• Pricing event notification capability 

• Power quality monitoring 

• Tamper detection 

• Other 

Figure III-9 shows the results of this query. The most often reported function was “Enhanced 

customer service,” and the least often reported was “pricing event notification capability.” Other uses 

that received a relatively high percentage of usage were tamper detection and power quality 

monitoring. 

Figure III-9. Reported uses of AMI system by entities that use AMI 

0% 10% 20% 30% 40% 50% 60% 70% 80%

Pricing event notification capability

Interface with water or gas meters

Price responsive DR

Remotely change metering parameters

Premise device - load control interface or capability

Reduce line losses

Asset mgmt, including transformer sizing

Load forecasting 

Outage mgmt

Power quality monitoring

Tamper detection

Enhanced customer service

Yes, Entity Uses Capability

Source: FERC Survey 
Chapter III – Advanced Metering Penetration 

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Survey results on the use of advanced metering for outage detection and management (40 percent) are 

lower than might have been expected from anecdotal industry reports. Anecdotal reports in the 

industry have suggested significant savings from the use of AMI in outage management, especially for 

restoration. This may reflect a recent recognition that meter data management is necessary to build the 

interface between utility outage management systems and AMI. As utilities invest in meter data 

management, the use of AMI for outage management may increase. 

Recent Deployments of AMI Systems 

To supplement the market penetration estimates drawn from the FERC Survey and to review patterns 

in the use of the various AMI types, Commission staff assessed information from recent deployments 

of AMI. There have been a number of contracts signed for fixed network automated meter reading 

and AMI over the past 10 years (see Table III-3 and Figure III-10). System-wide deployments of AMI 

began in 1994 with large fixed RF deployments. The deployment rate for large roll-outs72 continued at 

a steady pace until 2000, when activity dropped off. Deployments increased again in 2006 with the 

PG&E contract for nine million gas and electric meters, and will likely grow in 2007 and 2008.73 

Table III-3. Announced Large AMI Deployments in U.S. 

Utility Commodity AMI type Number Year Started

Kansas City Power & Light (MO) Electric Fixed RF 450,000 1994

Ameren (MO) Electric & Gas Fixed RF 1,400,000 1995

Duquesne Light (PA) Electric Fixed RF 550,000 1995

Xcel Energy (MN) Electric & Gas Fixed RF 1,900,000 1996

Indianapolis Power & Light (IN) Electric Fixed RF 415,000 1997

Puget Sound Energy (WA) Electric & Gas Fixed RF 1,325,000 1997

Virginia Power Electric Fixed RF 450,000 1997

Exelon (PA) Electric & Gas Fixed RF 2,100,000 1999

United Illuminating (CT) Electric Fixed RF 320,000 1999

Wisconsin Public Service (WI) Electric PLC 650,000 1999

Wisconsin Public Service (WI) Gas Fixed RF 200,000 2000

JEA (FL) Electric Fixed RF 450,000 2001

PPL (PA) Electric PLC 1,300,000 2002

WE Energies (WI) Electric & Gas Fixed RF 1,000,000 2002

Bangor Hydro Electric PLC 125,000 2004

Ameren (IL) Electric & Gas Fixed RF 1,000,000 2006

Colorado Springs Electric Fixed RF 400,000 2005

Laclede Gas Fixed RF 650,000 2005

TXU Electric BPL 2,000,000 2005

PG&E (CA) Electric PLC 5,100,000 2006

PG&E (CA) Gas Fixed RF 4,100,000 2006

Hundreds of Small Utilities Electric & Gas Various 5,000,000 2004

Source: UtiliPoint International 

 72 Large-scale deployments involve more than 100,000 meters. 

73 Large utilities (including San Diego Gas and Electric, Portland General Electric, Florida Power and Light, and 

CenterPoint Energy) have issued a number of RFPs within the past six months for advanced metering. Other large utilities 

are likely to go forward with large deployments over the next couple of years. The possible additional deployments are 

shown in Figure III-10 as “Pending” (shown in Orange). 
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Figure III-10. Large AMI deployments 

1994

1996

1998

2000

2002

2004

2006

2008

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

Broadband Over

Power Lines

Power Line

Communications

Fixed RF

Pending

Grand Total

Source: UtiliPoint International 

Figure III-10 illustrates that fixed RF had the majority of the market for system-wide deployments 

through 2002, but power line communications and broadband over power lines emerged as alternatives 

in 2004 and 2005. Two deployments of the advanced fixed RF systems are approaching large 

deployment status: Elster Electricity at Salt River Project (now approaching 75,000 endpoints) and 

Sensus/AMDS at Alabama Power Company (50,000 endpoints). 

Costs and Benefits Associated with Advanced Metering 

Electric utility deployment of advanced metering will need to be cost-effective for the utilities and for 

their ratepayers. This section reviews recent information on the costs and benefits associated with 

advanced metering. 

Costs of Deploying Advanced Metering 

The total capital cost of deploying AMI has not declined significantly even though the AMI and meter 

vendor revenue per meter has gradually declined by approximately 23 percent over the past 10 years. 

The total capital costs of deploying AMI include the hardware costs (meter modules, network 

infrastructure, and network management software for AMI system), as well as installation costs, meter 

data management, project management, and information technology integration costs. Examination of 

data obtained on 10 large AMI deployments over the last decade, suggests that AMI hardware costs 

have decreased during this time period. This trend can be seen in Figure III-11. 
Chapter III – Advanced Metering Penetration 

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Figure III-11. Total AMI capital and hardware costs per meter 

$-

$50.00

$100.00

$150.00

$200.00

$250.00

1994 1996 1998 2000 2002 2004 2006 2008

Hardware Per Meter

Total Capital per Meter

Source: UtiliPoint International

In the late 1990’s, the hardware costs per meter averaged $99.74 By 2005/2006, the average hardware 

cost per meter had decreased to $76. The capital costs of installing the AMI communications 

infrastructure, in contrast, have stayed relatively constant except for the deployment at Jacksonville 

Electric Associates in 2001 (which included water and electric meters), generally bound by $125 per 

meter on the low end and $150 on the high end. Table III-4 below shows the hardware and total 

detailed data on each of the 10 deployments. 

There is considerably more expense and capital investment involved for a successful deployment of 

AMI than metering and AMI system components. Deployment costs include: 

• Project management 

• Installation of meters and network 

• Meter data management 

• Information technology integration costs with meter data management and other systems 

For the AMI deployments where both the hardware costs per meter and the total AMI capital cost per 

meter were available, the hardware costs per meter represented as low as 50 percent and as high as 70 

percent of the total AMI capital costs. A study by Charles River Associates found that hardware costs 

represented only 45 percent of total costs (see Figure III-12 for a breakdown of AMI System Costs). 

 74 All dollar values are nominal dollars. 
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Table III-4. AMI Cost Benchmarks 

Utility Year Meters 

(millions) 

Hardware 

(millions) 

Total 

Capital 

(millions) 

Hardware 

per meter 

Total 

Capital per 

Meter 

DLCo 1996 0.6 $60 - $99.23 - 

Virginia Power 1997 0.5 $44 - $97.78 - 

PREPA 1998 1.3 $130 - $100.00 - 

ENEL 2000 30.0 $2,673 - $89.10 - 

JEA 2001 0.7 - $150 $214.29 

PPL 2002 1.3 $112 $160 $86.15 $123.08 

Bangor Hydro 2004 0.1 $7.50 $15.0 $68.18 $136.36 

TXU 2005 0.3 $19 $38 $75.60 $150.00 

PG&E 2005 9.8 $721 $1,328 $73.57 $135.48 

SDG&E 2006 2.3 $199 $329 $86.43 $143.04 

Source: Utilipoint International 

Figure III-12. AMI System Cost Breakdown 

20%

11%

15%

9%

45%

Endpoint Hardware

Network Hardware

Installation

Project Management

IT

Source: David Prins et. al. (CRA International), “Interval Metering Advanced Communications Study,” August 2005 

Benefits Associated with Advanced Metering 

The deployment of advanced metering creates multiple benefits. These benefits include: 

• Meter reading and customer service 

• Asset management 

• Value added services 

• Outage management 

• Financial 
Chapter III – Advanced Metering Penetration 

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This section presents the benefits that have been identified in the metering literature and from industry 

stakeholders.75

Utility Meter Reading and Customer Service Benefits 

Implementation of advanced metering or AMI can significantly reduce meter reading expenses and 

capital expenditures, and can also increase the accuracy and timeliness of meter reading and billing. 

In particular, eliminating estimated bills is a key driver for investment in automated meter data 

collection systems. Utilities rarely are able to estimate total consumption for a month accurately, even 

using weather and historical monthly consumption data. This is especially true for residential 

customers during vacations and customer moves (e.g., students attending college and returning home). 

Additional benefits include improved employee safety from the reduced need to visit customer 

facilities or enter customer premises, and reduced employee turnover and training needs. 

While many of these same meter readings can be achieved by automated meter reading, advanced 

metering allows additional benefits due to the ability to query the meter frequently, or as needed. For 

example, utilities need to report on sales on a monthly basis. Without actual meter readings, this is an 

estimate, and utilities have found this to be a labor intensive report to produce. With advanced 

metering, utilities can prepare this report using actual meter readings as of midnight on the last day of 

the month. 

Asset Management Benefits 

Advanced metering can provide important information to assist in electric utility asset management. 

First, proper sizing of equipment, based on detailed and accurate data on customer demand and usage 

patterns can be a sizeable benefit for some utilities. In the past, operational managers have been at a 

disadvantage when defending their requests for capital investment in distribution equipment. 

Executive management could easily see the impact on the bottom line of the investment in terms of 

increased debt /capital spending, but operational managers did not always have good tools to 

demonstrate the corresponding value of making distribution capital expenditures. Advanced metering 

provides information that can be used to model the benefits and risks of not investing. In one case, 

Oklahoma Gas and Electric considered raising the load levels on distribution transformers. Using 

estimates for load that distribution transformers carried at peak times, similar to what can be 

developed using the information provided by advanced metering, it was clear to management that 

lowering the load levels on distribution transformers was the more prudent choice. Lowering load 

levels was selected even though it caused the utility to increase capital spending.76 The benefits of 

avoiding failures of distribution transformers outweighed the costs, something the operational 

managers had not been able to show without reliable estimates of peak load on transformers. 

Another key asset management benefit provided by advanced metering is the ability for electric 

utilities to more efficiently monitor and maintain the distribution equipment necessary to reliably 

deliver power to customers. These benefits include theft detection, improving cost allocation across 

the customer base, deferring investment, and predictive maintenance of equipment. 

Other asset management benefits include: 

• Vegetation management 

 75 A recent meeting of the AMI-MDM Working Group, which focuses on meter data management issues associated 

with advanced metering, developed a comprehensive listing of benefits. This list of benefits can be found at 

www.amimdm.com. The discussion in this section draws from the ADM-MDM list. 

76 Patti Harper-Slaboszewicz (UtiliPoint), “Distribution Planning – A Tale of Two Utilities,” November 2005. 
Chapter III – Advanced Metering Penetration 

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37

• Improved information on voltage levels at customer premises 

• Reduced manual testing of a sample of meters through built-in electronic meter selfdiagnostics 

Ability to Offer Value-Added Services 

Advanced metering also provides benefits that are typically not available with manual meter reading 

or with AMR. These additional benefits include new or improved services that utilities can offer to 

customers with advanced metering, including additional rate options, flexible billing cycles, 

benchmarking of energy usage (especially important for commercial customers with similar set-ups in 

multiple locations), aggregation of accounts and/or synchronization of multiple account billing and 

meter reading, web services based on the more timely information provided by advanced metering, 

and bill prediction for large and small customers, including weather forecast data. With timely access 

to data, customer service representatives can also use interval data to more easily explain why bills are 

higher than expected. The interval data will show not only the total usage for each day but also when 

it was used. 

Outage Management Benefits 

Advanced metering can provide outage management benefits if configured appropriately. The most 

important benefit from the implementation of advanced metering in outage management is during 

restoration. After the work crews finish the first round of repairs, utilities can use advanced metering 

on customer premises to check for additional problems before work crews leave the area. This avoids 

needing to recall work crews to fix problems not handled in the first round of repairs, and can allow 

power to be restored faster. 

Another important benefit is to verify an outage before sending a truck to respond to the outage by 

checking for power to customer meters. The problem could be on the customer side of the meter. 

Utilities achieve cost savings by not dispatching a truck unnecessarily, and the customer can begin 

effecting repairs faster if the problem is on their side of the meter. Responding faster to small outages 

is another important benefit, especially in terms of improving customer service and improving 

regulatory relations. Utilities can restore power faster and often during regular hours, and customers 

are not faced with reporting the outage and then waiting for repairs to be made. 

Over time, utilities expect that, as customers learn that the AMI system send information on outages to 

the utility, call center volume during outages will be significantly reduced. When customers do call 

in, utilities will be able to provide a better estimate of repair times. 

Financial Benefits 

Financial benefits accrue not only from utility efficiency gains, but also indirectly from complaints 

and faster service restoration. For example, faster restoration and shorter outages may result in better 

outage metrics, which in turn may impact the earnings of some utilities. Improved cash flow stems 

from reducing the time it takes the utility to produce a bill after the meter is read. Before advanced 

metering, the average time for read-to-bill date is three to five days, and with advanced metering, this 

usually drops to one or two days. 

Benefit Estimates 

A key issue is how to quantify the benefits listed above. According to Gary Fauth and Michael 

Wiebe: 
Chapter III – Advanced Metering Penetration 

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Properly measured, AMR benefits can amount to between $1.35 and $3.00 per 

customer per month, over the useful life of the hardware. In contrast, AMR in many 

situations can cost $1.25 to $1.75 per customer per month, measured over the useful 

life of the hardware and including both capital and operating costs. These cost and 

benefit numbers by themselves produce a positive business case outcome in most 

cases. Business cases for AMR can produce internal rates of return ranging from 15 

to 20% and payback periods of less than six years.77

Utilities have reported significant benefits associated with improved outage management. For 

example, PPL, a large investor owned utility in Pennsylvania, has achieved savings of 10 percent in 

restoration costs after large outages.78 PPL also reported that it has reduced the number of estimated 

bills from an average of four to six percent of the total number of bills it processes to less than one 

percent. Ameren has achieved savings of $2 million annually by using its AMI system to measure the 

load on its distribution transformers at the system peak, and by reducing the size and inventory of 

transformers.79 

Bangor Hydro’s AMI system saved time and money by eliminating a problem where customers would 

call and report an outage before traveling to remote fishing camps to avoid having to wait for service 

crews should there be an outage. Now, if customers call, the utility can immediately verify power to 

the meter before the customer leaves home. In another example, PG&E has estimated it makes 48,000 

truck rolls each year for single no-outage calls, and could save $4.3 million annually with AMI.80

Data from PG&E’s AMI business case suggests that savings associated with meter reading are only a 

part of the benefits that can be achieved with AMI. PG&E has estimated that 46 percent of the 

benefits that they estimated in their business case were unrelated to meter reading. 

Current Issues Associated with Advanced Metering 

While there are benefits to advanced metering and AMI, there is not universal attraction to its 

implementation. What follows is an identification and discussion of issues associated with advanced 

metering and AMI. 

AMI specifications 

Most requests for proposals (RFPs) from electric utilities now include a requirement for delivering 

interval data, at least hourly, for all meters connected to the network on a daily basis. The requirement 

for interval data for all customers is relatively new, and reflects the increased functionality and 

performance of AMI products on the market. However, billing and settlement requirements in 

organized wholesale markets may influence what utilities specify in their RFPs. If wholesale 

settlement is based on 15 minute interval profiles, utilities may be more likely to ask for 15 minute 

intervals for all customers. While the need to support time-based rates may prompt regulators to 

support an investment in AMI, the requirements for AMI are usually based on other considerations, 

 77 Gary Fauth and Michael Wiebe, “Fixed-Network AMR: Lessons for Building the Best Business Case”, AMRA 

newsletter, September 2004, 5. 

78 David Prins, et al. (CRA), “Interval Metering Advanced Communications Study,” August 2005, 24. 

79 Prins, et al., 25. 

80 Prins, et al., 24. 
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such as operational efficiencies and wholesale settlement. Consequently, consistent AMI 

specifications may be difficult to achieve in the near-term. 

Advanced Metering and Price Responsive Demand Response Networks 

With advanced metering, utilities can offer customers a variety of time-based rates, either charging 

higher prices when wholesale prices are high or offering rebates when customers reduce energy 

consumption during times of high prices, often called critical peak periods. AMI provides the 

information necessary to support the billing process and gives customers timely updates on their 

energy use and bills. 

An open question that is being discussed, is whether the AMI system should be used to provide price 

signals or notification of system emergencies. In some cases, the AMI system itself will likely provide 

the communication backbone to transmit signals to the end-use controllers, and in other cases, other 

networks will be used. 

If the AMI system is selected to transmit the signal to an appliance, the signal will not necessarily 

travel through the meter. An appliance such as a load control device may be designed to be treated as 

another node on the system, and communicate independently of the meter. Alternatively, the signal 

may be relayed to the load control device through another node on the system, such as the data 

collector or tower. 

A number of utilities use networks other than AMI systems to communicate with smart thermostats81

(see Figure III-13 for an example smart thermostat) and other load control devices, such as paging or 

FM radio. The California Energy Commission (CEC) is currently considering revising the building 

codes to require smart thermostats. As part of this proposal, the CEC is proposing sending a one-way 

broadcast signal using FM radio to smart thermostats, but the three investor-owned utilities in 

California did not support this concept as the only communication option. Rather, the utilities 

indicated that they wanted to use their AMI systems, once installed, for controlling these devices.82

Figure III-13. Example of a Smart Thermostat 

Source: Comverge 

 81 The temperature settings on smart thermostats, also known as programmable communicating thermostats (PCT), 

can be remotely adjusted through signals from a central controller or by a customer. 

82 Committee Workshop, California Energy Resources Conservation and Development Commission, Feb. 13, 

2006. 
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Other jurisdictions are having similar discussions, and the industry has not yet decided on a consistent 

approach for integrating smart thermostats and dedicated customer display devices into AMI. For 

regions with significant retail activity, the picture is more complex because electric distribution 

companies will likely be the owners of the AMI systems, but they may not necessarily be the entities 

offering demand response programs. This lack of consistency may complicate future deployments of 

equipment and procedues until standard approaches are adopted. 

Providing Timely Information to Customers 

The provision of timely, useful information to residential and commercial customers can assist 

customers in responding to time-based rates and to otherwise help in managing their energy costs. 

However, the degree to which customers use this information and the vehicle for providing the 

information is at issue. 

For customers with central air conditioning or heating, the trend is to use the smart thermostat as a 

customer display device to provide information on the current price in effect, whether a critical peak 

period is in effect, and other information specific to controlling the temperature within the home.83 

The example smart thermostat in Figure III-13 can provide price information. 

There is also interest in providing customers with daily bill updates which could also be displayed on 

smart thermostats.84 The thermostat vendors have modified the design of thermostats to accommodate 

price responsive demand response programs, providing a large screen on the smart thermostat that can 

display a variety of information for customers. 

For those without central air conditioning or heating, what information to provide to customers is still 

being explored, as well has how to provide the information. Utilities that have posted usage 

information on websites have reported that few customers take advantage of the service, and of those 

that do, most visit the site only once or twice. Customers have indicated in several studies that they 

prefer to receive information about their energy usage with their bill.85 Utilities are also considering 

providing or offering customers dedicated in-home display devices. Utilities will likely continue to 

post information on line for those interested, and over time, it is expected that the industry will learn 

what information customers find useful to manage their energy bills.86

Results from the FERC Survey suggest that only a tiny fraction of U.S. electricity customers receive 

interval usage information by any means, and the smallest proportion can view their usage via the 

AMI system. The FERC Survey asked how many customers had access to hourly interval data and the 

ways in which they receive that information. Figure III-14 displays the survey results. 760 entities 

responded to this question while 310 entities said that at least one customer receives interval usage 

 83 The CEC is pursuing this approach in California and is currently considering revising building standards to 

require a PCT wherever a setback thermostat is currently required. Using the PCT as a display device avoids the need for a 

dedicated in-home display device, and the customers already associate the PCT with energy. 

84 Providing customers with a daily bill update is part of the design of the SmartPowerDC program, a new dynamic 

pricing pilot in the District of Columbia. The SmartPowerDC program is managed by the Smart Meter Pilot Project 

(SMPPI). SMPPI is a non-profit corporation with a board membership of Pepco, the DC commission, two consumer 

advocacy groups, and the meter readers union. 

85 Idaho Power reported these findings based on their dynamic pricing pilot in 2006. 

86 Vendors are developing in-home display devices in response to utility interest. Some are similar to PCTs except 

that the device is not also a thermostat. Another version is to glow different colors depending on the current price. See

Committee Workshop Before the California Energy Resources Conservation and Development Commission, In the Matter of 

Systems Integration Framework Programmable Communicating Thermostat (PCT), Feb. 16, 2006. 
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Figure III-14. Number of customers receiving interval usage information 

by customer class and source of information 

0

20,000

40,000

60,000

80,000

100,000

120,000

Via the internet On their bills Via the AMI

network

Source of Information

Number of Customer

Other

Transportation

Industrial

Commercial

Residential

Source: FERC Survey 

information. Only about 226,000 nationwide customers receive interval usage information via at least 

one source: internet, bills, and AMI. 

There is also considerable discussion of how to provide customers with useful information from the 

customers’ point of view rather than the utility’s point of view. Was their usage significantly higher 

yesterday, even accounting for weather? Does their energy usage change more in response to weather 

than their neighbors? Would they be better off on a different rate schedule? In interviews with 

participants in the California Pricing Pilot program, customers evaluated the program differently from 

utilities. From the customer perspective, the program was successful if the customer saved money, or 

if they had the opportunity to save money, with the program.87 There is agreement among consumer 

advocates and regulators that customers understand time and money, and that giving customers the 

opportunity to receive information to better help them in managing their energy bills is a good thing.88 

Interoperability and Standard Interfaces 

Interoperability refers to the ability of suppliers to design and build products to meet standards 

established by an industry group. From 1996 to 1998, the American National Standards Institute 

(ANSI) issued new standards for meter communications and meter data storage developed in 

collaboration with the Automated Meter Reading Association (AMRA), Canadian standards bodies, 

numerous utilities, all major meter manufacturers, and others over a five year period. The standards 

released as a result of that effort were:89

 87 Craig Boice, “What Drives the Response in Demand Response”, Boice Dunham Group, April 13, 2005. 

88 This is one of the motivations of the SmartPowerDC program. 

89 Ted York, “Exploring ANSI Standards in Meter Communications,” Electricity Today, March 2000. 
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• C12.18 - 1996 Protocol Specification for ANSI Type 2 Optical Port 

o For reading a meter using infrared optical port when data stored in tables as specified 

in C12.19 

• C12.19 - 1997 Utility Industry End Device Tables 

o This standard defines a set of flexible data structures for use in metering products, 

including the option of including vendor defined tables 

• ANSI C12.21-1998 Protocol Specification for Telephone Modem Communication 

o This extends the C12.18 and C12.19 to telephone modem communications 

The next step, ANSI C12.22 - Protocol Specification for Interfacing to Data Communications 

Networks, covers network communications, which is pertinent to communicating with meters over a 

network as opposed to point-to-point communications.90 The adoption of the new standard (expected 

by the end of the year) and the recent announcement by Itron that its new AMI system will conform to 

the standard will put pressure on other AMI vendors to adapt their systems to conform as well. For the 

moment, even though some utilities have expressed an interest in open standards, which is consistent 

with C12.22, it has not been a major factor in recent AMI selections. That is likely to change, as 

evidenced by SCE and SDG&E. SCE has listed open protocols to be a requirement of AMI,91 and of 

interest by SDG&E in their latest filing on AMI. However, SDG&E also noted that “Any new AMI 

technologies or new market product offerings would need to provide SDG&E customers with 

additional value and functionality or reduced costs such that the net incremental benefits from the 

potential new technology or offering exceeds the cost to convert or change from the selected SDG&E 

AMI solution set(s).”92 This suggests that SDG&E would evaluate a new product with open standards 

to see if the value of the new product exceeds the cost of using the new product. For SDG&E, open 

standards is a feature of AMI, whereas for SCE it is a requirement. These two utilities illustrate the 

different attitudes toward open standards. 

There is a clear consensus on the need for standard interfaces between systems, such as between the 

host AMI system and MDM, and between MDM and other utility data systems. This would also apply 

to interfaces with DR networks and systems. 93 

Security 

Utilities need to take reasonable precautions to protect customer privacy, and to maintain the security 

of the grid. Monthly meter reads are not regarded as particularly valuable other than for generating a 

customer bill. Hourly meter reads, especially when viewed over a long time span, can provide a 

significant amount of information about customers. Interval data stored to provide a history of energy 

use must be secure from unauthorized use. 

 90 Point-to-point communications includes using a hand-held device to read the meter, covered in ANSI c12.18, or 

telephone modem communications, covered in ANSI c12.21. Network communications involve communications of one-tomany, or many-to-many, as are involved with advanced metering. 

91 “Advanced Metering Infrastructure -- Frequently asked questions,” and “Why is SCE interested in an AMI 

solution using open standards and interoperability,” available at http://www.sce.com/PowerandEnvironment/ami/faqs/. 

92 Chapter 8 Summary of AMI Implementation and Operations, Prepared Supplemental, Consolidating, 

Superseding and Replacement Testimony of Ted Reguly, San Diego Gas & Electric Company before The Public Utilities 

Commission of the State of California, March 28, 2006. 

93 EnerNex Corporation, “Advanced Metering and Demand Responsive Infrastructure: A Summary of the 

PIER/CEC Reference Design, Related Research and Key Findings Draft,” prepared for California Energy Commission, June 

1, 2005. 
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There is disagreement regarding the level of security that is required when meter data is transmitted 

from the endpoint to the AMI host system. The discussions that have taken place in various industry 

groups94 on standard interfaces within the AMI system have addressed security requirements, 

including discussions on encryption, verification of successful communication, and verification of 

identity of devices. The overall goal is to ensure that only authorized devices provide and receive 

meter data, and that unauthorized devices are not able to provide or receive meter data. 95 

Costs and Benefits to Include in Business Case Analyses 

Recent examinations of the business case for advanced metering have used a wide variety of costs and 

benefits in their assessments.96 For example, some business cases include demand response as an 

explicit benefit, while others do not. These differences make it difficult for retail rate regulators to 

compare proposals and deployments across electric utilities under their review, and for electric utilities 

to comprehensively judge whether they should deploy advanced metering.97 

 94 Various industry groups discussing reference designs, standards, and best practices such as OpenAMI, 

UtilityAMI, IntelliGrid, and AMI MDM have discussed security of customer meter data. 

95 Paul DeMartini (SCE), FERC Technical Conference, transcript, 89:10-90:13, 109:12-110:9; and Chris King, 

(eMeter), transcript, 106:22-107:5. 

96 See Chapter 2, “AMI Business Vision, Policy and Methodology”, Prepared Supplemental, Consolidating, 

Superseding and Replacement Testimony of Edward Fong, San Diego Gas & Electric Company, before The Public Utilities 

Commission of the State of California, Mar. 28, 2006, TR-7. SDG&E included DR benefits in their business case. See also 

“Section I Advanced Metering Infrastructure Project A.05-06-028 - Supplemental Testimony Pacific Gas and Electric 

Company Chapter 1 AMI Project and Project Management,” Application 05-06-028, filed October 13, 2005 with the 

California Public Utilities Commission. PG&E did not explicitly include DR benefits in their business case filing, but 

estimated that DR benefits would provide enough benefits to make the AMI investment worthwhile. 

97 Recent work by McKinsey & Company, Inc. with vendors, utilities, consultants and regulators has resulted in a 

consensus, pro forma modeling platform for business case development. This business case model is still under 

development, and will be made public at energydelivery.mckinsey.com. 
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Chapter IV – Existing Demand Response and Time-Based Rates 

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Chapter IV. Existing Demand Response Programs and 

Time-Based Rates 

This chapter addresses the second area, in EPAct Section 1252(e)(3), that Congress directed the 

Commission to consider: 

(B) existing demand response programs and time-based rate programs. 

The discussion within this chapter reviews the various demand response programs and time-based rate 

options currently in existence. In addition to reviewing these programs, the results of the first-of-itskind, comprehensive FERC Demand Response and Advanced Metering Survey98 (FERC Survey) were 

used to determine how prevalent these programs and rates are nationally and regionally. The results of 

this survey suggest that the use of demand response is not widespread. Only approximately five 

percent of customers are on some form of rate-based or incentive-based program. The most common 

demand response programs offered are direct load control programs, interruptible/curtailable tariffs, 

and time-of-use rates. 

This chapter is organized into six sections and builds on the discussion of demand response and timebased rate programs included in Chapter II. These sections include: 

• Discussion of incentive-based demand programs 

• Discussion of time-based demand response programs 

• Results from FERC Survey on the use of demand response 

• Motivations for industry and customer interest in demand response programs 

• Issues and challenges associated with implementing demand response programs 

• Demand response activities at the state, regional, and federal level 

Incentive-Based Demand Response Programs 

The first form of demand response includes an inducement or incentive for customer participation, 

instead of the direct price signals associated with time-based rates. Because they do not rely on direct 

responses of customers to prices, which is difficult to measure or predict, incentive-based demand 

response programs provide a more active tool for load-serving entities, electric utilities, or grid 

operators to manage their costs and maintain reliability. 

The types of incentive-based programs that exist include: 

• Direct load control 

• Interruptible/curtailable rates 

• Demand bidding/buyback programs 

• Emergency demand response programs 

• Capacity market programs 

• Ancillary-service market programs 

 98 See Appendix F for a description of the FERC Survey. 
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This section reviews these programs, and explores implementation experience with these programs. 

Direct Load Control 

Direct load control (DLC) programs refer to programs in which a utility or system operator remotely 

shuts down or cycles a customer’s electrical equipment on short notice to address system or local 

reliability contingencies in exchange for an incentive payment or bill credit. Operation of DLC 

typically occurs during the times of system peak demand. However, DLC is also operated when 

economic to avoid high on-peak electricity purchases. 

DLC has been in operation for at least two decades. A variety of utilities developed and deployed 

large programs in the late 1960s,99 and expanded those programs significantly during the 1980s and 

1990s. By 1985, 175 residential customer direct-load control projects and 99 commercial projects 

were in place at electric utilities.100 The FERC Survey found that 234 utilities reported direct loadcontrol programs. Florida Power & Light has implemented the largest program, with 740,570 

customers. 

The most common form of DLC is a program that cycles the operation of appliances such as airconditioners or water heaters. In these programs, a one-way remote switch (also known as a digital 

control receiver) is connected to the condensing unit of an air conditioner or to the immersion element 

in a water heater. By remotely switching off the load at the appliance, peak loads can be reduced. 

Although the actual reductions vary by size of the appliance, customer usage patterns, and climate, the 

demand reductions for each air conditioner is about 1 kW and for water heaters about 0.6 kW. The 

operation of the switch is controlled through radio signals (for older systems) or through digital 

paging. Depending on the duty cycle selected, the switch turns off the condensing unit or element for 

the full duration of an event or for various fractions of an hour (e.g., a common duty cycle is 15 

minutes off during an hour). DLC programs also typically limit the number of times or hours that the 

customer’s appliance can be turned off per year or season. 

In recent years, remote switches have become more sophisticated through new technologies. Virtually 

all of the new switches are individually addressable, meaning that individual switches can be 

controlled independently. This allows more targeted reductions to address localized problems. 

Software upgrades can now be done wirelessly and communication with switches can be conducted 

using public paging networks instead of building and maintaining expensive communications 

networks. Most switches also contain multiple relays so that air conditioners and water heaters can be 

controlled by the same switch with independent control strategies for each relay. 

In addition, remote control of individual appliances is being supplanted by remote control of smart, or 

programmable, communicating thermostats in recently implemented programs. DLC programs that 

use these smart thermostats, such the Long Island Power Authority’s LIPA Edge program, remotely 

adjust the temperature settings on the thermostats. During the summer the utility can remotely adjust 

the temperature upward to reduce demand. After an event, the temperature setting is readjusted to the 

pre-event, customer-selected level. Some smart thermostat programs also provide the customer the 

ability to change the thermostat settings through the Internet. 

 99 According to the EPRI, Detroit Edison was the first utility to implement a load control program in 1968, EPRI, 

The Demand-Side Management Information Directory, EPRI EM-4326, 1985. 

100 EPRI EM-4326, 3-2. 
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While DLC has been an important demand response resource for many years, and while several utilities 

have recently implemented or increased the size of programs, several key utilities have been mothballing 

or phasing out their programs, especially in restructured states. For example, since load management was 

designated a competitive service in the Texas restructuring act, CenterPoint Energy Houston Electric’s air 

conditioner cycling program was sold and eventually shut down. Similarly, Pepco suspended its 

Kilowatchers Club air conditioner cycling program after it sold its generation assets when Maryland’s 

electric sector was restructured. There is also concern that the equipment in older programs operated by 

many utilities is aging and degrading.101 

Interruptible/Curtailable Rates 

Customers on interruptible/curtailable service rates/tariffs receive a rate discount or bill credit in 

exchange for agreeing to reduce load during system contingencies. If customers do not curtail, they 

can be penalized. Interruptible/curtailable tariffs differ from the emergency demand response and 

capacity-program alternatives because they are typically offered by an electric utility or load-serving 

entity, and the utility/load serving entity (LSE) has the ability to implement the program when 

necessary. 

Interruptible/curtailable tariffs are generally filed tariffs with regulatory commissions and offered to a 

utility’s largest customers. Typical minimum customer sizes to be eligible for interruptible/curtailable 

tariffs range from 200 kW for the base interruptible program in California to 3 MW in American 

Electric Power’s (AEP) Ohio service territory. Customers on these rates agree to either curtail a 

specific block of electric load or curtail their consumption to a pre-specified level. Customers on these 

rates typically must curtail within 30 to 60 minutes of being notified by the utility. The number of 

times or hours that a utility can call interruptions is capped (e.g., AEP-Ohio will not call its 

interruptible/curtailable customers more than 50 hours during any season).102 In exchange for the 

obligation to curtail load, interruptible/curtailable tariff customers receive either discounted rates or a 

bill credit when they curtail. 

Interruptible programs are also not for all customers. In particular, customers with 24 hour-a-day, 

seven-days-a-week operations or continuous processes (e.g., silicon chip production) are not good 

candidates. Similarly, schools, hospitals, and other customers that have an obligation to continue 

providing service are also not good candidates. 

While interruptible/curtailable tariffs have been in place for decades, there is concern amongst 

resource planners about whether interruptible/curtailable tariffs provide a reliable and sustainable 

resource. The number of customers taking interruptible/curtailable tariffs from utilities has dropped in 

the last decade.103 The cause for this drop is a combination of the impacts of restructuring, reductions 

in price discounts associated with interruptible/curtailable tariffs due to the current excess capacity in 

much of the country, and customer departure because of perceived risk. 

 101 Frank Magnotti, Comverge, presentation to MADRI Workshop, June 2006, 3. 

102 During that winter of 2000-2001, as of January 22, 2001, PG&E had exhausted its interruptible program, having 

called upon 140 customers for 100 hours each. Jane M. Clemmensen, “Californians Facing a Power-Strapped Summer,” 

EC&M, April 1, 2001. 

103 See the experience in California -- Charles A. Goldman, Joseph H. Eto, and Galen L. Barbose, California 

Customer Load Reductions during the Electricity Crisis: Did they Help to Keep the Lights On?, Lawrence Berkeley National 

Laboratory: LBNL-49733, May 2002. 
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Emergency Demand Response Programs 

Emergency demand response programs have developed in the last decade. Emergency demand 

response programs provide incentive payments104 to customers for reducing their loads during 

reliability-triggered events, but curtailment is voluntary.105 Customers can choose to forgo the 

payment and not curtail when notified. If customers do not curtail consumption, they are not 

penalized. The level of the payment is typically specified beforehand. 

While emergency programs are offered by electric utilities, these programs are most closely associated 

with their use at Independent System Operators/Regional Transmission Organizations (ISO/RTO). In 

particular, the Emergency Demand Response Program (EDRP) at the New York Independent System 

Operator (NYISO) has been successful in achieving a high level of participation, and operation of the 

EDRP has provided a key resource during periods of reserve shortage in New York over the last 

several years. Figure IV-1 portrays the importance of the EDRP during a reserve shortage that 

occurred during July 2002. During this event, the NYISO was concerned about the high peak 

demands and real-time price spikes on July 29, 2002. Based on a forecast of similar or hotter weather 

on July 30, NYISO operated its EDRP and capacity program. The combined impact of these two 

programs significantly reduced peak demand and reduced the real-time price during July 30. 

Figure IV-1. Impact of NYISO emergency demand response during July 

2002 

Source: David Patton, Potomac Economics 

The voluntary nature of emergency demand response programs does have implications for its use in 

grid operation and planning. Since there is no contractual obligation to curtail, system operators 

 104 Typical payments are $350/MWh or $500/MWh of curtailed demand. 

105 Utilities have requested voluntary curtailments from customers during system emergencies in the past, but did 

not pay customers for these curtailments. 
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cannot accurately forecast how much load curtailment will occur when the program is activated. 

Consequently, participants in these programs do not receive capacity payments. 

Capacity-Market Programs 

In capacity-market programs, customers commit to providing pre-specified load reductions when 

system contingencies arise, and are subject to penalties if they do not curtail when directed. Capacitymarket programs can be viewed as a form of insurance. In exchange for being obligated to curtail load 

when directed, participants receive guaranteed payments (i.e., insurance premiums). Just like with 

insurance, in some years load curtailments will be not be called, even though participants are paid to 

be on call. Capacity market programs are typically offered by wholesale market providers such as 

ISOs/RTOs that operate installed capacity (ICAP) markets, and are the organized market analog of 

interruptible/curtailable tariffs. 

In addition to agreeing to the obligation to curtail, capacity-market program eligibility is based on a 

demonstration that the reductions are sustainable and achievable. For example, the requirements to 

receive capacity payments in NYISO’s Special Case Resources program are: minimum load 

reductions of 100 kW, minimum four-hour reduction, two-hour notification, and to be subject to one 

test or audit per capability period.106 These requirements are designed to ensure that the reductions 

can be counted upon when they are called. LSEs that have programs or offerings that meet the 

eligibility requirements can receive capacity credits or count the capacity toward ICAP requirements. 

ISO/RTO capacity programs have been important resources in recent years. NYISO operated the 

Special Case Resources program during the July 30, 2002, reserve shortage event (displayed in Figure 

IV-1), and relied on Special Case Resources to help restore power after the August 14, 2003, blackout. 

The ISO New England (ISO-NE) relied upon its capacity program assets to forestall rolling blackouts 

in southwest Connecticut during the summer 2005 heat wave. The PJM Interconnection (PJM) relied 

on demand response assets in its Active Load Management program in the Baltimore-Washington 

region during the same heat wave. 

Many curtailment service providers (CSPs) and customers prefer these programs because they provide 

guaranteed payments, instead of the prospect of uncertain payments. Grid operators like the capacity 

programs because they represent a firm resource that can be implemented quickly.107 The level of the 

capacity payments that have been offered in NYISO and ISO-NE (e.g., $14/kW-month in the 2005-06 

ISO-NE Winter Supplemental Program) have contributed to increased customer interest.108

Demand Bidding/Buyback Programs 

One of the newest types of incentive-based demand response programs is the demand bidding/buyback 

program. Demand bidding/buyback programs encourage large customers to offer to provide load 

reductions at a price at which they are willing to be curtailed, or to identify how much load they would 

 106 NYISO, Installed Capacity Manual, section 4.12. 

107 For example, in anticipation of a cold winter and natural gas shortages in New England, ISO-NE implemented a 

winter supplemental capacity program in December 2005. Curtailment service providers were able to enroll more than 333 

MW of new demand-response capacity by January 18, 2006. http://www.isone.com/committees/comm_wkgrps/mrkts_comm/dr_wkgrp/mtrls/2006/feb12006/winter_supplemental_program_update_02-

01-2006.ppt 108 See http://www.iso-ne.com/genrtion_resrcs/dr/sp_proj/wntr/wsp_factsheet_120105.pdf. In areas such as PJM 

where the value of capacity is lower, the applicable capacity program has not been as successful. 
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be willing to curtail at posted prices. These demand-bidding programs provide a means to elicit priceresponsiveness when prices begin to increase. Both vertically integrated utilities and ISOs/RTOs 

operate these programs. If customer bids are cheaper than alternative supply options or bids, the load 

curtailments are dispatched and customers are obligated to curtail their consumption. These programs 

are attractive to many customers because they allow the customer to stay on fixed rates, but receive 

higher payments for their load reductions when wholesale prices are high. Customers, who are not on 

time-based rates, can use the demand-bidding programs to receive value for their reductions. 

Otherwise, these customers are on fixed retail rates. 

The most well-known forms of demand-bidding programs are operated by the ISOs. There are two 

forms of these programs. The first incorporates demand bids directly into the optimization and 

scheduling process. In programs such as NYISO’s Day-Ahead Demand Response Program (DADRP), 

customers typically bid a price at which they would be willing to curtail their load and the level of 

curtailment in MW on a day-ahead basis. If these bids are selected for operation during the securityconstrained dispatch process, then customers must execute the curtailment the next day. If they do not 

reduce their load, they are subject to a penalty. In the second form of demand bidding, the customer 

acts as price-taker. A good example of this program is the Real-Time Price Response Program at the 

ISO-NE. When participants in this program reduce consumption when notified, they receive the 

market-clearing price, whatever it may be, as payment. 

The ISOs have suggested that demand-bidding programs are transitional programs that will be 

supplanted by retail pricing that reflects and signals wholesale prices. The stated goal of the PJM 

Economic Program is to “provide a program offering that will help in the transition to an eventual 

permanent market structure whereby customers do not require subsidies to participate but where 

customers see and react to market signals or where customers enter into contracts with intermediaries 

who see and react to market signals on their behalf.”109 

Electric utilities also operate demand-bidding programs. While several of these programs (e.g., Con 

Edison’s Day Ahead Demand Reduction Program) are designed to aggregate customers for 

participation in ISO demand-bidding programs, several utilities operate these programs to meet their 

own resource needs. For example, WE Energies has operated the Power Market Incentives program 

for several years. In this program, the utility identifies how much it is willing to pay for load 

curtailments. Participating customers respond to this request and if they are accepted they are 

obligated to reduce their consumption. 

Nevertheless, operation of these demand bidding/buyback programs has been the subject of 

controversy, particularly over the issue of who is responsible for the costs associated with successful 

bids. A 2002 National Association of Regulatory Utility Commissioners (NARUC) report examined 

this controversy and concluded that there was no consensus on the issue and additional effort would be 

needed to examine the issue.110 The issue is still active in 2006, particularly in PJM, where 

discussions continue to determine the size of the incentive provided in PJM’s Economic Program. For 

example, in a recent case, AEP asserted that “while, in certain circumstances, incentives may be 

effective to launch a program, the continued use of economic incentives for a permanent program is 

inappropriate. This issue needs to be addressed now rather than ignored in order to avoid a program 

 109 PJM, Market Monitoring Unit, 2004 State of the Market, March 8, 2005, 87. 

110 David Kathan, Policy and Technical Issues Associated with ISO Demand Response Programs, prepared for 

NARUC, 2002. 
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that cannot stand on its own merits.”111 PJM intends to complete these stakeholder discussions within 

the year. 

Ancillary Services 

The final type of incentive-based demand response is ancillary-service market programs. Ancillaryservices programs allow customers to bid load curtailments in ISO/RTO markets as operating reserves. 

If their bids are accepted, they are paid the market price for committing to be on standby. If their load 

curtailments are needed, they are called by the ISO/RTO, and may be paid the spot market energy 

price.112 

In order to participate in ancillary-service markets, customers must be able to adjust load quickly when 

a reliability event occurs. The response duration depends on the nature of the event and the type of 

reserve being supplied, but is typically provided in minutes rather than the hours required when peak 

shaving or responding to price signals. There is typically a higher minimum size for reductions and 

customers are required to install advanced real-time telemetry. These short timeframes and program 

requirements limit the type of resources that can participate. These resources could include large 

industrial processes that can be safely curtailed quickly without harm to equipment, such as air 

products or electric-arc steel furnaces, large water pumping load, or remote automatic control of 

appliances such as air conditioners.113

At present, only the CAISO and ERCOT allow a limited amount of demand response to participate in 

their ancillary-services markets. The Participating Load Program at the CAISO allows qualifying 

loads to bid directly into the CAISO non-spin and replacement reserve and supplemental energy 

markets. At present the primary resource in the Participating Load Program is the large water pumps 

operated by the California Department of Water Resources. The Loads Acting as a Resource (LaaR) 

program in ERCOT currently provides more than 1,800 MW of responsive reserves through automatic 

under frequency relays. In order to qualify as a LaaR, the load, breaker status, and relay status must 

have real-time telemetry to ERCOT. 

PJM, ISO-NE, and NYISO are in various stages of the development of allowing demand response to 

participate in ancillary-service markets. While ISO-NE and NYISO are still in the process of 

implementing the software and optimization changes necessary to allow demand to provide reserves, 

PJM began allowing demand response to provide synchronized reserves on May 1, 2006. 

Time-Based Rate Programs 

The second form of demand response is time-based rate programs. Historically, utilities offered small, 

or low-volume, commercial and residential customers a flat rate based on their average cost of serving 

that customer class. These flat rates were developed based on historical regulatory principles of rate 

design that were originally articulated by noted utility rate expert, James Bonbright. According to 

Bonbright, rates should be fair, simple, acceptable, effective, equitable, nondiscriminatory, and 

 111 AEP, comments filed in Docket ER06-406, January 18, 2006. 

112 The role of demand response resources in providing ancillary services is discussed in greater detail in Chapter 

VI. 

113 See Brendan J. Kirby, Spinning Reserve From Responsive Loads, Oak Ridge National Laboratory: ORNL/TM2003/19, March 2003, for a discussion of how residential direct load control programs are capable of meeting 10-minute 

operating reserve rules. 
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efficient.114 The regulatory process balances these principles, which reflect the competing interests of 

customers, utilities, and social justice.115 

Utilities or other LSEs buy the power to serve these customers through a combination of long-term 

contracts, ownership of generating plants, or purchases on the spot wholesale markets (based on dayahead or day-of, or real-time, electricity prices). Since prices of electricity have locational and/or 

time-based differences, an average price for all customers needs to build in a risk premium for the 

supplier, who bears the risk of price volatility in wholesale markets.116

Economists and policy-makers increasingly have been arguing in favor of time-based rates (also known 

as dynamic pricing) for retail customers, a practice that can link wholesale and retail markets. The 

primary objective of incorporating time-based rates in retail electric markets is to send price signals to 

customers that reflect the underlying costs of production. By exposing at least some customers to prices 

based on these marginal production costs, resources can be allocated more efficiently.117 Furthermore, 

price-based demand response can be used by retail providers in both restructured and non-restructured 

states to reduce or shape customer demand to balance electricity use and overall costs. Alternatively, 

flat electricity prices based on average costs, according to the U.S. Department of Energy (DOE), can 

lead customers to “over-consume – relative to an optimally efficient system in hours when electricity 

prices are higher than the average rates, and under-consume in hours when the cost of producing 

electricity is lower than average rates.”118 Basing customer rates on wholesale prices also has the benefit 

of increasing price response during periods of scarcity and high wholesale prices, which can help 

moderate generator market power. 

Rates and pricing that are considered time-based include time-of-use (TOU) rates, critical peak pricing 

(CPP), and real-time pricing (RTP). These programs expose customers to varying levels of price 

exposure – the least with TOU and the most with RTP. Figure IV-2 illustrates the type of hourly price 

variation customers would face under the different time-based rates. 

Each of these tariff types is described in greater detail below, using current program examples and 

issues raised by each type. 

 114 James C. Bonbright, Albert L. Danielsen, David R. Kamerschen, Principles of Public Utility Rates, 2nd ed. 

(Arlington, VA: Public Utilities Reports, 1988). 

115 Bernie Neenan, “Focusing on Issues of Rate Design,” Utilipoint IssueAlert, March 10, 2006; and Frederick 

Weston, “Dynamic Pricing: Options and Policies,” white paper for MADRI regulatory subgroup, November 2005, 1. 

116 Eric Hirst, “The Financial and Physical Insurance Benefits of Price-Responsive Demand,” The Electricity 

Journal 15 #4 (2002), 66-73. 

117 There is a substantial literature on setting rates based on marginal costs in the electric sector. See, for example, 

M. Crew and P. Kleindorfer. Public Utility Economics (New York: St. Martin’s Press, 1979, and B. Mitchell, W. Manning, 

and J. Paul Acton. Peak-Load Pricing (Cambridge: Ballinger, 1978). Other papers suggest that setting rates based on 

marginal costs will result in a misallocation of resources (see S. Borenstein, “The Long-Run Efficiency of Real-Time 

Pricing,” The Energy Journal 26 #3 (2005)). Nevertheless, the literature also indicates that marginal cost pricing may result 

in a revenue shortfall or excess, and standard rate-making practice is to require an adjustment (presumably to an inelastic 

component) to reconcile with embedded cost-of-service. Various rate structures to accomplish marginal-cost pricing include 

two-part tariffs (see W. Kip Viscusi, John M. Vernon and Joseph E. Harrington. Economics of Regulation and Antitrust, 3rd

ed. (Cambridge: MIT Press, 2000)) and allocation of shortfalls to rate classes. 

118 DOE February 2006 EPAct Report, 7. 
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53

Figure IV-2: Time-based pricing hourly variations 

0

10

20

30

40

50

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 of the day

Price (cents/kWh)

Critical Peak Critical Peak

Pricing

0

10

20

30

40

50

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 of the day

Price (cents/kWh)

On-Peak

Time-of-Use

Pricing

Time-of-Use (TOU) Pricing: 

These daily energy or energy and 

demand rates are differentiated by 

peak and off-peak (and possibly 

shoulder) periods. 

Critical Peak Pricing (CPP): 

CPP is an overlay on either TOU 

or flat pricing. CPP uses real-time 

prices at times of extreme system 

peak. CPP is restricted to a small 

number of hours per year, is much 

higher than a normal peak price, 

and its timing is unknown ahead 

of being called. 

Real-Time Pricing: 

RTP links hourly prices to hourly 

changes in the day-of (real-time) 

or day-ahead cost of power. One 

option is ‘one-part’ pricing, in 

which all usage is priced at the 

hourly, or spot price. A second 

approach is ‘two-part’ pricing. 

0

10

20

30

40

50

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 of the day

Price (cents/kWh)

Real-Time

Pricing

Source: Weston & Shirley, Scoping Paper on Dynamic Pricing: Aligning Retail Prices with Wholesale Markets, June 2005, pp. 4-5 (definitions); 

and Goldman, et al., Customer Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing, Lawrence Berkeley National 

Laboratory: LBNL-57128, August 2005 (graphics). 
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 Time-of-Use Rates 

Time-of-use (TOU) rates are the most prevalent time-varying rate, especially for residential customers. 

Most customers are exposed to some form of TOU rates, if only with rates that vary by six-month 

seasons. For instance, a summer-peaking utility may charge a higher rate for the energy use part of a 

bill than for the same amount of electricity consumed during the off-peak six months. This is a 

seasonal (time-varying) rate. 

More sensitive time-of-use rates establish two or more daily periods that reflect hours when the system 

load is higher (peak) or lower (off-peak), and charge a higher rate during peak hours. Off-peak hours 

are usually some part of the evening and night, as well as weekends. The length of the on-peak period 

varies, but can last between 8 a.m. and 8 p.m. By way of example, the on-peak period for residential 

TOU rates at the Kansas City Power and Light is from 1 p.m. to 7 p.m. 

The definition of TOU periods differs widely among utilities, based on the timing of their peak system 

demands over the day, week, or year. TOU rates sometimes have only two prices, for peak and off-peak 

periods, while other tariffs include a shoulder period or partial-peak rate. Some TOU rates apply yearround, although many tariffs include two seasons. 

History 

Utilities’ TOU rates or TOU pilot offerings have risen and fallen over time, in part depending on 

regulatory encouragement or restructuring disincentives. DOE’s predecessor agency, the Federal 

Energy Administration, sponsored 16 demonstration TOU pilots between 1975 and 1981.119 

Experiments tested single and multiple TOU rates, and lasted from six months to three years. The 

group which offered multiple rates included programs in Arizona, California (Los Angeles 

Department of Water and Power and Southern California Edison), Puerto Rico, Wisconsin, and North 

Carolina (Carolina Power & Light). EPRI later pooled the data from these experiments to estimate 

price elasticities of demand. They found the estimated elasticity of substitution was -0.14 (in other 

words, a doubling of on-peak to off-peak ratio would result in a drop of 14 percent in the 

corresponding quantity ratio). One of the last comprehensive national surveys of demand response 

programs in the United States prior to the current FERC Survey was conducted by EPRI in 1994. That 

survey gathered information on “1,959 demand-side efforts conducted by 512 electric utilities.”120 

Respondents reported 55 competitive rate programs offered by 39 utilities; only three of these included 

residential customers. The competitive rate programs involved more than 590,000 customers, 

including 559,000 residential customers. Some of the competitive rates were experimental; others 

included real-time pricing.121 Another survey category was load management rate programs; EPRI 

survey respondents cited 177 of these, including 80 TOU rate programs with over 500,000 

participants.

122 The bulk of TOU program participation came from residential customers participating 

in voluntary programs offered by four utilities: Pacific Gas & Electric, California (four programs, 

including a residential one with 102,000 participants); Baltimore Gas & Electric, Maryland (voluntary 

for 31,956 residential participants; mandatory for new single-family homes, with 39,092 customers); 

 119 Ahmad Faruqui & Stephen George, “The Value of Dynamic Pricing in Mass Markets,” The Electricity Journal, 

15 (6) July 2002, 47-48. 

120 EPRI, 1994 Survey of Utility Demand-Side Programs and Services: Final Report, November 1995, TR-105685, 

iii. 

121 EPRI, TR-105685, section 1.6. 

122 EPRI, TR-105685, section 2.6. 
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55

Metropolitan Edison, Pennsylvania123 (68,946 residential participants); and Salt River Project, Arizona 

(46,549 participants). 

 

Many utilities now require their larger commercial and industrial (C&I) customers to be on TOU rates. 

TOU rates are common outside of the United States. Electricité de France (EdF) has offered TOU 

rates for decades; it now also offers a “Tempo” critical peak rate, layered on a TOU rate; “Tempo” 

employs color-coded signals sent by power line carrier to a customer’s plug-in device on a day-ahead 

basis, as well as smart thermostats and programmable space and water-heating controls.124 As 

different U.S. states began to restructure, especially where utilities divested their generation, utilities 

allowed their TOU (or other load-response) demand response programs to lapse, particularly for 

smaller customers.125

Implementation Experience 

Experience with TOU rates and customer acceptance of the rates has varied widely across the United 

States. The experiences of utilities with residential TOU rates in Arizona and Washington are 

instructive. 

Salt River Project Agricultural Improvement and Power District (SRP) and Arizona Public 

Service (APS) residential TOU programs. APS and SRP, which compete in the Phoenix area, are 

cited as having residential participation rates that approach one-third of their customers.126 Demand 

response is important for an area that is growing as rapidly as Phoenix, and competition seems to 

contribute to the utilities offering attractive time-based packages that work. 

APS offers two residential TOU plans plus a flat-rate plan. Its Time Advantage plan has energy-only 

charges, which better suits customers who use 60 percent or more of their power off-peak. The 

Combined Advantage plan features much lower hourly energy prices, but adds a demand charge based 

on a customer’s peak use. SRP offers residential and business TOU plans plus a basic residential plan. 

SRP advises customers to opt for the E-26 TOU plan only if they use at least 1,000 kWh in summer 

periods and if they can shift usage to off-peak hours. SRP’s TOU customers save about eight percent 

on their annual bill. Those customers who find that they are not saving are allowed to revert to the 

basic plan, but must remain on it for at least one year. Each utility’s plan has peak and off-peak hours 

that vary seasonally, but no shoulder period. 

Both SRP and APS recognize the importance of customer education. Their web sites feature 

calculators for customers to compare costs under time-based and flat plans, along with energy-saving 

tips and advice on choosing a plan based on usage patterns. Interestingly, both utilities require 

unlimited physical access to customers’ meters, which must be read more than once monthly.127 

 123 Metropolitan Edison is now part of FirstEnergy Corporation. 

124 Energy & Environmental Economics, A Survey of Time-of-Use Pricing, Summer 2006 (forthcoming), prepared 

for the U.S. Environmental Protection Agency, section E.2, and http://particuliers.edf.fr/article343.html (accessed June 26, 

2006). 

125 For instance, prior to its divestiture of generation assets, Pepco (Maryland) required large residential customers 

to be on TOU rates. After divestiture, existing customers were allowed to elect non-TOU tariffs; new Pepco customers have 

been unable to sign up for time-of-use rates if they did not have TOU meters. Pepco is currently running the SmartPowerDC 

program, a dynamic pricing pilot in Washington, D.C. 

126 Demand Response and Advanced Metering Coalition (DRAM), comments filed in Docket AD06-2, December 

19, 2005, 4. 

127 APS and SRP web sites: http://www.aps.com/aps_services/residential/rateplans/ResRatePlans_8.html; 

http://www.aps.com/aps_services/residential/rateplans/ResRatePlans_9.html; http://www.srpnet.com/prices/home/tou.aspx 
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Puget Sound Energy (PSE) began a TOU pilot in June 2001; it installed new meters. PSE enrolled 

240,000 customers who moved from flat rates to its TOU program. During the mid-day period (10 

a.m. to 5 p.m.), TOU customers paid the same amount (5.8¢/kWh) as those on flat rates. Morning (6 

a.m. – 10 a.m.) and evening (5 p.m. – 9 p.m.) periods were priced only one cent higher. Enthusiastic 

customers achieved five-to-six percent peak reductions, and conserved 5 percent in the first year. PSE 

instituted a $1/month charge to recoup part of its metering costs in July 2002. This substantially cut 

into customer savings. In the fall of 2002, customers began receiving cost comparisons of TOU bills 

with what they would have paid on flat rates; 90 percent were saving less than the metering charge. 

Washington state discontinued the TOU pilot in November 2002.128 

Evaluations of the PSE program included several possible explanations for the need to discontinue the 

program. PSE is a winter-peaking utility, which normally faces mild weather and energy prices well 

below the national average; right before the pilot, prices were exceptionally high and volatile. By the 

fall of 2002, prices were lower and less volatile, due to the abatement of the California energy crisis 

(and critical need to export power to California). According to Eric Hirst, “dynamic pricing induces 

customers to reduce their electricity consumption when prices are high; the same customers will 

increase their use when prices are low. Dynamic pricing can hedge against high gas prices or lowhydro years. But, dynamic pricing benefits are not evenly distributed: “price increases during lowpriced periods are much less than the price reductions during high-price periods.”129 Other analyses 

noted a lack of sufficient difference between PSE’s peak and off-peak prices. Regions with less mild 

weather might offer higher incentives (in terms of rate differences) to shift usage to off-peak hours.130 

The absence of automated equipment and prior customer education about their energy consumption 

habits may have also minimized response rates. 

Issues 

All time-based rates other than seasonal rates require meters that register customer electricity 

consumption based on time-of-day or more frequent billing blocks. Traditional meters for smaller 

customers that were installed several years ago, or even newer remotely readable ones, do not 

necessarily record time-of-day usage. The additional capital and operating cost of replacing or 

upgrading these meters can be included in separate customer charges, as determined by individual 

public utility commissions, if customers choose TOU rates. Alternatively, if AMI systems are 

deployed, the necessary infrastructure would be in place to support TOU rates. 

Regulators who implement TOU plans need to decide how many periods are relevant: two daily; peak 

and off-peak plus a shoulder; weekends as off-peak; or seasonal differences layered on the time-of-day 

periods. The size of the price-spread between peak and off-peak hours is important so that customers 

perceive real price signals, but also so they can achieve bill savings without a loss of revenue to 

utilities. 

 128 Washington Utilities and Transportation Commission (UTC), Puget’s Time-of-Use Program: 

http://www.wutc.wa.gov/webimage.nsf/0/62515a89dde8130388256ae800699ca5?OpenDocument (accessed June 15, 2006). 

129 Direct Testimony of Eric A. Hirst on Behalf of Puget Sound Energy, Inc., November 26, 2001, before the 

Washington Utilities and Transportation Commission, 11-12. 

130 See Lewis Nerenberg, “From Promise to Progress”, UC Santa Cruz, May 2005, 4-7; and Dan Delurey, “Retail 

Demand Response”, IEA Workshop presentation, Paris, France, February 2003, 4-6. 
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57

Critical Peak Pricing 

Critical Peak Pricing (CPP) is a relatively new form of retail TOU rates that relies on very high, 

critical peak prices, as opposed to the ordinary peak prices in TOU rates. A specified high per-unit 

rate for usage is in operation during times that the utility defines as critical peak periods. CPP events 

may be triggered by system contingencies or high prices faced by the utility in procuring power in the 

wholesale market. Unlike TOU blocks, which are typically in place for 6 to 10 hours during every day 

of the year or season, the days in which critical peaks occur are not designated in the tariff, but 

dispatched on relatively short notice as needed, for a limited number of days during the year. CPP 

rates can be superimposed on either a TOU or time-invariant rate. While CPP is price-based, the fact 

that it is called in real-time at periods of extreme system stress makes it equally a reliability-based 

demand response. 

CPP rates have several variants, including:

• Fixed-period CPP (CPP-F). In CPP-F, the time and duration of the price increase are 

predetermined, but the days when the events will be called are not. The maximum number of 

called days per year is also usually predetermined. The events are typically called on a dayahead basis. 

• Variable-period CPP (CPP-V). In CPP-V,131 the time, duration, and day of the price 

increase are not predetermined. The events are usually called on a day-of basis. CPP-V is 

typically paired with devices such as communicating thermostats that allow automatic 

responses to critical peak prices. 

• Variable peak pricing (VPP). This is a recent form of CPP that has been proposed in New 

England.132 As with CPP, the off-peak and shoulder period energy prices would be set in 

advance for a designated length of time, such as a month or more. In the version proposed in 

Connecticut, the peak price for each peak-period hour would be set each day based on the 

average of the corresponding ISO Day-Ahead Connecticut Load Zone locational marginal 

prices (LMPs), adjusted to account for delivery losses and other costs typically recovered 

volumetrically. The advantage of VPP is that it more directly links the wholesale market to 

retail pricing. 

• Critical peak rebates. In critical peak rebate programs, customers remain on fixed rates but 

receive rebates for load reductions that they produce during critical peak periods. 

History 

CPP rates are relatively uncommon in the United States; the first major implementation occurred at 

Gulf Power in 2000. Overseas, France’s EdF has used a variation on CPP as its default residential rate 

since the late 1980s. Recent adoption of CPP rates in the United States is based on the realization that 

some of the price spikes experienced between 1998 and 2001 could have been drastically diminished 

had there been real-time (or near real-time) signals to customers to curtail their electricity use. The 

FERC Survey found that 25 utilities currently offer CPP tariffs or pilots. 

 131 Charles River Associates (CRA), Impact Evaluation of the California Statewide Pricing Pilot: Final Report, 

March 16, 2005 for a discussion of CPP-F and CPP-V. 

132 Filed Testimony of Bernard F. Neenan on Behalf of ISO New England Inc. before the Connecticut Department 

of Public Utility Control, Docket No. 05-10-03, February 10, 2006. 
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Implementation Experience 

The results of the CPP program at Gulf Power and various CPP pilots suggest that CPP programs can 

provide important benefits without exposing customers to significant risk. 

Gulf Power, Florida. Gulf Power, a subsidiary of Southern Company, began marketing its 

GoodCents Select program to residential customers in March 2000 after experimenting with an earlier 

version between 1991 and 1994. By the end of 2001, the program had grown to include 2,300 homes, 

and by 2003 had 6,000 participants. The key features of the program are a monthly participation 

charge (about $5/month), an absence of incentive payments (incentives are imbedded in the four-part 

time-of-use), and no penalties for not modifying use. GoodCents Select comprises four elements: a 

TOU rate with a CPP component; a smart meter that receives pricing signals and provides outage 

detection; customer-programmed automated response technologies (including a smart thermostat 

governing air conditioning and water heaters, plus heat- and pool-pump timers); and multiple ways to 

communicate rate changes and critical peak conditions to participants. There are three time-of-use 

prices for non-critical hours, and a critical-peak price that can be invoked no more than one percent of 

the hours in a year. Gulf Power’s customers have saved more than 1 MW under this program.133

Gulf Power believes that both customers and utilities benefit from customer-controlled load 

management programs when price signals are used in conjunction with technology to automate 

demand responses. Its customers program the settings on their equipment and have the ability to 

override price signals; they are willing to participate; and they can save on their bills. Gulf Power said 

that the utility benefits in several ways: the “program facilitates the promotion of the most 

economically efficient electric and end-use technologies;” “significant demand reduction can be 

achieved in real-time (more than 2kW per participant during summer peaks);” demand response is 

profit-preserving; and, demand response programs to clip peaks should be assessed with the same 

payback criteria as 30-year combustion turbines (CT) installed to handle peak. Gulf Power reports 

that the GoodCents program creates initial savings of $35 million, plus annual O&M savings of $2.5 

million.134

California Statewide Pricing Pilot. California implemented a statewide pilot of CPP, known as the 

Statewide Pricing Pilot, which included 2,500 customers, involved all three investor-owned utilities 

(IOUs), and ran from July 2003 to December 2004. Three agencies cooperated in implementing the 

Statewide Pricing Pilot, including the California Public Utilities Commission (CPUC), the California 

Energy Commission (CEC), and the California Power Authority (CPA). The pilot tested three rate 

structures, including a TOU rate in which the peak price was 70 percent higher than the standard rate 

and twice as high as the off-peak price. It also tested two CPP rates: a statewide TOU rate layered 

with a CPP that could be dispatched with day-ahead notice up to 15 times annually (CPP-F), and a 

variable critical-peak rate (CPP-V), targeted at a population that had already participated in a smart 

thermostat pilot. CPP-V was dispatched with four-hour day-of notification, for two-to-five hours. 

The CPP-V customers had the option of free enabling technology to facilitate their responses. 

Results demonstrated customer responsiveness across all groups and geographies, with and without air 

conditioning. Figure IV-3 presents the results from the pilot across a number of characteristics. 

Figure IV-4 displays how customer peak reduction differed by type of rate. Residential customers, 

 133 Southern Company Services, comments filed in Docket AD06-002, December 19, 2005, 8, noting that 

participants had saved over 1 MW “thus far” under this program. 

134 Dan Merilatt, GoodCents Solutions, “Demand Response Programs: New Considerations, Choices, and 

Opportunities,” white paper (January 2004), 13-17. 
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59

Figure IV-3. California CPP: Residential CPP Response by Attribute 

Source: Roger Levy, Joint California Workshop, “Advanced Metering Results and Issues” September 2004. 

Figure IV-4. Average Residential Critical Peak Impacts by Rate Treatment 

Source: Roger Levy, Joint California Workshop, “Advanced Metering Results and Issues” September 2004. 

who had been thought to be less price-responsive than larger customers, achieved 15 percent or more 

reductions with high price signals on critical days; they achieved five percent reductions with more 

modest TOU prices. Residential customers were in fact more price responsive as a group than C&I 

customers, although the absolute effects on energy savings may have been higher with the latter group. 

The presence of enabling technologies made a dramatic difference in the response rates of customers – 

up to two-thirds of the reductions in some groups were attributable to smart thermostats (Figure IV4).135 Satisfaction among participants was high, with 87 percent of participants responding that the 

 135 Faruqui & George, “Quantifying Customer Response to Dynamic Pricing,” The Electricity Journal (May 2005), 

58-59. 

17.2%

15.1%

13.5%

19.2%

12.1% 12.8%12.3% 12.1% 12.5%

9.8% 9.8%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

High vs.

Low User

Income Single vs.

Multi-Family

Central AC

Ownership

Pool

Ownership

State-wide

Average

Peak Load Reduction

200% Average Use

Single Family

50% Average Use

<$40,000

>$100,000

Multi-Family

YES

NO

YES

NO

17.2%

15.1%

13.5%

19.2%

12.1% 12.8%12.3% 12.1% 12.5%

9.8% 9.8%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

High vs.

Low User

Income Single vs.

Multi-Family

Central AC

Ownership

Pool

Ownership

State-wide

Average

Peak Load Reduction

200% Average Use

Single Family

50% Average Use

<$40,000

>$100,000

Multi-Family

YES

NO

YES

NO

Average Critical Peak Day

4.1%

12.5%

34.5%

0%

10%

20%

30%

40%

50%

Time of Use CPP-F CPP-V

Peak Load Reduction

Critical 

Peak 

Variable 

With 

Automated 

Controls

Critical 

Peak Fixed

TOU

CPP-V

Critical 

Peak 

Variable 

With 

Automated 

Controls

Hottest Critical Peak Day
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program was fair.136 In fact, a number of the participants remained in the time-of-use program after 

the pilot was discontinued, even though they then began paying for their own enabling technologies. 

Post-pilot interviews revealed that, contrary to popular belief, residential customers considered the 

CPP tariffs easier to understand than their previous inverted tier rates.137

Real-Time Pricing 

Real-time pricing (RTP) rates vary continuously during the day, directly reflecting the wholesale price 

of electricity, as opposed to rate designs such as time-of-use or CPP that are largely based on preset 

prices. RTP links hourly prices to hourly changes in the day-of (real-time) or day-ahead cost of 

power. The direct connection between wholesale prices and retail rates introduces priceresponsiveness into the retail market, and serves to provide important linkages between wholesale and 

retail markets. There are several RTP variants in place across the United States – day-of versus dayahead pricing, one-part versus two-part pricing, and mandatory versus voluntary. A two-part RTP rate 

is the more common form of price-risk sharing;138 however, the largest customers in Delaware, 

Maryland, and New Jersey are starting to be placed on day-of mandatory RTP in default-service 

market designs. 

The first RTP programs, in the mid-1980s, were introduced in California as a novel strategy for 

meeting demand-side management (DSM) objectives and testing critical assumptions about customer 

acceptance and price response. Utilities such as Niagara Mohawk Power Co. (now part of National 

Grid) and Georgia Power also were early adopters of real-time pricing tariffs. According to a report 

on RTP conducted by the Lawrence Berkeley National Laboratory,139 more than 70 utilities in the 

United States have offered voluntary RTP tariffs on either a pilot or permanent basis. The motivations 

of these utilities to implement RTP were varied: either to promote retail market development or to 

lessen the need to build additional peaking generators. 

Day-Ahead Real-Time Pricing (DA-RTP) 

DA-RTP customers are given one-day notice of the prices for each of the next day’s 24 hours. This 

gives customers time to plan their responses, such as shifting use (often by shifting load to off-peak 

hours or by using onsite generation) or to hedge day-ahead prices with other products if they cannot 

curtail their demand. Niagara Mohawk is an oft-cited example of an early adopter of default DA-RTP 

for its largest customers. More recently, its experiences with TOU and RTP served as the basis for a 

New York Public Service Commission (NYPSC) decision to phase-in default RTP for all large 

customers. 

From the early 1980s to November 1998, the default tariff (SC-3A) for Niagara Mohawk’s largest 

customers was a time-of-use rate. In November 1998, Niagara Mohawk implemented default dayahead RTP for all customers with more than 2 MW of demand, which comprised more than 130 

industrial, commercial, and institutional customers. By 2003, 50-55 percent of customers faced real-

 136 Charles River Associates, March 2005, 13. 

137 Residential Customer Understanding of Electricity Usage and Billing, Momentum Market Intelligence, WG3 

Report, Jan. 29, 2004, viii-ix., cited by Roger Levy, “Advanced metering and dynamic rates: the Issues,” September 30, 

2004.

138 Frederick Weston & Wayne Shirley, Dynamic Pricing: Aligning Retail Prices with Wholesale Market, June 

2005, 5. 

139 Galen Barbose, Charles Goldman, & Bernie Neenan, A Survey of Utility Experience with Real Time Pricing,

Lawrence Berkeley National Laboratory: LBNL-54238, 2004. 
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time pricing; in 2004, between 45 percent and 60 percent still had hourly prices.140 While generally 

satisfied, customers wished there had been more hedging options available in the earlier years, either 

through flat-rate supply contracts or financial hedges.141 In April 2006, NYPSC affirmed an earlier 

order requiring all utilities to adopt DA-RTP (mandatory hourly pricing) as the default service for their 

largest customers. Beginning dates vary according to tariff and schedule needs; the phase-in began in 

May 2006. Each utility has a different threshold to define its largest customers, ranging from 0.5 MW 

to 1.5 MW.142 

The Chicago-area Energy Smart Pricing Plan is an example of a popular voluntary residential DARTP program. Jointly offered by Community Energy Cooperative and Commonwealth Edison, it first 

enrolled 750 customers in 2003; 1,100 customers were on the plan in 2006. Participants receive 

simple interval meters and can check day-ahead prices by calling a toll-free number or visiting a web 

site. Hedging and risk were built into the program: if the next day’s peak price will exceed a specified 

threshold, customers are notified by phone, fax, or e-mail. The co-op bought a financial hedge to 

ensure customers never pay more than 50 cents per kilowatt-hour. The co-op’s general manager 

credits the success of this voluntary RTP program to providing members with clear information on 

how rates work. Its success and popularity across a variety of residential customer types provides an 

important lesson about smaller customers’ willingness and ability to respond to time-based demand 

response programs. Partially due to the success of this pilot, the Illinois General Assembly voted in 

April 2006 to require Illinois utilities to allow residential customers to choose RTP in 2007.143 

Two-Part Real-Time Pricing 

An important alternative to DA-RTP is two-part RTP. Two-part RTP designs include a historical 

baseline for customer usage, layered with hourly prices only for marginal usage above or below the 

baseline. Customers thus see market prices only at the margin. The baseline design serves as a hedge 

for customers against real-time pricing volatility, and allows them to achieve savings by curtailing 

their marginal use at times when prices are higher and by using more during the off-peak tariff times. 

Figure IV-5 illustrates how two-part RTP tariffs operate. 

Georgia Power’s RTP program, probably the most successful voluntary real-time pricing program in 

the United States, uses two-part RTP. It installed meters to record hourly usage for large customers in 

1992; the program is available to customers with connected load of 900 kW or more.144 More than 

1,700 commercial and industrial retail customers have signed up for this program or another of 

Georgia Power’s RTP tariffs. According to a Government Accountability Office (GAO) report on 

demand response, “Georgia Power could count on participants reducing 750 MW of power during 

 140 Charles Goldman, et al., Does Real-time Pricing Deliver Demand Response? A Case Study of Niagara 

Mohawk's Large Customer RTP Tariff, Lawrence Berkeley National Laboratory: LBNL-54974, August 2004, 3; and 

Goldman & Levy, “Demand Response in the US: Opportunities, Issues, and Challenges,” presentation at the National Town 

Hall Meeting on Demand Response, Washington, D.C., June 21, 2005, 8. 

141 Charles Goldman, et. al., LBNL-54974, 3-6. 

142 The first utilities to phase in default mandatory hourly pricing were Consolidated Edison (ConEd) and Orange 

and Rockland Utilities, which began in May 2006. NY PSC order on Case 03-E-0641, 16-18. 

143 Restructuring Today, April 10, 2006; Lynne Kiesling, www.knowledgeproblem.com, March 2, 2004, and 

January 14, 2005; and P.A. 094-0977, 94th Gen. Assem., Reg. Sess. (Ill. 2006), effective June 30, 2006. 

144 Southern Company, comments filed in AD05-17-000, November 18, 2005, 40. 
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Figure IV-5. Two-part Real-Time Pricing Tariff: How it Works 

0

500

1000

1500

2000

2500

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

Time of Day

Load (kW)

Credit for 

unused energy 

below baseline Energy 

bought

at RTP

Baseline energy

purchased at

off-peak tariff 

rate

Baseline energy

purchased at

on-peak tariff rate

Customer Basline

Source: Goldman, et al., Customer Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing, August 2005: LBNL-57128. 

high-priced hours,” with reductions up to “17 percent on critical peak days. These savings reduce the 

amount of costly peak-generation equipment necessary. This allows the utility to pass along savings 

to customers.”145

The secret to success for Georgia Power’s program appears to be a combination of corporate 

commitment to the program, aggressive marketing, customers’ ability to hedge through two-part RTP, 

and rules that allow customers to generate bill savings.146 Also critical is Georgia Power’s belief that 

customer education is a continuous process, even for a successful program that has been in place for 

years. The manager of RTP at a customer location may be different this year than last, and companies 

tend to pay more attention in years with higher or more volatile prices than in relatively lower-priced 

years.147

Use of two-part RTP is also not limited to regulated utilities and is a popular offering of unregulated 

retailers. Large customers may choose this tariff as an alternative to the default tariff. They may be 

willing to take on some price risk, but do not want their entire cost of energy exposed to real time 

prices. Constellation NewEnergy, an unregulated retailer, reports that a large portion of its customers 

use its two-part RTP structure (known as block index).148

Mandatory RTP

Several restructured states have made RTP the standard offer (default) service for the largest customer 

class, unless they choose an alternative supplier. Delaware, New Jersey, Pennsylvania, Maryland, 

Ohio, New York, and Illinois have initiatives aimed at implementing default RTP for the largest 

customers. Default tariffs in New York and Illinois index hourly prices to day-ahead ISO prices, 

 145 GAO, Electricity Markets: Consumers Could Benefit from Demand Programs, But Challenges Remain (GAO04-844, August 2004), 22–23. 

146 Goldman et al., LBNL-54974, 2004 7, 11. 

147 Faruqui & Mauldin, “The Nine Lessons of RTP,” Public Utilities Fortnightly, July 15, 2002, 32-39. 

148 Constellation NewEnergy, ISO-NE Demand Response Summit, April 27, 2006. 
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while Delaware, New Jersey, Maryland, and some Pennsylvania utilities index to real-time hourly ISO 

prices. Through April 2006, default RTP for large C&I customers had been implemented by 11 

utilities in four states, and it was proposed or planned for 15 additional utilities.149 

Demand Response Program Survey Results 

The FERC Survey requested information on the use and prevalence of demand response programs 

across the United States. This section summarizes information on how many programs are offered, 

and how many customers are currently on these programs.150

Incentive-Based Demand Response 

Table IV-1 lists the number of entities that offered the various types of incentive-based demand 

response in the United States in 2005. The FERC Survey indicates that DLC programs and 

interruptible/curtailable tariffs are the most popular type of incentive-based demand response. The 

following discussion presents detailed results on the number of incentive-based demand response 

programs and the number of customers enrolled in these programs by region and by type of company. 

Table IV-1. Number of entities offering incentive-based demand response 

programs in the United States 

Type of Program Number of Entities 

Direct Load Control 234 

Interruptible/Curtailable 218 

Emergency Demand Response Program 27 

Capacity Market Program 16 

Demand Bidding/Buyback 18 

Ancillary Services 1 

Source: FERC Survey 

Direct Load Control (DLC) 

DLC programs are widely available nationally, with 234 entities offering at least one DLC program. 

DLC programs were targeted primarily to residential customers; however, 33 percent of these entities 

also offered at least one DLC program for commercial customers. DLC programs are particularly 

popular among utilities in the MRO region (39 percent of the total number of entities offering DLC 

programs) followed by SERC and RFC, 17 percent each (see Figure IV-6). Several states in the MRO 

region (Minnesota and Iowa) have historically either required or encouraged utilities to spend a 

portion of their revenue on demand-side management programs, including direct load control, and 

utilities in the upper Midwest have historically had favorable rules that allowed load-management 

resources to be counted towards meeting reserve requirements. Cooperative utilities and political 

subdivisions account for the largest (51 percent) portion of entities offering DLC programs followed 

by municipal entities and IOUs. 

 149 Neenan, “Default RTP Service Links Wholesale and Retail Markets,” UtiliPoint IssueAlert, October 28, 2005, 

and Goldman, April 27, 2006, 3-6. 

150 Appendix H lists the entities who offer demand response programs. 
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Figure IV-6. Direct Load Control programs offered by region and entity 

type 

0

20

40

60

80

100

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities offering DLC programs

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political Sub-divisions

Source: FERC Survey 

Figure IV-7 shows the number of customers enrolled in each NERC region as reported by entities that 

responded to the FERC survey. Approximately 4.8 million customers were enrolled in DLC programs 

across the nation, with significant participation by customers served by utilities in the FRCC, MRO, 

RFC, SERC, and WECC regions. The top ten utilities that offered DLC programs are listed in Table 

IV-2, and these utilities account for 60 percent of all the customers enrolled in DLC programs. 

Figure IV-7. Number of customers enrolled in DLC programs 

(Number of responding entities = 229) 

-

300,000

600,000

900,000

1,200,000

1,500,000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Customers 

Enrolled in DLC

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and

Political Sub-divisions

Source: FERC Survey 
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Table IV-2. Top 10 entities by customers enrolled in DLC programs 

Name of Utility Number of Customers 

Enrolled in DLC 

Florida Power and Light 740,570 

Progress Energy Florida 401,720 

Detroit Edison 347,750 

Baltimore Gas and Electric 338,568 

Northern States Power 283,317 

Duke Power 207,794 

Southern California Edison 166,318 

Public Service Electric & Gas 119,310 

Dairyland Power Cooperative 112,656 

Sacramento Municipal Utility District 104,079 

Source: FERC Survey 

Interruptible/Curtailable Rates 

Some 218 entities reported that they offer interruptible/curtailable tariffs, primarily to large industrial 

and commercial customers. This type of demand response program is particularly popular among coops; about 95 cooperatives and political subdivisions151 have customers enrolled on 

interruptible/curtailable tariffs. Figure IV-8 shows the distribution of these programs by type of utility 

and region. The greatest number of entities that offer interruptible/curtailable tariffs are located in the 

MRO, RFC, and SERC regions. 

Other Incentive-Based Demand Response 

To varying degrees, utilities also reported offering other types of demand response programs, 

including capacity, demand bidding/buyback and emergency programs (see Figure IV-9). Emergency 

demand response programs were particularly popular in NPCC, where many utilities, retailers, and 

curtailment-service providers participate in ISO/RTO emergency programs. 

Time-Based Rates 

The FERC Survey also requested information on time-based rate programs. Table IV-3 summarizes 

the number of entities152 that offered TOU, CPP, or RTP programs in the United States in 2005. As 

can be seen, only a small number of the 2,620 entities that responded to the survey offered time-based 

rates, and TOU rates were the most popular rate offering. Comparison of tables IV-1 and IV-3 

indicates that TOU rates are the third-most popular rate offering, after DLC programs and 

interruptible/curtailable tariffs. The following discussion presents more detailed results on the number 

of time-based programs and the number of customers enrolled in these programs by region and by type 

of company. 

 151 This represents 15.5 percent of the total number of cooperatives and political subdivisions who responded to the 

survey. 

152 The term “entity” is used herein to refer to the companies that asked to respond to the survey. These entities 

include investor-owned utilities, municipal utilities, rural electric cooperatives, ISOs/RTOs, and power marketers. 
Chapter IV – Existing Demand Response and Time-Based Rates

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Figure IV-8. Number of entities offering interruptible / curtailable tariffs 

by region and entity type 

0

10

20

30

40

50

60

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities offering I/C Programs

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and

Political Sub-divisions

Source: FERC Survey 

Figure IV-9. Number of entities offering capacity, demand bidding, and 

emergency programs by region 

0

4

8

12

16

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities

Capacity Programs

Demand Bidding

Emergency

Source: FERC Survey 
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Table IV-3: Number of entities offering time-based rates in the United 

States 

Type of Program Number of Entities 

Time-of-Use Rates 187 

Real-time Pricing 47 

Critical Peak Pricing 25 

Source: FERC Survey 

Time-of-Use Rates 

Figure IV-10 shows the number of entities that offer time-of-use (TOU) tariffs to their residential 

customers by NERC region; 148 utilities reported that they offer a time-of-use tariff to their residential 

customers, while the remaining 39 offer TOU rates to nonresidential customers. Publicly-owned 

utilities are large users of these programs. Cooperative utilities, political subdivisions, and municipal 

entities together account for 55 percent of entities offering TOU rates. In order to get a sense of 

regional differences in TOU tariffs offered to residential customers, the percentage of residential sales 

of those entities in each region that offer residential TOU tariffs is reported in Figure IV-10. For 

example, even though only five entities report offering a residential TOU tariff, they account for 78 

percent of residential sales in the FRCC region. Residential TOU tariffs appear to be most widely 

available in the FRCC and SERC regions (78 percent and 72 percent, respectively, of residential 

sales), followed by WECC (57 percent). 

Figure IV-10. TOU tariffs offered to residential customers by entity type153

0

10

20

30

40

50

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities that Offer TOU 

Tariff to Residential Customers

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political Sub-Divisions

% of 

Residential 

Sales

44 15 78 41 47 39 72 51 57

Source: FERC Survey 

Electric distribution companies typically offer a TOU tariff as an optional tariff service for residential 

customers; thus, it is important to track actual customer enrollment on TOU tariffs in order to assess 

 153 Regional definitions used in this figure and subsequent figures are based on NERC regions. Chapter I contains 

a map and listing of the regions. 
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customer acceptance and market penetration. About 1.57 million out of 120 million residential 

customers were signed up for a TOU tariff in the United States, which represents a market penetration 

of 1.4 percent nationally. Figure IV-11 displays the regional distribution of customer participation in 

these rates. As can be seen, most of the customers enrolled in TOU rate programs are concentrated in 

the RFC and WECC regions, and that the vast majority of residential customers on TOU rates are 

served by investor-owned utilities. Indeed, 10 entities, mainly investor-owned utilities located 

primarily in the RFC and WECC regions, account for about 85 percent of the residential customers 

enrolled in TOU tariffs. These 10 entities are listed in Table IV-4. 

Critical Peak Pricing 

About 25 entities reported offering at least one CPP tariff with an enrollment of about 11,000 

customers nationally. Many of the CPP tariffs appeared to be pilot programs (e.g., utilities that 

participated in the California Statewide Pricing Pilot). About 70 percent of the customers enrolled in 

CPP rates were served by an IOU, even though 72 percent of the entities offering CPP rates are co-ops 

and munis.154 The top five entities by number of customers enrolled in CPP programs are shown in 

Table IV-5. These five entities account for 96 percent of the total number of customers reported to be 

on CPP rates. 

Figure IV-11. Residential customers on TOU tariffs by region and entity 

type 

-

200,000

400,000

600,000

800,000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Residential 

Customers Enrolled in TOU

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and

Political Sub-divisions

Source: FERC Survey 

 154 We have concerns regarding the classification by several respondents of their tariff as CPP. For example, one 

rural cooperative (Cass County Electric Cooperative) with a large number of residential customers enrolled described its CPP 

tariff as a demand-limiting program involving electric heat backed up by onsite generation for residential customers. 

Similarly, 12 small cooperatives and municipal utilities reported offering CPP rates for large commercial and industrial 

customers. 
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Table IV-4. Top 10 entities by residential customers enrolled in TOU 

programs

Name of Utility Number of Residential 

Customers enrolled in TOU 

Public Service Co. of Oklahoma 429,737 

Arizona Public Service Company 332,823 

Salt River Project 151,000 

Southwestern Electric Power Co. 135,816 

Pacific Gas and Electric Company 82,055 

Baltimore Gas and Electric Company 81,072 

Ohio Power Company 38,482 

Metropolitan Edison Co 35,640 

United Illuminating Company 35,041 

Jersey Central Power & Light Co 26,186 

Source: FERC Survey 

Table IV-5. Top five entities by number of customers enrolled in CPP 

programs 

Name of Utility Number of Customers 

enrolled in CPP 

Gulf Power Company 6,878 

Cass County Electric Cooperative 2,892 

Southern California Edison Company 462 

San Diego Gas and Electric 230 

Pacific Gas and Electric Company 121 

Source: FERC Survey 

Real-Time Pricing 

Forty-seven entities reported offering at least one RTP tariff, with 4,310 customers enrolled nationally 

(see IV-12). These survey results are consistent with several other recent studies that involved more 

in-depth analysis of real-time pricing offered as either an optional or default service tariff service by 

utilities for large industrial and commercial customers.155 About half of all the entities offering RTP 

tariffs are located either in RFC or NPCC; several states in these regions (New Jersey, Maryland, New 

York, and Pennsylvania) have mandated RTP as the default tariff for large customers. 

Motivations for the Use of Demand Response and Time-Based 

Rates 

 

The use and development of demand response programs and time-based rates have been and will be 

motivated by several factors: 

• EPAct 2005 demand response provisions. EPAct section 1252(b) directs the states and 

utilities to consider the costs and benefits of demand response programs and enabling 

 155 Galen Barbose & Bernie Neenan, 2004; and Galen Barbose, et al., Real Time Pricing as a Default or Optional 

Service for C&I Customers: A Comparative Analysis of Eight Case Studies, report to the California Energy Commission, 

Lawrence Berkeley National Laboratory: LBNL-57661, 2005. 
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Figure IV-12. RTP tariffs offered by region and entity type 

0

5

10

15

20

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities 

Offering RTP rates

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political Sub-divisions

Source: FERC Survey 

technologies such as advanced meters. While states are not required to implement demand 

response or advanced metering, this congressional directive should promote reexamination of 

demand response and advanced metering, and may lead to additional state policies. See 

Appendix A for the full text of the Smart Metering Section of EPAct 2005.

• Reliability. Incentive-based demand response programs enhance system reliability by 

providing grid operators another tool to use during system emergencies and reserve shortages. 

Incentive-based programs can provide reliability support for grid operators, whether they are 

ISOs or vertically-owned utilities. 

• Resource need. In many instances, incentive-based demand response programs have been 

implemented to economically meet growing demand or to defer construction or upgrades of 

generation or distribution. The emergency request for proposals conducted for southwest 

Connecticut by the ISO-NE in 2004 is an example of such a program. 

• Quick rollout. In relative terms, incentive-based demand response can be implemented more 

rapidly than building new generation or transmission. This flexibility allows resourceconstrained regions to respond rapidly to meet critical needs (e.g., ISO-NE implemented the 

winter supplemental program in December 2005 to address concerns about the availability of 

natural gas supplies during the winter). 

• Regulatory. Regulatory directives and initiatives have spurred additional growth of demand 

response. The rapid growth of demand-side management and load management in the 1980s 

and 1990s was driven by state and federal encouragement and the implementation of 

integrated resource planning. Recent policies in states like California and New York are 

leading to renewed growth in demand response as a resource. Federal encouragement of 

demand response by Congress, DOE, the GAO, and the Commission has provided additional 

focus on the issue. 

• Rising energy costs. The rising cost of energy in the intervening years between restructuring 

and the present means that many states’ retail customers now face dramatically higher bills 

within the next year. The time-lag in customers seeing the real costs of supplying them with 

power was exacerbated by the dramatic rise in gas prices after hurricanes Katrina and Rita. 

Armed with knowledge about their power supply, and provided with a portfolio of pricing 
Chapter IV – Existing Demand Response and Time-Based Rates 

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71

plans along with education, training, and enabling technologies, customers can be given the 

ability and opportunity to change their habits and lower their energy bills. 

• Advances in enabling technologies. The price for technologies to implement dynamic 

pricing and automated customer responses has been falling, just as the capabilities of these 

technologies have been rising. The increasingly advanced functionality of enabling 

technologies has the potential to provide wider power system and societal benefits beyond 

those solely within the scope of demand response programs. Automated customer responses 

is now possible in more situations, allowing both greater customer receptivity and higher 

utility confidence that customers can and will respond to price-based demand response. These 

advances have contributed to the rekindling of interest in demand-side policies. 

• Customer interest. Many customers, particularly large industrial customers, are interested in 

incentive-based demand response to reduce utility bills and to help maintain system reliability, 

without exposing them to price risks. Industrial customers have participated in interruptible/ 

curtailable tariffs for years and have been some of the most active participants in the various 

utility and ISO incentive-based programs. 

• Lowered utility costs. LSEs and vertically-integrated utilities are interested in incentivebased demand response when it is cost-effective and can lower their resource acquisition or 

procurement costs. 

• Risk management. Customers and LSEs can use demand response to hedge their exposure to 

high prices and price volatility by operating these resources and programs during these 

periods. 

UtiliPoint International conducted a survey to determine what electric utilities and regulators 

considered the primary drivers of demand response programs in 2005.156 Figure IV-13 displays these 

results. According to the utilities surveyed, regulatory directives and requirements were the primary 

drivers for their development of programs. UtiliPoint also found that the relative weight given to each 

driver differs by type of utility. IOUs focus on reliability and reducing utility costs, and have only a 

modest interest in lowering participant’s energy costs. Municipal utilities have a higher interest in 

lowering participant’s energy bills. Co-operative utilities were highly motivated to lower bills for 

participants and to lower utility costs, and not by increasing reliability. 

The UtiliPoint survey also uncovered a difference in perceptions about regulators as drivers of demand 

response programs. While only 20 percent of regulators reported that regulation was a primary driver 

for demand response, 68 percent of IOUs that responded cited “regulatory” as the primary driver for 

developing or expanding demand response.157 

Current issues/challenges 

Even with the drivers listed above to motivate increased utilization of incentive-based demand 

response, the previous discussion suggests that use of incentive-based demand response is not 

widespread. There are multiple reasons for the lack of greater usage, including: 

• Need for investment in meters and other enabling technology. Without the ability to 

measure consumption by time of day (preferably hourly – See Chapter III), it will be difficult 

to offer and conduct many incentive-based demand response programs, and to measure any 

reductions. Customers and LSEs also need new automation or control equipment or retrofits 

 156 UtiliPoint, Outlook and Evaluation of Demand Response, June 10, 2005. 

157 UtiliPoint, Outlook, 18, 22-23. 
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Figure IV-13. Drivers for developing or expanding demand response 

programs 

18%

22%

22%

26%

28%

30%

36%

52%

55%

55%

0% 10% 20% 30% 40% 50% 60%

Less Pollution

Genreation Shortage

Add'l Power to Sell

Reduce Local Congestion

Fewer Brownouts/Blackouts

Reduce Energy Costs

Lower Energy Bills for Participants

Reliability

Regulatory

Reduce Utility Costs

Source: UtiliPoint, Outlook , 18. 

to existing equipment and appliances that will allow them to easily adjust consumption. 

Recent advances in controls, electronics, and communications have dramatically decreased the 

cost and increased the functionality of these technologies. Greater saturation of advanced 

meters will support additional demand response, where economic and effective. 

• Lack of incentive for utilities to promote demand response. The lack of utility incentives 

has been a long-standing problem with demand resources such as incentive-based demand 

response and energy efficiency. Since most utility rates are based on a combination of kWh 

and peak kW demand charges, demand reductions associated with incentive-based demand 

response negatively impact utility revenues. Even though the reductions may be short-lived, 

the potential for a reduction in revenues presents a disincentive. The disincentive is greater 

for utilities in restructured states with active ISO demand response programs. Consequently, 

as representatives for industrial customers have asserted, electric utilities have been either 

reluctant to promote these programs or request some form of lost-revenue recovery. This 

issue has proven to be difficult to address and various solutions have been attempted over the 

past several decades, with vary levels of success.158

• Negative impact of industry restructuring on delivery of demand response by utilities. A 

related challenge is the impact of restructuring on utility incentives. Restructuring has 

changed the ability of utilities to operate programs and to gain benefits from their operation in 

two manners. First, the benefits associated with operating incentive-based demand response 

programs are less for utilities that have divested their generation assets. A primary source of 

benefits from demand response is through avoiding costs. Consequently, a utility that has 

divested generation is only able to avoid distribution and transmission costs, not the typically 

larger benefit from avoiding generation costs or procuring power during peak periods. The 

benefits associated with operating demand response as a resource are driven more by impacts 

on local distribution operation and reliability, which is generally a fraction of avoided 

generation costs. In these states, the utilities cannot internalize the full benefits associated 

 158 This issue is the subject of a MADRI-led effort to develop incentives for distributed resources. A good 

summary of the issue is contained in a white paper prepared for EEI by NERA Economic Consulting, Distributed Resources: 

Incentives, 2006. 
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with these programs, and additional benefits accrue either to the customer or potentially to a 

third-party vendor. Second, as was discussed earlier, in some states, such as Texas, 

distribution companies are not allowed to offer demand response as a service. While these 

factors reflect key underlying cost and benefit issues, they may represent transitional 

problems. Ultimately, the proper allocation of costs and benefits should result in competition 

and innovation among retailers that may include demand response programs and time-based 

rates. 

• Subsidization. The form of payment for reductions in incentive-based demand response 

programs is viewed as a subsidy by many parties, including economists such as Larry Ruff 

and by industry associations such as EEI. The basic argument raised by these parties is that 

the correct form of inducing demand response is through pricing and that “any payment to a 

customer for demand reduction should never exceed the wholesale price minus the retail price 

that the customers would have otherwise paid to own the power. Any payment above this 

level would be a subsidy, that is, a nonmarket payment that has to be recovered through a tax 

or charge on all customers.”159 

• Measurement of demand reductions. The measurement of demand reductions associated 

with incentive-based demand response programs has proven to be a difficult and controversial 

problem, particularly for demand-bidding, emergency demand response, and capacity 

programs.160 The key measurement issue is how to calculate the level of consumption that 

would have occurred if the participant had not curtailed consumption – i.e., the customer 

baseline level. Once the customer baseline is determined, the level of reduction is calculated 

by subtracting the actual demand from the estimated baseline normal demand. However, there 

are a variety of means to estimate the baseline that are used by utilities and ISOs,161 typically 

involving an average of usage over several recent days. A key problem with most estimation 

methods is the potential for gaming – participants may bid into the market or state that they 

will curtail when they would already be shut down for the day. The ultimate solution for this 

measurement problem would be to directly measure usage in real-time or to move toward 

specific entitlements or to set reduction levels, instead of after-the-fact measurement and 

estimation. 

• Boom-bust nature of demand response. A fundamental challenge with incentive-based 

demand response is the boom-bust nature of electric markets. The use of incentive-based 

demand response is largely concentrated during periods of tight supplies or reserve shortages. 

When generation is plentiful, the need for these programs is less, with consequent reduction in 

payments – either through reduced capacity payments or through infrequent usage. This 

overcapacity situation exists today in many parts of the country. As a result, customer interest 

may atrophy and demand response programs are likely to be mothballed or terminated in these 

regions. However, when supply and demand become tighter, the stock of available demand 

response resources may not be adequate. 

• Valuation and cost-effectiveness. One of the key challenges for regulatory approval and 

review of demand response is the lack of an adopted method or consensus procedure for the 

evaluation and definition of cost-effectiveness. The cost-effectiveness tests that were 

developed to assess demand-side management in the 1980s and 1990s162 focus on avoided 

 159 Richard Tempchin (EEI), FERC Technical Conference, transcript, 26-27. 

160 Measurement issues are less for interruptible/curtailable tariffs because the tariffs generally specify the level of 

demand reduction or specify the level to which the facility demand must not exceed during an event. 

161 A review of baseline methods can be found in Xenergy, “Protocol Development for Demand Response 

Calculation,” prepared for the California Energy Commission, Contract 400-28-002, August 2002. 

162 The most recent version of tests that were developed in the 1980s is California Standard Practice Manual: 

Economic Analysis of Demand-Side Programs And Projects, State of California, Governor’s Office of Planning and 
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generation costs and are inadequate to capture the additional market and reliability benefits 

that demand response can bring to retail and wholesale markets. Several ISO/RTOs have 

attempted to evaluate the cost-effectiveness of demand response in their yearly evaluations, 

but there is no consistency among them. The Demand Response Resource Center is 

conducting a comprehensive evaluation and results from this research should be available in 

late 2006.163

• Delayed payments to demand response providers. One problem in ISO/RTO markets is the 

delayed processing and disbursement of payments for demand reductions. ISOs typically wait 

60 days or more to finalize settlements. Customers and curtailment service providers object 

that this delay creates cash flow problems. 

• Customer inertia/desire for simplicity. Most customers (particularly residential ones) will 

be resistant to programs if they require effort, such as when the basic design of the program is 

not simple. Focusing these educational efforts first on the largest customers will allow these 

customers to adequately assess the rewards and costs associated with participation in demand 

response programs. Experience in other states such as New York and California (which use 

some system benefit funds for customer education) has shown that targeted customer 

education and training increases participation and response rates. 

• Focus on single time-based rate program structures. Because of their different needs and 

knowledge levels of how to respond, as well as their varying abilities to respond, customers 

need targeted and ongoing training and education to help them understand how to increase 

their response rates to demand response programs. Customer price-responsiveness varies 

significantly by market segment among commercial and industrial users. The differences in 

customers’ ability to respond at peak times and the degree to which they are able or willing to 

respond implies that policy-makers need to create a portfolio of dynamic pricing products 

from which customers can choose and offer different incentives to different types of 

customers. 

• Need for simple and fair time-based pricing. The principles of simplicity and fairness are 

keys to the success of real-time programs. UtiliPoint found that “as long as customers are 

convinced that utility-posted prices are fair and reflect actual system circumstances, and are 

based on competitive markets, they will accept them as the basis for time-varying rates.”164 

This seems to be a common refrain from satisfied customers. Customers notified by various 

means about daily prices and price spikes achieve better responses and are more satisfied with 

the programs. Both in re-regulated electricity markets and traditional utility territories, 

multiple notification channels (such as toll-free numbers, pagers, cell phones, and the Internet) 

increase success rates of RTP programs. Customers’ use of programmable communicating 

thermostats is important for easier response to these rates. 165

• Mandatory vs. voluntary participation in price-based programs. Experience has shown 

that when participation in price-based programs is voluntary, the level of customer 

participation and aggregate load reductions have been modest.166 Voluntary TOU or RTP 

programs with opt-in can create a self-selection bias problem from the perspective of some 

LSEs: customers who know they already use less at peak enroll, while those who use more at 

peak but who may not want to risk shifting or paying higher peak prices do not. Thus, little or 

 Research, July 2002, http://drrc.lbl.gov/pubs/CA-SPManual-7-02.pdf. 163 See http://drrc.lbl.gov/drrc-ron-7-21-05.html 164 Bernie Neenan, “Taxonomy of Time-Varying Pricing Designs,” UtiliPoint IssueAlert, March 29, 2006), 4. 

165 Patti Harper-Slaboszewicz, “Analysis of Time-Based Retail Pricing for Smaller Customers,” presentation at 

“American Utility Week” Conference, Atlanta, GA, April 25, 2006. 166 Charles Goldman, “Does Real-Time Pricing Deliver Demand Response?,” New England Restructuring 

Roundtable 2005, 7, 11. 
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no load is shifted from peak, defeating the purpose of the program. In addition, since most 

voluntary time-based rate programs are designed to be revenue neutral (i.e., on- and off-peak 

rates designed to collect the same revenue as the non-TOU default tariff from a hypothetical 

customer), customers with below average on-to-off-peak consumption ratios are free riders 

who can reduce their bills by taking the TOU rate option without changing their consumption 

behavior. The revenue shortfall can have undesirable consequences and possibly create 

revenue losses for LSEs.167 Customers tend to stay in voluntary programs with clear opt-out 

options. Customer responses to well-designed, simple programs they perceive as fair are high: 

they want to stay in the programs, and felt they achieved savings and control. Experience in 

California suggests that customers especially like dynamic pricing programs that pair 

automated customer technologies. Customers with access to smarter appliances and systems 

thought they became more aware of their energy use and costs as well as their routines at 

home and at work.168 

• Varying willingness among utilities to work with third parties. A 2005 demand response 

survey found dramatic differences among traditional IOUs, co-ops, and municipal electric 

utilities (munis) in their preferences in partnering with third parties.169 Co-ops, which believe 

they already have a higher interest in using demand response to lower their customers’ bills, 

have a high negative response to using third parties. It is likely that the best fit for third-party 

involvement may be in organized markets where third parties can aggregate load across IOUs 

or where aggregators can offer one program design for large companies with multiple 

locations. Third parties may offer models to bridge that gap for customers served by 

traditional utilities. 

Demand Response Activities at the State, Regional and Federal 

Level 

While the trend in utility investment and activity in demand response over the last decade has been 

downward, there has been a recent upsurge in interest and activity in demand response nationally and, 

in particular, regional markets.170 A recent study stated, “the resurgence of demand response programs 

stems directly from their rediscovered value as a dual hedge against both reliability risks such as 

generation shortfalls and transmission congestion, as well as financial risks such as wholesale price 

spikes.”171 This upsurge has been the result of several factors. First, tight supply conditions in densely 

populated regions such as California, New York, and the Chicago area created a need for resources 

that could be quickly deployed. Second, the development of organized markets within ISOs or RTOs 

created an interest and need for demand response resources. These ISOs/RTOs created programs to 

coordinate and encourage demand response programs offered by unregulated providers and utilities. 

These programs have been found to be effective, and have had a far larger impact on market prices 

 167 Chi-Keung Woo et al., “Pareto-superior time-of-use rate option for industrial firms,” Economics Letters (1995), 

267-272. 

168 A post-pilot analysis of California’s statewide pricing program described 87 percent of pilot customers who 

perceived program as fair; many stayed on the rate after the pilot was over, although they then paid for the enabling 

equipment they were given during the pilot. George & Faruqui, CRA (March 2005), 13. 

169 UtiliPoint, Outlook, 26-37. 

170 Note that the EIA and NERC data sources may not be capturing this upswing because they do not collect 

information from unregulated demand-response providers or ISOs/RTOs. The discussion in Chapter V indicates that when 

ISO programs are included, total resource contribution from demand response stabilized beginning in 2000. 

171 Research Reports International, Demand Response Programs, 2005, 6. 
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than the costs avoided or incurred by the individual participating customer and the ISOs/RTOs.172 

Third, state legislation or regulatory initiatives in many states have provided additional investment or 

requirements for additional demand response. 

Activities at the state and regional level are extremely important to increasing the level of priceresponsiveness in markets and promoting demand response. A recent CERA study found a “direct 

correlation ... between the levels of regulatory support for implementing DSM programs and the level 

of energy savings achieved by the state’s utilities.”173 State activities can include direct investigations 

into demand-side issues, including demand response, time-of-use rates, and the feasibility of advanced 

metering. Important activities can also include state regulatory re-examination of utilities’ return 

structure for investment in demand response and advanced meters. 

State policies already distinguish a full range of demand-side tools to meet their energy needs beyond 

demand response defined only as load-curtailment, including energy efficiency, distributed generation, 

industrial response, and price-based demand response programs.174 Several states have initiated 

proceedings in response to EPAct 2005 Section 1252(b) on time-based metering and communications. 

 

Section 1252 (g) (4)(A)-(B) directed states to commence consideration by August 2006, and to 

complete consideration by a year later.175 Many states have opened these proceedings; others, by 

virtue of related proceedings opened within the three years prior to the passage of EPAct 2005, can 

count those as qualifying. 

Other examples of state policies and regional cooperation include: 

• The CPUC and the California Energy Commission are promoting demand response and 

advanced metering through its Statewide Pricing Pilot, Advanced Metering Initiative, and 

Energy Action Plan II. The Action Plan creates a “loading order” to meet capacity, which 

places demand response and energy efficiency goals before generation additions; those begin 

with renewable energy.176 The CPUC has required investor-owned utilities to meet five 

percent of their load requirements with demand response.177 While the CPUC rejected critical 

peak pricing as the default rate for commercial and industrial customers, it will re-examine it 

in utility rate cases to focus more on residential customers.178

• The Connecticut legislature passed “An Act Concerning Energy Independence” in July 2005, 

followed by recommendations from the Connecticut Energy Advisory Board. The 

Connecticut Energy Advisory Board advocated for the state to set goals to reduce its peak 

demand 10 percent by 2010; promote the increased development of demand response; develop 

and offer time-of-use rates, interruptible/curtailable tariffs, and advanced meters (beginning 

 172 For example, ISO-NE, Independent Assessment of Demand Response Programs of ISO New England Inc., 

Docket No. ER02-2330-040. 

173 Hope Robertson, Cambridge Energy Research Associates (CERA); Focusing on the Demand Side of the Power 

Equation: Implications and Opportunities (Private Report), Cambridge, MA: CERA, May 2006, 12. 

174 For example Connecticut is offering financial incentives for industrials to use onsite non-grid connected 

distributed generation, including CHP, under its Energy Independence Bill, July 21, 2005. 

175 EPAct 2005 section 1252(g)(4)(A)-(B). 

176 Sandra Fromm, et al., Implementing California’s Loading Order For Electricity Resources. California Energy 

Commission Staff Report, July 2005. 

177 CPUC Decision (D.) 03-06-032, June 2003. 

178 Platts Megawatt Daily, May 30, 2006, 8-9 and SNL Energy Power Daily, May 26, 2006, 4. 
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with customers whose demand is more than 350 kW); and offer seasonal rates and aggressive 

education on energy efficiency, costs, and demand management to all customers.179 

• New York, Texas, and California are examples of states that worked deliberately to coordinate 

policy across multiple agencies and stakeholders. In New York, this entails coordination 

between New York State Energy Research and Development Authority (NYSERDA), the 

NYISO, the NYPSC, and New York Department of Environmental Resources. While for 

those states, the ISO, the state, and the retail regulatory agency are nearly geographically the 

same, lessons about policy coordination across stakeholder agencies and jurisdictions are 

important for other areas where jurisdictional overlap or confusion impedes policy changes. 

• Regional coalitions representing stakeholders from utilities, state public utility commissions, 

federal regulatory agencies, technology developers, metering companies, and third-party 

providers have been working together in the Mid-Atlantic (MADRI) and New England 

(NEDRI, Massachusetts Energy Technology Collaborative) states to find ways to collaborate 

on promoting demand response and advanced metering. 

• State funding of programs, enabling technologies, and education, can advance these 

initiatives: “two state agencies – NYSERDA in New York and the CEC in California – have 

been conspicuous leaders in the demonstration of demand response (demand response) 

programs utilizing enabling technologies.”180

• State policies on standard offer service or “provider of last resort” (POLR) have increased the 

number of customers exposed to RTP and time-based rates and pricing. The default tariff rate 

for the largest customers in New Jersey and Maryland is currently a direct pass-through of the 

PJM real-time price. Similarly, large customers in National Grid USA’s New York territory 

have been exposed to real-time prices since 1998.181 The NYPSC recently directed utilities to 

file draft tariffs that would make real-time hourly pricing mandatory for their largest customer 

classes already subject to mandatory time-of-use rates.182 The law further requires that 

voluntary time-of-use rates be available for New York residential customers.183 

Another key development is that third-party providers have emerged whose only business is to 

maximize demand response and use related technologies. They aggregate and deliver load-response to 

markets, and have skills needed to monitor energy markets and prices. These third parties provide a 

valuable service to customers, because many large consumers have limited expertise or experience 

with aggregating or managing demand response, especially in markets. An Lawrence Berkeley 

National Laboratory survey showed that 70 percent of business managers in Niagara Mohawk’s RTP 

program rarely or never monitored next-day hourly prices; only 17 percent consulted prices routinely; 

13 percent only checked day-ahead hourly prices when other signals (such as NYISO events or very 

hot weather) suggested they would be high.184 Most businesses monitor their own business, not the 

energy business. 

 179 Connecticut, PA 05-1: An Act Concerning Energy Independence. 180 Charles Goldman, Michael Kintner-Meyer, and Grayson Heffner, Do "Enabling Technologies" Affect Customer 

Performance in Price-Responsive Load Programs? Lawrence Berkeley National Laboratory: LBNL-50328, August 2002, 3. 

181 Galen Barbose et al., LBNL-57661. 

182 Case 03-E-0641, “Proceeding on motion of the Commission regarding expedited implementation of mandatory 

hourly pricing for commodity service, Order instituting further proceedings and requiring the filing of draft Tariffs,” 

September 23, 2005. 

183 N.Y. Pub. Serv. Law § 66(27). 

184 Charles Goldman, October 28, 2005. 
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Examples of third-party providers and the services and innovative practices that they conduct include: 

 Comverge is a vendor of smart, or programmable, communicating thermostats. These are 

replacing DLC equipment from utility legacy programs, or being installed fresh. These 

thermostats can be used to support time-based rate programs such as critical peak pricing. 

 EnerNOC is a curtailment-service provider (CSP) or load aggregator for emergency demand 

response. EnerNOC has aggregated load reductions in the commercial buildings sector, and 

has sold these reductions into ISO/RTO emergency demand response and capacity programs. 

It has systems installed in New England, California, and New York. Participating businesses, 

office buildings, and other medium-sized participants benefit through lower bills or rebate 

checks.185

 Consumer PowerLine (CPLN) is another aggregator that has been innovative in working with 

urban multiple-family buildings as well as with commercial and industrial customers. It 

aggregates pools of electricity from clients, creating a virtual power plant that local utilities or 

ISOs can call on with a half-hour’s notice. 

The federal government also has been supportive of demand response. DOE has funded multiple 

projects, which included analyses of the value of demand response, research and development on 

technologies such as automated controls,186 and support for regional examinations of demand response 

and distributed resources (such as MADRI). The Federal Energy Management Program has 

incorporated advanced metering and demand response directly into policies and procedures that it 

expects federal facility managers to consider.187 The GAO examined demand response in two reports 

in 2004 and 2005. 

 185 CNet news.com., April 29, 2005. 

186 The Pacific Northwest National Laboratory began a pilot called “Gridwise” in January 2006, involving about 

300 volunteers and 200 homes. Gridwise supports a regional initiative to test and speed adoption of new smart grid 

technologies that can make the power grid more resilient and efficient. The homes in the pilot receive real-time price 

information through a broadband Internet connection and automated equipment that adjusts consumers’ energy use based on 

price. Some customers also have computer chips embedded in their dryers and water heaters that can sense when the power 

transmission system is under stress and automatically turn off certain functions briefly until the grid can be stabilized by 

power operators. 

187 EnergyBizInsider, “Letters from Readers”, Apr. 5, 2006, letter from Kevin Myles, GSA. 
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Chapter V. Demand Response as a Resource188

This chapter addresses the third area, in EPAct section 1252(e)(3), that Congress directed the 

Commission to consider: 

(C) the annual resource contribution of demand resources; 

This chapter develops an estimate of the annual resource contribution of demand resources in the 

United States of about 37,500 MW, and discusses the potential for demand response as a resource for 

utilities and load serving entities.189 Information on demand response programs and time-based rates 

collected in the FERC Demand Response and Advanced Metering (FERC Survey) forms the basis for 

this estimate. 

This chapter is organized into three sections: 

• Description of the resource contribution information on demand response programs collected 

in the FERC Survey 

• Demand response resource contribution estimates from the FERC Survey 

• Commission staff estimates of resource contribution from existing programs 

FERC Survey: Demand Response Program Information 

The FERC Survey collected comprehensive information from entities on their demand response 

programs and time-based rates and tariffs. The survey allowed respondents to provide information on 

up to eight demand response programs/tariffs for each customer class.190 When a particular 

program/tariff was applicable to more than one customer class (e.g. industrial and commercial), 

respondents were asked to enter the relevant information for each customer class. For wholesale 

customers, data collected included: enrolled load (in MW) and program design information such as 

minimum reduction, response time, and others. 

For each program and/or tariff, respondents were requested to provide a short description of features, 

number of customers enrolled, maximum demand (in MW) of enrolled customers, potential peak 

reductions (in MW), and actual peak reductions (in MW).191 The FERC Survey defines information 

on demand response potential for demand response programs or time-based tariffs as: 

 188 Chuck Goldman and Ranjit Bharvirkar of Lawrence Berkeley National Laboratory assisted with the drafting of 

this chapter. 

189 Chapter VI continues this discussion of the potential for demand resources for regional planning and explores 

how demand resources can be analyzed and included in regional planning and transmission expansion and operation. 

190 Customers were classified as residential, commercial, industrial, transportation, and other. 

191 Wholesale entities were not required to report demand response program information by customer class; thus 

they are treated as a separate category in addition to residential, commercial, industrial, and other customers. From program 

evaluations conducted by several Independent System Operator/Regional Transmission Organizations (ISOs/RTOs), 

industrial and commercial customers account for the bulk of enrolled load, although Curtailment Service Providers (CSPs) 

and Load Serving Entities (LSEs) are allowed to aggregate load reductions from residential customers to participate in 

ISO/RTO demand response programs. However, it was not possible to develop estimates by customer class for each 

ISO/RTO. 
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Potential Peak Reduction (PPR): The potential annual coincident peak load reduction (as measured in 

MW) that can be deployed from demand response programs, rates and tariffs that coincides with the 

annual system peak load of the entity (see Figure V-1 which shows a stylized example for a mediumsized utility with a large demand response program).192 The survey asked respondents to provide PPR 

as of the end of 2005. This quantity reflects the installed load reduction capability and represents the 

load that can be reduced either by the direct control of the utility system operator or by the customer in 

response to a utility request to curtail load. PPR forms the basis for the estimates of resource 

contribution requested by Congress. 

Actual Peak Reduction (APR): The coincident reductions to the annual peak load (as measured in 

MW) in 2005 achieved by customers that participate in a demand response program that coincides 

with the annual system peak of the utility or Independent System Operator (ISO). 

The PPR values provided by entities for the various customer classes and enrolled load information 

provided by wholesale market entities (e.g., ISOs) serve as the primary basis for estimating the annual 

resource contribution of demand response resources. Commission staff developed estimates of the 

annual demand response resource contribution for various United States regions and by type of entity, 

along with comparisons of actual peak reductions vs. potential peak reduction capability. 

Figure V-1. Schematic representation of demand response potential peak 

reduction for a demand response program 

0

1000

2000

3000

4000

5000

6000

7000

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

Hours of the day

Maximum Demand of

Enrolled Customers (MW)

Non-Discretionary

Load

Discretionary Load

Load 

Curtailment

Utility

System

Peak

Total Load

Source: Federal Energy Regulatory Commission 

The following sections present estimates for resource contribution. First, the report summarizes the 

results from the FERC Survey for PPR. Second, it estimates resource contribution by combining data 

from the FERC Survey with publicly available information on demand response capacity. The FERC 

 192 The entity can be an investor-owned utility, a cooperative utility, a political sub-division, a municipal utility, a 

municipal marketing authority, a federal or state utility, an ISO or an RTO, a power marketer, or a curtailment service 

provider. 
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Survey results were supplemented with the additional information because, after reviewing the data 

provided by survey respondents, it became clear that the FERC Survey results alone should not be 

utilized to estimate the annual demand response resource contribution because of various data quality 

issues (e.g., non-response, missing data on demand response potential). 

FERC Survey Results: Demand Response Resource Estimates 

Potential Peak Load Reduction of Demand Response Programs and 

Time-Based Rates 

The total potential peak reduction for all regions and customer classes is 29,655 MW (see Figure V-2) 

based on the FERC Survey data. This represents approximately four percent of the total United States 

projected electricity demand for summer 2006 (743,927 MW).193 The Reliability First (RFC) region 

accounts for the largest share of potential peak reduction for existing demand response resources (24 

percent) followed by the Midwest Reliability Organization (MRO) and SERC Reliability Corporation 

(SERC) regions (approximately 16 percent each).194

Wholesale demand response programs195 (primarily operated by ISOs and RTOs) account for about 30 

percent of the total demand response resource potential peak reductions nationally and about 50 

percent or more of regional resource contribution in three regions: Electricity Reliability Council of 

Texas (ERCOT) (80 percent); RFC (55 percent); and the Northeast Power Coordinating Council 

(NPCC) (49 percent). In contrast, wholesale demand response programs account for only about six 

percent of the potential peak reduction in the MRO and five percent in SERC. 

Demand response programs/tariffs targeted to industrial customers provide 32 percent of the total 

national demand response resource potential. This potential is concentrated in two regions – SERC 

(73 percent of total regional potential) and MRO (57 percent). Residential customers account for 

about 20 percent of total demand response resource potential nationally and represent nearly 1,000 

MW or more in several regions (Florida Reliability Coordinating Council (FRCC), MRO, RFC, and 

the Western Electricity Coordinating Council (WECC)). In the FRCC region, residential customers 

provide 58 percent of the regional demand response resource potential. Commercial customers 

account for about 16 percent of the demand response resource potential at a national level. 

Investor-owned utility-operated demand response programs and time-based tariffs account for 44 

percent of total national demand response resource potential (see Figure V-3). The second largest 

contributors of demand response resource are ISOs and RTOs (24 percent). Cooperative utilities 

(including political sub-divisions)196 and federal/state utilities each provide approximately 13 percent 

of the demand response resource potential. Most of the demand response resource for federal and state 

utilities is available from industrial customers (66 percent of total potential from companies in this 

category); in contrast, residential and commercial customers provide about 43 percent of the demand 

response potential for cooperative utilities and political sub-divisions. 

 193 NERC, 2005 Long-term Reliability Assessment, September 2005. 

194 The report includes a complete listing and map of the NERC regions in Chapter I. 

195 In wholesale demand response programs, retail companies aggregate individual customer load reductions and 

sell or provide the reductions to the wholesale provider. 

196 While Commission staff tracked responses from electric cooperatives and political subdivisions in the FERC 

Survey, this report combines results due to their similarity. 
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Figure V-2. Demand response potential peak reduction by region and 

customer class

0

2000

4000

6000

8000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 

Figure V-3. Demand response potential peak load reduction by type of 

entity and customer class 

0

3000

6000

9000

12000

15000

InvestorOwned UtilityCooperative

Utility and

Political Subdivision

Municipal

Utility and

Municipal

Marketing

Authority

Curtailment

Service

Provider and

Power

Marketer

Federal and

State Utilities

ISO/RTO

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

Source: FERC Survey 
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83

Electric industry participants were also asked to provide information in the FERC Survey on the type 

of demand response programs or time-based tariffs offered to customers.197 The results are displayed 

in Figure V-4. Interruptible/curtailable tariffs account for about 7,504 MW of demand response 

resource potential (27 percent of the total national potential), followed closely by direct load control 

(DLC) (24 percent). Most of the potential peak reduction associated with interruptible/curtailable 

tariffs is available from industrial customers (84 percent of total interruptible/curtailable potential), 

while most of the DLC resource is available from residential customers (84 percent of the total direct 

load potential). In contrast, a significant share of the demand response resource potential in ancillary 

services, capacity market programs, demand bidding, and emergency demand response programs are 

provided by wholesale customers of ISOs and RTOs. Respondents indicated that a number of demand 

response programs/tariffs, primarily targeted to industrial and commercial customers, had more than 

one type of program feature; these entries were classified in the “Multiple” category after review of 

data quality. 

Figure V-4. Resource potential of various types of demand response 

programs and time-based tariffs

0

2000

4000

6000

8000

Interruptible

Direct Load Control

Emergency Demand Response

Capacity

Ancillary Services

Demand Bidding

Multiple

Other

Real-Time Pricing

Critical Peak Pricing

Time-of-Use

Potential Peak Reductions (MW)

ISO/RTO

Other (Agriculture)

Industrial

Commercial

Residential

Incentive-based DR Programs Time-based 

Tariffs

Source: FERC Survey 

 

Based on responses to the FERC Survey, time-varying pricing tariffs (includes time-of-use, real-time 

pricing, and critical peak pricing) comprise only five percent of the total demand response resource 

potential. However, it is likely that the reported PPR values for time-based tariffs, particularly timeof-use rates, are too low for several reasons. First, 67 percent of the survey respondents that stated 

that they offered time-of-use type programs only provided data on the number of customers signed up 

for the tariff, and were unable to provide a demand response resource potential value. Second, it is 

more difficult for respondents to accurately estimate the demand response potential for customers on 

 197 See Chapter IV for a detailed discussion of the various demand response program and time-based rate types. 
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time-varying tariffs because estimates of customer demand elasticities are typically required.198 It is 

unclear what methods respondents used to estimate demand response potential for customers on timevarying tariffs. However, it is clear that demand response resource potential reported by respondents 

for time-of-use tariffs significantly underestimates this quantity because of missing data for PPR 

values. 

Actual vs. Potential Peak Reductions of Demand Response Programs 

and Time-Based Rates 

Potential versus actual peak load reductions for demand response programs for each reliability region 

in Figure V-5. In interpreting information on actual peak reductions of demand response programs or 

time-based tariffs, it is important to recognize that: (1) certain types of demand response programs 

(interruptible/curtailable tariffs, emergency demand response programs, and DLC) are often only 

called on during system emergencies, which are infrequent and do not occur each year because they 

are dependent on weather and system conditions; (2) activity levels in “economic” demand response 

programs (e.g., demand bidding) are influenced by the volatility and level of electricity commodity 

prices; (3) demand response program design features influence customer response (e.g. penalties for 

non-performance); and (4) most utilities do not routinely track or estimate actual peak reductions for 

customers on time-based rates as measurement and evaluation studies are required – consequently, 

survey non-response is an issue for time-based rates. On a national basis, respondents to the FERC 

Survey reported about 8,716 MW of actual peak reductions in 2005. Although the RFC region has the 

largest existing demand response resource potential (see Figure V-2), respondents reported that 

demand response programs and price-based tariffs in the MRO, WECC and SERC regions accounted 

for the largest number of MWs actually deployed in 2005 (see Figure V-5). The ratio of actual to 

potential peak load reductions for demand response programs was between 40-50 percent in three 

regions (FRCC, MRO, and WECC). 

It is important to note that ISO/RTOs did not report actual peak load reductions in the FERC Survey, 

which potentially leads to underestimates of actual peak reduction for those regions with significant 

wholesale demand response programs.199

In Table V-1, the median value of the ratio of actual to potential peak reductions is presented for 

various types of demand response programs. Among the sample of DLC programs, the actual peak 

load reduction in 2005 is 56 percent of the potential peak reduction for the typical (i.e., median) 

program.200 For interruptible/curtailable tariffs, the actual peak load reduction is lower: median value 

of 39 percent of the potential peak reduction.201 These results suggest that a DLC program (because 

the utility has some control over the customer’s end use equipment) may offer a more predictable 

 198 Customer demand models require hourly interval usage data, retail prices, and information on customer 

characteristics. 

199 PJM reported a maximum hourly reduction of 205 MW out of 1,619 MW of emergency demand response 

resource and 226 MW out of 2,210 MW of economic resources. ISO-NE reported a total energy reduction of 66,251 MWh 

from 472 MW of demand response resources enrolled in various programs. (Reference: State of the Market Reports for PJM 

and ISO-NE. ERCOT reports that Load Acting as a Resource (LAAR) provided 4,637 GWh in 2005 and received $71.1M in 

payments (S. Krein, “Load Participation in ERCOT Ancillary Services Markets,” April 18, 2006, AESP Brown Bag 

Seminar). 

200 Another interpretation is that the median value of 0.75 (or 75 percent) indicates that exactly half of the demand 

response programs targeted to residential customers have the ratio of APR to PPR greater than 0.75 in 2005. 

201 Customers on I/C tariffs typically initiate and control load curtailments when events are called by the utility (in 

contrast to residential customers in DLC programs); most I/C tariffs include penalties for non-performance. 
Chapter V – Demand Response as a Resource 

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Figure V-5. Demand response resource potential versus actual deployed 

demand response resources by region

0

2000

4000

6000

8000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Peak Redutions (MW)

Potential Peak Reduction

Actual Peak Reduction

 Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 

Table V-1. Ratio of actual deployed demand response resource to demand 

response resource potential by program type 

Program Feature Sample 

Size 

Median 

Value 

Direct Load Control 440 .56 

Interruptible/Curtailable 195 .39 

Emergency Demand Response 25 .01 

Capacity Programs 10 .14 

Demand Bidding 12 .10 

Source: FERC Survey 

demand response resource than other demand response programs that rely on customers to respond to 

events or calls. The actual vs. potential peak load reduction is significantly lower (less than 15 

percent) for other demand response programs such as emergency demand response programs, capacity 

market, and demand bidding; these results should be interpreted with caution as sample sizes are small 

(25 or fewer entities reporting). 

Table V-2 shows median values for the ratio of actual to potential peak load reductions for different 

types of entities that responded to the FERC Survey. The ratio of actual to potential peak load 

reductions was somewhat higher among customers enrolled in demand response programs offered by 

the typical cooperative and municipal utility (0.66 and 0.65) compared to an investor-owned utility 

(0.40). This result suggests that municipal utilities and cooperatives, as a group, tended to call or rely 

on their demand response programs in 2005 more than investor-owned utilities and/or that actual 

performance during events was closer to customers’ subscribed load reductions. 
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Table V-2. Ratio of actual demand response peak reduction versus 

potential peak load reduction 

Type of Entity Sample Size Median 

Value 

Investor-owned Utility 74 0.40 

Co-operative Utility or Political Sub-division 209 0.66 

Municipal Utility or Municipal Marketing 

Authority 91 0.65 

Curtailment Service Provider or Power Marketer 9 0.37 

Source: FERC Survey 

Existing Demand Response Resource Contribution 

In this section, estimates of the existing demand response resource contribution for the United States 

drawing upon an analysis of FERC Survey responses and other sources (e.g., EIA Form 861, 

ISO/RTO demand response program evaluations) are presented.202 Nationally, existing demand 

response resource contribution of 37,552 MW is estimated. This represents approximately five 

percent of the total United States projected electricity demand for summer 2006.203 A breakdown of 

resource contribution by reliability regions is shown in Figure V-6. The three regions with the largest 

demand response resource contribution to the national total are RFC (22 percent of the total national 

potential) followed by SERC (21 percent) and MRO (16 percent). The demand response potential 

reported by entities in the RFC, SERC, and MRO reliability regions ranges from about 6,000 to over 

8,000 MW in each region. 

Given that peak loads vary significantly among reliability regions, it is also useful to characterize the 

existing demand response potential capability relative to each region’s summer peak demand. 

Demand response resource potential ranges from three to seven percent in most NERC reliability 

regions, with the notable exception of the MRO region. The demand response resource potential 

reported by utilities in the MRO region as a share of the region’s summer peak demand is significantly 

higher (20 percent) compared to other reliability regions. Since the MRO value is significantly higher 

than the other regions, an exploratory analysis was conducted in an attempt to understand and offer 

possible explanations for this somewhat surprising result. First, several states (Minnesota and Iowa) in 

the MRO region currently have or previously had laws that required utilities to invest a certain 

percentage of revenues in demand side management programs (1.5-2 percent), which contributed to 

demand response resource development. Utilities in this region have made significant investments in 

residential DLC programs, including both air conditioning and water heating programs. Second, 

utilities in the upper Midwest have historically had favorable rules that allowed load management 

resources to be counted towards meeting reserve requirements. Third, the characteristics of the 

customer base in the region, particularly among industrial customers, may be relatively more favorable 

 202 Commission staff chose to draw upon additional sources for the resource contribution estimate because of data 

quality issues associated with the potential peak reduction estimates in the FERC Survey. These issues included: nonresponse to the survey, missing or partial responses to the potential peak reduction questions, and possible double-counting. 

These issues and how the various data quality checks and corrections that the Commission staff utilized are discussed at 

greater length in Appendix F. 

203 NERC, 2005. 
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Figure V-6. FERC staff estimate of existing demand response resource 

contribution 

0

2000

4000

6000

8000

10000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

As Percent of 

Projected 

Summer 2006 

Peak Demand

3% 4% 7% 4% 20% 6% 4% 5% N/A

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 

to demand response resource development (e.g. steel plants and processes that can be interrupted). 

Utilities in the MRO region report that interruptible/curtailable tariffs are particularly popular among 

their large industrial customers. 

In Figure V-7, the demand response potential reported by electric industry participants are presented 

using the previous boundaries for NERC Reliability Regions, prior to recent consolidations. This may 

facilitate comparison between previous industry (NERC) and government (EIA) studies that have 

assessed demand response capability. 

Investor-owned utilities account for about 47 percent of the total demand response resource 

contribution on a national basis, followed by ISO/RTO demand response programs, which account for 

about 19 percent of the national demand response resource contribution (see Figure V-8). 

Results from the FERC Survey supplemented with data from other sources indicate that almost 530 

entities operate at least one demand response program/tariff. These programs vary substantially in 

their design and features and also by their sheer size. The top 25 retail entities with the largest demand 

response programs account for about 56 percent of the national total demand response resource 

contribution, while the top 50 retail entities account for about 73 percent of the demand response 

resource contribution (see Table V-3). This means that less than 10 percent of all retail entities with 

demand response programs/tariffs provide almost three-fourth of the total demand response 

resource.204

 204 ISO and RTOs, as wholesale entities, are excluded from this analysis; PJM, NYISO, and ISO-NE, together 

provide approximately 8,500 MW of demand response resource potential. 
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Figure V-7. FERC estimate of existing demand response resource 

contribution using old NERC region definitions 

0

2000

4000

6000

8000

ERCOT FRCC MAPP NPCC MAIN ECAR MAAC SERC SPP WECC Other

Resource Contribution (MW)

Wholesale

Other (Agriculture)

Industrial

Commercial

Residential

MRO MRO, RFC, RFC

SERC

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 

Figure V-8. FERC staff estimate of existing demand response resource 

contribution by entity type and customer class 

0

4000

8000

12000

16000

20000

InvestorOwned UtilityCooperative

Utility and

Political Subdivision

Municipal

Utility and

Municipal

Marketing

Authority

Curtailment

Service

Provider and

Power

Marketer

Federal and

State Utilities

ISO/RTO

Potential Peak Reductions (MW)

Wholesale 

Other (Agriculture)

Industrial

Commercial

Residential

Source: FERC Survey 
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Table V-3. Demand response resource contribution of the largest retail 

entities. 

 Retail 

Entities 

Potential Peak 

Reductions 

(MW) 

Percent of Total 

Potential Peak 

Reductions 

Top 25 15,172 56 

Top 40 18,344 69 

Top 50 19,947 73 

Source: FERC Survey 

Note: These figures do not include demand response programs operated by ISOs and RTOs. 
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Chapter VI – Role of Demand Response in Regional Planning and Operations 

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Chapter VI. Role of Demand Response in Regional 

Planning and Operations205

This chapter addresses the fourth and fifth area Congress directed the Commission to consider in 

EPAct section 1252(e)(3): 

(D) the potential for demand response as a quantifiable, reliable resource for regional 

planning purposes; and 

(E) steps taken to ensure that, in regional transmission planning and operations, demand 

resources are provided equitable treatment as a quantifiable, reliable resource 

relative to the resource obligations of any load-serving entity, transmission provider, 

or transmitting party. 

Demand response is an important, reliability resource for the power system in the United States. As 

was reported in Chapter V, there is approximately 37,500 MW of existing demand response potential 

in the United States, which represents roughly five percent of the peak load; large enough to be “real” 

but still relatively small. These resources are factored into regional resource planning and 

transmission enhancement planning either explicitly or implicitly as modifiers to the load forecast in 

most regions. Demand response resources currently supply ancillary services and efforts are 

underway to allow them to supply more. However, sole and explicit use of demand response as an 

alternative to transmission expansion is extremely rare. 

The primary focus of this chapter is on the integration of demand response resources into regional 

planning, with a significant focus on the role of these resources in regional transmission planning and 

operation. 

This chapter is organized into six sections: 

• Potential for demand response for regional planning 

• Transmission planning process and demand response 

• Regional treatment of demand response 

• Examples of projects that incorporate demand response into regional transmission planning 

• Concerns and obstacles 

• Steps that could be taken to ensure that, in regional transmission planning and operations, 

demand resources are provided equitable treatment 

Potential for Demand Response for Regional Planning 

Demand response can play a role in regional planning. This role is examined in the following 

discussion on regional planning in general and in the more detailed discussion on regional 

transmission expansion planning and operations in the remainder of this chapter. The goals of 

regional planning include, but are not limited to: ensuring that all customers have access to service, 

maintaining a reliable electricity supply, maximizing economic benefits, and/or minimizing costs. The 

 205 Brendan Kirby of Oak Ridge National Laboratory assisted in the drafting of this chapter. 
Chapter VI – Role of Demand Response in Regional Planning and Operations 

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application of these goals varies depending on specific regional load requirements, available 

generation mix, customer interest, and state and regional policies. 

Historically, most regions of the United States satisfied their load requirements through generation and 

transmission planning activities conducted by individual utilities. Beginning in the 1980s, many states 

such as California, Hawaii, Nevada, New York, Ohio, and others adopted integrated resource planning 

procedures and requirements to formalize these planning efforts, to ensure full examination of a 

variety of resources, and to allow regulator and public input into resource planning. These utilityintegrated resource plans were typically prepared by individual utilities, but various states, such as 

California, engaged in statewide resource planning exercises. The use of resource planning at a larger, 

multi-state regional scale is limited,206 but in recent years its use has expanded with the development 

of Independent System Operators/Regional Transmission Organizations (ISOs/RTOs) and other 

entities pursuing broad planning.207 However, such planning is not universal or uniform which 

presents challenges for realization of a truly effective regional plan. 

In the past, traditional resource planning concentrated on supply-side and transmission resources. 

With the advent of integrated resource planning, demand-side options (including various forms of 

demand response such as direct load control) were directly examined and integrated into the planning 

process. The two primary means used to incorporate demand-side measures in an integrated resource 

plan: (a) as an adjustment to the long-term demand forecast; or (b) as an explicit resource. 

Several states require each utility to include demand-side measures as a part of their particular demand 

forecast but not necessarily as an energy resource. Massachusetts includes demand-side measures 

only to the extent that they impact load on infrastructure during peak or critical times.208 Another 

state, Hawaii, includes demand-side management in both the forecasting and resource procurement 

processes. Energy efficiency options play a more important role in Hawaii’s demand-side 

management than options such as load management.209 

Other state legislatures and regulators require utilities to include demand-side measures more directly. 

In California, the California Public Utility Commission (CPUC) introduced a requirement that forced 

each utility to meet three percent of annual system peak demand for 2005 through demand response 

programs. The requirement increases one percent each year until 2007.210 California also includes 

demand-side measures as a resource after utility energy contracts expire. Once the long-term contracts 

that were signed by the California Power Authority during the California crisis expire, each utility 

must employ all possible energy efficiency, demand response, and distributed resources before issuing 

offer requests for supply-side resources. The utility must exhaust all available energy efficiency, 

demand response, and distributed generation resources and prove to the CPUC that the use of fossil 

fuels over renewable resources has justification.211

 206 One notable exception is the regional planning activities of the Northwest Power and Conservation Council 

over the years in the Pacific Northwest. 

207 The role of regional planning is discussed in the Open Access Transmission Tariff (OATT) Reform NOPR 

Docket Nos. RM05-25-000 and RM05-17-000. See Preventing Undue Discrimination and Preference in Transmission 

Service, 71 Fed. Reg. 32,686 (June 6, 2006), FERC Stats. & Regs. ¶ 32,603 (2006). 

208 Regulatory Assistance Project, Regulatory Assistance Project Electric Resource Long-range Planning Survey: 

Massachusetts, July 2003. 

209 Liz Baldwin, Regulatory Assistance Project Electric Resource Long-range Planning Survey: Hawaii, June 

2005. 

210 CPUC Decision (D.) 03-06-032, June 2003. 

211 Regulatory Assistance Project, Regulatory Assistance Project Electric Resource Long-range Planning Survey: 

California, August 2005. 
Chapter VI – Role of Demand Response in Regional Planning and Operations 

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Many other states do not incorporate demand-side measures or demand response in any way. In more 

than 20 percent of the states examined in a survey conducted by the Regulatory Assistance Project, 

demand-side measures were either not required by the state or no incentive existed to include demandside measures in the integrated resource plan.212 The rationale for not requiring the inclusion of 

demand responses varies. Arizona’s rationale is that since it is a net exporter of power, utilities have 

not developed demand response strategies such as real-time pricing, and no incentive exists to 

motivate creation of these measures.213 Maine has not required integrated resource planning, energy 

efficiency, or demand-side projects since it restructured its electric industry. Maine utilities used to 

have demand-side targets, but that ended with restructuring; ISO New England is now the primary 

entity that coordinates regional planning.214 Energy efficiency and load management also are not 

included in integrated resource plans in Kansas, conceivably because supply options often appear to 

make more economic sense to utilities that have demand options. Kansas utilities can sell excess 

power on the wholesale market, and the resulting wholesale revenues can be used to keep regulated 

rates lower. Consequently, demand options are not always considered by the utilities.215

A principal challenge to including demand response measures in an integrated resource plan is how to 

directly model and value these measures. A recent case study conducted by Dan Violette and Rachel 

Freeman for the International Energy Agency provides a comprehensive assessment of the potential of 

demand response resources for regional planning.216 According to Violette and Freeman, for demand 

response resources to be valued correctly within an integrated resource planning framework, resource 

plans must have a sufficiently long time horizon. Demand response can reduce the costs of lowprobability, high-consequence events, but these events may only occur once a decade. The modeling 

and resulting integrated resource plan must also address various uncertainties, such as fuel prices, 

weather, and system factors. By explicitly including the risk factors, demand response can be assessed 

as a risk management tool. 

The Violette and Freeman case study involved creating a model that would allow tradeoffs between 

both supply and demand-side resources. They examined changes in system costs with and without the 

inclusion of demand response resources for a 19-year time horizon. The case study provided an 

estimate of the valuation of demand response resources for the electric system, and included results on 

uncertainty measurements, hourly costs, capacity charges, demand response capacity usage, and loss 

of load, among other things. 

In particular, substantial differences for plans with demand response resources and those without 

existed with regards to hourly costs, capacity charges, and capacity usage. In a simulated case 

comprised of a peak demand day with additional system stresses, the addition of demand response 

reduced the maximum hourly costs by more than 50 percent. Figure VI-1shows a total cost savings of 

$24.5 million. 

 212 These states include: Wyoming, Arizona, Ohio, Kansas, Michigan, Delaware, Pennsylvania, and Maine. 

213 Regulatory Assistance Project, Regulatory Assistance Project Electric Resource Long-range Planning Survey: 

Arizona, July 2003. 

214 Catherine Murray, Regulatory Assistance Project Electric Resource Long-range Planning Survey: Maine, July 

2003. 

215 Liz Baldwin, Regulatory Assistance Project Electric Resource Long-range Planning Survey: Kansas, 

September 2005. 

216 Daniel M. Violette and Rachel Freeman, “Demand Response Resources (DRR) Valuation And Market 

Analysis: Assessing DRR Benefits And Costs,” Summit Blue Consulting, 

http://www.summitblue.com/publications/DRR%20Valuation%20and%20Market%20Analysis.pdf, 2006. 
Chapter VI – Role of Demand Response in Regional Planning and Operations 

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Figure VI-1. Marginal costs savings from demand response resource 

programs

Source: Daniel M. Violette and Rachel Freeman, “Demand Response Resources (DRR) Valuation And Market Analysis: Assessing DRR 

Benefits And Costs,” Summit Blue Consulting, 2006 

A substantial percentage of new capacity charges was deferred due to the availability of demand 

response. The savings amounted to $892 million (2004 dollars) over the 20-year horizon. Capacity 

charge savings were affected by the amount of demand response resources dispatched per year. The 

model reflected a significant deployment of demand response resources once every four years. A 

small amount of demand response resources was used frequently, while use of all available demand 

response resources happened infrequently. Figure VI-2 shows the percent of demand response 

resources used under three different program scenarios: without real-time pricing, with real-time 

pricing, and with critical peak pricing. 

The net present value of the total system cost showed a reduction with the inclusion of demand 

response. The savings in incremental costs were 10 percent for the peak-pricing scenario and 23 

percent for the real-time pricing scenario. 

Violette and Freeman concluded that “overall, this case study shows that a Monte Carlo approach, 

coupled with a resource planning model, can address the value of DRR given uncertainties in future 

outcomes for key variables, and can also assess the impact DRR has on reducing the costs associated 

with low-probability, high-consequence events. In this case study, the addition of DRR to the resource 

plan reduced the costs associated with extreme events, and it reduced the net present value of total 

system costs over the planning horizon.”217 The importance of the results achieved by Violette and 

Freeman in their case study is that demand response resources can be directly incorporated into 

integrated resource planning methods. 

 217 Daniel M. Violette and Rachel Freeman, 2006; DRR refers to demand response resources. 
Chapter VI – Role of Demand Response in Regional Planning and Operations 

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Figure VI-2. Percent of capacity from demand response resources used for 

different percents of time horizon

Source: Violette and Freeman, 2006 

Violette and Freeman also recommended that, in future modeling efforts, care should be taken to 

indicate the specific costs and capabilities of individual demand response and pricing products. 

Greater specificity could have a significant impact on model results and could reduce the costs of 

implementing demand response products without affecting system benefits. In addition, the model 

limited competition of demand response resources to only combustion turbines. Upon inspection of 

the model results, this limitation forced older generation with higher costs to remain online later in the 

planning horizon, thus increasing the energy production costs which could otherwise have been offset 

by demand response programs. Reoptimization with the correct costs could lower overall average 

system costs, leading to greater savings. A third recommendation for future models is to develop more 

realistic system stress cases. The stresses in the model could be considered too extreme or not extreme 

enough, depending on the real-world application. 

Transmission Planning and Operations and Demand Response 

In this section, Commission staff focuses on the role of demand response in transmission planning and 

operations. After reviewing the transmission planning process, the discussion focuses on how demand 

response resources can be integrated into planning and operations. 

Transmission Planning Process 

Transmission planning is conducted to identify system upgrade and expansion needs for reliability and 

economic benefits. Details of the planning process vary from entity to entity but the basic process is 

the same. The power system is modeled under expected future conditions. When inadequacies in the 

transmission system are identified, there are specific processes that are utilized to find solutions. 

Typically system planners use load flow, transient stability, and voltage collapse analysis to assess 

system adequacy. This analysis is an elaborate, well orchestrated, inclusive, effective process which 

typically provides years of warning with regards to the need to upgrade the power system in order to 
Chapter VI – Role of Demand Response in Regional Planning and Operations 

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meet the expected needs. The process often distinguishes between system upgrades that are needed to 

maintain reliability and those that are only needed to facilitate commerce or increase efficiency. 

ISOs/RTOs, regional reliability councils, and regional planning organizations do not typically have the 

obligation or authority to directly design or construct transmission enhancement solutions. Once they 

identify transmission system inadequacies, they publicize the needs and expect transmission, 

generation, and demand-side investors to propose projects to solve the problems. The planners 

evaluate the proposed solutions to see if they meet the technical and economic requirements of the 

system. The best projects are endorsed and put into the regional transmission expansion plan. The 

projects must then be approved by state and federal regulators as appropriate. 

The ISO/RTO Planning Committee is an organization composed of the Alberta Electric System 

Operator (AESO), the California Independent System Operator (CAISO), the Electric Reliability 

Council of Texas, Inc. (ERCOT), the Independent Electricity System Operator (IESO) in Ontario, the 

ISO New England (ISO-NE), the Midwest ISO, the New York ISO (NYISO), the PJM Interconnection 

(PJM), and the Southwest Power Pool (SPP). The committee provides a concise description of the 

evolving state of regional transmission planning: 

Regional electric system planning is evolving. In the early days of an ISO/RTO planning 

effort, transmission expansion plans often represented a compilation of the member utilities’ 

local transmission plans. As the planning organization and stakeholder relationships grow 

stronger, the plans grow in scope and complexity, starting with work to conduct reliability 

planning on an intraregional basis and then moving to interregional reliability and economic or 

environmental improvement projects. Often, the next step is to strengthen the plan to address 

a particular system need or policy issue that exceeds reliability alone. After the RTO’s 

planners and transmission owners become comfortable with regionally integrated reliability 

planning, the next step is to look at intraregional and interregional economic opportunities, 

where new transmission investment can significantly increase interregional flows and reduce 

costs.218 

The generation and transmission solutions offered to the regional planner are typically developed by 

well established competitive generation companies and regulated transmission providers. A few 

developers of merchant transmission also occasionally develop projects. Transmission planners 

explore a host of possible solutions including upgrading existing lines, building new lines, adding 

control devices, etc. Separate departments exist to perform the electrical analysis, acquire right-ofway, design civil engineering solutions, procure equipment, and interface with the affected 

communities, construction. Getting new transmission lines built is difficult, but there is a large, 

elaborate, and detailed process that exhaustively examines all possible transmission solutions and 

actively seeks the most desirable. Generation planning is also well established. No such similar 

process exists for examining demand response solutions. Instead, Commission staff has determined 

that demand response is typically treated as a solution that may be examined if it is offered by others 

and if the offering meets criteria that were established based upon traditional transmission and 

generation technical solutions. 

 218 ISO/RTO Planning Committee, ISO/RTO Electric System Planning, Current Practices, Expansion Plans, and 

Planning Issues, February 10, 2006. 
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Demand Response in Transmission Planning 

All of the various types of demand response resources discussed earlier in this report (particularly in 

Chapter IV) can impact transmission adequacy, and several of these options can be used as direct 

substitutes for transmission enhancement. For example, time-based rates and direct load control can 

target specific hours when response is desired. The former facilitates voluntary market response to 

price signals while the latter utilizes direct control commands. Both types can be used to address 

capacity inadequacy caused by a lack of generation or a lack of transmission. In addition, while not 

the subject of this report, energy efficiency reduces consumption during all hours and typically 

reduces the need for transmission. It is not focused on hours when transmission is congested and may 

not provide as cost effective a response to a specific transmission problem as more directed 

alternatives. 

Demand response is not treated in transmission planning uniformly across the United States. As is 

discussed later in this chapter, many organizations state that their responsibility is limited to 

identifying transmission concerns and evaluating the viability of proposed solutions. Specific projects 

are to be proposed by generation, transmission, and demand response companies. Conversely, some 

institutions specifically state that they always evaluate demand response alternatives for transmission 

enhancements but demand response solutions do not show up in their transmission expansion plans. 

The 2006 ISO/RTO Planning Committee report states that its nine organizations have approved 1,121 

transmission projects worth $15.6 billion including 5,070 miles of new transmission lines and 133,062 

MW of approved new generation. In contrast, only 4,000 MW of new and existing demand response 

projects are mentioned and only for New York and California. An additional 500 MW of demand 

response are mentioned by ISO-NE. 

In one sense, demand response is included in almost all transmission planning. Known existing or 

expected demand response is incorporated into the reliability assessment, either as a modification to 

the expected load or as a responsive resource. Load that is responsive to real-time or time-of-use 

prices, for example, is accounted for by modifying the forecast peak and off-peak load. Load that 

responds to system operator calls is used as a responsive resource, similar to generation, to mitigate 

problems found in the transmission analysis. Energy efficiency measures simply reduce energy 

requirements and are incorporated into future load forecasts, often without explicit consideration by 

transmission planners. 

Commission staff has concluded that system planners do not typically include new demand response 

as a potential solution to transmission adequacy problems. Demand response is not considered equally 

when a system planner lays out options for dealing with the discovered transmission inadequacies. 

The Bonneville Power Administration (BPA) and MISO have policies calling for demand response 

considerations but these policies have not resulted in actual projects. 

Provision of Ancillary Services by Demand Response 

Demand response resources can also assist in the operation of transmission systems in the form of 

ancillary services such as operating reserves.219 Customers participating in these programs are 

 219 Reliability rules currently prohibit the use of responsive load to provide some ancillary services (spinning 

reserve for example) in some regions but technically the generation/load balance can always be restored by changing either 

side of the equation. See B. Kirby, Spinning Reserve From Responsive Loads, Oak Ridge National Laboratory: ORNL/TM2003/19, March 2003. 
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continuously poised to respond, but only has to reduce consumption when a reliability event actually 

occurs. The response duration depends on the nature of the event and the type of reserve being 

supplied (see Figure VI-3) but is typically provided in seconds to minutes rather than the hours 

required when peak shaving or responding to price signals. Fast communications are often required to 

notify the load when response is needed. While customer load loads providing reliability reserves do 

not reduce transmission loading itself under normal conditions, they can reduce the amount of 

transmission capacity that must be held in reserve to respond to contingencies. This both reduces the 

need for new transmission and increases the utilization of existing transmission to provide energy from 

low cost generation. 

Some demand response resources are technically superior to generation when supplying spinning 

reserve; the ancillary service requiring the fastest response. Many systems can curtail consumption 

faster than generation can increase production. The only time delay is for the control signal to get 

from the system operator to the load. This is typically 90 seconds or less (much less with dedicated 

radio response), much faster than the 10 minutes allowed for generation to fully respond. When 

responding to system frequency deviations, the curtailment can be essentially instantaneous. 

Communications delays are not encountered because frequency is monitored at the load itself. 

An example where demand response provides superior spinning reserve when compared with 

generation can be seen in Figure VI-4.220 In this Figure, WECC’s interconnection frequency response 

is shown for the sudden loss of the Palo Verde unit 1 generator. The lower curve shows system 

frequency response, with generators providing all of the spinning reserve. The upper curve shows that 

system frequency when 300 MW of spinning reserves were provided by a large pumping load instead 

of from generation. As can be seen, system frequency does not dip as low and recovers more quickly. 

Markets for ancillary services typically develop shortly after markets for energy are established. The 

interdependence between the supply of energy and ancillary services makes this natural. Table VI-1 

shows the current state of ancillary service markets, and whether demand response is allowed to 

participate. 

Demand response has typically allowed provided supplemental (non-spinning) and slower reserves. 

Restrictions on allowing demand response to provide spinning reserve have eased recently in some 

areas. ERCOT allows demand response as a supplier of spinning reserve. PJM permits demand 

response to supply spinning reserves and regulation. NYISO expects to allow demand response to 

supply spinning reserves in the third quarter of 2007. MISO is in the midst of ancillary service market 

design and the supply rules are not yet clear. 

 220 John Kueck and Brendan Kirby, Presentation to the WECC CMOPS, January 7, 2005. Stability runs performed 

by Donald Davies of the Western Electricity Coordinating Council (WECC). 
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Figure VI-3. Response time and duration that characterize ancillary 

services

Source: Brendan Kirby of Oak Ridge National Laboratory 

Figure VI-4. Impact of demand response on WECC system stability 

Source: Donald Davies of WECC 

0.1 1 10 100

TIME (MINUTES)

Regulation

Fast Energy Balancing Markets

Frequency Responsive Spinning Reserve

Supplemental Reserve

Backup Supply

Hourly

Energy

Contingency Operations

Normal Operations
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Table VI-1 Current and pending ancillary service markets221

Regulation Spinning Non-spinning 

Supplemental 

(10 min) 

Long Term 

Supplemental 

(30 min) 

Replacement 

(60 min) 

Cooptimization 

exemption 

ISO-NE ; ; ; D ; D No 

NYISO ; ; D ; D ; D No 

PJM ; D ;&C D ;&C D Yes 

MISO C C C Not yet set 

ERCOT ; ; D ; D ; D Yes 

CAISO ; ; ; D Yes 

Notes: 

; – Market based 

C – Cost based 

F – Fixed monthly MVAR payment 

D – Demand response is allowed to participate (or will be shortly) 

New England has forward reserves for obtaining supplemental and regulation 

Co-optimization of ancillary services and energy markets presents a unique problem for demand 

response. Co-optimization (and in California, the Rational Buyer) is based on the idea that the various 

services can be ranked in order of “quality.” Quality is judged by required speed of response, with 

regulation being the highest quality service followed by spinning, non-spinning, supplemental, longterm supplemental, replacement reserves, and energy supply. The reasoning is that higher quality 

services can and should always be substituted for lower quality services if the higher quality services 

are available at a lower price. If not enough replacement reserves are offered into the market but there 

is an excess of spinning reserves, for example, the system operator is able to purchase spinning 

reserves and use them as replacement reserves. The reserve supplier is supposed to be indifferent 

since it is being paid the spinning reserves price and being asked to provide the slower and therefore 

easier to provide replacement reserves service. This rationale is often extended to allow the system 

operator to use excess reserves as an energy supply when energy prices are high. This works well for 

most generators since they are indifferent as to how long they run (they may have minimum run times 

but generally do not have maximum run times). 

Unfortunately, co-optimization can unintentionally block many demand response resources from 

participating in reserves markets. An air-conditioning load, which can respond rapidly and provide 

excellent spinning reserve at low price, for example, may be unwilling to provide the multi-hour 

response required for replacement reserves or energy.222 The chance that it will be forced to do so by 

the co-optimizer may block demand resources from making themselves available to enhance system 

reliability. Very recently this problem has been recognized and addressed in several (but not all) 

markets. The CAISO, for example, allows demand response resources to declare themselves as 

unavailable for providing anything except the reserve market it has bid into. Energy is traded through 

bilateral contracts in ERCOT so it is separate from the ancillary service markets and the problem does 

not arise. PJM allows resources to submit different capacities in the ancillary service and energy 

markets so a demand response resource can state that it has zero energy capacity. These markets are 

noted in Table VI-1 under the “Co-optimization exemption” column. 

 221 This table was adapted from the Ancillary Services Round Table, Midwest Independent System Operator, 

Carmel Indiana, April 26-27, 2006. 

222 Energy limited hydro generators and emissions-limited thermal generators have a similar constraint and cannot 

afford to risk being called on for extended operations. 
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Regional Treatment of Demand Response 

Transmission system planning responsibilities are spread among a number of groups. The North 

American Electric Reliability Council (NERC) is the industry organization which addresses power 

system reliability. Regional councils provide added specificity as it relates to the particular needs of 

their region. ISOs, RTOs, and balancing authority (control area) operators have very specific concerns 

with the transmission systems they operate. Concerns about the impact demand response can have on 

transmission planning span a broad range. While it was not possible to conduct an exhaustive survey 

of the demand response activities of all the organizations with transmission planning responsibility in 

North America for this report various organizations were selected for inclusion in order to span the 

geographic scope as well as the range of organizational structures. Prior to examining how each 

region addresses demand response, the following discussion presents its treatment at the NERC level. 

The information provided in this section draws upon information obtained directly from the NERC 

regions and ISO/RTOs.223

North American Electric Reliability Council 

NERC was formed in 1968 as the utility industry organization which develops voluntary reliability 

rules to coordinate how the bulk electric system is planned and operated. The voluntary structure is 

being replaced with a structure that requires mandatory compliance with reliability standards pursuant 

to the provisions of the Energy Policy Act of 2005 (EPAct 2005). Under the new system, the Federal 

Energy Regulatory Commission has the authority to review reliability standards proposed by the 

Electric Reliability Organization (ERO) that when approved, provide reliability of the nation’s bulkpower system. The rule concerning the certification of the ERO has been issued by the Commission 

and the selection of an ERO is expected shortly. NERC filed the initial standards for formal review on 

April 4, 2006. On May 11, 2006, Commission staff issued a preliminary assessment containing a 

thorough review of the 102 NERC standards and on July 5, 2006, it held a technical conference with 

the industry to discuss the standards. A notice of proposed rulemaking concerning which standards 

might be accepted or remanded is expected to be issued in the fall. 

NERC Reliability Standards address the types of assessments and the applicable criteria to be used in 

evaluating the reliability of the bulk electric system. They do not directly address the use of demand 

response or any other solutions to achieve compliance with the applicable criteria. In general, there 

are three classes of options; generation solutions, transmission solutions, and demand response 

solutions. The choice of one or more classes of options is usually based on their relative cost and 

effectiveness.224

Of the 102 standards and the Glossary of Terms Used in Reliability Standards presented by NERC for 

approval as mandatory standards, eight standards directly or indirectly deal with demand-side issues 

and demand response. They are:225

 223 The following individuals provided information during discussions concerning regional demand response: 

Adam Keech and Jeff Bladen of PJM; Keith Tynes of SPP; Tom Abrams of Santee Cooper and SERC; Brian Silverstein of 

BPA; Robert Burke and Mario DePillis of ISO-NE; Dave Lawrence of NYISO; Charles Tyson, Dale Osborn, and Jeff Webb 

of MISO; Art Nordlinger of Tampa Electric and FRCC; Alan Isemonger of CAISO; Stephen Pertusiello of Consolidated 

Edison; and Donald Davies, Dick Simons, and Jay Loock of WECC. 

224 Note that demand response is unique in that it is essentially the only solution that is directly discussed in the 

standards. 

225 NERC, Reliability Standards for the Bulk Electric Systems of North America, North American Electric 

Reliability Council, Princeton, NJ, February 7, Downloaded from www.nerc.com on March 20, 2006. 
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• Standard BAL-002 — Disturbance Control Performance 

o The permissible mix of Operating Reserve – Spinning and Operating Reserve – 

Supplemental that may be included in Contingency Reserves. 

• Standard BAL-005 — Automatic Generation Control 

o The standard also ensures that all facilities and load electrically synchronized to the 

Interconnection are included within the metered boundary of a Balancing Area so that 

balancing of resources and demand can be achieved. 

• Standard TOP-002 —Normal Operations Planning 

o Identifies performance to be achieved using all tools available to the operators. 

• Standard MOD-016-0 — Actual and Forecast Demands, Net Energy for Load, Controllable 

DSM (demand side management) 

o Planning Authority and Regional Reliability Organizations must document actual and 

forecast demand data, net energy for load data, and controllable DSM data. 

• Standard MOD 019-0 — Forecasts of Interruptible Demands and DCLM Data 

o Load Serving Entities must provide forecasts of summer and winter peak interruptible 

demands and Direct Control Load Management (DCLM) response capabilities for the 

next five to ten years. 

• Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data 

o Load Serving Entities must report their interruptible demands and direct load control 

management capabilities to Balancing Authorities, Transmission Operators, and 

Reliability Coordinators on request. 

• Standard MOD-021-0 — Accounting Methodology for Effects of Controllable DSM in 

Forecasts 

o Load-Serving Entities, Transmission Planners, and Resource Planners must document 

how conservation, time-of-use rates, interruptible demands, and Direct Control Load 

Management are addressed in peak demand and net energy forecasts. 

• Standard TPL-006-0 — Assessment Data from Regional Reliability Organizations 

o Regional Reliability Organizations are required to provide data concerning actual and 

projected demands and net energy for load, forecast methodologies, forecast 

assumptions and uncertainties, and treatment of Demand-Side Management including 

program ratings, effects on annual system loads and load shapes, contractual 

arrangements, and program durations. 

Seven additional MOD standards contain guidance concerning collecting and reporting forecast 

demand and (if interpreted broadly) demand side management program performance data. NERC 

states that the purpose of these standards includes: “Forecast demand data is needed to perform future 

system assessments to identify the need for system reinforcement for continued reliability. In addition 

to assist in proper real-time operating, load information related to controllable Demand-Side 

Management programs is needed”

226 (emphasis added). Forecasted load, with demand response 

included, drives the need for generation expansion and transmission to deliver the generation to the 

load. 

The following NERC MOD standards try to assure that accurate demand and demand side response 

data is collected by requiring the Regional Reliability Organizations (RROs) “to establish consistent 

data requirements, reporting procedures, and system models to be used in the analysis of the reliability 

of the Interconnected Transmission Systems:” 

 226 NERC, 2006 
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• Standard MOD-011-0 — Regional Steady-State Data Requirements and Reporting Procedures 

• Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and Simulation. 

• Standard MOD-013-0 — RRO Dynamics Data Requirements and Reporting Procedures 

• Standard MOD-014-0 — Development of Interconnection-Specific Steady State System 

Models 

• Standard MOD-015-0 — Development of Interconnection-Specific Dynamics System Models 

• Standard MOD-017-0 — Aggregated Actual and Forecast Demands and Net Energy for Load 

• Standard MOD-018-0 — Reports of Actual and Forecast Demand Data 

NERC submitted its “Glossary of Terms Used in Reliability Standards” to the Commission with the 

102 reliability standards for approval as mandatory reliability standards. There is a discrepancy 

between the definition of “Spinning Reserve”227 and “Operating Reserves – Spinning.”228 The latter 

permits demand response to be considered as part of the spinning reserve requirement while the former 

does not. Furthermore as pointed out in the “FERC Staff Preliminary Assessment of NERC 

Reliability Standards”229 under BAL-002-0 “the minimum percentage of spinning reserve required as 

part of the contingency reserve is not defined in the standard but is at the discretion of the RRO. 

Various regions have different definitions as to which resources are eligible to be counted as spinning 

reserves. For example in some regions large irrigation pumping and pumped hydro resources are 

permitted to be used as spinning reserves, and in other regions they are not. These deficiencies need to 

be addressed. Under BAL-005, the reliability goal of balancing generation and load requires the 

ability of the Balancing Authority to have control over adequate amounts and types of generation 

reserves and controllable load management resources.”230 

Texas Interconnection and the Electric Reliability Council of Texas 

Electric Reliability Council of Texas (ERCOT) is both a NERC Region and an interconnection which 

lies completely within the borders of the state of Texas. In 2001, ERCOT consolidated the operation 

of 10 control areas into a single control area with bilateral energy transactions and ancillary service 

markets serving 20 million people with a peak load of 60,000 MW, 24,000 miles of transmission, and 

a $20 billion electricity market. Energy is arranged through bilateral agreements. ERCOT obtains 

ancillary services and balancing energy (15 minutes) through markets. While ERCOT does 

simultaneous selection of ancillary service resources it does not force ancillary service providers into 

the energy market. 

ERCOT coordinates transmission planning with the various transmission and distribution service 

providers in Texas. Modeling expected future conditions identifies transmission limitations and helps 

in the comparison of alternative solutions. ERCOT also determines the transmission enhancements 

necessary to accommodate generation interconnection. ERCOT distinguishes between transmission 

enhancements that are required to maintain reliability regardless of the generation dispatch and those 

for which generation redispatch can be substituted. Demand response alternatives are considered 

 227 Unloaded generation that is synchronized and ready to serve additional demand (emphasis added). 

228 The portion of Operating Reserve consisting of: Generation synchronized to the system and fully available to 

serve load within the Disturbance Recovery Period following the contingency event; or Load fully removable from the 

system within the Disturbance Recovery Period following the contingency event 

229 Federal Energy Regulatory Commission, Staff Preliminary Assessment of the North American Electric 

Reliability Council’s Proposed Mandatory Reliability Standards (“FERC Staff Preliminary Assessment of NERC Mandatory 

Reliability Standards”), Docket RM06-16, May 11, 2006, 30. 

230 FERC Staff Preliminary Assessment of NERC Reliability Standards, 32. 
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where possible. The ERCOT board approves all major transmission projects. ERCOT determines 

which transmission provider will build the transmission enhancement and notifies the Public Utility 

Commission (PUC). The transmission provider applies for and obtains PUC approval to build the 

transmission enhancement; ERCOT supports the PUC approval process. 

ERCOT makes extensive use of demand response. Load is allowed to provide responsive reserves 

(spinning reserve), non-spinning reserves (30 minute response), replacement reserve, and balancing 

energy. Over 1,100 MW of load is qualified to provide spinning reserves and over 1,200 MW of loads 

is qualified to provide non-spinning reserve. Over 500 MW of response was observed during recent 

frequency excursions. Demand response is currently limited to providing half of the reserves needed 

until system operator experience is gained.231 Interestingly, not a single load has offered to provide 

balancing energy while demand response is providing as much responsive reserve as allowed. This 

may indicate that demand response duration is more limiting than response speed. 

On April 17, 2006, ERCOT was forced to use 1,000 MW of involuntary demand response and 1,200 

MW of voluntary demand response to successfully prevent a system-wide blackout. Unusually high 

and unexpected load due to unanticipated hot weather, coupled with 14,500 MW of generation that 

was unavailable due to planned spring maintenance, resulted in insufficient capacity to meet load. 

System frequency dropped to 59.73 Hz at one point. Rolling blackouts were required for about two 

hours, with individual customers curtailed between 10 and 45 minutes at a time. All of the load called 

upon to respond did so successfully (voluntary and involuntary), though there was a 15 minute delay 

with one block of involuntary load curtailment. 

Western Interconnection and the Western Electric Coordinating Council 

WECC is the NERC regional reliability council responsible for the Western Interconnection, 

encompassing all or parts of fourteen states, two Canadian provinces, and a portion of Mexico. Peak 

load is about 146,000 MW. There are a number of transmission planning groups within WECC that 

are responsible for portions of the interconnection: Southwest Transmission Expansion Plan group 

(STEP), Northwest Transmission Assessment Committee (NTAC), Southwest Area Transmission 

(SWAT), Rocky Mountain Area Transmission Study (RMATS), and Colorado Coordinated Planning 

Group (CCPG). 

WECC does not encourage or discourage demand response; it is neutral concerning technology 

choices for reliability solutions. WECC does not conduct transmission system planning; instead each 

WECC member to plan its portion of the transmission system. WECC compiles the system-wide base 

cases used by others to plan the transmission system and evaluate the need for new transmission. 

These base cases incorporate the input from each of the members, both for existing conditions and for 

conditions expected in the future. WECC notes that it is not specifically aware of what demand 

response is included in the information supplied by the members. Expected peak loads may be 

reduced by the amount of expected demand response. WECC indicated that it is not aware of any 

obstacles to greater use of demand response. 

 231 Joel Mickey, Competitive Ancillary Services Market in ERCOT, MISO Ancillary Services Round Table, April 

26, 2006. 
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Alhough it does not perform transmission planning,232 WECC does report on the amount of 

interruptible demand and demand side management capacity that is available. The breakdown by 

subregion is shown in Table VI-2.233

Table VI-2. Interruptible demand and demand-side management in WECC 

Interruptible Demand 

(MW)*

Demand Side 

Management 

(MW) 

WECC Total 1950 514 

California-Mexico 1352 458 

Arizona-New Mexico S. Nevada 285 1 

Rocky Mountain 161 0 

Northwest Power Pool 160 55 

Source: WECC, 2005 Summer Assessment, Salt Lake City, UT, May 2005 

* Note: Total is not the sum of the parts because they are not simultaneous 

The WECC 2005 Summer Assessment discusses transmission congestion concerns in each of the 

subregions. It explicitly discusses recent transmission upgrades that help to alleviate congestion. It 

does not discuss demand response as helping to reduce transmission congestion. The closest it gets to 

connecting demand response with congestion relief is: 

The CAISO control area has 1,610 MW of reliability-related interruptible load programs that 

may be activated should adverse operating conditions occur. However, only about 1,290 MW 

of the total is in the more constrained southern portion of the control area. In addition to these 

reliability-related interruptible load programs, up to 915 MW of additional total-area demand 

relief may be available, but some of that demand relief is limited by restrictions such as dayahead notification.234

Similarly, the WECC 2005 Summer Assessment on the Pacific Direct Current Intertie states that the 

capacity of the Intertie is impacted by the amount of available demand response: 

The Pacific Direct Current Intertie (PDCI) will have a 3,100 MW north to south (export) limit. 

The PDCI south to north (import) limit will be 2,200 MW due to lack of direct service 

industry load tripping remedial action. ... The Northwest Direct Service Industry, which is 

composed mostly of aluminum smelters, experienced an electricity consumption decrease 

from just above 2,500 average megawatts in 2000 to less than 500 average megawatts in 

2002.235

Even though the transfer capacity on the intertie has been reduced because of a reduction in available 

demand response, there is no further discussion of either the value of or methods to increase demand 

response. 

 232 The purpose of the WECC Planning Coordination Committee is to (in part): (a) recommend criteria for 

adequacy of power supply and reliable system design; (b) accumulate necessary data and perform regional reliability studies; 

(c) evaluate proposed additions or alterations in facilities for reliability; and (d) identify the types and investigate the impact 

of delay on the timing and availability of power generation and transmission facilities. WECC, Downloaded from 

www.wecc.biz on February 12, 2006. 

233 WECC, 2005 Summer Assessment, Salt Lake City, UT, May 2005. 

234 WECC, 2005 

235 WECC, 2005 
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WECC has adopted a uniform underfrequency load shedding plan and requires members to have 37 

percent of the load shed in various steps for underfrequency conditions.236 

The following discussion explores the role of demand response in two WECC subregions: BPA and 

CAISO. While not an exhaustive examination of the full WECC, examination of these subregions 

provides useful information on how the role of demand response is evolving in the region. 

Bonneville Power Administration 

BPA owns and operates 15,000 miles of transmission, about 75 percent of the high voltage grid in the 

Pacific Northwest. It does not own generation; it markets wholesale electrical power from federal and 

non-federal generators. About 40 percent of the electric power used in the Northwest comes from 

BPA.237 At peak use, the system transports about 30,000 MW of electricity to customers.238

BPA has a highly visible effort aimed at identifying non-wires alternatives to transmission 

enhancement. Load in the Pacific Northwest has continued to grow but BPA has not build any 

substantial transmission enhancements between 1987 and 2003. BPA is concerned that congestion is 

increasing and reliability may suffer. BPA believes non-wires solutions may be a more cost effective 

solution while deferring the need to build new transmission facilities.239 Non-wires solutions are 

attractive because transmission constraints often occur 40 hours or less per year. New transmission to 

meet these peak conditions would sit idle most of the time. Alternatively, customers could respond 

without much disruption to their normal operations. BPA cites two past successful demand response 

projects that justify its current efforts at finding additional non-wires solutions. Traditional 

conservation measures lowered peak loads on Orcas Island for several years while an underwater cable 

was replaced. The Puget Reinforcement Project used conservation programs to helped avoid voltage 

collapse in the Puget Sound area and delayed construction of additional transmission lines crossing the 

Cascade mountains for ten years. Technological advances in load control and distributed generation 

lead BPA to conclude that additional opportunities now exist. BPA has committed to study non-wires 

solutions before deciding to build any transmission enhancements.240

BPA is now targeting the Olympic Peninsula with a pilot project that started in 2004. The 

transmission system on the Olympic Peninsula (and in other areas) does not meet NERC’s reliability 

criteria. BPA’s focus is on deferring transmissions enhancement temporarily, rather than looking at 

demand response as a permanent resource. BPA evaluates each project based upon the savings 

associated with transmission project deferral. A demand response project might be viewed as a threeyear deferral of a $60 million transmission project, for example. In that case, the value of the demand 

response project would be $11 million based on a 7 percent interest rate. Unlike the ultimate 

transmission project that demand response is delaying, the economic viability of demand response 

would not be examined over the 30-year life of a typical transmission line. 

 236 WECC, Western Electricity Coordinating Council Relay Work Group Underfrequency Load Shedding Relay 

Application Guide - Revised, August 3 2004. 

237 BPA, Downloaded from www.bpa.gov on April 14, 2006. 

238 BPA, Transmission Planning Through a Wide-Angle Lens, A Two-Year report on BPA’s Non-Wires Solutions 

Initiative, Bonneville Power Administration, (“BPA Non-Wires Solutions Initiative”), September 2004. 

239 BPA, Non-Wires Solutions, Questions & Answers , Exploring Cost-Effective Non-Construction Transmission 

Alternatives, Bonneville Power Administration, www.transmission.bpa.gov/planproj/non-wires_round_table/ (“Non-Wires 

Solutions Q&A”), 2004. 

240 BPA Non-Wires Solutions Initiative, 2004. 
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BPA identified 20 transmission problem areas in 2001, and nine were designated as high priority. A 

study was commissioned to examine both the overall BPA transmission planning process and the 

specific transmission needs. The resulting report recommended process changes in BPA’s 

transmission planning to consider non-wires alternatives early enough that they can make a difference. 

The report also identified specific projects that might be amenable to non-wires solutions. 

BPA formed a Non-Wires Solutions Round Table to obtain opinions from a diverse set of stakeholders 

within the region. Members included environmental groups, regulators, large energy consumers, 

Indian tribes, renewables advocates, and independent power producers. They addressed four issues: 

screening criteria, detailed studies for particular problem areas, non-wires technology, and institutional 

barriers.241 

Specific projects that were identified as candidates for non-wires solutions were: 

• Puget Sound Area – the required non-wires load reduction was too large and the wires solution 

also reduced transmission losses so the Kagley-Echo Lake transmission line solution was 

selected. 

• Olympic Peninsula – this was selected as a pilot project to test non-wires technologies 

including aggregated distributed generation and demand reduction. 

• Lower Valley, Wyoming. 

Institutional barriers identified by the Round Table include: 

• Lost utility revenue – utilities are reluctant to pursue demand response when it may reduce 

sales and revenue. 

• Lack of incentive for accurate forecasting – high load forecasts can justify additional 

transmission; thereby making it more difficult for demand response solutions to be adopted. 

• Lack of transparency in transmission planning. 

• Load shielded from actual wholesale electricity price volatility – additional demand response 

would make economic sense if loads could see the true value of that response. 

• Reliability of non-wires solutions – this can be both an actual and a perceptual problem. 

• Funding and implementation – multiple parties can benefit from demand side solutions 

(generation, transmission, and distribution) but it can be difficult to determine who should pay 

and who should implement the programs. Partnerships are often necessary but difficult to 

arrange. 

Currently BPA demand response efforts are still in the pilot program stage. Through pilots, BPA will 

test the dependability of demand response solutions. The first full initiative to actually defer a 

transmission project may happen late in 2006. 

California ISO 

The State of California has a very active demand response program supported by the California 

Energy Commission, the California Public Utility Commission, and the California Consumer Power 

and Conservation Financing Authority. Demand response resources range in size from residential air 

conditioners to California Department of Water Resources 80,000 horsepower pumps. As was 

 241 BPA Non-Wires Solutions Initiative, 2004. 
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discussed in Chapter IV, California expects to have demand response equal to five percent of the 

system peak available by 2007. California has established a “preferred loading order” to guide energy 

decisions. The loading order consists of decreasing electricity demand by increasing energy efficiency 

and demand response, and meeting new generation needs, first with renewable and distributed 

generation resources, and second with clean fossil-fueled generation.242 Quantitative goals are not 

included for the use of distributed generation or demand response as an alternative to transmission 

enhancement and coordination with transmission planning is a recognized problem in California. 

CAISO was created by the state to operate the transmission system for most of the state including 

25,000 miles of transmission lines and a peak load of over 47,000 MW. The CAISO transmission 

planning process reviews the transmission expansion plans submitted by the participating transmission 

owners to assure that they solve identified problems, are the best alternatives, and are the most 

economical from a system point of view. The CAISO performs a comprehensive review to assure that 

nothing is missing. Management approves projects costing less than $20 million and refers larger 

projects to the CAISO board for approval. Studies are performed to establish Reliability Must Run 

generation requirements. CAISO has approved 337 transmission enhancement projects costing over 

$3 billion. Both the CAISO and the California Public Utility Commission have authority to require 

transmission enhancements to meet regulatory obligations. 

The CAISO is currently proposing a new planning process. The CAISO will produce a five-year 

project-specific plan and a ten-year conceptual plan will be produced to address reliability and 

economic needs. It will submit identified projects to the transmission owners. Participating 

transmission owners are then expected to submit transmission plans that incorporate the CAISO plan. 

The transmission plan is designed to eliminate congestion and reliability must run requirements as 

well as to provide economic signals for generation siting.243 The 2005 CAISO transmission initiatives 

encompassed seven projects, which included substation and line work. No demand response projects 

were included. 

The CAISO has a great deal of experience obtaining ancillary services from competitive markets. It 

operated the first ancillary service markets and currently has a proposal before the Commission to 

redesign those markets. The CAISO proposes to implement its redesign by November 2007. Demand 

response resources are currently not allowed to supply regulation or spinning reserves. While the 

CAISO has used a “Rational Buyer” mechanism and proposes in the future to use co-optimization to 

substitute “higher quality” ancillary services for “lower quality” services and energy supply, demand 

response resources and energy-limited hydro generators can flag their capability as being available for 

contingency response only.244

Eastern Interconnection 

The Eastern Interconnection is the largest of the three interconnections in North America but it has no 

organization with overall reliability responsibility. Instead, it is composed of six regional reliability 

councils that coordinate activities to assure that the interconnection remains reliable. Since there are 

multiple ISOs within the Eastern Interconnection, the Inter-RTO/ISO Council is also developing an 

inter-RTO/ISO expansion plan process. Steps are being taken to facilitate coordinated joint planning 

 242 S. Fromm, K. Kennedy, V. Hall, B.B. Blevins, Implementing California’s Loading Order For Electricity 

Resources, California Energy Commission Staff Report, July 2005. 

243 A. J. Perez (CAISO), New ISO Transmission Planning Process, August 1, 2006. 

244 Alan Isemonger, CAISO Ancillary Service (AS) Procurement Under MRTU, MISO Ancillary Services Round 

Table, April 26, 2006. 
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over a vast region but this process does not appear to include much in the way of demand response. 

The following discussion presents the transmission planning activities of the various Eastern 

Interconnection RTO/ISO and regional reliability councils. 

Midwest ISO 

The Midwest ISO (MISO) manages the transmission system and operates electricity markets for a 

region that covers all or part of fifteen states and one Canadian province. Peak load is approximately 

132,000 MW; 16 percent of the total US/Canadian load and 21 percent of the Eastern Interconnection 

load. The Midwest ISO Transmission Expansion Plan 2005 (MTEP 05)245 describes the currently 

recommended transmission needs for the MISO system. The plan identifies 615 facility additions 

requiring $2.9 billion in investment by 2010. MISO develops the regional plan based upon a roll-up 

and integration of the individual transmission owners’ plans. The results are discussed with the 

Organization of Midwestern States and approved by the MISO board. 

There is essentially no attention paid to demand response in the MTEP 05. No demand response 

projects have been identified within the $2.9 billion in reliability investment. Generation redispatch 

and transmission system expansion are recognized as methods to address inadequate reliability, but 

demand response is not mentioned. Line conversion is specifically addressed as an alternative to new 

construction, but demand response is not. The description of the process for determining system 

adequacy, needed additions, and generation redispatch does not include a discussion of demand 

response. However, the plan does recognize that controlled involuntary load shedding is an effective 

tool that the system operator can rely upon to contain rare events and prevent uncontrolled outage 

cascading. MTEP 05 only mentions “Demand-side options” once, when it states that their evaluation 

is required: “The MTEP process is to consider all market perspectives, including demand-side 

options, generation location, and transmission expansion alternatives.” Commission staff cannot 

determine whether demand-side options actually are considered in the process.246 

There is a brief section on “Load Technologies,” which discusses the possible future use of controlled 

floor heating to help shape wind output to more closely follow other loads. Alternatively, “the load 

could be used as a dynamic brake for generator stability considerations following a fault on the 

transmission system.”247 There is no mention of the adequacy or inadequacy of current load control 

technologies to address current system needs. 

MISO is currently engaged in an active ancillary service market design process that, while not 

explicitly using demand response to address transmission adequacy, is considering how demand 

response can participate in supporting system reliability.248 The MISO stakeholder process is 

examining how ancillary service markets operate in other regions, including how they accommodate 

demand response. That process should result in a filing with the Commission in 2006.249

 245 MISO, Midwest ISO Transmission Expansion Plan 2005 – MTEP 05, June 2005. 

246 There is one further sentence in the report that states “In rare situations the ‘redispatch’ can manifest itself as 

dropping load and backing down generation rather than simply shifting generation among sources.” 

247 MISO, June 2005. 

248 MISO, Ancillary Services Round Table, Midwest Independent System Operator, Carmel, Indiana, April 26-27, 

2006. 

249 See June 6, 2006 resource adequacy report in Docket No. ER06-1112 at 7. In addition, MISO will be including 

effectively implementing enhanced DSM programs in its Phase II filing expected in 2007. 
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PJM Interconnection 

At this time, the PJM Interconnection (PJM) serves 51 million people in all or parts of 13 states and 

the District of Columbia. It has a peak demand of approximately 135,000 MW; roughly 16 percent of 

the total US/Canadian load and 22 percent of the Eastern Interconnection load. PJM began in 1927 

and developed as a tight power pool. In 1997, it became fully independent and started its first bidbased energy market, and it became an RTO in 2001.250 

Transmission planning in the PJM region is accomplished through the Regional Transmission 

Expansion Planning Protocol which annually generates a Regional Transmission Expansion Plan 

(RTEP) covering the next 10 years. RTEP determines the best way to integrate transmission with 

generation and demand response projects to meet load-serving obligations.251 Over $1.8 billion in 

transmission enhancement projects have been identified through the RTEP process. Although supply 

or demand side solutions may be found to be a more efficient or effective replacement for transmission 

enhancements, PJM is not authorized to implement them directly.252 Instead, PJM identifies 

transmission solutions to problems and, subject to cost/benefit analysis, recommends their 

implementation through the RTEP if no solution has been proposed by a market participant within a 

one-year window. PJM’s approach is to give market forces an opportunity to determine whether 

transmission investment beyond that needed to ensure reliability is warranted. While PJM planners 

work with transmission owners to assess the impact of a proposed project on the PJM system, the 

upgrades are the sole right of each transmission owner to construct. 

Each RTEP includes: 1) a set of recommended “direct connection” transmission enhancements; 2) a 

set of “network” transmission enhancements; 3) a set of market-proposed generation or merchant 

transmission projects; 4) a set of baseline upgrades; and 5) the cost responsibility of each party 

involved. Most demand response is implicitly included in PJM regional transmission planning as a 

modifier to forecast load. PJM typically assumes that the current level of demand response will 

continue into the future when evaluating any specific transmission area. 

PJM has recently made changes to its market structure to allow demand response resources to 

participate in ancillary services markets. As of May 1, 2006, demand response resources may provide 

spinning reserves and regulation. PJM is the first RTO to allow demand response to participate in 

each of the ancillary services markets.253 Demand response in the regulation and synchronized reserve 

markets is initially limited to 25 percent of total requirements until system operator experience is 

gained. Loads are compensated for their capacity contributions as well. PJM has stated that “Demand 

response should be encouraged so long as it is the right economic answer. However, it is not an end in 

itself.”254

PJM has identified a number of obstacles to incorporating demand response into PJM transmission 

planning and operations: lack of widespread use of hourly and sub-hourly metering, which is required 

 250 PJM, downloaded from www.pjm.com on April 3, 2006 

251 PJM, Amended And Restated Operating Agreement Of PJM Interconnection, L.L.C., Schedule 6 Regional 

Transmission Expansion Planning Protocol, PJM Interconnection, April 26, 2006, and PJM, PJM Regional Transmission 

Expansion Plan, 2006, and PJM Interconnection, www.pjm.com, February 22, 2006. Note that the planning horizon is 

expanding to 15 years with the next RTEP. 

252 PJM Interconnection L.L.C, comments filed in Docket AD06-2, December 19, 2005. 

253 A. Keech, PJM Ancillary Services Markets, MISO Ancillary Services Round Table, April 26, 2006. Load can 

not supply black start or reactive power. 

254 PJM Comments, December 19, 2005. 
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to accurately measure demand response, and the lack of good long-term demand response 

forecasting.255

Southwest Power Pool 

Southwest Power Pool (SPP) is a NERC regional reliability council and a FERC-approved RTO for all 

or parts of Arkansas, Kansas, Louisiana, Mississippi, Oklahoma, New Mexico, and Texas. SPP serves 

4 million customers with about a 39,000 MW peak load with 33,000 miles of transmission lines. 

SPP identifies the region’s transmission expansion needs through an open stakeholder process. 

Coordinating with the region’s 45 electric utilities, SPP identifies the best overall regional 

transmission expansion plan. SPP then directs or arranges for the necessary transmission expansions, 

additions, and upgrades including coordination with state and federal regulators. 

SPP does not itself explicitly include demand response in transmission planning studies, although it 

does consider generation as an alternative to transmission enhancement. Individual LSEs incorporate 

any current or expected demand response that is within their boundaries in their load forecasts. 

Individual transmission owners could investigate demand response solutions as alternatives to 

transmission expansion projects but they are not required to do so by the region. SPP does require 30 

percent of the load to be interruptible on under frequency load shedding relays in three blocks of 10 

percent each. 

Florida Reliability Coordinating Council 

Florida Reliability Coordinating Council (FRCC) is the regional reliability council for the state of 

Florida. Transmission system planning for the approximately 43,000 MW peak load region is 

dominated by its peninsular geography, with all connections to the Eastern Interconnection made at 

the northern border. FRCC coordinates the transmission planning efforts of the members for the 

region and assesses resource adequacy for the 10 year future period. 

Although the amount of demand response in FRCC is sizable (seven percent of peak demand, see 

Chapter V), the Florida PUC has been reevaluating the cost effectiveness of demand-side management 

and has been reducing the rebates offered to consumers. Consequently, the amount of available 

demand-side management capability has been decreasing. Transmission planners do not consider 

demand response, and the demand forecast is not reduced by the amount of expected demand 

response. Planners feel that there is not sufficient demand response in any one location to eliminate 

the need for transmission enhancement. Demand response could delay the need for a project by a 

year, at most. 

Still, there is a lot of demand response capability in Florida. Progress Energy Florida (formerly 

Florida Power Corporation), for example, has operated a very successful demand response program 

that it began in the 1980’s and includes 800,000 out of 4.4 million customers. 1000 MW of peak load 

reduction and 2000 MW of emergency response ares available within two seconds to one minute. 

However, FRCC does not qualify this resource as spinning reserve.256

 255 Jeff Bladen (PJM), FERC Technical Conference, January 25, 2006, transcript, 251-256. 

256 Ed Malemezian, Interview with Brendan Kirby, ORNL, 2005. 
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New York ISO 

NYISO was formed in 1998 as part of the restructuring of New York State's electric power industry. 

The NYISO is an outgrowth of the New York Power Pool which was formed following the Northeast 

Blackout of 1965. The power pool coordinated the statewide interconnected transmission system and 

economically dispatched the generation fleet. Its mission is to ensure the reliable, safe, and efficient 

operation of the state's 10,775 miles of major transmission system and to administer an open, 

competitive and nondiscriminatory wholesale market for electricity in New York State. Peak summer 

load is about 32,000 MW. The NYISO’s market exceeded $10 billion in 2005.257 

NYISO recently initiated a Comprehensive Reliability Planning Process which identifies reliability 

concerns and transmission needs. This process involves extensive modeling, considering expected 

loads, generation resources, transmission limitations, and demand response resources including the 

Emergency Demand Response Program and Special Case Resource programs, discussed later. The 

process identifies reliability based needs rather than solutions. Generation, transmission, and demand 

response-based projects can be proposed. NYISO selects acceptable solutions based on their technical 

capability to address the identified problem and the economic viability. Only in rare cases when no 

acceptable solutions are proposed will the ISO discuss compelling a transmission owner to construct a 

transmission-based solution (backstop solution). As was the case with PJM, the NYISO intends this 

process to promote market based solutions to reliability problems. 

Transfer limits into southeastern New York are limited by voltage rather than thermal constraints with 

a significant need arising by 2008. 1,750 MW of resources from generation or demand response will 

be needed by 2010 in order to free up voltage-support capability. As a partial response to this 

problem, the New York Public Service Commission (NYPSC) is requiring 300 MW of demand 

reduction in New York City. Consolidated Edison is to obtain half of that response (150 MW). The 

other half will come from other suppliers. The NYPSC has also set time lines and metering 

requirements to help accelerate acceptance. Demand response solutions may receive funding from 

New York State Energy Research and Development Authority. 

NYISO may allow demand response to supply spinning reserves. This will likely occur in the third 

quarter of 2007. Currently, demand response can only supply non-spinning reserve. 

Ancillary service bids are co-optimized with energy requirements by the NYISO, allowing the system 

operator to use ancillary service resources to supply energy if needed. This may be limiting the 

amount of demand response offered to the system, since some loads may be unwilling to expose 

themselves to the risk of being required to curtail operations for an extended period. 

ISO New England 

ISO New England (ISO-NE) evolved out of the NEPOOL tight power pool which, prior to 1999, 

provided joint economic dispatch across Connecticut, Maine, Massachusetts, New Hampshire, Rhode 

Island, and Vermont. The ISO-NE has over 8,000 miles of transmission lines to serve about a 27,000 

MW peak load. 

ISO-NE stated that it works with stakeholders to develop fair and efficient wholesale electricity 

markets, to plan a reliable bulk power system, and to protect the short-term reliability of the control 

 257 NYISO, downloaded from www.nyiso.com, April 3, 2006. 
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area. ISO-NE annually develops a 10-year Regional System Plan which accounts for the addition of 

generation units, demand response, load growth, and generation retirements. System economics and 

air emissions are considered, along with reliability, in planning the transmission system. In addition to 

specifying what transmission enhancements are required, the Regional System Plan also helps attract 

market solutions (generation and demand response) to mitigate the need for the transmission 

enhancements. The current Regional System Plan includes 272 transmission projects that are expected 

to cost between $2 and $4 billion. 

Demand response is not the same as transmission enhancement in ISO-NE’s eyes. Demand response 

can provide a temporary solution until a permanent transmission enhancement is in place. When the 

power system in Southwest Connecticut was recognized as being inadequate, it was also 

acknowledged that neither transmission nor generation solutions could be implemented in time to 

restore reliability. Demand response solutions of 250 MW were sought to quickly fill the reliability 

gap. Transmission solutions are still being pursued to permanently resolve the problem. 

ISO-NE believes it has authority from FERC to order transmission construction if needed to maintain 

reliability. Conditions have never warranted that action. Instead the ISO has preferred to identify 

needs and allow the market to propose generation, transmission, or demand response solutions. The 

ISO views its role as selecting the best from what is proposed rather than identifying the best solution 

on its own. Selected projects then move through the state and federal regulatory process to enter the 

rate base or transmission tariff if they are transmission based. Generation and demand response 

projects move through their own regulatory and commercial processes. 

 

The existing form of ISO-NE’s capacity markets makes it difficult for demand response resources to 

fully participate in the ancillary service markets. Forward capacity markets mean that reserve costs 

are mostly sunk in real-time and rational real-time offers are expected to clear at $0. Further, ISO-NE 

utilizes forward reserve auctions, two to five months in advance, to procure 10-minute non-spinning 

reserve and 30 minute operating reserves. These are difficult commitments for demand response 

resources to make. These markets are designed to satisfy 95 percent of the reserve requirements and 

include penalties for failure to respond in real time. Any resource can participate, but it must look like 

a low-capacity generator with a high energy price and capable of providing reserves 98 percent of the 

time.258

Demand response resources can also register as a Dispatchable Asset Related Demand, and essentially 

will be treated as generators. The resources cannot restrict its response to contingency events; energy 

and ancillary services are co-optimized based upon the bid response price. Submitting a $999/MWh 

only partially mitigates the energy deployment risk and also undesirably reduces contingency event 

deployments.259

Southeastern Electric Reliability Council 

Southeastern Electric Reliability Council (SERC) encompasses all or parts of 16 states in the 

southeastern and central United States. Prior to the recent consolidation of the 10 regions into eight, 

SERC was the largest with a peak load of about 165,000 MW. It has 5,057 MW of interruptible load 

and demand response and 50,000 MW of load shedding capability. SERC does not have a regional 

policy concerning the use of demand response related to transmission enhancement. Transmission 

 258 Mario DePillis, The New Ancillary Services Markets of New England, MISO Ancillary Services Round Table, 

April 26, 2006. 

259 Mario DePillis, 2006. 
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planning and the role of demand response is left to the individual transmission owners. 

International Examples 

In many parts of the world, as in many parts of the United States, demand response impacts 

transmission planning indirectly by impacting expected demand. In the Nordic countries, for example, 

Nordel (the regional transmission operator) regards demand response as critical to supporting 

reliability but it does not implement demand response programs itself as this is done by the individual 

countries. Demand response appears to be more aimed at providing balancing capability than at 

deferring transmission and distribution investment.260 Australia provides a counterpoint. 

Australia’s National Electricity Market operates the longest interconnected power system in the world 

– more than 4,000 kilometers from Queensland to South Australia. Peak demand is 31,000 MW. 

Energy prices are typically under A$40/MWh but can go as high as A$10,000/MWh during system 

emergencies.261 Such a geographically large power system is necessarily dependant on transmission 

and transmission constraints are not uncommon. A major method for demand response to participate 

in markets is in support of the deferral of capital expenditure for load-growth related network 

expansion. 

New South Wales enacted a “D Factor” which allows Distribution Network Service Providers to retain 

capital expenditures avoided through targeting of demand management. The New South Wales DM 

Code of Practice also requires Distribution Network Service Providers to exhaust demand-side 

management as an alternative before undertaking load-driven network expansion. 

Example Demand Response Projects 

The following examples illustrate the steps that have been taken to consider and use demand response 

as an alternative to transmission at various utilities and regions. 

LIPA Edge 

The LIPA Edge project is a good example of how a demand reduction project that controls residential 

and small commercial air conditioners using modern technology has the potential of serving as a 

resource for ancillary services. The installed technology has the technical ability to provide spinning 

reserves, as well as peak load reduction. 

Remotely controllable Carrier Comfort Choice thermostats, coupled with two-way communication 

provided by Silicone Energy and Skytel two-way pagers allow the Long Island Power Authority 

(LIPA) to monitor capability and response, as well as to control, load reductions. It also enables 

customers to control their individual thermostats via the Internet, a benefit that motivates 

participation.262 The project currently controls 25,000 residential units and 5,000 small commercial 

 260 Grayson Heffner, Demand Response Providing Regulation and Reserve Services in Nordic Electricity Markets 

– DRAFT, Consortium for Electric Reliability Technical Solutions, March 2006. 

261 Grayson Heffner, Demand Response Provision of Ancillary Services in Australia’s National Electricity Market 

- DRAFT, Consortium for Electric Reliability Technical Solutions, March 2006. 

262 LIPA, LIPA Edge, presentation to the New York Independent System Operator Price-Responsive Load 

Working Group, 21 November 21, 2002. 
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units provide 36 MW of peak load reduction.263

Detailed discussions with Carrier in 2002 revealed that the technology is fast enough to provide 

spinning reserves and provides ample monitoring capability. Further analysis of test data revealed that 

the program can typically deliver 75 MW of 10-minute spinning reserves264 at little or no additional 

cost at times of heavy system loading. This could provide a significant benefit for capacityconstrained Long Island. Significant spinning reserve capability remains even if the system is being 

used for peak reduction as shown in Figure VI-5.265 Spinning reserves capacity is now likely over 100 

MW. 

Figure VI-5. LIPA Edge spinning reserve capability during August 14, 

2002 curtailment 

-10

0

10

20

30

40

50

60

70

80

0:00 4:00 8:00 12:00 16:00 20:00 0:00

Hour

MW

Available Spinning Reserve Without

Demand Reduction Response

Available Spinning Reserve With

Demand Reduction Response

Demand Reduction Response

Source: Brendan Kirby of Oak Ridge National Laboratory 

Southern California Edison Feeder Relief 

Southern California Edison (SCE), with California Energy Commission support, is conducting a 

Demand Response Dispatch Verification Research and Demonstration Project in the summer of 2006 

to demonstrate the impacts of distributed resources both as a means to provide specific load relief at 

the substation and distribution feeder level, and as a spinning reserves resource. The system uses the 

Internet, the SCE-wide area network, and various wireless technologies to provide two-way control 

and monitoring of the devices that control electric loads at approximately 450 sites in Southern 

California. Two specific objectives are to demonstrate that, when load is curtailed by a dispatch 

signal, the available MW demand response of a specific circuit can be predicted with a 90 percent 

statistical confidence and demonstrate that the load can be curtailed reliably and quickly on the 

issuance of a dispatch signal. The load shed is expected to start within 10 seconds of the signal and be 

fully implemented within two minutes. 

 263 Michael Marks, E-mail discussion with Michael Marks of the Applied Energy Group, April 15, 2006. 

264 This test was conducted when the peak reduction program only had 25 MW of capacity. 

265 Kirby, 2003. 
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SCE is implementing a special contract for the test with 400 to 500 residential customers and 50 to 

100 commercial customers. Various curtailment intervals are to be tested. The selected circuit has a 

peak load of 9 MW. SCE expects to curtail 2 to 3 MW depending on time of day, temperature, and 

day of week. A rigorous statistical analysis has been performed in planning the number of customers 

under the test, the number of tests, and the data acquisition system to ensure the results provide a 

relative precision of 15 percent at the 90 percent level of confidence. SCE expects the test to provide a 

benchmark for repeatable, precise, rapid demand response used as a reliability service.266

BPA Olympic Peninsula 

BPA is conducting several pilot projects aimed at deferring the need for transmission enhancements. 

Several technologies are being utilized including: 

 

• Direct load control – 20 MW from electric water heating, pool pumps, heat pumps, forced air 

furnaces, and baseboard heating. One-way radio pagers and power line communications 

within the residence are being used. 

• Demand response – 16 MW from electric water heaters, cloths dryers, pool pumps, heat 

pumps, and forced air furnaces. Fiber optic and cable internet connections are being used to 

communicate with Grid-FriendlyTM appliances. Customers can set prices for response. GridFriendlyTM appliances will also respond to system frequency disturbances. 

• Voluntary load curtailment – 22 MW through the Demand Exchange internet-based auction 

where loads can offer to reduce consumption in response to reliability or market volatility 

events. 

• Distributed generation – 4 MW from industrial and commercial backup generators. 

• Energy efficiency – 15 MW. 

Consolidated Edison 

Consolidated Edison provides an example where demand-side resources are being explicitly sought as 

an alternative to transmission and distribution expansion. Consolidated Edison issued a request for 

proposals in April 2006 seeking at least 123 MW of demand side management in targeted areas of 

New York City and Westchester County in order to defer transmission and distribution capital 

investment. Multiple proposals will be considered; each proposal must be for at least 500 kW of 

aggregated peak summer load reduction. Consolidated Edison provided detailed information and 

maps for each geographic area to help project developers. Materials include: 

• Numbers and types of customers (residential, commercial, small commercial, types of 

business, types of residential, numbers of central air conditioners, numbers of room air 

conditioners, etc.) 

• Sizes of individual customer loads (10-300+KW) 

• Total required load reduction (2-25 MW) 

• Need date (2008-2011) 

• Minimum project duration (two to four years) 

 266 SCE, California Independent System Operator and California Energy Commission, CERTS Demand Response 

Project, Plan For Summer 2006 Demand Response Test on Southern California Edison Distribution Circuit, March 23, 2005 
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Clean distributed generation may be proposed, as well as energy efficiency measures. Distributed 

generators can reduce customer load but they may not export to the grid to be considered for this 

program. Energy efficiency measures are allowed (compact florescent lights, energy efficient motors, 

efficient air conditioning, and steam chillers, for example). 

Consolidated Edison has chosen not to include direct load control and measures that “temporarily 

curtail or interrupt loads” in this request for proposals. These will also not consider operating and 

maintenance improvements and improved new construction measures.267

Mad River Valley Project 

In 1989, Green Mountain Power (GMP) needed to enhance the distribution system feeding Sugarbush 

Resort in the Mad River Valley in central Vermont. Load was expected to grow and a $5 million 

parallel 34.5 kV line was needed. Instead, Sugarbush installed an energy management system to 

enable it to monitor and control its load and keep the total feeder load below 30 MW. Snowmaking 

was the major controlled load. GMP also engaged in an energy efficiency program for other 

customers on the feeder. Note that GMP largely abandoned the follow-on demand side management 

work once the network problems were resolved.268

The Energy Coalition 

The Energy Coalition was formed in 1981 by end users to aggregate demand response to help alleviate 

generation and network capacity shortages in southern California. The Business Energy Coalition of 

the Energy Coalition is a specific project in the San Francisco area that specializes in short-term 

network relief. A 10 MW pilot project is based on the area’s 200 largest customers with day-ahead 

and same-day response. Response is limited to five hours/event, one event/day, five events/month, 

and one hundred hours/year. Response can be called upon for CAISO Stage 2 emergencies, spinning 

reserve shortfalls, forecasted San Francisco temperatures above 78 degrees, local emergencies, and 

total CAISO load forecast to exceed 43,000 MW. 

Concerns And Obstacles 

There are a number of obstacles to the greater use of demand response as an element in transmission 

planning and operations. Specific concerns and obstacles that have been identified by Commission 

staff are discussed below. 

Lack of Uniform Treatment of Demand Response. 

There are many examples of features of reliability rules that accommodate generator limitations that 

do not increase system reliability. They are necessary to enable generators to provide the desired 

reliability response but they are not themselves directly related to that desired reliability response. A 

partial list includes: 

 267 Consolidated Edison, Request For Proposals To Provide Demand Side Management To Provide Transmission 

And Distribution System Load Relief And Reduce Generation Capacity Requirements To Consolidated Edison Company Of 

New York, Inc., www.coned.com, April 14, 2006. 

268 Richard Cowart, Distributed Resources and Electric System Reliability, The Regulatory Assistance Project, 

2001. 
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• Minimum run times 

• Minimum off times 

• Minimum load 

• Ramp time for spinning reserve 

• Accommodation of inaccurate response 

• Limiting regulation range within operating range to accommodate coal pulverizer 

configuration 

These rules are necessary to elicit the reliability response the power system requires. Similar 

accommodations could be afforded to other technologies, such as demand response, based on their 

limitations. A partial list might include: 

• Maximum run time 

• Value of capacity that is coincident with system load 

• Value of response speed 

• Value of response accuracy 

• Match metering requirements to resource characteristics 

Perceived Temporary Nature of Demand Response 

When demand response is considered as an alternative to transmission expansion, it is typically 

considered as deferral rather than as an alternative. This has important implications for demand 

response financing as well as performance. The economic viability of demand response is determined 

by comparing the cost of the demand response project with the present value of the savings obtained 

by delaying construction of the transmission investment for a few years. The transmission alternative, 

however, is evaluated over a 20 to 30-year facility life. Since transmission additions are large projects, 

transmission additions typically reduce or eliminate the need for targeted demand response resources. 

The basic reasoning is that load growth will eventually make the transmission investment necessary so 

demand response can only delay the inevitable. Operating practice often follows the same temporary 

logic. Demand response programs may be discontinued once the transmission project they have been 

delaying is finally installed. The excess capacity that is typically initially made available by 

transmission expansion (discussed below) makes demand response, at least temporarily unnecessary. 

A transmission investment is not considered in the same way. If additional transmission is needed 

later, it is additional transmission, not replacement. Note that demand response can also be long-lived 

– Progress Energy Florida’s demand response program has been operating for over 20 years. 

While this argument that demand response is a temporary solution is logical, it is different from how 

other transmission investments are evaluated. A subtransmission line might be installed or upgraded, 

delaying the need for a new transmission line for a few years. The subtransmission line would not be 

taken out of service or out of the rate base, however, once the larger line was in place. It would 

instead be considered a permanent part of the power system. 

How transmission costs are incurred and paid for is also important. Transmission is a long-lived, 

capital intensive, low maintenance investment with almost no cost related to use. Once installed, in 

one sense, use of transmission is free; there appears to be no marginal cost. Conversely, demand 

response typically has costs (or user inconvenience) associated with each use; there is a marginal cost. 

Consequently, once transmission is available it is used instead of demand response, furthering the idea 

that demand response is a short lived, high operating cost solution when compared with transmission. 
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While transmission projects have few costs associated with use they do have significant annual 

maintenance costs. Transmission assets deteriorate rapidly with no maintenance (tree trimming, relay 

and breaker maintenance, etc.). It is difficult to tie specific costs to specific users but the marginal 

costs are there. 

Regulatory Treatment of Transmission and Demand Response Costs 

Transmission is almost always a regulated asset. Once it is in the rate base, its costs are fully covered. 

Demand response is not usually treated as a regulated capital resource placed in a rate base. Demand 

response may be cheaper overall but once transmission is available transmission always appears to be 

lower cost. Transmission cost recovery is essentially guaranteed once a project is built. A 230 kV 

high voltage transmission line would not be taken out of the rate base when an extra high voltage 765 

kV line was overlaid on the transmission system, regardless of how line loadings changed. 

Reliability regions and ISOs are typically barred from actively developing demand side resources as 

alternatives to transmission enhancement. Their role is limited to facilitating competitive markets 

where generators and loads can economically optimize their production and use of energy. Their 

transmission planning activities identify constraints that are or will be impacting reliability or 

commerce. Regulated transmission providers and competitive generation and demand entities are 

expected to offer solutions, which the ISO and region assess. 

BPA seems to have considered this rational as well. A 2001 BPA consultant report stated: “In many 

respects these nonwires activities have been outside of TBL’s (Transmission Business Line – BPA’s 

transmission side of the business) purview and TBL has had to be passive with respect to them. If 

they happen, TBL can account for them, but it cannot make them happen.”269 BPA changed its 

approach to transmission planning and now formally considers non-wires alternatives for all 

transmission enhancement projects costing $2 million or more. 

Reliability of Statistical Demand Response 

An often expressed concern is that demand response is not as reliable or as certain as generation 

response. While there is no absolute guarantee that any physical resource will be able to provide a 

specific response at any specific time, large generators have dedicated staff, extensive monitoring and 

control, and strong economic incentives to actually provide the response they are contracted to 

provide. Loads, especially small loads, do not have the same staffing or equipment resources. 

Response is voluntary in some cases. Nevertheless, there is good reason to believe that the inherent 

reliability of the response from aggregations of small loads is actually better than the reliability of 

response from large generators. 

Fundamentally, curtailments based on customer actions are a statistical resource, while generation is a 

deterministic resource. Some load reductions are large and deterministic while some generators are 

small and statistical; but as a general rule, individual load reductions are small, are important in 

aggregate, and behave statistically; individual generators are large, are important individually, and 

 269 R. Orans, S. Price, D. Lloyd, T. Foley, and E. Hirst, Expansion of BPA Transmission Planning Capabilities, 

Bonneville Power Administration, November 2001. 
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behave deterministically. There are advantages to both types of resources and both should be used. 

The important thing to note is that there are differences.270

Aggregations of small demand response resources can provide greater reliability than fewer numbers 

of large generators, as illustrated in Figure VI-6. In this simple example, operating reserves are being 

supplied by six generators that can each provide 100 MW of response with 95 percent reliability. 

There is a 74 percent chance that all six generators will respond to a contingency event and a 97 

percent probability that at least five will respond, which implies a nontrivial chance that fewer than 

five will respond. This can be contrasted to the performance from an aggregation of 1,200 demand 

response resources of 500 kW each with only 90 percent reliability each. This aggregation typically 

delivers 540 MW (as opposed to 600 MW) but never delivers less than 520 MW. As this example 

illustrates, the aggregate demand response is much more predictable and the response that the system 

operator can “count on” is actually greater. 

Figure VI-6 Comparison of probability of response between aggregated 

demand response and fewer large generators 

50%

60%

70%

80%

90%

100%

0 100 200 300 400 500 600

Responding Reserve (MW)

Probability

6 - 100 MW Generators

95% Reliability

1200 - 500 KW Responsive Loads

90% Reliability

Source: Brendan Kirby of Oak Ridge National Laboratory 

Operating reserves have historically been provided by large generators that are equipped with 

supervisory control and data acquisition monitoring equipment that telemeters generator output and 

various other parameters to the system operator every few seconds. Operating reserve resources are 

closely monitored for three reasons: (1) to inform the system operator of the availability of reserves 

before they are needed; (2) to monitor deployment events in real time so that the system operator can 

take corrective action in case of a reserve failure; and (3) to monitor individual performance so that 

compensation motivates future performance. Because the same monitoring system provides all three 

functions, we often fail to distinguish between these functions. For small loads, it may be better to 

look at each function separately. 

 270 Kirby, 2003. 
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The statistical nature of aggregated demand response lends itself to useful forecasting in place of realtime monitoring. Forecasting errors for load-supplied reserves can be more easily accommodated than 

forecast errors for the total load. A 10 percent error in the load forecast for a 30,000 MW balancing 

authority can result in a 3,000 MW supply shortfall. A 10 percent error in 600 MW of expected 

reserve response from demand response can be handled by derating the resource and calling for 10 

percent more response than is needed. This derating can be refined as experience is gained. 

Demand response forecasting errors for large aggregations of small responding loads are fortunately 

correlated with overall load forecasting errors. If total load is higher than the forecast, so are the 

available reserves from demand response. 

Metering requirements could be based on the reliability requirements of the system, recognizing that 

large deterministic resources present a different monitoring requirement than aggregations of small 

statistical resources in order to achieve the same system reliability. 

Manual Override and Voluntary Response 

Demand response programs often find that they must accommodate voluntary response in order to 

increase participation. This is not surprising. While the cost of electricity is important to most 

consumers, it is only one of many costs. Loads often find it impossible to make firm, long-term 

curtailment commitments because there is some chance that external events (external to the power 

system) will prevent them from reducing power consumption when requested. Even if a customer is 

able to respond 99 percent of the time, the other one percent of the time may be perceived to be of 

such high importance that the load is unwilling to participate in a curtailment program. This reaction 

is surprisingly universal; it can be true for residential as well as commercial and industrial 

customers.271 Day-ahead and hour-ahead hourly markets reduce or eliminate this problem for many 

large loads and generators. But the transaction burden of constantly interacting with energy and 

ancillary service markets is likely too great for many small loads. Many will prefer to establish a 

standing offer for response that they are able to honor the vast majority of the time. 

Manual override provides an alternative with benefits for both the power system and the customer. 

With a manual override feature, the load curtailment occurs, but the individual customer has the option 

of overriding the curtailment. The advantage to the power system is that this option increases the load 

participation and likely reduces the required compensation. The advantage to the customer is that it 

can opt out of a particular curtailment if the inconvenience or cost for the specific event is unusually 

high. Many peak reduction programs now include this feature, and it appears to be successful. Most 

important, the increase in participation outweighs the number of customers overriding the curtailment. 

How the opt-out is configured can be important. 

The natural fear from the power system side is that many customers will always opt out, but the size of 

this problem may not be large. Opting out requires the customer to notice that the curtailment is 

happening and decide that the inconvenience is too great. The customer must take specific action for 

 271 An industrial load may have an unexpected order and consequent production goal. A residential customer may 

have a sick child at home and be unwilling to allow air conditioning curtailment. Neither event could be predicted in advance 

and neither event is tied to power system conditions. 
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each event. Customers that chronically opt out could also be dropped from the program. Figure VI-7 

shows the override experience for the LIPA Edge program during peak reduction testing on the 

afternoon of August 14, 2002.272 By three hours into the curtailment, a significant number of 

customers were overriding and this must be considered when valuing the program. 

Figure VI-7 Statistics from the LIPA Edge program manual override 

experience 

Source: Brendan Kirby of Oak Ridge National Laboratory 

Manual override is less of a problem when spinning reserve and contingency response is being 

supplied than when the peak load is being reduced for two reasons: (1) contingency event duration is 

shorter, and (2) natural human inertia and the slow temperature rise prevents customer response within 

the typical spinning reserve deployment event. But there is a technical solution as well. For example, 

there are types of smart thermostats that offer the power system operator the additional option of 

distinguishing between events that the customer can override and events that the customer cannot. 

This provides the customer with the ability to opt out of longer demand reduction events while 

blocking the override during shorter contingency events. 

Capacity Credit 

Demand response programs are sometimes economically disadvantaged in areas with formal capacity 

markets. For example, some markets impose an artificial requirement that response must be available 

24 hours a day, all season long. This is reasonable when the only source of response is generation 

whose availability is typically not time variant. Some load is not available to respond in rectangular 

strips, however. But it is always available when the power system is most heavily loaded and most 

stressed; at the time of the daily load peak. The ancillary services of regulation, spinning, and nonspinning reserves are needed just as much as capacity that is delivering real-power to serve load. 

 272 Kirby, 2003. 

0%

5%

10%

15%

20%

25%

30%

35%

40%

0:00 1:00 2:00 3:00 4:00

Hours Into Curtailment

Dropout Rate

Commercial

Residential
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Co-Optimization – Response Cost Vs Duration 

Many demand response resources differ from most generators in that the cost of response rises with 

response duration. An air conditioning load, for example, incurs almost no cost when it provides a 10-

minute interruption but incurs unacceptable costs when it provides a six hour interruption. Conversely 

a generator typically incurs startup and shutdown costs, even for short responses but only has ongoing 

fuel costs associated with its response duration. In fact, many generators have minimum run times and 

minimum shutdown times. This low-cost-for-short-duration-response (coupled with fast response 

speed) makes some demand response resources ideal for providing spinning reserve but less well 

suited for providing energy response or peak reduction. 

This policy works well for most generators but causes severe problems for loads that need to limit the 

duration or frequency of their response to occasional contingency conditions.273 Loads can submit 

very high energy bids in an attempt to be the last resource called but this is still no guarantee that they 

will not be used as a multi-hour energy resource. Submitting a high cost energy bid also means that 

the load will be used less frequently for contingency response than is economically optimal. Price 

caps on energy bids further limit the ability of the loads to control how long they are deployed for. 

California had this problem with its Rational Buyer approach, but it has since changed its market rules. 

It now allows resources to flag themselves as available for contingency response only. PJM allows 

resources to establish different prices for each service and energy providing a partial solution. 

ERCOT does not have this problem because energy is supplied through bilateral arrangements. 

Energy and ancillary service markets are separate. Possibly as a consequence, half of ERCOT’s 

contingency response comes from demand response. 

Steps that could be taken to ensure that, in regional transmission 

planning and operations, demand resources are provided 

equitable treatment 

Section 1252(e)(3) of EPAct 2005 requires that the Commission identify steps that could be taken to 

ensure that, in regional transmission planning and operations, demand resources are provided equitable 

treatment. Based on comments and Commission staff review of regional transmission planning and 

operations, Commission staff has identified several actions and steps that could be taken to obtain 

increased access for demand resources. The merits of taking the following steps should be considered 

by appropriate transmission planners and state and federal regulators: 

• Assure that regions that schedule resources and reserve needs properly recognize the 

capabilities and characteristics of demand resources, particularly when energy and ancillary 

services are co-optimized. 

• Assure that requirements are specified in terms of functional needs rather than in terms of the 

technology that is expected to fill the need. This applies to ancillary services as well as to 

transmission enhancement. 

o Value response speed and accuracy. 

o Value statistical response. 

 273 Co-optimization often does not work for energy or emissions-limited generators either. 
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• Accommodate the inherent characteristics of demand response resources (just as generation 

resource characteristics are accommodated). 

o Recognize that some demand response resources have maximum run times. 

o Recognize the statistical nature of demand response from aggregations of numerous 

small loads. 

o Recognize that the monitoring and communications requirements to maintain system 

reliability are fundamentally different for aggregations of large numbers of small 

resources than they are for fewer large resources. 

o Recognize the coincidence of demand response capability and total system load. 

Allocate appropriate capacity credit to demand response. 

o Accommodate voluntary response and perform the research required to establish the 

level of reliable response capability. 

• Allow appropriately designed demand response resources to provide all ancillary services 

including spinning reserve, regulation, and any new frequency responsive reserves. 

• Allow for the consideration of demand response alternatives for all transmission enhancement 

proposals at both the state and ISO/RTO level. 

o At the minimum, transmission expansion planning procedures would allow demand 

response resources to be proposed and considered as solutions to congested interfaces 

or load pockets along with local generation or transmission enhancements. 

o Require demand response evaluations early enough in the process so that demand 

response solutions can actually be developed. 

o Require reporting of alternatives considered and reasons for decisions. 

• When appropriate, treat demand response as a permanent solution, similar to transmission 

enhancements. 
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Chapter VII. Regulatory Barriers 

This chapter addresses the sixth area, in EPAct 2005 section 1252(e)(3), that Congress directed the 

Commission to consider: 

(F) regulatory barriers to improved customer participation in demand response, peak 

reduction and critical period pricing programs. 

The regulatory barriers discussed in this chapter are based on input received in written comments, 

comments filed and discussion heard at the FERC Demand Response Technical Conference (FERC 

Technical Conference), a review of demand-response program experience, and through a 

comprehensive literature review.274

Regulatory Barriers 

Disconnect Between Retail Pricing and Wholesale Markets 

The most frequently mentioned regulatory barrier in the literature and in the comments reviewed by 

Commission staff is the disconnect between fixed retail rates and fluctuating wholesale prices. By 

placing even a small percentage of customers on tariffs based on time-based rates, resources can be 

allocated more efficiently. Time-based rates offer customers incentives to shift their consumption to 

periods with lower rates and allow them to save on their energy bills. This is true with or without 

retail choice. And because the cost of delivering energy during peak periods is higher than averaged 

flat rates, average pricing results in an income transfer from customers who use a lower proportion of 

their energy during peak periods to those who use a high fraction of their electricity on peak.275 

Because most customers do not face time-varying prices (see Chapter IV discussion), they are charged 

prices associated with the average cost to produce electricity calculated over extended period of 

months or years. Large customers in a few states have direct exposure to hourly pricing, but this is the 

exception, not the rule.276 The Government Accountability Office (GAO), in its 2004 report on 

demand response, highlighted this disconnect: “Most of today’s electricity system is a hybrid – 

competition setting wholesale prices and regulation largely setting retail prices. In addition, local 

public power entities (munis) and rural electric coops (co-ops) account for about 25 percent of the 

wholesale market and are self-regulated.”277

Even though the benefits of placing at least some customers on time-based rates is well documented, 

and while major industry organizations and regulatory agencies are in favor of greater implementation 

 274 Earlier chapters discussed barriers associated with non-regulatory areas such as implementation and customer 

perception. 

275 California Energy Commission, Feasibility of Implementing Dynamic Pricing in California, report to the 

legislature to satisfy the legislative requirement of SB 1976, October 2003, http://energy.ca.gov/reports/2003-10-31_400-03-

020F.PDF. 

276 Only a few states such as California, Connecticut, Illinois, and New York have taken actions to introduce 

greater amounts of time-based rates into their jurisdictions. 

277 GAO, Electricity Markets: Consumers Could Benefit from Demand Programs, But Challenges Remain, GAO04-844, August 2004, 9. 
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of time-based rates,278 the structure of retail rates is largely based on fixed rates. Only a few states 

such as California, Connecticut, Illinois, and New York have taken actions to introduce greater 

amounts of time-based rates into their jurisdictions. The basic structure of retail rates has not changed 

significantly for decades, and even the default (standard offer service or Provider of Last Resort 

(POLR)) rates offered in restructured states usually maintain the historic non-varying rates and rate 

structures or use pre-specified fixed prices. The disconnect between retail rates and wholesale markets 

has grown larger as opportunities to integrate demand response into wholesale markets have increased, 

but retail offerings have stagnated. 

ISO-NE’s CEO, Gordon van Welie, posited that the continuation of flat retail pricing is “paternalistic 

and outdated,” stating his belief that “some form of dynamic pricing should be the basis for default 

service pricing for large customers.”279 However, others argue against implementation of time-based 

rates based on concerns about whether consumers can reasonably be expected to adjust their demand 

for essential uses. For example, the Pennsylvania Office of Consumer Advocate argues that timebased rates “are not appropriate when the usage relates to essential home heating or air conditioning 

and necessary appliance usage.”280 

Although there have been many experimental and pilot programs, it is not clear why these have not 

moved into full implementation. As a panelist at the FERC Technical Conference expressed it, “we 

are suffering the death by a thousand pilots.”281

The examination of smart metering and time-based rates in the state deliberations required by EPAct 

2005 should shed some light on this barrier, and may lead to greater deployment of advanced metering 

and time-based rates. In addition, advances in technology and cost declines associated with metering 

and controls, in combination with the greater system benefits they now offer, should also help 

ameliorate concerns about cost-effectiveness. 

Utility Disincentives Associated with Offering Demand Response 

A long-standing barrier to electric utility investment in and promotion of customer demand-side 

programs is that historically, utilities make money from the sale of electricity. Otherwise stated, 

traditional rate-making models have been based on formulas of: 

PROFIT = REVENUE – COSTS and REVENUE = PRICE * QUANTITY 282

Any actions taken by customers to reduce their overall consumption through energy efficiency, 

adjustment of their consumption in response to prices or load reductions during peak periods or 

reserve shortages, will likely reduce short-term utility revenues if they result in a reduction in kWh 

consumption or reduced customer peak demand. In particular, utilities cannot be assured that if 

customers shift their peak load reductions to off-peak usage, the utility will remain revenue neutral. 

As NERA stated, “while utilities have long championed conservation for a variety of long-term 

business reasons, it is possible that demand response would decrease earnings in the short-term and 

 278 For example, the Edison Electric Institute and New York Public Service Commission. 

279 Gordon van Welie, speech to 2006 ISO-NE Demand Response Summit, April 27, 2006. 

280 Pennsylvania Office of Consumer Advocate, comments filed in Docket AD05-17, November 18, 2005. 

281 Alison Silverstein, FERC Technical Conference, transcript, 42:9. 

282 Frederick Weston and Wayne Shirley, “Scoping Paper on Dynamic Pricing: Aligning Retail Prices with 

Wholesale Markets,” prepared for MADRI Regulatory Subgroup, June 2005, 1, 12-15.
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that this would serve as a disincentive for the utility to play an active role in promoting demand 

response.”283 

The restructuring of the electric industry has added additional disincentives for distribution utilities. 

In some states, utility divestiture of generation and load-management assets 284 and the transfer of the 

POLR obligation to serve have removed significant drivers for utility investment. If a distribution 

utility does not have a direct load responsibility, then the long-term benefits associated with operating 

demand response as a resource are driven more by impacts on local distribution operation and 

reliability, and these are usually a small fraction of avoided generation costs. 

Policies to address utility disincentives to demand-side activities and management have been 

suggested and implemented for many years.285 Policy changes fall into three categories: 

• Remove Disincentives. Policies that remove retail rate structures and rate designs that have 

discouraged implementation of demand response by decoupling profits from sales volumes. 

• Recover Costs. Policies that give utilities a reasonable opportunity to recover the costs of 

implementing demand-response programs. 

• Reward Performance. Sometimes referred to as performance-based ratemaking, retail rates 

and regulatory policies can include incentives for implementing high-performance demandresponse programs. Incentives are usually higher returns on investment if the programs 

demonstrate success, through reduction of peak demand or peak period energy use, or 

payments based on increased customer enrollment. Shared-savings mechanisms (where 

utilities share the savings and/or profits associated with the demand-response programs with 

customers or third-party aggregators) can also be employed as another performance incentive. 

Productive discussions on the best means to address utility disincentives continue. Decoupling 

policies are being actively examined in state proceedings, and have been implemented in California 

and Oregon. Other states such as New York286 and Connecticut287 rejected rate decoupling, noting the 

negative impact that large revenue accruals can have on rate stability. A recently approved rate plan 

for Consolidated Edison provides an additional example of policies that are directed at removing 

disincentives. Under the rate plan, Consolidated Edison will recover demand-response 

implementation costs (spread over three to five years) through monthly adjustment charges for all 

electric customers who benefit. Their incentive to perform is based on a process Consolidated Edison 

and the NYPSC agreed on in order to monetize the costs of demand response and “make the 

distribution company whole” by doing demand response.288 Consolidated Edison is entitled to recover 

the lost revenues from demand management that are incremental to what are already contained in its 

 283 NERA Economic Consulting (NERA), Distributed Resources: Incentives, prepared for EEI, April 20, 2006, 10. 

284 More than 3,500 MW of capacity from interruptible contracts no longer exists. Steven Braithwait, B. Kelly 

Eakin, Laurence D. Kirsch, Encouraging Demand Participation In Texas’s Power Markets, Laurits R. Christensen 

Associates, Inc., prepared for the Market Oversight Division of the Public Utility Commission of Texas, August 2002. 

285 A good summary of these policies in included in Hope Robertson, Focusing on the Demand Side of the Power 

Equation: Implications and Opportunities, Cambridge Energy Research Associates, May 2006, 15-16. 

286 State of New York Public Service Commission, Case No. 03-E-0640, Staff Report, July 9, 2004, 7-8. 

287 Connecticut Department of Public Utility Control, Investigation into Decoupling Energy Distribution Company 

Earnings from Sales, Final Decision, Docket No. 05-09-09, January 18, 2006. 

288 MADRI business case subgroup meeting and conference call, May 15, 2006; for ConEd’s demand-side 

agreement; and NYPSC Order on Demand Action Plan, Case 04-E-0572, March 15, 2006, see 

http://www.energetics.com/MADRI/#may06 
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electric rate plan forecast for the megawatt reductions achieved.289 Decoupling policies are also the 

subject of ongoing discussions within the Mid-Atlantic Distributed Resources Initiative (MADRI).290

Cost Recovery and Incentives for Enabling Technologies 

Without additional technology, customer actions in response to prices, incentives, or directions from 

grid operators cannot be (a) measured and compensated, or (b) enabled. One study noted that without 

near universal installation of advanced metering, demand response activity for smaller customers will 

likely be limited to customers with large loads suitable for load control.291 Wide-scale upgrading of 

meters or deployment of advanced metering and other enabling technologies requires substantial 

investments and outlays of capital. Utilities are reluctant to undertake these investments unless the 

business case for deployment is sufficiently positive to justify the outlay. In addition, utilities are 

concerned about whether meters could become a stranded asset under future deregulation – that is, is 

there long-term regulatory certainty to their investment? 

As Chapter III noted, the business case for advanced metering can include numerous operational cost 

savings for distribution utilities, in addition to demand response-related savings. Operational benefits 

may largely cover much of the cost of the deployment, as well as accelerating its cost recovery. 

Utilities need to conduct a fair and reasonable cost-benefit analysis of adopting metering infrastructure 

that takes into account the nature and needs of the service territory.292 Recovery of at least part of 

utility investment in metering, either through expensing or rate-basing, may be necessary. Without 

cost recovery, utilities may not have an incentive to roll out advanced metering to all customers. As 

was the case with utility investment in demand response, in order to provide sufficient incentive for 

utility investment in advanced metering, returns from this investment need to be at least commensurate 

with returns that utilities can get from their generation and transmission assets. 

Cost recovery of advanced metering in rates has been the subject of regulatory proceedings. Because 

these deployments may require an increase in rates, it is uncertain whether states will allow full 

deployments to be fully rate-based, amortized, or expensed. UtiliPoint presented the results of an 

earlier survey at the FERC Technical Conference (see Figure VII-1) that suggested that most of the 

regulators contacted supported at least partial cost recovery of advanced metering and demand 

response. Rate recovery is not without controversy. For instance, consumer groups in California 

argued against rate recovery of advanced metering in the proceedings associated with statewide 

deployment.293

Until uncertainty about rate recovery of advanced metering can be resolved, and that meters will not 

become a stranded asset under future deregulation, utilities will be reluctant to invest in the 

technology.294 Similarly, utilities will also need to know whether retail rate regulators will approve a 

 289 Richard Miller (Consolidated Edison), FERC Technical Conference, January 25, 2006, transcript, 64: 250. 

290 See http://www.energetics.com/MADRI/ for presentations and papers. 

291 UtiliPoint, Outlook & Evaluation of Demand Response, June 2005, 9. 

292 After the assessment period in California’s Advanced Metering Initiative, the three investor-owned utilities 

proposed very different metering systems and infrastructure, based on the “nature” of their customers and on customer 

responses during the pilot period. See “California’s Statewide Pricing Pilot: Overview of Key Findings,” Presentation made 

to MADRI, May 4, 2005, 18-22.

293 See, for example, prepared Testimony of Jeffrey A. Nahigian, in SDG&E’s Application for Adoption of an 

Advanced Metering Infrastructure (A. 05-03-015). 

294 Colledge, Justin A., et al., “Power by the Minute.” McKinsey Quarterly, 2002, #1: 73-80. 
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Figure VII-1. Regulator treatment of AMI and Demand Response

Allowance of Cost Recovery for Future 

Expenses of AMI/AMR and/or Demand 

Response

Yes - full 

recovery 

of prudent 

expenses, 

35%

Yes - 

some 

recovery 

of prudent 

expenses, 

39%

No, 17%

No reply, 

9%

Source: Patti Harper-Slaboszewicz, UtiliPoint, “Regulator Interest in AMI and Demand Response,” written remarks submitted as panelist, 

FERC Technical Conference, 5

concurrent retail dynamic pricing structure. Utility delay or non-action on advanced metering 

deployment due to these uncertainties may limit the potential for demand response in the United 

States. 

Another cost-recovery barrier raised at the FERC Technical Conference is the disconnect between the 

economic life of advanced metering infrastructure and its accounting depreciation period. Southern 

California Edison (SCE) reports that “many utilities, including us, are concerned about the potential 

that AMI technology will not last as long as its depreciation period... Since the ANSI meters and 

communication networks will have to operate in very difficult environmental conditions over a long 

time, if the life of these systems falls short, this could result in significant cost impacts for our 

customers.”295 Aligning the economic life with the accounting life will remove this disincentive. 

In addition, advances in technology and cost declines associated with metering and controls, in 

combination with the greater system benefits they now offer, should also help ameliorate concerns 

about cost-effectiveness. 

Barriers to Providing Demand-Response Services by Third Parties 

While the development of organized markets and independent system operators (ISOs) and Regional 

Transmission Organizations (RTOs) demand-response programs has created opportunities for the 

development of third-party demand response providers, shifting regulatory rules and potential sunset 

of various demand-response programs has proven to be a disincentive. Many third-parties partner 

with utilities, using various risk- and profit-sharing models. The providers are often invisible to retail 

customers whose demand response they enable. Because third parties often bear the risks of programs 

 295 Paul DeMartini (Southern California Edison), FERC Technical Conference, transcript, 23: 88-89. 
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dependent on enabling technologies, they need long-term regulatory assurance or long-term contracts 

to finance the capital they need from banks.

Need for Additional Research on Cost-Effectiveness and Measurement of 

Reductions 

As states and ISOs have implemented various price-based and incentive-based demand response 

programs, it has become clear that there are key deficiencies in the measurement of demand response 

and the means to assess cost-effectiveness. The need was articulated by Chuck Goldman of the 

Lawrence Berkeley National Laboratory (LBNL) at the FERC Technical Conference, “the third 

general area is strengthening demand-response analysis and valuation, so that program designers, 

policymakers, and customers can anticipate demand-response impacts and benefits. Demand-response 

program managers need to be able to reliably measure the net benefits of demand-response options, 

both costs and benefits, to ensure that they are effective at providing needed demand reductions and 

are cost effective to consumers.”296 Improvements in these areas will assist in state deliberations and 

in increasing the level of effective and beneficial demand response. 

There are several problems with the current demand-response measurement methods. Evaluation of 

demand-response programs requires accurate measurement or estimation of the reductions effected by 

customers. At present, calculation of demand-response impacts is based on a combination of 

statistical estimation and engineering analysis, but there does not appear to be any consistency in these 

methods across utilities, states, and ISOs. For instance, several methods are currently used in ISO 

programs to estimate what customer demand would have been in lieu of customer actions to reduce 

consumption (i.e., the customer baseline). Some ISOs use an average usage over a set number of days, 

while others use the average of consumption immediately prior to and after demand-response events. 

The ability to forecast and understand how greater price-responsiveness will affect load shapes, load 

growth, and resource needs is limited. LBNL’s Chuck Goldman stated: “The impacts from price 

based demand response, which depend heavily on customer behavior, are really less well known. 

There are a number of studies that have tried to calculate the elasticity of demand, and there's been a 

lot of work done on it, but when you actually translate that work into the actual system impacts, hour 

by hour, there's a lot of work that needs to be done.”297

There is also disagreement about what should be included in the cost-effectiveness and program 

evaluations. Most of the current tests for cost-effectiveness298 were designed to assess energy 

efficiency and load-management activities by vertically-integrated utilities in non-restructured 

environments. In particular, the current tests were originally designed to establish generation 

equivalency for demand response, not to evaluate demand response in its entirety. Given the changes 

in industry structure and the existence of organized markets, these tests need to be updated. Other 

costs and benefits such as customer, environmental, societal, risk information, opportunity, and other 

difficult-to-quantify impacts are excluded. The need to update the tests is well understood, and 

California has taken a lead in developing an integrated efficiency and demand-response framework 

 296 Charles Goldman (LBNL), FERC Technical Conference, transcript, 14: 7-15. 

297 Goldman, FERC Technical Conference, transcript, 21:18-24. 

298 The most well-known set of cost-effectiveness tests is the Standard Practice Methodology developed in 

California in the late 1970s and early 1980s (also known as the “California tests”). 
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and is funding research in this area.299 There is also no consistency in the evaluation methodologies 

that have been conducted by the ISOs on their programs. 

The need for clarity on cost-effectiveness methods is also an issue in the assessment of advanced 

metering. In particular, the inclusion and valuation of a wide variety of operational benefits such as 

remote shut-off/turn-on, reduction in estimated bills, and demand response is subject to debate. When 

these features are part of the cost-benefit calculus, the payback period for an investment in advanced 

meters shortens considerably.300 Utilities and regulators may also fail to include the operations and 

maintenance savings that accrue from demand-response programs and advanced metering but exceed 

narrow program costs. Research and consensus on appropriate costs and benefits to measure are 

needed in this area. 

Existence of Specific State-Level Barriers to Greater Demand Response 

In several states, the policies of retail rate regulators and state statutes create barriers to implementing 

greater levels of demand response and development of price-based programs. For example, California 

and New York laws effectively limit the ability to introduce new time-based rates, especially real-time 

pricing. In California, a bill was passed during the California Crisis (AB1-X) that limits the ability of 

the California Public Utility Commission (CPUC) to implement time-based rates such as Critical Peak 

Pricing (CPP) for residential customers. Bruce Kaneshiro of the CPUC reported at the FERC 

Technical Conference that “depending on your legal interpretation of the code of the language in that 

bill, you could interpret it to mean that the commission is prohibited from actually raising the rates for 

most of its residential customers until the power that was procured by the Department Water 

Resources has been effectively paid off. That won't happen until 2011.”301 In New York, state law 

prohibits mandatory time-of-use rates for residential customers.302 The New York law places a cap on 

the level of price-responsiveness that can be implemented in the state, and limits state policy to 

voluntary price-based demand response in the residential sector. One commenter interpreted the 

recently passed HB 6 in Delaware to phase-in higher retail prices to contain similar restrictions.303

State policies with regard to disbursement of societal-benefit charge funds304 can also provide a barrier 

to greater demand response. Commissioner Anne George of Connecticut reports that they “had some 

initial problems with lack of support from our energy conservation and management board and the 

utility in terms of how to spend the system benefit charge – the funds collected from that. I think a lot 

of that was centered around not understanding demand response as a permanent tool.”305 

Until these statutes and policies (and others like them in other states) are no longer enforced or are 

repealed, the full potential for demand response will not be achieved. 

 299 PIER Demand Response Research Center, Research Opportunity Notice DRRC RON-01, Establish the Value of 

Demand Response; Develop an Integrated Efficiency Demand Response Network. July 21, 2005. 

300 Roger Levy, “Establishing the AMI Business Case Framework: Advancing Technology to Support Utility, 

Customer and Societal Needs,” presentation to MADRI AMI subgroup, Philadelphia, PA: May 4, 2005; and David B. Smith, 

Citigroup, Meter Read: Pushing the Needle to Smart Metering. February 2006. 

301 Bruce Kaneshiro (CPUC), FERC Technical Conference, transcript, 201:7-13. 

302 See, New York State Public Service Law §66(27). 

303 Delaware HB 6, http://www.legis.state.de.us/LIS/LIS143.NSF/vwLegislation/HB+6?Opendocument. 304 Societal benefits charges are non-bypassable charges on customer bills that are used by multiple states to fund a 

variety of activities, including energy efficiency, renewable energy, low-income energy assistance, and demand response. 

305 Anne George (CT DPUC), FERC Technical Conference, 236-237. 
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Specific Retail and Wholesale Rules that Limit Demand Response 

Similar to the barriers caused by existing state statutes and policies about pricing and disbursement of 

funds, certain wholesale and retail market designs that have evolved over the last decade include rules 

and procedures that are not particularly friendly to demand participation. These problems include 

provisions included in state restructuring statutes, settlement and payment procedures, and frequent 

changes in market design and rules. 

An example of provisions in state restructuring statutes that have the effect of limiting demand 

response is the requirement that retail electric companies in the Electric Reliability Council of Texas 

(ERCOT) must be associated with and settle with only one Qualifying Scheduling Entity (QSE). This 

requirement creates problems for companies that are interested in aggregating customer load 

reduction. Unless the load-reduction company limits its aggregation to the customers of one retail 

electric company, it needs to develop contractual agreements with multiple retail electric companies 

and QSEs in order to get paid for any load reduction it provides to the market. This dynamic is one of 

the reasons that the demand-response provider company Comverge chose not to activate the air 

conditioner switches that it bought from CenterPoint Energy. 

Settlement issues related to payment for load reductions to third-party companies continues to be a 

problem in the ISO markets.306 Standard settlement procedure in the ISOs is to complete final 

settlement for positions between 60 to 90 days after the close of the real-time or day-ahead market. 

Third-party aggregators complain that this settlement provision delays when they can provide 

customers payments for their actions. For example, participants in a Mid-Atlantic Distributed 

Resources Initiative (MADRI) meeting in December 2005 indicated that they still had not received 

payments for load reductions that had occurred during the previous summer. Provisions in the PJM 

tariff also make it difficult for third-party aggregators to provide the ISO an accounting of when 

curtailments occurred within a set time period. Since distribution utilities have exclusive access to 

meter data, third-party aggregators must wait until the utilities complete their meter reading and 

verification processes before they can submit the curtailment data to the ISOs. While PJM indicates 

that this problem has been resolved by the time of the FERC Technical Conference, a more systemic 

solution is needed. Deployment of advanced metering and greater real-time access to meter reads by 

third-party providers will assist in the resolution of this payment issue.307

Insufficient Market Transparency and Access to Data 

Lack of access to data has been identified as a barrier to demand response. Greater transparency of 

unregulated retailer price offers and information on the amount of load under time-based rates or 

pricing will assist grid operation and planning. As Chuck Goldman of LBNL states: “If you want to 

move toward having customers being exposed to prices, you have to understand what's happening in 

the market, and, right now, we have very little information about what's happening among retailers in 

this area.”308

 306 Bernie Neenan, Richard N. Boisvert and Peter A. Cappers, “What Makes a Customer Price-Responsive?” The 

Electricity Journal, 15 #3 (April 2002), 53, discussing NYISO’s price-response load programs in the summer of 2001; 

conversations with PJM officials in the summer of 2005 reveal that this problem persists. 

307 PJM is discussing solutions to this problem in its Demand-Side Working Group: 

http://www.pjm.org/committees/working-groups/dsrwg/dsrwg.html. 308 Chuck Goldman (LBNL), FERC Technical Conference, 48:20-24. 
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A connected but larger barrier related to data is timely access to meter data. Customer response to 

time-varying prices has the most impact when customers can see the result of their actions in real-time 

or near real-time. One of the benefits associated with advanced metering is the ability to measure and 

provide usage. Nevertheless, policies on access to meter data have not kept up with the developments 

and advancements in advanced metering technology and data retrieval. Typically, the rules and tariffs 

in operation for distribution utilities provide access to meter reads to customers, but with some time 

lag. More problematic is the access to customer meter data for independent retailers and aggregators. 

Ideally, in an efficient and transparent market, retailers would be able to base their price offerings and 

scheduling/settlement on knowledge about actual customer load shape. While there are exceptions, 

such as the meter data access policies in ERCOT, current utility tariffs and policies make access to this 

data time-consuming and expensive. 

Better Coordination of Federal-State Jurisdiction Affecting Demand 

Response 

While states have primary jurisdiction over demand response, demand response plays a role in 

wholesale markets under Commission jurisdiction. Some commentators such as Steel Manufacturers 

Association,309 Alcoa,310 and Heffner and Sullivan311 have suggested that confusion over the scope of 

demand response in wholesale markets has limited the full potential of demand response. Greater 

clarity and coordination between wholesale and state programs is needed. 

Recommendations 

Demand response deserves serious attention. Staff recommends that the Commission: (1) explore 

how to better accommodate demand response in wholesale markets; (2) explore how to coordinate 

with utilities, state commissions and other interested parties on demand response in wholesale and 

retail markets; and (3) consider specific proposals for compatible regulatory approaches, including 

how to eliminate regulatory barriers to improved participation in demand response, peak reduction and 

critical peak pricing programs. Staff also encourages states to continue to consider ways to actively 

encourage demand response at the retail level. In particular, staff recommends that the Commission 

and states work cooperatively in finding demand response solutions. 

 309 Steel Manufacturers Association, comments filed in Docket AD06-2, December 19, 2005. 

310 Alcoa, comments filed in Docket AD06-2, December 19, 2005. 

311 Grayson Heffner and Freeman Sullivan, A Critical Examination of ISO-Sponsored Demand Response 

Programs, August 2005. 
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Appendices to the Report

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Appendices 

Appendix A: 

 EPAct 2005 Language on Demand Response and Smart Metering 

Appendix B: 

 Acronyms Used in the Report 

Appendix C: 

 Glossary for the Report 

Appendix D: 

 Bibliography for the Report 

Appendix E: 

 The Public Process Leading to the Report 

Appendix F: 

 The FERC Survey 

Appendix G: 

 FERC Survey Respondents 

Appendix H: 

 Demand Response (DR) Programs and Services at Responding Utilities 

Appendix I: 

 Data and Sources for Figures 

Appendix J: Acknowledgements 

Appendix A: EPAct 2005 Language 

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A-1

Appendix A: EPAct 2005 Language on 

Demand Response and Smart Metering 

SEC. 1252. SMART METERING. 

(a) IN GENERAL.—Section 111(d) of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 

2621(d)) is amended by adding at the end the following: 

‘‘(14) TIME-BASED METERING AND COMMUNICATIONS.— 

(A) Not later than 18 months after the date of enactment of this paragraph, each electric utility shall 

offer each of its customer H. R. 6—371 classes, and provide individual customers upon customer 

request, a time-based rate schedule under which the rate charged by the electric utility varies during 

different time periods and reflects the variance, if any, in the utility’s costs of generating and 

purchasing electricity at the wholesale level. The time-based rate schedule shall enable the electric 

consumer to manage energy use and cost through advanced metering and communications technology. 

‘‘(B) The types of time-based rate schedules that may be offered under the schedule referred to in 

subparagraph (A) include, among others— 

‘‘(i) time-of-use pricing whereby electricity prices are set for a specific time period on an 

advance or forward basis, typically not changing more often than twice a year, based on the 

utility’s cost of generating and/or purchasing such electricity at the wholesale level for the 

benefit of the consumer. Prices paid for energy consumed during these periods shall be preestablished and known to consumers in advance of such consumption, allowing them to vary 

their demand and usage in response to such prices and manage their energy costs by shifting 

usage to a lower cost period or reducing their consumption overall; 

‘‘(ii) critical peak pricing whereby time-of-use prices are in effect except for certain peak 

days, when prices may reflect the costs of generating and/or purchasing electricity at the 

wholesale level and when consumers may receive additional discounts for reducing peak 

period energy consumption; 

‘‘(iii) real-time pricing whereby electricity prices are set for a specific time period on an 

advanced or forward basis, reflecting the utility’s cost of generating and/or purchasing 

electricity at the wholesale level, and may change as often as hourly; and 

‘‘(iv) credits for consumers with large loads who enter into pre-established peak load 

reduction agreements that reduce a utility’s planned capacity obligations. 

‘‘(C) Each electric utility subject to subparagraph (A) shall provide each customer requesting a timebased rate with a time-based meter capable of enabling the utility and customer 

to offer and receive such rate, respectively. 

‘‘(D) For purposes of implementing this paragraph, any reference contained in this section to the date 

of enactment of the Public Utility Regulatory Policies Act of 1978 shall be deemed to be a reference to 

the date of enactment of this paragraph. 

‘‘(E) In a State that permits third-party marketers to sell electric energy to retail electric consumers, 

such consumers shall be entitled to receive the same time-based metering and 

communications device and service as a retail electric consumer of the electric utility. 

‘‘(F) Notwithstanding subsections (b) and (c) of section 112, each State regulatory authority shall, not 

later than 18 months after the date of enactment of this paragraph conduct an investigation in 

accordance with section 115(i) and issue a decision whether it is appropriate to implement the 

standards set out in subparagraphs (A) and (C).’’. H. R. 6—372 
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(b) STATE INVESTIGATION OF DEMAND RESPONSE AND TIMEBASED METERING.—Section 

115 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2625) is amended as follows: 

(1) By inserting in subsection (b) after the phrase ‘‘the standard for time-of-day rates established by 

section 111(d)(3)’’ the following: ‘‘and the standard for time-based metering and 

communications established by section 111(d)(14)’’. 

(2) By inserting in subsection (b) after the phrase ‘‘are likely to exceed the metering’’ the following: 

‘‘and communications’’. 

(3) By adding at the end the following: 

‘‘(i) TIME-BASED METERING AND COMMUNICATIONS.—In making a determination with 

respect to the standard established by section 111(d)(14), the investigation requirement of section 

111(d)(14)(F) shall be as follows: Each State regulatory authority shall conduct an investigation and 

issue a decision whether or not it is appropriate for electric utilities to provide and install time-based 

meters and communications devices for each of their customers which enable such customers to 

participate in time-based pricing rate schedules and other demand response programs.’’. 

(c) FEDERAL ASSISTANCE ON DEMAND RESPONSE.—Section 132(a) of the Public Utility 

Regulatory Policies Act of 1978 (16 U.S.C. 2642(a)) is amended by striking ‘‘and’’ at the end of 

paragraph (3), striking the period at the end of paragraph (4) and inserting ‘‘; and’’, and by adding the 

following at the end thereof: ‘‘(5) technologies, techniques, and rate-making methods related to 

advanced metering and communications and the use of these technologies, techniques and methods in 

demand response programs.’’. 

(d) FEDERAL GUIDANCE.—Section 132 of the Public Utility Regulatory Policies Act of 1978 (16 

U.S.C. 2642) is amended by adding the following at the end thereof: 

‘‘(d) DEMAND RESPONSE.—The Secretary shall be responsible for— 

‘‘(1) educating consumers on the availability, advantages, and benefits of advanced metering and 

communications technologies, including the funding of demonstration or pilot projects; 

‘‘(2) working with States, utilities, other energy providers and advanced metering and communications 

experts to identify and address barriers to the adoption of demand response programs; and 

‘‘(3) not later than 180 days after the date of enactment of the Energy Policy Act of 2005, providing 

Congress with a report that identifies and quantifies the national benefits of demand response and 

makes a recommendation on achieving specific levels of such benefits by January 1, 2007.’’. 

(e) DEMAND RESPONSE AND REGIONAL COORDINATION.— 

(1) IN GENERAL.—It is the policy of the United States to encourage States to coordinate, on a 

regional basis, State energy policies to provide reliable and affordable demand response services to the 

public. 

(2) TECHNICAL ASSISTANCE.—The Secretary shall provide technical assistance to States and 

regional organizations formed by two or more States to assist them in— 

(A) identifying the areas with the greatest demand response potential; H. R. 6—373 

(B) identifying and resolving problems in transmission and distribution networks, including 

through the use of demand response; 

(C) developing plans and programs to use demand response to respond to peak demand or 

emergency needs; and 

(D) identifying specific measures consumers can take to participate in these demand response 

programs. 
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(3) REPORT.—Not later than 1 year after the date of enactment of the Energy Policy Act of 

2005, the Commission shall prepare and publish an annual report, by appropriate region, that 

assesses demand response resources, including those available from all consumer classes, and 

which identifies and reviews— 

(A) saturation and penetration rate of advanced meters and communications 

technologies, devices and systems; 

(B) existing demand response programs and time-based rate programs; 

(C) the annual resource contribution of demand resources; 

(D) the potential for demand response as a quantifiable, reliable resource for regional 

planning purposes 

(E) steps taken to ensure that, in regional transmission planning and operations, 

demand resources are provided equitable treatment as a quantifiable, reliable resource 

relative to the resource obligations of any load-serving entity, transmission provider, 

or transmitting party; and 

(F) regulatory barriers to improve customer participation in demand response, peak 

reduction and critical period pricing programs. 

(f) FEDERAL ENCOURAGEMENT OF DEMAND RESPONSE DEVICES.—It is the policy of the 

United States that time-based pricing and other forms of demand response, whereby electricity 

customers are provided with electricity price signals and the ability to benefit by responding to them, 

shall be encouraged, the deployment of such technology and devices that enable electricity customers 

to participate in such pricing and demand response systems shall be facilitated, and unnecessary 

barriers to demand response 

participation in energy, capacity and ancillary service markets shall be eliminated. It is further the 

policy of the United States that the benefits of such demand response that accrue to those not 

deploying such technology and devices, but who are part of the same regional electricity entity, shall 

be recognized. 

(g) TIME LIMITATIONS.—Section 112(b) of the Public Utility Regulatory Policies Act of 1978 (16 

U.S.C. 2622(b)) is amended by adding at the end the following: 

‘‘(4)(A) Not later than 1 year after the enactment of this paragraph, each State regulatory authority 

(with respect to teach electric utility for which it has ratemaking authority) and each nonregulated 

electric utility shall commence the consideration referred to in section 111, or set a hearing date for 

such consideration, with respect to the standard established by paragraph (14) of section 111(d). 

‘‘(B) Not later than 2 years after the date of the enactment of this paragraph, each State regulatory 

authority (with respect to each electric utility for which it has ratemaking authority), and each 

nonregulated electric utility, shall complete the consideration, and shall make the determination, 

referred to in section 111 with respect to the standard established by paragraph (14) of section 

111(d).’’. 
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Appendix B – Acronyms Used in the Report 

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 Appendix B: Acronyms Used in the Report 

Acronym Term (see glossary for definition)

ACEEE American Council for an Energy Efficient Environment 

AEP American Electric Power 

AMI Advanced Metering Infrastructure 

AMR Automated Meter Reading OR Automatic Meter Reading 

AMRA Automatic Meter Reading Association 

ANSI American National Standards Institute 

APPA American Public Power Association 

APR Actual peak reduction 

APS Arizona Public Service 

A/S Ancillary services 

BPA Bonneville Power Administration 

BPL Broadband over power-line 

C&I Commercial and industrial customers 

CAEM Center for the Advancement of Energy Markets 

CAISO California Independent System Operator 

CAP Capacity market programs 

CBL Customer baseline level 

CEC California Energy Commission 

CERA Cambridge Energy Research Associates 

CCPG Colorado Coordinated Planning Group 

CERTS Consortium for Electric Reliability Technology Solutions 

CPA California Power Authority 

CPP Critical peak pricing 

CPP-F Critical peak-fixed 

CPP-V Critical peak-variable 

CPUC California Public Utilities Commission 

CRA Charles River Associates (now renamed CRA) 

CSEM Center for the Study of Energy Markets 

CSP Curtailment service provider 

CT Combustion turbine 

DADRP Day-Ahead Demand Response Program 

DA-RTP Day-ahead real-time pricing 

DEFG Distributed Energy Financial Group 

DG Distributed generation 

DLC Direct load control 

DOE Department of Energy (U.S.) 

DR Demand response 

DRR Demand response resources 

DRCC Demand Response Coordinating Council (coalition) 

DRRC Demand Response Research Center (California) 

DRAM Demand Response and Advanced Metering Coalition 

DSM Demand-side management 

ECAR * East Central Area Reliability Coordination Agreement 

EdF Electricité de France 

EDRP Emergency demand response program 

EE Energy efficiency 
Appendix B – Acronyms Used in the Report

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EEI Edison Electric Institute 

EIA Energy Information Administration (U.S.) 

EPA Environmental Protection Agency (U.S.) 

EPAct 2005 Energy Policy Act of 2005 

EPRI Electric Power Research Institute 

ERCOT * ** Electric Reliability Council of Texas, Inc. 

FERC Federal Energy Regulatory Commission (U.S.) 

FRCC * ** Florida Reliability Coordinating Council 

GAO General Accountability Office (U.S.) 

GMP Green Mountain Power 

HVAC Heating, ventilation, and air conditioning 

kW Kilowatt-hour 

kWh Kilowatt-hour (one thousand watt-hours) 

I/C Interruptible /Curtailable 

ICAP Installed capacity 

ICAP-SCR Installed capacity special case resources (NYISO category) 

ICF ICF International – consulting firm 

IEA International Energy Agency (Paris) 

IOU Investor-owned utility 

ISO Independent system operator 

ISO-NE Independent System Operator of New England 

LaaR Load acting as a resource (ERCOT category) 

LBNL Lawrence Berkeley National Laboratory 

LIPA Long Island Power Authority 

LMP Locational marginal price/pricing 

LSE Load-serving entity 

MAAC * Mid-Atlantic Area Council (geographically within PJM) 

MADRI Mid-Atlantic Distributed Resources Initiative 

MAIN * Mid-America Interconnected Network 

MDM Meter data management 

MISO Midwest Independent System Operator 

MRO ** Midwest Reliability Organization 

MTEP Midwest ISO Transmission Expansion Plan 2005 

MW Megawatt (one million watts) 

MWh Megawatt-hour (one million watt-hours) 

NARUC National Association of Regulatory Utility Commissioners 

NEDRI New England Distributed Resources Initiative 

NERA NERA Economic Consulting 

NERC North American Electric Reliability Council 

NPCC ** Northeast Power Coordinating Council 

NRECA National Association of Rural Electric Cooperatives 

NTAC Northwest Transmission Assessment Committee 

NYDER New York Department of Environmental Resources 

NYISO New York Independent System Operator 

NYPSC New York Public Service Commission 

NYSERDA New York State Energy Research and Development Authority 

O&M Operations and maintenance 

ORNL Oak Ridge National Laboratory (U.S.) 

PCT Programmable communicating thermostat 

PDCI Pacific Direct Current Inter-tie 
Appendix B – Acronyms Used in the Report 

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PG&E Pacific Gas & Electric 

PIER Public Interest Energy Research (CEC) 

PJM PJM Interconnection, L.L.C 

PLC Power line communication 

PNNL Pacific Northwest National Laboratory (DOE) 

POLR Provider of last resort 

PLMA Peak Load Management Association 

PPR Potential peak reduction 

PSC Public Service Commission 

PSE Puget Sound Energy 

PUC Public Utility Commission 

PURPA Public Utility Regulatory Policies Act of 1978 

QSE Qualifying scheduling entity 

RAP Regulatory Assistance Project 

RF Radio frequency 

RFC ** ReliabilityFirst Corporation 

RFP Request for proposals 

RMATS Rocky Mountain Area Transmission Study 

RRO Regional reliability organization 

RTEP Regional transmission expansion plan 

RTO Regional transmission organization 

RTP Real-time pricing 

SCADA Supervisory control and data acquisition 

SCE Southern California Edison 

SCR Special Case Resources (NYISO category) 

SDG&E San Diego Gas & Electric 

SERC ** SERC Reliability Corporation 

SERC * Southeastern Electric Reliability Council 

SPP * ** Southwest Power Pool, Inc. 

SPP Statewide Pricing Pilot (California) 

SRP Salt River Agricultural Improvement & Power District 

SSG-WI PWG Seams Steering Group – Western Interconnection Planning Work Group 

STEP Southwest Transmission Expansion Plan group 

SWAT Southwest Area Transmission 

TBL Transmission business line 

TWACS Two-way automatic communication system 

TO Transmission owner 

TOU Time-of-use (rate) 

UFLS Under frequency load shedding 

UVLS Under voltage load shedding 

VPP Variable peak pricing 

WECC * ** Western Electricity Coordinating Council 

* former NERC region used in FERC Surveys and in Chapter VI 

** proposed new Regional Reliability Organizations 
Appendix B – Acronyms Used in the Report

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Appendix C: Glossary for the Report 

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C-1

Appendix C: Glossary for the Report 

Actual Annual MWh change: The actual sum of MWh changes due to customer participation in a 

sponsored Demand Response (DR) program. 

Actual MWh Change: The total annual change in energy consumption (measured in MWh) that 

resulted from the deployment of demand response programs during the year. 

Actual Peak Reduction (APR): The coincident reductions to the annual peak load (measured in 

megawatts) achieved by customers that participate in a demand response program at the time of the 

annual system peak of the utility or ISO. It reflects the changes in the demand for electricity resulting 

from a sponsored demand response program that is in effect at the same time a utility or ISO 

experiences its annual system peak load, as opposed to the installed peak load reduction capability 

(i.e., Potential Peak Reduction). It should account for the regular cycling of energy efficient units 

during the period of annual system peak load. For curtailment service providers (CSP), the actual 

peak reduction should include the demand response load provided at the time of the peak for the 

region in which they aggregate customer load. For utilities, it should include the demand response 

load at the time of the utility annual system peak load. For ISOs/RTOs, it should include the demand 

response load at the time of the ISO/RTO annual system peak load.

Advanced Metering Infrastructure (AMI): AMI is defined as the communications hardware and 

software and associated system and data management software that creates a network between 

advanced meters and utility business systems and which allows collection and distribution of 

information to customers and other parties such as competitive retail providers, in addition to 

providing it to the utility itself. 

American Council for an Energy-Efficient Economy (ACEEE) is a nonprofit organization whose 

research reports examine energy efficiency as a means of promoting both economic prosperity and 

environmental protection. 

Ancillary Services: Those services necessary to support the transmission of electric power from seller 

to purchaser, given the obligations of control areas and transmitting utilities within those control areas, 

to maintain reliable operations of the interconnected transmission system. Ancillary services supplied 

with generation include load following, reactive power-voltage regulation, system protective services, 

loss compensation service, system control, load dispatch services, and energy imbalance services. 

Ancillary Service Market Programs: Demand response programs in which customers bid load 

curtailments in ISO/RTO markets as operating reserves. If their bids are accepted, they are paid the 

market price for committing to be on standby. If their load curtailments are needed, they are called by 

the ISO/RTO, and may be paid the spot market energy price. 

Asset Management: The ability to leverage the value of metering data and other available 

information to increase the value of utility investments and/or to improve customer service. One 

example is using hourly interval data to measure the load on transformers at the time of the system 

peak. 

Automated Meter Reading: automatic or automated meter reading -- allows meter read to be 

collected without actually viewing or touching the meter with any other equipment. One of the most 

prevalent examples of AMR is mobile radio frequency whereby the meter reader drives by the 

property, and equipment in the car receives a signal sent from a communication device under the glass 

of the meter. 

Bid Limits: The maximum $/MWh bid that can be submitted by a program participant. 
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Billing or Revenue Meter: Meters installed at customer locations that meter electric usage and 

possibly other parameters associated with a customer account and provide information necessary for 

generating a bill to the customer for the customer account. 

Bonneville Power Administration (BPA): A federal power marketing and electric transmission 

agency headquartered in Portland, Oregon. 

Capable: AMI network could initiate interval data and collection without a physical visit to the meter 

site to reprogram it or to add an extra device of some kind. 

Capacity Market Programs (CAP): Demand response programs in which customers offer load 

curtailments as system capacity to replace conventional generation or delivery resources. Customers 

typically receive day-of notice of events and face penalties for failure to curtail when called upon to do 

so. Incentives usually consist of up-front reservation payments. 

Commercial sector: An energy-consuming sector that consists of service-providing facilities and 

equipment belonging to: businesses; federal, state, and local governments; and other private and 

public organizations, such as religious, social, or fraternal groups. The commercial sector includes 

institutional living quarters, sewage treatment facilities, and street lighting. Common uses of energy 

associated with this sector include space heating, water heating, air conditioning, lighting, 

refrigeration, cooking, and running a wide variety of other equipment. Note: This sector includes 

generators that produce electricity and/or useful thermal output primarily to support the activities of 

the above-mentioned commercial establishments. 

Cooperative Electric Utility: An electric utility legally established to be owned by and operated for 

the benefit of those using its service. The utility company will generate, transmit, and/or distribute 

supplies of electric energy to a specified area not being serviced by another utility. Such ventures are 

generally exempt from federal income tax laws. Most electric cooperatives were initially financed by 

the Rural Utilities Service (formerly the Rural Electrification Administration), U.S. Department of 

Agriculture. 

Critical Peak Pricing (CPP): CPP rates are a hybrid of the TOU and RTP design. The basic rate 

structure is TOU. However, provision is made for replacing the normal peak price with a much higher 

CPP event price under specified trigger conditions (e.g., when system reliability is compromised or 

supply prices are very high). 

Curtailment Service Provider (CSP): Demand response load providers that are not necessarily load 

serving entities. CSPs may sponsor demand response programs and sell the demand response load to 

utilities, RTOs and/or ISOs. 

Customer Account: A record at the energy provider that identifies an entity receiving electric service 

at one or more locations within the utility service footprint. The identified entity is responsible for 

paying the cost of energy consumed and metered at the location(s) on the account. There may be no 

meter associated with the customer account (such as with street lights), or one or more meters 

associated with a particular customer account. 

Demand: Represents the requirements of a customer or area at a particular moment in time. Typically 

calculated as the average requirement over a period of several minutes to an hour, and thus usually 

expressed in kilowatts or megawatts rather than kilowatt-hours or megawatt-hours. Demand and load 

are used interchangeably when referring to energy requirements for a given customer or area. 

Demand Bidding/Buyback (DB): A demand response program where customers or curtailment 

service providers offer bids to curtail based on wholesale electricity market prices or an equivalent. 

Mainly offered to large customers (e.g., one MW and over), but small customer demand response load 

can be aggregated by curtailment service providers and bid into the demand bidding program sponsor. 
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Demand Response (DR): The planning, implementation, and monitoring of activities designed to 

encourage customers to modify patterns of electricity usage, including the timing and level of 

electricity demand. Demand response covers the complete range of load-shape objectives and 

customer objectives, including strategic conservation, time-based rates, peak load reduction, as well as 

customer management of energy bills. 

Demand Response Event: A period of time identified by the demand response program sponsor 

when it is seeking reduced energy consumption and/or load from customers participating in the 

program. Depending on the type of program and event (economic or emergency), customers are 

expected to respond or decide whether to respond to the call for reduced load and energy usage. The 

program sponsor generally will notify the customer of the demand response event before the event 

begins, and when the event ends. Generally each event is a certain number of hours, and the program 

sponsors are limited to a maximum number of events per year. 

Demand Response Load: The load reduction that results from demand response activities. 

Direct Load Control (DLC): A demand response activity by which the program operator remotely 

shuts down or cycles a customer’s electrical equipment (e.g. air conditioner, water heater) on short 

notice. Direct load control programs are primarily offered to residential or small commercial 

customers. 

Duration of Event: The length of an Emergency or Economic Demand Response Event in hours. 

EIA ID Number: Unique identification number assigned by EIA to companies and entities operating 

in the electric power industry. 

Economic Demand Response Event: A demand response event in which the demand response 

program sponsor directs response to an economic market opportunity rather than for reliability or 

because of an emergency in the energy delivery system of the program sponsor orthe RTO/ISO. 

Edison Electric Institute (EEI): The trade association for the investor-owned utility companies. 

Elasticity of Demand: The degree to which consumer demand for a product responds to changes in 

price, availability or other factors. 

Electric Power: The rate at which electric energy is transferred. Electric power is measured by 

capacity and is commonly expressed in megawatts (MW).

Electric Power Research Institute (EPRI): An independent, non-profit energy and environmental 

research organization which brings together members, participants, and the Institute's scientists and 

engineers to work collaboratively on solutions to electric power issues. 

Electric Reliability Council of Texas (ERCOT): The electric reliability organization which ensures 

reliable and cost-effective operation of the grid in the Texas area. 

Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality 

aligned with distribution facilities for delivery of electric energy for use primarily by the public. 

Included are investor-owned electric utilities, municipal and state utilities, federal electric utilities, and 

rural electric cooperatives. A few entities that are tariff based and affiliated with companies that own 

distribution facilities are also included. 

Electricity: A form of energy characterized by the presence and motion of elementary charged 

particles generated by friction, induction, or chemical change. 

Emergency Demand Response Event: A demand response event called by the program sponsor in 

response to an emergency of the delivery system of the demand response sponsor or of another entity 

such as a utility or ISO. 
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Emergency Demand Response Program (EDRP): A demand response program that provides 

incentive payments to customers for load reductions during periods when reserve shortfalls arise. 

Energy: The capacity for doing work as measured by the capability of doing work (potential energy) 

or the conversion of this capability to motion (kinetic energy). Energy has several forms, some of 

which are easily convertible and can be changed to another form useful for work. Most of the world's 

convertible energy comes from fossil fuels that are burned to produce heat that is then used as a 

transfer medium to mechanical or other means in order to accomplish tasks. Electrical energy is 

usually measured in kilowatt-hours.

Energy Efficiency (EE): Refers to programs that are aimed at reducing the energy used by specific 

end-use devices and systems, typically without affecting the services provided. These programs 

reduce overall electricity consumption (reported in megawatt-hours), often, but not always, without 

explicit consideration for the timing of program-induced savings. Such savings are generally achieved 

by substituting technologically more advanced equipment to produce the same level of end-use 

services (e.g. lighting, heating, motor drive) with less electricity. Examples include energy saving 

appliances and lighting programs, high-efficiency heating, ventilating and air conditioning (HVAC) 

systems or control modifications, efficient building design, advanced electric motor drives, and heat 

recovery systems. 

Enhanced Customer Service: The ability to offer ultimate customers the choice of bill data, 

additional rate options such as real time pricing or critical peak pricing, verify an outage or restoration 

of service following an outage, more information to understand a customer concern over an electric 

bill, reduce bill estimates when a meter read is not available, opening or closing of an account due to 

customer relocation without requiring a site visit to the meter(s), and/or more accurate bills. 

Executive Dashboard: The ability of the AMI network to provide information that would support 

utility management viewing on a timely basis. The information might include current outages and 

MW sales. In this context, the utility would need to also have an executive dashboard application. 

Timely would not necessarily mean in real-time but it would likely mean that within an hour to 24 

hours, management would be able to view usage measured at revenue and billing meters across the 

utility service territory. 

Florida Reliability Coordinating Council (FRCC): The FRCC is one of eight Regional Reliability 

Councils in the lower 48 states that comprise the North American Electric Reliability Council 

(NERC). It covers Peninsular Florida, east of the Apalachicola River. 

Gas Meter: A meter that measures natural gas usage for ultimate customers. 

ICAP Credit: An ISO capacity credit to satisfy a resource requirement. 

Independent system operator (ISO): An organization that has been granted the authority to operate, 

in a nondiscriminatory manner, the transmission assets of the participating transmission owners in a 

fixed geographic area. ISOs often run organized markets for spot electricity. 

Industrial: The energy-consuming sector that consists of all manufacturing facilities and equipment 

used for producing, processing, or assembling goods. The industrial sector encompasses the following 

types of activity: manufacturing; agriculture, forestry, and fisheries; mining; and construction. 

Overall energy use in this sector is largely for process heat and cooling and powering machinery, with 

lesser amounts used for facility heating, air conditioning, and lighting. Fossil fuels are also used as 

raw material inputs to manufactured products. This sector may include energy deliveries to large 

commercial customers, and may exclude deliveries to small industrial customers which may be 

included in the commercial sector. It also may classify by using the North American Industry 

Classification System or on the basis of energy demand or annual usage exceeding some specified 
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limit set by the energy provider.

Industrial Customer: Electric power consumers which usually consume large amounts of electricity 

and are usually in the manufacturing, construction, mining, agriculture, fishing or forestry industries. 

Utilities usually classify service to these consumers based on their power demand or an annual usage 

amount which exceeds some specified limit. 

Interface with Water or Gas Meters: The ability of the AMI network to collect water or gas meter 

readings and to transmit the gas or water meter readings over the AMI network to an entity that can 

provide the gas or water meter readings to the gas or water utility providing the service. 

Interruptible/Curtailable Service (I/C): Curtailment options integrated into retail tariffs that 

provide a rate discount or bill credit for agreeing to reduce load during system contingencies. 

Penalties may be assessed for failure to curtail. In some instances, the demand reduction may be 

affected by direct action of the System Operator (remote tripping) after notice to the customer in 

accordance with contractual provisions. For example, demands that can be interrupted to fulfill 

planning or operating reserve requirements normally should be reported as Interruptible Demand. 

Interruptible programs have traditionally been offered only to the largest industrial (or commercial) 

customers. Interruptible Demand as reported here does not include Direct Control Load or price 

responsive demand response. 

Investor-Owned Utility (IOU): A utility organized under state law as a publicly traded corporation 

for the purposes of providing electric power service and earning profits for its stockholders. 

Kilowatt (kW): One thousand watts.

Kilowatthour (kWh): One thousand watt-hours. 

Line Loss: Electric energy lost because of the transmission of electricity. Much of the loss is thermal 

in nature.

Load (Electric): The amount of electric power delivered or required at any specific point or points on 

a system. The requirement originates at the energy-consuming equipment of the consumers.

Load Acting as a Resource (LaaR): An interruptible program operated by ERCOT in which 

customers may qualify to provide operating reserves. 

Load Forecasting: The estimation of future load requirements for specified intervals for a period of 

time. The load forecast may provide an estimate of hourly loads for a group of ultimate customers for 

the next five years, for example. 

Load-serving entity (LSE): Any entity, including a load aggregator or power marketer, that serves 

end-users within a control area and has been granted the authority or has an obligation pursuant to 

state or local law, regulation, or franchise to sell electric energy to end-users located within the control 

area. 

Maximum Demand: This is determined by the interval in which the 60-minute integrated demand is 

the greatest. 

Maximum Hourly Load: The highest amount of demand that is measured or expected to be curtailed 

at a certain point in time. 

Megawatt (MW): One million watts of electricity. 

Megawatthour (MWh): One thousand kilowatt-hours or 1 million watt-hours. 

Midwest Reliability Organization (MRO): The Midwest Reliability Organization (MRO) is one of 

eight Regional Reliability Councils in the lower 48 that comprise NERC. Its members include the 
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following states: Minnesota, Wisconsin, Iowa, North Dakota, South Dakota, Nebraska, Montana, 

Illinois and Upper Peninsula of Michigan. 

Minimum Term: The minimum length in years that customers are obligated to participate in a 

demand response program. 

Municipality: A village, town, city, county, or other political subdivision of a state.

National Association of Regulatory Utility Commissioners (NARUC): A non-profit organization 

whose members include the governmental agencies that are engaged in the regulation of utilities and 

carriers in the fifty states, the District of Columbia, Puerto Rico. 

North American Electric Reliability Council (NERC): The organization certified by the 

Commission as the reliability organization for the nation’s bulk power grid. NERC consists of eight 

Regional Reliability Councils in the lower 48 states. The members of these Councils are from all 

segments of the electricity supply industry - investor-owned, federal, rural electric cooperative, 

state/municipal, and provincial utilities, independent power producers, and power marketers. 

Operating Company: The name a utility uses in doing business within a particular state associated 

with a particular service territory. 

Outage Management: The response of an electric utility to an outage affecting the ultimate 

customers of the electric service. The utility may use the AMI network to detect outages, verify 

outages, map the extent of an outage, or verify the service has been restored after repairs have been 

made. 

Peak Demand: The maximum load during a specified period of time. 

Potential MWh Change: The potential total annual change in energy consumption (measured in 

MWh) that would result from the deployment of demand response programs. It reflects the total 

change in consumption if the full demand reduction capability of the program were deployed, as 

opposed to actual MWh change during the year.

Potential Peak Reduction: The potential annual coincident peak load reduction (measured in 

megawatts) that can be deployed from demand response programs. It represents the load that can be 

reduced either by the direct control of the utility system operator or by the consumer in response to a 

utility request to curtail load. It reflects the installed load reduction capability, as opposed to the 

Actual Peak Reduction achieved by participants, during the time of annual system peak load. It should 

account for the regular cycling of energy efficient units during the period of system peak load. For 

utilities, it should be the potential sum of demand reduction capability to their annual peak load 

(measured in megawatts) achieved by the program participants. For an ISO or RTO, it should be the 

sum of coincident reduction capability to the ISO or RTO achieved by participants at the time of 

system peak of the ISO or RTO. Similarly, for CSPs, it should be the sum of coincident reduction 

capability sponsored by the CSP and achieved by demand response program participants at the time of 

the peak for the region in which the CSP is aggregating customer load. 

Power Marketers: Business entities, including energy service providers, that are engaged in buying 

and selling electricity, but do not own generating or transmission facilities. Power marketers and 

energy service providers, as opposed to brokers, take ownership of the electricity and are involved in 

interstate trade. Power marketers file with the Federal Energy Regulatory Commission (FERC) for 

status as a power marketer. Energy service providers may not register with FERC but may register 

with the states if they undertake only retail transactions.

Power Quality Monitoring: The ability of the AMI network to discern, record, and transmit to the 

utility instances where the voltage and/or frequency were not in ranges acceptable for reliability. 
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Premise Device/Load Control Interface or Capability: The ability of the AMI network to 

communicate directly with a device located on the premises of the ultimate customer, which may or 

may not be owned by the utility. These might include a programmable communicating thermostat or a 

load control switch. 

Pre-Pay Metering: A metering and/or software and payment system that allows the ultimate 

customer to pay for electric service in advance. 

Price Responsive Demand Response: All demand response programs that include the use of timebased rates to encourage retail customers to reduce demands when prices are relatively high. These 

demand response programs may also include the use of automated responses. Customers may or may 

not have the option of overriding the automatic response to the high prices. 

Pricing Event Notification Capability: The ability of the AMI network to convey to utility 

customers participating in a price responsive demand response program that a demand response event 

is planned, beginning, ongoing, and/or ending. 

Provision of Usage Information to Customers: The ability of the AMI network to convey to 

ultimate customers information on their usage in a timely fashion. Timely in this context would be 

dependent on the customer class, with larger customers generally receiving the information with less 

lag time than residential customers. 

Public Utility: An enterprise providing essential public services, such as electric, gas, telephone, 

water, and sewer under legally established monopoly conditions.

Public Utility District: Municipal corporations organized to provide electric service to both 

incorporated cities and towns and unincorporated rural areas. 

Publicly Owned Electric Utility: A class of ownership found in the electric power industry. This 

group includes those utilities operated by municipalities, political subdivisions, and state and federal 

power agencies (such as BPA or TVA). 

Railroad and Railway Electric Service: Electricity supplied to railroads and interurban and street 

railways, for general railroad use, including the propulsion of cars or locomotives. Such electricity is 

supplied under separate and distinct rate schedules.

Real Time Pricing (RTP): A retail rate in which the price for electricity typically fluctuates hourly 

reflecting changes in the wholesale price of electricity. RTP prices are typically known to customers 

on a day-ahead or hour-ahead basis. 

Reduce Line Losses: The ability to use the AMI network to lower the line losses on the transmission 

system. 

Regional transmission organization (RTO): An organization with a role similar to that of an 

independent system operator but covering a larger geographical scale and involving both the operation 

and planning of a transmission system. RTOs often run organized markets for spot electricity. 

Remotely Change Metering Parameters: The ability to change parameters associated with a 

particular revenue or billing meter, such as the length of the data interval measured, without a site visit 

to the meter location. 

Remote Connect/Disconnect: The ability to physically turn on or turn off power to a particular 

billing or revenue meter without a site visit to the meter location. 

Residential: The energy-consuming sector that consists of living quarters for private households. 

Common uses of energy associated with this sector include space heating, water heating, air 

conditioning, lighting, refrigeration, cooking, and running a variety of other appliances. The 
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residential sector excludes institutional living quarters. This sector may exclude deliveries or sales to 

apartment buildings or homes on military bases (these buildings or homes may be included in the 

commercial sector). 

Response Time: The maximum notice and lead time that a demand response program sponsor 

provides to demand response program participants prior to an economic or emergency demand 

response event. 

Retail: Sales covering electrical energy supplied for residential, commercial, and industrial end-use 

purposes. Other small classes, such as agriculture and street lighting, also are included in this 

category.

Revenue Assurance: A set of activities designed to increase the revenue from providing electric 

service to ultimate customers, including locating meters without associated customer accounts, 

relatively high line losses compared with other similar locations, energy theft, and/or improper 

metering installations. 

Service Territory: The area within a particular state where an electric utility is allowed to provide 

ultimate customers for distribution, transmission, or energy services. 

Specific Event Limits: The maximum number of events that can be called during a year. 

Southwest Power Pool (SPP): The Southwest Power Pool is both the RTO and NERC reliability 

organization for Kansas, Missouri, Oklahoma, and part of New Mexico. 

System (Electric): Physically connected generation, transmission, and distribution facilities operated 

as an integrated unit under one centralized manager or operations supervisor.

Theft Detection: The ability to detect when a revenue or billing meter has been potentially tampered 

with and to indicate a potential energy theft in progress that should be further investigated by the 

utility. 

Time-Based Rate (TBR): A retail rate in which customers are charged different prices for different 

times during the day. Examples are time-of-use (TOU) rates, real time pricing (RTP), hourly pricing, 

and critical peak pricing (CPP). 

Time-of-use (TOU) Rate: A rate with different unit prices for usage during different blocks of time, 

usually defined for a 24 hour day. TOU rates reflect the average cost of generating and delivering 

power during those time periods. Daily pricing blocks might include an on-peak, partial-peak, and 

off-peak price for non-holiday weekdays, with the on-peak price as the highest price, and the off-peak 

price as the lowest price.

Transformer: A device that operates on magnetic principles to increase (step up) or decrease (step 

down) voltage.

Transmission: The movement or transfer of electric energy over an interconnected group of lines and 

associated equipment between points of supply and points at which it is transformed for delivery to 

consumers or is delivered to other electric systems. Transmission is considered to end when the 

energy is transformed for distribution to the consumer.

Transmission System (Electric): An interconnected group of electric transmission lines and 

associated equipment for moving or transferring electric energy in bulk between points of supply and 

points at which it is transformed for delivery over the distribution system lines to consumers.

Transportation: An energy consuming sector that consists of electricity supplied and services 

rendered to railroads and interurban and street railways, for general railroad use including the 

propulsion of cars or locomotives, where the electricity is supplied under separate and distinct rate 
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schedules. 

Type of Organization: in fielding the FERC Survey, this allowed Commission staff to identify the 

type of organization that best represents the energy market participant. The possible categories were : 

Investor-owned utilities (IOU), Municipal Utility (M), Cooperative Utility (C), State-owned Utility 

(S), Federally-owned Utility (F), Independent System Operator (ISO), Regional Transmission 

Operator (RTO), Curtailment Service Provider (CSP), or other (O).

Ultimate Consumer: A consumer that purchases electricity for its own use and not for resale.

Uncommitted Capacity: Generating resources that are physically located in the region, but are not 

dedicated or contractually committed to serve load in the region.

Water meter: A meter that measures water usage for end-use customers. 

Watt (W): The unit of electrical power equal to one ampere under a pressure of one volt. A watt is 

equal to 1/746 horsepower.

Watt-hour (Wh): The electrical energy unit of measure equal to one watt of power supplied to, or 

taken from, an electric circuit steadily for one hour.

Year of Study: Identification of the projected years covered by a specified study.
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Appendix D – Bibliography 

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 Appendix D: Demand Response and Advanced Metering Source 

List and Bibliography 

Note: where reports are publicly available on the internet, we have provided a link to the source. 

Demand Response and Competition: 

Federal and State Reports, Orders, Conferences: 

FEDERAL: 

Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(e)(3), 119 Stat. 594 (2005) (EPAct section 

1252(e)(3). 

U.S.-Canada Power System Outage Task Force. Final Report on the August 14, 2003 Blackout in the 

United States and Canada: Causes and Recommendations. April 2003. 

https://reports.energy.gov/BlackoutFinal-Web.pdf

U.S. Department of Energy (DOE). Benefits of Demand Response in Electricity Markets, and 

Recommendations for Achieving Them: A Report to the U.S. Congress. February 2006. 

http://www.oe.energy.gov/documents/congress_1252d.pdf 

U.S. Environmental Protection Agency’s (EPA). 

–. Clean Energy-Environment Guide to Action: Policies, Best Practices, and Action Steps for States. 

April 2006. http://www.epa.gov/cleanenergy/pdf/gta/guide_action_full.pdf 

–. Energy & Environmental Economics, for EPA-State Energy Efficiency Renewable Energy Projects. 

A Survey of Time-of-Use Pricing and Demand-Response Programs. July 2006. (forthcoming)

U.S. Federal Energy Regulatory Commission (FERC) and the Electric Energy Market Competition 

Task Force. Draft Report to Congress on Competition in the Wholesale and Retail Markets for 

Electric Energy. Docket No. AD05-17-000. June 5, 2006. 

–. Office of Market Oversight. “Demand Response.” In 2004 State of the Market Report. June 2005. 

http://www.ferc.gov/EventCalendar/Files/20050615093455-06-15-05-som2004.pdf

–. Transcript from “Technical Conference on Demand Response and Advanced Metering,” January 25, 

2006. http://www.ferc.gov/eventcalendar/Files/20060214164735-DemandResponseTranscript.pdf 

U.S. Government Accountability Office (GAO). Electricity Restructuring: Key Challenges Remain. 

November 2005: GAO-06-237. http://www.gao.gov/new.items/d06237.pdf 

–. Consumers Could Benefit from Demand Programs, but Challenges Remain, GAO-04-844. August 

2004. http://www.gao.gov/new.items/d04844.pdf 

STATES: 

California: California Energy Commission (CEC) and California Public Utilities Commission, 

Energy Action Plan II: Implementation Roadmap for Energy Policies, adopted, Sept. 21, 2005. 

http://www.energy.ca.gov/energy_action_plan/2005-09-21_EAP2_FINAL.PDF 

–. CEC. Feasibility of Implementing Dynamic Pricing in California. Report to the Legislature to 

satisfy the legislative requirement of SB 1976, October 2003. http://energy.ca.gov/reports/2003-

10-31_400-03-020F.PDF

–. CEC Staff Report by Fromm, S., et al. Implementing California’s Loading Order For Electricity 

Resources. July 2005. http://energy.ca.gov/2005publications/CEC-400-2005-043/CEC-400-2005-043.PDF 

–. Committee Workshop Before the California Energy Resources Conservation and Development 

Commission. In the Matter of Systems Integration Framework Programmable Communicating 

Thermostat (PCT). February 16, 2006. 

Connecticut: Public Act No. 05-1: An Act Concerning Energy Independence, House Bill 7501 [July 

21, 2005], http://www.cga.ct.gov/2005/act/Pa/2005PA-00001-R00HB-07501SS1-PA.htm 

–. Connecticut Energy Advisory Board, Energy Plan for Connecticut, February 2006. 
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D-2 

–. Department of Public Utility Control (DPUC). Orders implementing utility and customer incentive 

programs to promote development of distributed resources. Docket Nos. 05-07-16 and 05-07-

17, March 27, 2006. 

–. DPUC. Investigation into Decoupling Energy Distribution Company Earnings from Sales, Final 

Decision. Docket No. 05-09-09, January 18, 2006. 

http://www.dpuc.state.ct.us/dockhist.nsf/6eaf6cab79ae2d4885256b040067883b/1720fa522a11e3cf852571390072d5

60?OpenDocument

Delaware: Delaware Public Service Commission, Order No. 6912, PSC Regulation Docket No. 57, in 

the matter of the Commission’s combined consideration of the utilization of Advanced 

metering technologies under 26 Del. C. § 1008(b) (1)b. and the implementation of Federal 

standards for time-based metering and time-based rate schedules under 16 U.S.C. §§ 2621(d) ) 

(14) AND 2625(i)), opened May 9, 2006. 

–. HB 6. 143rd Gen. Assem., Reg. Sess. (Del. 2006). Electric Utility Retail Customer Supply Act. 

http://www.legis.state.de.us/LIS/LIS143.NSF/vwLegislation/HB+6?Opendocument 

Idaho: Idaho Public Utilities Commission, Idaho Power: Review of Phase One AMR Implementation 

Status Report, Case No. IPC-E-06-01. 

http://www.puc.idaho.gov/internet/cases/summary/IPCE0601.html

Illinois: P.A. 094-0977, 94th Gen. Assem., Reg. Sess. (Ill. 2006), effective June 30, 2006. Amends the 

Public Utility Act to allow residential consumers to elect real-time pricing. 

http://www.ilga.gov/legislation/publicacts/fulltext.asp?Name=094-0977 

Louisiana: Louisiana Public Service Commission. Investigation to determine if it is appropriate for 

LPSC jurisdictional electric utilities to provide and install time-based meters and participate in 

time-based pricing rate schedules and other demand response programs. Docket R-2913, 

12/5/2005. 

–. Commission Examination of the public benefits of potentially adopting rules, new tariffs, and / or 

other regulatory mechanisms that would promote (or require) the use of wireless metering in 

Louisiana. Docket No. R-29213, Subdocket A.

Massachusetts: Massachusetts Division of Energy Resources, Creating and Demonstrating Incentives 

for Electricity Providers to Integrate Distributed Energy Resources (DER). EPRI DER/Public 

Private Partnership, July 11, 2005.

New York: New York State Public Service Commission (NYPSC). Order Denying Petitions for 

Rehearing and Clarification in Part and Adopting Mandatory Hourly Pricing Requirements, 

issued and effective April 24, 2006. 

http://www3.dps.state.ny.us/pscweb/webfileroom.nsf/ArticlesByCategory/B3B48B2CC1547638852571

4C00666B91/$File/301_03-E-0641_04_24_06.pdf?OpenElement 

–. Proceeding on Motion of the Commission Regarding Expedited Implementation of Mandatory 

Hourly Pricing for Commodity Service, NYPSC Case No. 03-E-0641, April 11, 2006. 

http://www.dps.state.ny.us/fileroom.html 

–. Staff Report. Case No. 03-E-0640, July 9, 2004. 

Pennsylvania: Pennsylvania Office of Consumer Advocate. Comments filed in Docket AD05-17, 

“Electric Energy Market Competition Task Force”, November 18, 2005.
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-3

Demand Response and Advanced Metering: 

Works Cited and Consulted. 

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Barbose, Galen et al. for DRCC. Real Time Pricing as Default or Optional Service for C&I 

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LBNL-57661. http://drrc.lbl.gov/pubs/57661.pdf

Barbose, Galen, Charles Goldman (LBNL), Bernie Neenan (Neenan Associates). A Survey of Utility 

Experience with Real Time Pricing. Berkeley, CA, December 2004: LBNL-54238. 

http://eetd.lbl.gov/EA/EMP/reports/54238.pdf 

Bladen, Jeffrey. Testimony of J. Bladen for Technical Conference on Demand Response and Advanced 

Metering. PJM Interconnection, Valley Forge PA, January 25, 2006. 

Blevins, R.P. (Plexus Research, Inc.) for Electric Power Research Institute. 1994 Survey of Utility 

Demand-Side Programs and Services, Pleasant Hill, CA: EPRI, November 1995: TR-105685. 

Available only to members and by purchase. 

Blumsack, Seth A., Jay Apt, and Lester B. Lave. “Lessons from the Failure of U.S. Electricity 

Restructuring.” The Electricity Journal, 19 #2 (March 2006): 15-32. 

Boice, Craig. What drives the response in Demand Response? Boice Dunham Group, April 13, 2005. 

Boisvert, Richard, et al. Industrial and Commercial Customer Response To Real Time Electricity 

Prices. December 2004. http://eetd.lbl.gov/ea/emp/reports/Boisvert.pdf 

Boisvert, Richard N. and Bernie F. Neenan. Social Welfare Implications of Demand Response 

Programs in Competitive Electricity Markets. Berkeley, CA, August 2003: LBNL-52530. 

http://eetd.lbl.gov/ea/emp/reports/LBNL-52530.pdf 

Bonbright, James C., Albert L. Danielsen, David R. Kamerschen. Principles of Public Utility Rates. 

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Borenstein, Severin. “The Long-Run Efficiency of Real-Time Pricing.” The Energy Journal. 26 #3 

(June 2005): 93-116. 

Braithwait, Steven and Ahmad Faruqui. “The Choice not to Buy: Energy Savings and Policy 

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Texas’s Power Markets, prepared for the Market Oversight Division of the Public Utility 

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Brown, Marilyn and Mark Levine, “Overview of Load as a Resource”, Consortium for Electric 

Reliability Technology Solutions, Oak Ridge National Laboratory (ORNL), May 2002. 

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Camp, Ward. “AMI Case Studies: PP&L, Idaho, FP&L.” Presentation to the Joint California 

Workshop on “Advanced Metering Results and Issues.” Sacramento, CA: September 30, 2004. 

Cappers, Peter. “Everything You Ever Wanted to Know About Price Elasticities, but Were Afraid to 

Ask.” UtiliPoint’s IssueAlert, April 7, 2006.
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-4 

Caves, Douglas, Kelly Eakin, and Ahmad Faruqui. “Mitigating Price Spikes in Wholesale Markets 

through Market-Based Pricing in Retail Markets.” The Electricity Journal, (April 2000): 13-23. 

Charles River Associates. Impact Evaluation of the California Statewide Pricing Pilot: Final Report

(to the California Energy Commission). March 16, 2005. 

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24_SPP_FINAL_REP.PDF

Colledge, Justin A. et al. (McKinsey & Co.) “Power by the Minute.” McKinsey Quarterly, 2002 #1: 73-

80. 

Consolidated Edison. Request For Proposals To Provide Demand Side Management To Provide 

Transmission And Distribution System Load Relief And Reduce Generation Capacity 

Requirements To Consolidated Edison Company Of New York, Inc. April 14, 2006. 

“Constellation NewEnergy’s Experience with Dynamic Pricing.” Presentation at ISO-NE DR Summit, 

April 27, 2006. http://www.iso-ne.com/genrtion_resrcs/dr/events/2006/PKellyDetwiler.pdf

Crossley, David .J. Worldwide Survey of Network-driven Demand-side Management Projects. IEA 

Demand Side Management Programme, Task XV Research Report No 1. Australia, Energy 

Futures Australia Pty Ltd. September 2005. 

Delurey, Dan. “Retail Demand Response: Challenges and Outlook.” Presentation at IEA Workshop, 

Paris, France, February 24, 2005. www.dramcoalition.org 

DePillis, M. The New Ancillary Services Markets of New England. MISO Ancillary Services Round 

Table. Carmel, IN, April 26, 2006. 

Distributed Energy Financial Group and Center for the Advancement of Energy Markets. A Critical 

Examination of Demand Response Programs at the ISO Level: End Goals, Implementation, and 

Equity, Final Report. October 2005. http://www.defgllc.com/Assets/downloads/defgcaem_demandresponsestudyfinalreport_oct2005(2).pdf

Earle, Robert and Ahmad Faruqui. “Toward a New Paradigm for Valuing Demand Response.” The 

Electricity Journal 19 # 4 (May 2006): 21-31. 

Eakin, Kelly and Ahmad Faruqui, editors. Electricity Pricing in Transition. Boston: Kluwer Academic 

Publishers, 2002. 

EnerNex Corporation. “Advanced Metering and Demand Responsive Infrastructure: A Summary of 

the PIER/CEC Reference Design, Related Research and Key Findings: Draft.” Prepared for the 

California Energy Commission June 1, 2005. 

http://ciee.ucop.edu/dretd/PIERDemandResponseSummaryReport.pdf 

Faruqui, Ahmad, and Melanie Mauldin. “The Barriers to Real-Time Pricing: Separating Fact from 

Fiction.” Public Utilities Fortnightly, July 2002: 30 – 40. 

–. “The Nine Lessons of Real-Time Pricing.” Public Utilities Fortnightly, July 2002: 33-39. 

Faruqui, Ahmad, and Stephen S. George. “Pushing the Envelope on Rate Design.” The Electricity 

Journal 19 #2 (March 2006): 33-42. 

–. “Quantifying Customer Response to Dynamic Pricing.” The Electricity Journal 18 #4 (May 2005): 

53-63. 

–. “The Value of Dynamic Pricing in Mass Markets,” The Electricity Journal, 15 #6 (July 2002): 45-

55. 

Fauth, Gary and Michael Wiebe. “Fixed-Network AMR: Lessons for Building the Best Business 

Case.” AMRA newsletter, September 2004. 

Fromm, Sandra, et al. Implementing California’s Loading Order For Electricity Resources. California 

Energy Commission Staff Report, July 2005. http://energy.ca.gov/2005publications/CEC-400-2005-

043/CEC-400-2005-043.PDF 

George, Stephen S. and Ahmad Faruqui, CRA, “California’s Statewide Pricing Pilot: Overview of Key 

Findings.” Presentation to MADRI, May 2005. 

Glazer, Craig. Comments of PJM on the Demand Response and Time Based Rate Issues Raised and/or 

Identified in EPAct 2005 Section 1252 (e)(3). Valley Forge, PA: PJM, 2005. 
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-5

Goldman, Charles (LBNL). “Customer Experience with Real Time Pricing as the Default Service.” 

Presentation at the ISO-NE Demand Response Summit, Sturbridge, MA, April 27, 2006. 

–. "Demand Response: Issues and Challenges.” Keynote presentation, FERC Demand Response 

Technical Conference, Washington, DC, January 25, 2006. 

–. “Does Real-Time Pricing Deliver Demand Response?” Presentation to New England Restructuring 

Roundtable, Oct. 25, 2005. www.raabassociates.org/Articles/Goldman_10.28.05.ppt 

Goldman, Charles, et al. Customer Response to Day-ahead Wholesale Market Electricity Prices: Case 

Study of RTP Program Experience in New York. Berkeley, CA: LBNL-54761, June 2004. 

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–. Does Real-time Pricing Deliver Demand Response? A Case Study of Niagara Mohawk's Large 

Customer RTP Tariff. Berkeley, CA, August 2004: LBNL-54974. 

http://eetd.lbl.gov/ea/emp/reports/54974.pdf

Goldman, Charles and Ranjit Bharvirkar (LBNL). “Load Management Resources in the U.S.” 

Presentation to FERC staff, October 4, 2005. 

Goldman, Charles A., Joseph H. Eto, and Galen L. Barbose. California Customer Load Reductions 

during the Electricity Crisis: Did they Help to Keep the Lights On? Berkeley, CA: LBNL49733, May 2002. 

Goldman, Charles, N. Hopper and R. Bharvirkar (LBNL) and Bernie Neenan, et al. Customer 

Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing. Berkeley, CA: 

LBNL-57128, August 2005. http://eetd.lbl.gov/ea/emp/reports/57128.pdf 

Goldman, Charles and Roger Levy, Demand Response in the U.S.: Opportunities, Issues, and 

Challenges. Presentation at the National Town Hall Meeting on Demand Response, 

Washington, DC, June 21, 2005. 

Goldman, Charles A., Grayson Heffner, and Galen Barbose. Customer Load Participation in 

Wholesale Markets: Summer 2001 Results, Lessons Learned and Best Practices. Berkeley, CA: 

LBNL-50966, February 2002. http://eetd.lbl.ov/ea/emp/reports/50966.pdf

Goldman, Charles, Grayson Heffner (LBNL), and Michael Kintner-Meyer (PNNL). Do "Enabling 

Technologies" Affect Customer Performance in Price-Responsive Load Programs? May 2002, 

ACEEE Conference Paper. and August 2002: LBNL-50328. 

http://eetd.lbl.gov/ea/emp/reports/50328.pdf 

Patti Harper-Slaboszewicz (UtiliPoint). “Market Trends in AMR and Demand Response,” prepared for 

Automatic Meter Reading Association (AMRA), 2005. 

–. “Regulator Interest in AMI and Demand Response,” presentation at FERC Technical Conference, 

January 25, 2006. 

Heffner, Grayson C. Configuring Load as a Resource for Competitive Electricity Markets: Review of 

Demand Response Programs in the U.S. and Around the World. Berkeley, CA, November 

2002: LBNL-51496. http://eetd.lbl.gov/EA/EMP/reports/51496.pdf 

–. Demand Response Providing Regulation and Reserve Services in Nordic Electricity Markets: draft. 

Consortium for Electric Reliability Technical Solutions, March 2006. 

–. Demand Response Provision of Ancillary Services in Australia’s National Electricity Market: draft. 

Consortium for Electric Reliability Technical Solutions, March 2006. 

Heffner, Grayson and Freeman Sullivan. A Critical Examination of ISO-Sponsored Demand Response 

Programs, white paper prepared for multi-client study organized by CAEM/DEFG. August 

2005. http://www.defgllc.com/Assets/downloads/caem-defg_heffner_drwhitepaperno1_final(2).pdf 

Hirst, Eric. Direct Testimony on Behalf of Puget Sound Energy, Inc., before the Washington Utilities 

and Transportation Commission, November 26, 2001. 

–. “The Financial and Physical Insurance Benefits of Price-Responsive Demand.” The Electricity 

Journal 15 #4 (May 2002): 66-73. 

Hirst, Eric and Brendan Kirby. Opportunities for Demand Participation in New England Contingency 

Reserve Markets. New England Demand Response Initiative (NEDRI) technical paper, 
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-6 

February 2003. 

Holland, Stephen P. and Erin T. Mansur. The Distributional and Environmental Effects of timeVarying Prices in Competitive Electricity Markets. Berkeley, CA: Center for the Study of 

Energy Markets (CSEM), May 2005. 

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Hunt, Sally. Making Competition Work. See especially Chapter 4, “Requirements for Competition: 

Demand Side.” New York: John Wiley & Sons, 2002. 

ICF Consulting. Economic Assessment of RTO Policy. Study prepared for the Federal Energy 

Regulatory Commission (FERC). February 2002. http://www.ferc.gov/industries/electric/indusact/rto/cost/02-26-02-report.pdf 

Isemonger, Alan. “CAISO Ancillary Service Procurement Under MRTU.” Presentation at MISO 

Ancillary Services Roundtable. Carmel, IN, April 26, 2006. 

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ISO-New England. Staff White Paper. Controlling Electricity Costs. June 1, 2006. http://www.isone.com/pubs/whtpprs/electricity_costs.pdf 

ISO/RTO Planning Committee. ISO/RTO Electric System Planning,Current Practices, Expansion 

Plans, and Planning Issues. February 10, 2006. 

Irastorza, Veronica. “New Metering Enables Simplified and More Efficient Rate Structures.” The 

Electricity Journal, 18 #10 (December 2005): 53-61. 

Kathan, David, for the National Association of Regulatory Utility Commissioners (NARUC). Policy 

and Technical Issues Associated with ISO Demand Response Programs. July 2002. 

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Keech, Adam. “PJM Ancillary Services Markets.” Presentation at MISO Ancillary Services 

Roundtable. Carmel, IN, April 26, 2006. 

Kiesling, Lynne. “The Role of Retail Pricing in Electricity Restructuring.” In The Challenge of 

Electricity Restructuring, edited by Andrew Kleit. Lanham, MD: Rowman & Littlefield, 2006. 

(forthcoming) 

–. “Demand Response: Progress and Barriers.” Presentation at MIT-CEEPR Conference. Cambridge, 

MA, November 2005. www.knowledgeproblem.com/KieslingCEEPRNov2005.pdf 

–. “Energy Smart” columns, March 2, 2004, and January 14, 2005. www.knowledgeproblem.com

King, Chris. “Advanced Metering Infrastructure: Overview of System Features and Capabilities, 

September 2005.

King, Chris and Dan Delurey. “Efficiency and Demand Response: Twins, Sibling, or Cousins?” 

Public Utilities Fortnightly, March 2005: 54-61. 

Kirby, Brendan. Spinning Reserve From Responsive Loads, ORNL/TM-2003/19, Oak Ridge National 

Laboratory, March 2003. 

Kirby, Brendan and Eric Hirst. Load as a Resource in Providing Ancillary Services. American Power 

Conference, Chicago, IL, April 1999. 

–. Technical Issues Related to Retail Load Provision of Ancillary Services. New England Demand 

Response Initiative technical paper. February 2003. 

Kirby, Brendan, et al. Frequency Control Concerns In The North American Electric Power System, 

Oak Ridge National Lab. ORNL/TM-2003/41, December 2002. 

Kueck, John and Brendan Kirby. Presentation to the WECC Compliance Monitoring and Operating 

Practices Subcommittee. January 7, 2005. 

Laurita, Robert and Henry Yoshimura. Interview by Brendan Kirby, 2005. 

Levy, Roger. “Advanced Metering and Dynamic Rates: the Issues.” September 30, 2004. 

–. “California Statewide Pricing Pilot (SPP): Overview and Design Features.” Presentation at the 

Joint California Workshop on “Advanced Metering Results and Issues.” Sacramento, CA: 

September 30, 2004. 
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-7

–. “Establishing the AMI Business Case Framework: Advancing Technology to Support Utility, 

Customer and Societal Needs,” presentation to MADRI AMI subgroup, Philadelphia, PA: May 

4, 2005. 

–. “Meter Scoping Study,” prepared for the California Energy Commission, March 2002. 

Leonhardt, David, “Save Yourself,” The New York Times, April 11, 2006, section G, 1. 

Long Island Power Authority (LIPA). LIPA Edge, presentation to the NYISO Price-Responsive Load 

Working Group. November 21 2002. 

–. Data supplied through Applied Energy Group for 2002. 

Loughran, David S. and Jonathan Kulick. “Demand-Side Management and Energy Efficiency in the 

United States.” Energy Journal, 25 #1 (January 2004): 19 – 40. 

Lynk, Fred, PSE&G. “myPower Pilot Program,” presentation to MADRI Regulatory Subgroup, 

November 2005. 

McKinsey & Co., Inc. “The Benefits of Demand-Side Management and Dynamic Pricing Programs.” 

White Paper, May 2001. (see also Colledge, Justin A., et al. “Power by the Minute.” ) 

–. AMI tool, under development; may be made available on pro-bono basis. 

McAuliffe, Pat and Arthur Rosenfeld, California Energy Commission. Response of Residential 

Customers to Critical Peak Pricing and Time-of-Use Rates during the Summer of 2003, 

September 23, 2004. 

Magnotti, Frank A., Comverge. “Bridging the Gap between Wholesale and Retail Markets.” 

Presentation to MADRI business-models subgroup, Washington, DC: March 10, 2006. 

http://www.energetics.com/MADRI/pdfs/magnotti_031006.pdf

–. “Smart Thermostat DER Initiative.” Presentation to MADRI, Trenton, NJ: June 5, 2006. 

http://www.energetics.com/MADRI/pdfs/Magnotti.pdf 

Malemezian, Ed. Interview by Brendan Kirby, 2005. 

Marks, Michael, Applied Energy Group. E-mail discussion with Brendan Kirby. April 15, 2006. 

Merilatt, Dan, GoodCents Solutions. “Demand Response Programs: New Considerations, Choices, 

and Opportunities.” White paper, January 2004. 

http://www.goodcents.com/Info/Demand%20Response%20Programs.pdf 

Mickey, Joel. Competitive Ancillary Services Market in ERCOT. MISO Ancillary Services Round 

Table. Carmel, IN, April 26, 2006. 

Midwest Independent System Operator (MISO). MISO Ancillary Services Round Table. Carmel 

Indiana: April 26-27, 2006. Presentations: 

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–. Midwest ISO Transmission Expansion Plan 2005 – MTEP 05. June 2005. 

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Moezzi, Mithra, et al. Real Time Pricing and the Real Live Firm. August 2004: LBNL-54978. 

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Moore, Taylor. “Energizing Customer Demand Response in California,” EPRI Journal, Summer 

2001, 8. 

Neenan, Bernie. “The Benefits of Dynamic Pricing in New England.” Presentation to ISO-NE 

Demand Response Summit, April 27, 2006. http://www.isone.com/genrtion_resrcs/dr/events/2006/BNeenan.pdf 

–. 4-part series on time-varying retail rates in UtiliPoint’s IssueAlert. “Focusing on Issues of Rate 

Design,” March 10, 2006; “Taxonomy of Time-Varying Pricing Designs,” March 24, 2006; 

with Jeremey Anderson, “Estimates of the Price Elasticity of Electricity,” May 8, 2006; and 

with Peter Cappers, “Everything You Ever Wanted to Know About Price Elasticities, but Were 

Afraid to Ask,” April 7, 2006.

Neenan, Bernie, et al. (Neenan Associates). Improving Linkages between Wholesale and Retail 

Markets through Dynamic Retail Pricing. Report prepared for ISO-New England, December 

2005. 
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-8 

Neenan, Bernie, Richard N. Boisvert, and Peter A. Cappers. “What Makes a Customer PriceResponsive?” The Electricity Journal, 15 #3 (April 2002):52-59.

NERA Economic Consulting. Distributed Resources: Incentives. Prepared for Edison Electric 

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Nerenberg, Lewis. “From Promise to Progress: Unleashing Consumer Power through the Real-Time 

Pricing of Electricity.” Working Paper (on Puget Sound Energy, Georgia Power), Baskin 

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Northeast Power Coordinating Council (NPCC). Emergency Operation Criteria: Document A-3. 

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New York Independent System Operator (NYISO). Downloaded from www.nyiso.com on April 3, 

2006. 

Orans, R., S. Price, D. Lloyd, T. Foley, and Eric Hirst. Expansion of BPA Transmission Planning 

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Pacific Northwest National Laboratory. “GridWise” Initiative to test new electric grid Technologies.” 

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Perez, A. J. New ISO Transmission Planning Process. California Independent System Operator 

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PJM. Market Monitoring Unit. 2004 State of the Market, March 8, 2005. 

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–. Amended And Restated Operating Agreement Of PJM Interconnection, L.L.C., Schedule 6 

Regional Transmission Expansion Planning Protocol, PJM Interconnection. April 26, 2006. 

–. PJM Regional Transmission Expansion Plan, PJM Interconnection. February 22, 2006. 

–. Planning data, downloaded from www.pjm.com on April 3, 2006. 

PIER Demand Response Research Center. Research Opportunity Notice DRRC RON-01: Establish 

the Value of Demand Response; Develop an Integrated Efficiency Demand Response Network. 

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Prins, David, et al. (CRA International). Interval Metering Advanced Communications Study. 

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“Regulatory Reform: Removing the Disincentives to Utility Investment in Energy Efficiency.” 

Regulatory Assistance Project. Issues Newsletter, September 2005. 

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Robertson, Hope, CERA. Focusing on the Demand Side of the Power Equation: Implications and 

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Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-9

Rosenstock, Steve, Edison Electric Institute (EEI). Final Results of the EEI / PLMA 2003 Demand 

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Southern California Edison (SCE). “Advanced Metering Infrastructure: Frequently Asked Questions.” 

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Response Project, Plan For Summer 2006 Demand Response Test on Southern California 

Edison Distribution Circuit, 23 March 23, 2005. 

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Smith, Vernon L., “An Experimental Study of Competitive Market Behavior,” The Journal of Political 

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UtiliPoint. Outlook & Evaluation of Demand Response. Albuquerque, NM: UtiliPoint International, 

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van Welie, Gordon. Address to ISO-NE Annual Demand Response Summit, April 27, 2006. 

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Viscusi, W. Kip, John M. Vernon, and Joseph E. Harrington. Economics of Regulation and Antitrust.

3rd edition. Cambridge: MIT Press, 2000. 

Western Electricity Coordinating Council. 2005 Summer Assessment. Salt Lake City, UT: WECC, 

May 2, 2005. 

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2004. 

Weston, Frederick (Rick), and Wayne Shirley, RAP, Dynamic Pricing: Aligning Retail Prices with 

Wholesale Markets; the Throughput Issue: Addressing the Adverse Impact of Distributed 

Resources on Utility Earnings; Role of Distributed Resources in System Planning, Scoping 

Paper for MADRI Regulatory subgroup, June 2005. 

Weston, Frederick (Rick), “Time Sensitive and Dynamic Pricing Options.” MADRI presentation, 

February 2006. www.energetics.com/MADRI

Weston. “Dynamic Pricing: Options and Policies.” White paper for MADRI regulatory subgroup. 

November 2005. www.raponline.org 

Woo, Chi-Keung, Ren Orans, Brian Horii and Peter Chow. “Pareto-superior time-of-use Rate Option 

for Industrial Firms,” Economics Letters 49 (1995): 267-272. 

York, Ted. “Exploring ANSI Standards in Meter Communications,” Electricity Today, March 2000. 
Appendix D – Bibliography 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

D-10 

Online Resources for further information on Demand Response and 

Advanced Metering: 

Associations / Collections of Studies: 

Association of Energy Services Professionals: http://www.aesp.org/i4a/pages/index.cfm?pageid=1

American Council for an Energy-Efficient Economy: http://www.aceee.org/

Demand Response and Advanced Metering Coalition (DRAM): http://www.dramcoalition.org 

Lawrence Berkeley National Laboratories, Demand Response Research Center (LBNL): 

http://drrc.lbl.gov/drrc.html 

Midwest Energy Efficiency Alliance: http://www.mwalliance.org/

Regulatory Assistance Project (RAP). Reports and Issues newsletters on Energy Efficiency, DemandSide Resources, and Demand Management: www.raponline.org (All RAP reports cited in this 

bibliography can be found at this site.) 

University of California Energy Institute (UCEI), Energy Market (CSEM) Working Papers: 

http://www.ucei.berkeley.edu/ 

Regional Demand Response Programs, Initiatives, Planning: 

Bonneville Power Authority (BPA), energy efficiency: http://www.bpa.gov/Energy/N/

California: 

 PIER Demand Response Research Center. Created by CEC in 2004 to plan and conduct 

multi-disciplinary research to advance DR in California. http://drrc.lbl.gov/drrc.html 

 CAISO, Demand Response: http://www.caiso.com/clientserv/load/

ERCOT: http://www.puc.state.tx.us/electric/projects/26055/26055.cfm

Mid-Atlantic Distributed Resources Initiative (MADRI) 

 Meeting agendas, presentations, and reports: http://www.energetics.com/MADRI/

 Advanced Metering Tool-box: http://www.energetics.com/madri/toolbox/ 

Midwest ISO (MISO): http://www.midwestmarket.org/page/MisoPortalHome

 Emergency Operations Procedure: 

http://www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-

7f700a48324a/_.pdf?action=download&_property=Attachment 

New England: 

 ISO-NE Demand Response

o Working Group materials: http://www.isone.com/committees/comm_wkgrps/mrkts_comm/dr_wkgrp/index.html

o Demand Response main page: http://www.iso-ne.com/genrtion_resrcs/dr/index.html

 New England Distributed Resource Initiative (NEDRI) 

o Studies: http://www.raponline.org/Feature.asp?select=20 

o Studies prepared state-by-state, by Raab Associates: 

http://www.nedri.raabassociates.org/main/projects.asp?proj=35&state=Completed 

New York: ISO – Demand Response:http://www.nyiso.com/public/products/demand_response/index.jsp

Pacific Northwest National Laboratory (DOE): 

 Energy Efficiency and Renewable Energy Research: http://eere.pnl.gov/program_areas.stm 

PJM Interconnection, LLC: 

 Demand Response Working Group: http://www.pjm.org/committees/workinggroups/dsrwg/dsrwg.html

 Demand Response: http://www.pjm.org/services/demand-response/demand-response.html
Appendix E: The Public Process 

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E-1

Appendix E: The Public Process Leading to the Report 

On November 3, 2005, Commission staff issued a notice of proposed voluntary survey and technical 

conference regarding Assessment of demand response resources, asking g for comments on a proposed 

survey, technical conference topics, and interest regarding participating at the conference.1

 The 

November 2005 Notice set a comment date of December 5, 2005 for entities that wanted to comment 

on proposed survey questions and/or request to participate in the technical conference. A number of 

entities provided comments: 

• Alcoa Inc. 

• American Electric Power Service Corporation 

• American Public Power Association 

• Avista Corporation 

• California Department of Water Resources State Water Project 

• Demand Response and Advanced Metering Coalition 

• Detroit Edison Company 

• Edison Electric Institute 

• Exelon Corporation 

• FirstEnergy Service Company 

• Stephen George of Charles River Association 

• Hunt Technologies Inc. 

• ISO New England 

• Mid-Atlantic Distributed Resources Initiative (MADRI) 

• Midwest Independent Transmission System Operator, Inc. 

• National Grid USA 

• New England Conference of Public Utilities Commissioners 

• New York State Electric and Gas Corporation 

• PJM Interconnection, L.L.C. 

• PNM Resources Inc. 

• Portland General Electric Company 

• San Diego Gas & Electric Company 

• Salt River Project Agricultural Improvement & Power District 

• Silver Spring Networks 

• Southern California Edison Company 

• Southern Company Services, Inc. 

• Steel Manufacturers Association 

• U.S. Environmental Protection Agency 

• Xcel Energy 

The November 2005 Notice established a comment date of December 19, 2005 for entities that wanted 

to comment on proposed technical conference topics. A number of entities provided comments: 

• Alcoa Inc. 

 1

 This notice was published in the Federal Register on November 9, 2005, 70 Fed. Reg. 68,002 (2005) (November 

2005 Notice). 
Appendix E: The Public Process 

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1⁄2 Federal Energy Regulatory Commission 3⁄4 

• American Public Power Association 

• California Public Utility Commission staff / California Energy Commission 

• Central Maine Power Corporation, New York State Electric and Gas Corporation, and 

Rochester Gas and Electric Company 

• Cinergy Services, Inc. 

• Consumers Energy Council of America 

• Demand Response and Advanced Metering Coalition 

• Distributed Energy Financial Group, LLC 

• Edison Electric Institute 

• Exelon Corporation 

• Idaho Power Company 

• ISO New England 

• Midwest Independent Transmission System Operator, Inc. 

• National Grid USA 

• Hunt Technologies Inc. 

• MADRI 

• MidAmerican Energy Company 

• Missouri Public Service Commission 

• National Energy Marketers Association 

• Nevada Power Company / Sierra Pacific Power Company 

• New England Conference of Public Utilities Commissioners 

• New York Independent System Operator, Inc. 

• New York State Public Service Commission 

• Pacific Gas and Electric Company 

• Pennsylvania Public Utility Commission 

• PJM Interconnection, L.L.C. 

• Portland General Electric Company 

• Public Service Commission of Maryland 

• Public Utilities Commission of Ohio 

• San Diego Gas & Electric Company 

• Silicon Valley Leadership Group 

• Southern California Edison Company 

• Southern Company Services, Inc. 

• Steel Manufacturers Association 

Commission staff issued notices of the January 25, 2006 technical conference.2 The following entities 

submitted comments / testimony: 

• Jeffrey Bladen, PJM Interconnection, L.L.C. – presentation 

• James Brew, Steel Manufacturers Association – presentation 

• Ken Corum, Northwestern Power and Conservation Council – presentation 

• Jeff Davis, Missouri Public Service Commission – presentation 

• Paul Demartin, Southern California Edison Company – presentation 

 2

 Notice of the technical conference was published in the Federal Register on December 16, 2005, 70 Fed. Reg. 

74,804 (2005). Subsequent notices to the technical conference were published in the Federal Register. See 71 Fed. Reg. 

3,287 (2006); see also 71 Fed. Reg. 4,361 (2006). 
Appendix E: The Public Process 

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E-3

• Charles Goldman, Lawrence Berkeley National Laboratory – presentation 

• Phil Giudice, EnerNOC – presentation 

• Patti Harper-Slaboszewicz, Utilitpoint International – presentation 

• Bruce Kaneshiro, California Public Utilities Commission – presentation 

• John M. Kelly, American Public Power Association – presentation 

• Tom Kerr, U.S. Environmental Protection Agency – presentation 

• David Lawrence, New York Independent System Operator, Inc. – presentation 

• Ronald McNamara, Midwest Independent System Operator, Inc. – presentation 

• David Meade, Praxair, Inc. – presentation 

• Jay Morrison, National Rural Electric Cooperative Association – presentation 

• Tim Roughan, National Grid – presentation 

• Peter Scarpelli, RETX – presentation 

• Doug Stinner, PPL Electric Utilities – presentation 

• Rick Tempchin, Edison Electric Institute – presentation 

• Alan Wilcox, Sacramento Municipal Utility District – presentation 

• Henry Yoshimura, ISO New England – presentation 

• Xcel Energy Comments 

On March 15, 2006, Commission staff issued a notice of issuance of voluntary survey of advanced 

metering and demand response programs regarding assessment of demand response resources.3

 3

 Notice of the survey was published in the Federal Register on March 24, 2006, 71 Fed. Reg. 14,888 (2006). 
Appendix E: The Public Process 

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1⁄2 Federal Energy Regulatory Commission 3⁄4 
Appendix F: The FERC Survey 

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F-1

Appendix F: The FERC Survey 

Summary 

The Energy Policy Act of 2005 (EPAct 2005) required that the Federal Energy Regulatory 

Commission (FERC) provide Congress with both qualitative information4

 about demand response 

(DR) and advanced metering infrastructure (AMI) as well as specific quantitative, region-specific 

information. Commission staff determined that a survey of all private and public entities that provide 

electric power and DR to customers would help fulfill the requirement. 

Between September 2005 and June 2006, Commission staff—with the technical support of UtiliPoint 

International, Inc. (UtiliPoint): 

• developed a survey and sampling design; 

• issued a proposed survey for public comment as well as a notice announcing a related 

technical conference in the November 9, 2005 Federal Register; 

• gathered public information and guidance for the FERC Survey through the January 2006 

technical conference; 

• initiated and successfully completed the Office of Management and Budget’s (OMB) 

authorization process for federal information collections; 

• fielded the FERC Survey, collected the data and completed a substantial amount of data 

analyses for this report. 

The response rate for the FERC Survey was 56% for the demand response section (1,886 of the 3,365 

entities who received the FERC Survey) and 55% for the AMI section (1,860 of the 3,365 entities who 

received the FERC Survey). 

The FERC Survey response rate resulted from its being voluntary (instead of mandatory, like the EIA861) and asking for more information on demand-side resources than the EIA Form-861survey. 

The following provides a detailed review of the steps Commission staff took to achieve this critical 

response rate documents the surveying process and addresses the OMB requirements for a summary of 

response rates and sampling results. An additional OMB requirement was to incorporate into its 

methodology a random sample derived from the respondent universe for the AMI section of the FERC 

Survey. 

Development of the FERC Survey and Sampling Design 

Coordination with EIA 

Commission staff coordinated with Robert Schnapp, Director, Electric Power Division, EIA, to 

determine what EIA information Commission staff could use to meet the requirements of EPAct 2005 

and to avoid imposing redundant reporting burdens on the industry. Neither the use of EIA DR data 

nor revisions of existing EIA information collections were going to help Commission staff meet the 

statutory requirement because: (1) there was a mismatch between the data collected and the data 

 4

 See this Report’s Chapter VI, Role of Demand Response in Regional Planning and Operations and Chapter VII, 

Regulatory Barriers. 
Appendix F: The FERC Survey 

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F-2 

Congress asked for;5

 and (2) the timetable for revising and collecting the needed data through EIA-861 

did not coincide with the Congressional deadline of August 8, 2006.6

 Based on these circumstances, 

Commission staff concluded that a separate survey was needed. 

The Draft Survey 

Commission staff decided to use a voluntary rather than mandatory survey because many of the 

entities it would be surveying were non-jurisdictional. To design the draft survey, Commission staff 

received advice and assistance from Chuck Goldman and Ranjit Bharvirkar from the Lawrence 

Berkeley National Laboratory, the Demand Response and Advanced Metering Coalition (DRAM) and 

the Mid-Atlantic Demand Response Initiative (MADRI). Commission staff designed the draft survey 

to collect the needed information using three forms: one was to collect general and identifying 

information on the respondents, the second was on demand response and time-based metering 

programs (FERC-727), and the third was on advanced metering infrastructure (FERC-728). Dividing 

the FERC Survey into three sections allowed different people within an organization to collect data 

and complete the forms at the same time. The general information section of the FERC Survey helped 

link data from all parts of the FERC Survey together for each respondent. It also provided a fast way 

for organizations to respond to the FERC Survey if they had no information to report. 

The Respondent Universe 

To analyze the survey data and calculate statistics for this report, Commission staff reviewed the 

composition of the respondent universe (RU) very closely, and found that there were 3,365 

organizations as listed in Table F-1. 

Table F-1. Respondent Universe of FERC Survey

Group Name # of Organizations in Group 

Municipally Owned Utilities 1,847 

Cooperative Utilities 884 

Investor Owned Utilities 219 

Power Marketers 165 

Political Subdivisions 126 

Municipal Marketing Authorities 19 

Curtailment Service Providers (CSPs) 68 

State Utilities 21 

Federal Utilities 9 

RTOs/ISOs 7 

Grand Total 3,365 

Source: EIA, Internet 

 5

 EIA-861 data provides total, aggregated data on energy efficiency and load management. It does not collect 

information on saturation and penetration rates of advanced meters, communications, technologies, devices and systems. In 

additon, the EIA-861 does not ask about existing demand resource programs or time-based rate programs. The form does not 

have detailed information on the annual resource contribution of demand resources. 

6

 Per an August 21, 2005 conversation between David Kathan of FERC and Robert Schnapp of EIA, it was 

determined to be too late for EIA to incorporate the additional data Commission staff needed in the EIA-861 which was soon 

to be issued to collect 2005 data. Moreover, EIA-861 responses are due by April of each year, and EIA does not publish the 

results of the survey until November or December. This timetable did not allow FERC to be able to respond to Congress. 
Appendix F: The FERC Survey 

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F-3

Table F-2 shows the adjustments Commission staff had to make to the number of organizations in 

three categories (Municipally Owned Utilities, Curtailment Service Providers (CSPs) and Regional 

Transmission Organization/Independent System Operator (RTO/ISO) to: 

• limit the geographic scope of the survey to businesses in American States, as required by 

Congress; 

• reflect a change in utility ownership status that occurred during the survey period; 

• ensure accurate survey outreach to all organizations which might have DR or AMI activities to 

report; and 

• eliminate data redundancy. 

Specifically, Commission staff and Utilipoint made four adjustments to the number of groups in each 

category of the RU as they proceeded from OMB authorization to fielding and analysis. First, the 

organizations that received the FERC survey included a municipal utility in Guam and three utilities in 

the United States territories of Puerto Rico, Virgin Islands, and Samoa. Commission staff did not 

include the organizations in the territories that responded in the final survey tabulations, and so the 

number of State utilities in the RU decreased from 24 to 21, and the number of municipally owned 

utilities decreased from 1,847 to 1,846. In the course of fielding the survey, one investor owned utility 

changed to a municipal utility, which increased the number of municipally owned utilities from 1,846 

back up to 1,847 and decreased the number of investor utilities from 220 to 219. Commission staff 

inadvertently counted four RTOs/ISOs as CSPs during its work with OMB for survey and sample 

authorizations. Commission staff also subsequently found that it had counted one of the CSPs three 

times because the company has three EIA identification numbers in the 2005 EIA 861 database used to 

field the FERC Survey. The necessary adjustments result in a decrease in the number of CSPs listed 

in the requests to OMB for survey and sample authorization (74) and in the number of CSPs who 

received the FERC Survey (70) to 68. 

Table F-2. Adjustments to Number of Organizations in RU Groups 

Group Name 

# of 

Organizations 

in RU by 

Group 

RU #s in 

FERC Survey 

Authorization 

Request to 

OMB 

RU #s in 

FERCProposed 

Sample 

Design 

RU #s 

who 

Received 

Survey 

Municipally Owned Utilities 1,847 1,847 1,847 1,847

Cooperative Utilities 884 884 884 884

Investor Owned Utilities 219 220 220 220

Power Marketers 165 165 165 165

Political Subdivisions 126 126 126 126

Municipal Marketing Authorities 19 19 19 19

CSPs 68 74 74 70

State Utilities 21 24 24 24

Federal Utilities 9 9 9 9

RTOs/ISOs 7 8 0 7

Grand Total 3,365 3,294 3,368 3,371

Source: EIA, Internet 

The utility component of the respondent universe consists of utilities in the United States that are 

involved in the generation, transmission, and distribution of electric energy. The region definition 

used in the FERC Survey was based on that used by the North American Electric Reliability Council 
Appendix F: The FERC Survey 

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F-4 

(NERC). Using NERC regions allowed collection of data based on how energy is traded and 

managed, and provided the most useful regional grouping for the consideration of DR resources, and 

advanced metering deployment that would potentially reduce barriers for participation in demand 

response and time-based rate programs and/or tariffs. 

FERC Survey Methodology 

The results in the final report reflect improvements Commission staff was able to make to the draft 

survey because of public comments. In addition, in order to obtain OMB approval, Commission staff 

had to incorporate a sample in its survey design methodology. 

Public Comment 

On November 3, 2005, Commission staff issued in Docket No. AD06-2-000 a notice with the 

proposed survey.7

 The notice was published in the November 9, 2005 Federal Register.

8

 In seeking 

public comment, Commission staff asked whether the questions would elicit accurate information on 

advanced meters and demand response programs, or whether the questions should be modified or 

supplemented to better obtain information. In addition, Commission staff asked for input on other 

sources of information on advanced metering and demand response programs. Twenty-nine entities 

filed comments regarding the proposed survey. 

In response to the comments, numerous changes were made including clarification of what was 

expected on the FERC Survey and the development of a glossary of terms. In addition, detailed 

instructions for completing each section of the FERC Survey were significantly revised and expanded. 

The FERC Survey web page was populated with information about the Commission’s demand 

response work, including a document listing and answering frequently asked questions; related 

notices; the draft survey; and a Commission-staff summary of comments on the draft survey. 

Respondents were also able to download a copy of the entire survey instrument to help them organize 

and conduct their data collections and to help them complete the FERC Survey online as quickly as 

possible. 

The structure of the FERC Survey was revised to allow respondents to enter as many as 8 demand 

response and/or time-based rate programs/tariffs per customer class per region. Respondents were 

provided with multiple choice questions in a format only requiring that respondents make a choice 

among options rather than enter codes. This was done to improve the quality of data and ease the 

burden on respondents. Other survey design enhancements included the use of tables whenever 

possible for respondents to be able to ensure that the numerical information provided was consistent 

across each customer class and routing to keep respondents from having to search for the next relevant 

question to answer. This feature was tested on the web before release of the survey to ensure that it 

worked correctly. Many of the comments revealed that potential respondents were interested in the 

results, understood the questions, and were very capable of discussing the issues in great detail. To 

allow for additional input, the FERC Survey provided comment boxes on a regular basis throughout 

the forms. This yielded information that could normally only have been obtained through an in-person 

interview. 

 7

 The two sections of the survey were FERC-727 “Demand Responses and Time-Based Rate Programs Survey” 

and FERC-728 “Advanced Metering Program Survey.” 

8

 70 FR 68002-6803. 
Appendix F: The FERC Survey 

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F-5

Commission staff received several comments on the draft survey regarding security and took steps to 

address the concerns. Commission staff issued a randomly generated, organization-specific, alphanumeric password to ensure that the survey responses received were the official response of the 

organization. The letter from Commission staff with the survey provided potential respondents with 

their password. UtiliPoint was diligent in keeping the survey responses and data secure. Access to the 

FERC Survey was through a FERC webpage link that took respondents to the UtiliPoint server. 

UtiliPoint’s server hosting company uses network intrusion detection in a signature based model. They 

also use a state based layer firewall with notification and alerting of abnormal events. The 

administrator at the server hosting company is a Certified Information Systems Security Professional. 

OMB Requirements 

Commission staff reviewed and met the OMB guidelines outlined in Questions and Answers When 

Designing Surveys for Information Collections. The biggest challenge Commission staff had in 

gaining OMB approval of the FERC Survey came from a belief OMB staff had that sending out the 

FERC Survey to the entire respondent universe would result in data with a self-selection bias. As a 

result, OMB required Commission staff to: (1) change the FERC Survey design to mitigate the 

potential for self-selection bias by drawing a random sample of 762 in the AMI section; (2) provide a 

report on the achieved response rates by strata and on the results of analyses comparing the random 

sample to the RU and (3) note any meaningful differences between the response rate of the AMI 

section of survey for the RU and for the sample of 762 in the final report to Congress. In its analysis, 

Commission staff found no significant self-selection bias in the data. 

Methodology 

Commission staff conducted the FERC Survey using the Internet. The FERC-727 and FERC-728 

were posted as forms on the Commission’s web page and the links allowed those who took the FERC 

Survey to submit their responses electronically directly to FERC and UtiliPoint. 

In designing the methodology for the DR and AMI sections of the survey, UtiliPoint: 

• Drew the pool of utility respondents from the 2005 EIA respondent list and verified the 

number of organizations in each group; 

• Segmented the pool of potential FERC Survey respondents by NERC region, type of utility 

and the number of retail customers served; 

• Sized utilities based on total number of customers each utility reported in its 2004 EIA-861 

form, as follows: 

o large (number of customers over 100,000); 

o medium (number of customers > 25,000 and less than 100,000); 

o other (0 retail customers or Generation and Transmission utility) and 

o small (less than or equal to 25,000 customers); and 

• Drew a random sample of 762 for the AMI section of the survey. 

Commission staff expected that the DR program/tariff offerings as well as the penetration of AMI 

would be substantially different across the different size utilities and across the different types of 

utilities. 
Appendix F: The FERC Survey 

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F-6 

The AMI survey methodology anticipated responses from utilities that have ownership and/or 

responsibility for revenue and billing metering, such as cooperative, federal, investor owned, 

municipal, political subdivision, and state utilities who serve retail customers. 

Utilities that do not serve retail customers—namely Municipal Marketing Authorities, Wholesalers or 

Generation and Transmission (G&T) utilities—were not expected to submit responses for the AMI 

section of the FERC Survey since these types of utilities typically do not own or have responsibility 

for billing and revenue meters for retail customers. In addition, Power Marketers (which include 

Competitive Retailers, Energy Service Providers, Retail Providers, and the other names generally used 

in regions with retail competition or retail choice) were not expected to submit responses to the AMI 

section of the FERC Survey because these utilities typically do not own or have responsibility for 

retail metering. 

Fielding the FERC Survey and Analyzing the Data 

Efforts to Maximize Response Rates 

Commission staff tried to maximize response rates by using an aggressive outreach approach of 

addressing large gatherings of organizations that were expected to respond to the FERC Survey. For 

example, Commission staff announced preliminary survey plans to and discussed with several trade 

and state associations including members and/or representatives of the National Association of 

Regulatory Commissioners, American Public Power Association, Edison Electric Institute, and the 

National Rural Electric Cooperative Association. In a cooperative spirit and in consideration of the 

authority that state utility commissioners have in this matter, Commission staff sent letters to state 

regulators over FERC Chairman Kelliher’s signature informing them of the organizations in their state 

that were asked to participate in the FERC Survey. The letter committed to giving them a status report 

of whether or not those utilities in their jurisdiction had responded to the FERC Survey. Commission 

staff sent the follow-up letters to the state regulators 30 days after the FERC Survey issued. 

Another effort to maximize response was that the letter Commission staff sent to the respondent 

universe used personalized greetings, provided information about the FERC Survey, gave general 

guidance on how to complete the FERC-727 and FERC-728 and referred to the potential respondent 

company by name to encourage its participation in the important study. Commission staff sent the 

FERC Survey letter via email as well as in hard copy. Delivery of a hard copy of the FERC Survey 

package at the place of business was especially useful because Commission staff anticipated contacts 

listed in the 2005 EIA-861 data base may have changed. 

Commission staff also worked to maximize response rates through the FERC Survey’s design. The 

FERC Survey included routing to only show the respondent relevant questions, used multiple choice 

questions where feasible, and kept validity checking to a minimum to reduce respondent frustration 

during the data entry process. 

To accommodate respondents who were not comfortable completing a web survey or who did not 

have access to the internet, the instructions provided a person’s name and contact information so they 

could find an alternative means for reporting their information. Respondents needing such 

accommodation received an email telling them the links to the FERC Survey web page to print the 

forms. The email included instructions for completing submitting the FERC Survey manually. 

Respondents were able to have someone fill out the FERC Survey for them during a phone call, if they 
Appendix F: The FERC Survey 

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F-7

chose to. There was a phone number at the bottom of each page of the FERC Survey for respondents 

to call if they encountered problems while filling out the survey and this boosted response rates by 

solving technical difficulties which might have discouraged respondents. For example, some 

respondents notified Commission staff and Utilipoint that they were not able to access the information 

on the web site. Investigation of the matter found that these respondents had pop-up ad blockers on 

their computers. By disabling this feature on their computer, they were able to complete the survey. 

Commission staff and Utilipoint collected and compiled this sort of information into a frequently 

asked question list which was then posted on the survey web page. 

Commission staff accommodated people at organizations with no internet by preparing and mailing 

copies of the FERC Survey and all the information needed to complete the FERC Survey to them. 

To increase the likelihood of getting survey responses from contacts listed in the EIA-861 data base 

who were responsible for reporting on three or more organizations, Commission staff sent customized 

letters to these contacts. The letter included a spreadsheet they could use to report their data and 

eliminated the need to fill out the multi-page survey repeatedly. 

Commission staff and Utilipoint followed through with those who had not completed the FERC 

Survey by the deadline by phoning them and filling out the relevant survey sections for them while 

they were on the phone. People who did all the follow-up had experience in interviewing energy 

market participants and had a deep knowledge of advanced metering, demand response, and timebased rates. 

UtiliPoint tracked responses as they came in to assess which NERC regions might have been showing 

under-representation and targeted these for early follow-up. 

Expected and Actual Response Rates 

With regard to expected response rates in general, Commission staff expected that large utilities would 

be very responsive and medium sized utilities less so. Small utilities were expected to be very 

responsive, but primarily if someone followed up with a phone call. 

The response rate for the demand response and time-based programs/tariffs section of the FERC 

survey was expected to be lower than for the AMI survey section for two reasons. First, utilities were 

going to need to submit fewer responses for this FERC Survey section since only one response was 

required per NERC region, whereas for the AMI survey section, one response was required per state. 

Large utilities with operations across states were to complete an AMI survey section for each state but 

were to provide only one response for the FERC Survey section on DR. The second reason for 

anticipating a lower response rate was that longer surveys have lower response rates. The actual 

response rates between the two sections were almost identical. 

Commission staff expected—and received—a large number of responses from larger utilities for two 

reasons. First, larger utilities have consistently reported more demand response load in MW than 

smaller utilities. Second, large utilities had shown a keen interest in the demand response section of 

the FERC Survey. 

Commission staff also expected a high response rate from the larger utilities on the AMI section 

survey design for three reasons. First, the larger utilities represent more retail customers. Second, the 

large utilities showed a keen interest in the AMI section of the FERC Survey in their responses to the 
Appendix F: The FERC Survey 

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F-8 

Commission’s draft survey. Third, Commission staff gave follow-up to non-responding, large utilities 

a high priority. 

The percentage of responses by utility size was consistent with UtiliPoint survey experience that large 

utilities are typically very responsive and medium sized utilities less so. Experience also had showed 

that small utilities are very responsive, but primarily if someone follows up with a phone call. The 

large number of small utilities limited the number of non-responding small utilities that could be 

economically included in planned follow-up. 

The follow-up calls were planned to first go to larger utilities since they represent the most meters per 

response, and then to any market segment that was having a lower than expected response rate. 

Commission staff achieved a very significant—and rare—response rate greater than 50% for the small 

cooperative and municipally owned utilities. Small municipals usually have a voluntary survey 

response rate of 5 %. Table F-3 displays the response rates received. 

In spite of follow up phone calls and in-person conversations with staff and leaders at all levels of the 

CSPs, Commission staff was only able to achieve a response rate for CSPs that was 29% for the DR 

section the FERC Survey and 28% for the AMI section of the FERC Survey. 

During the analysis phase of the FERC Survey, experienced industry analysts reviewed the data 

provided by the respondents. The data was carefully weighted based on the type of organization, size, 

and region, to allow analyses of the responses to accurately reflect the entire market. The industry 

analysts tabulated the data to provide meaningful and interesting information for the report to 

Congress. 

The FERC Survey response rate—overall and by strata—showed no statistically significant evidence 

of self-selection bias when Commission staff and Utilipoint compared the response rates of the 762 

organizations in the random AMI sample to the response rates of the 1,860 in the respondent universe 

who completed the AMI section of the FERC Survey. Table F-4 displays the expected and actual 

response rates for AMI. 

There were various categories of the ways in which organizations reported their information. In the 

most straightforward response, organization A submitted a DR and/or an AMI survey response for 

organization A. Other responses were sometimes more complicated in the organizations they covered. 

For example, in some cases Organization B submitted DR and or AMI responses for organization B 

that included the information for the organization A. This occurred when there were multiple 

operating companies within a particular NERC region for one entity. In other cases Organization A 

submitted a General Information for organization A indicating no DR and/or AMI programs. 

Organization B submitted a General Information for organization B indicating no DR and/or programs 

for Organization B. Organization A and B are separate operating companies for one entity. In yet 

other cases, Commission staff and Utilipoint received an email from a responsible authority indicating 

that organization A no longer is in business, or was never a separate entity. In a follow-up phone call 

with organization A, we learned they offered no DR programs and/or had no AMI. We always asked 

them to fill out the General Information section of the survey, and mostly did, but some did not. 
Appendix F: The FERC Survey 

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F-9

Table F-3. Expected and Actual Response Rates of the Respondent 

Universe

Ownership Size 

Nbr 

of 

Orgs 

Cell 

Response 

Goal 

DR 

Survey 

Section 

AMI 

Survey 

Section 

Response 

Rate Goal 

DR 

Response 

Rate 

AMI 

Response 

Rate 

Municipal Large 17 14 13 12 85% 76% 71%

 Medium 84 58 49 48 70% 58% 57%

 Small 1,738 1,421 878 871 82% 51% 50%

 

Wholesaler or 

G&T 6 5 4 4 80% 67% 67%

 XMultiRegion 2 0 1 1 0% 50% 50%

Municipal Total 1,847 1499 945 936 81% 51% 51%

Cooperative Large 19 18 17 17 95% 89% 89%

 Medium 180 133 102 98 74% 57% 54%

 Small 625 478 361 352 77% 58% 56%

 

Wholesaler or 

G&T 59 47 40 40 80% 68% 68%

 XMultiRegion 1 0 1 1 0% 100% 100%

Cooperative Total 884 676 521 508 77% 59% 57%

Investor Owned Large 109 98 108 103 90% 99% 94%

 Medium 18 16 15 15 90% 83% 83%

 Small 59 53 54 55 90% 92% 93%

 

Wholesaler or 

G&T 33 30 29 30 90% 88% 91%

Investor Owned 

Total 219 197 206 203 90% 94% 93%

Power Marketer Large 10 6 5 6 60% 50% 60%

 Medium 5 5 3 2 100% 60% 40%

 Small 42 25 18 19 60% 43% 45%

 

Wholesaler or 

G&T 49 29 21 20 60% 43% 41%

 XMultiRegion 59 35 33 33 60% 56% 56%

Power Marketer 

Total 165 101 80 80 61% 48% 48%

Political 

Subdivision Large 7 7 6 6 100% 86% 86%

 Medium 11 11 7 6 100% 64% 55%

 Small 83 40 47 46 48% 57% 55%

 

Wholesaler or 

G&T 25 20 14 15 80% 56% 60%

Political 

Subdivision Total 126 78 74 73 62% 59% 58%

Municipal 

Marketing 

Authority 

Wholesaler or 

G&T 19 15 11 11 80% 58% 58%

Municipal Marketing Authority Total 19 15 11 11 80% 58% 58%

 
Appendix F: The FERC Survey 

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F-10 

Ownership Size 

Nbr 

of 

Orgs 

Cell 

Response 

Goal 

DR 

Survey 

Section 

AMI 

Survey 

Section 

Response 

Rate Goal 

DR 

Response 

Rate 

AMI 

Response 

Rate 

CSP Small 68 54 20 19 0% 29% 28%

CSP Total 68 54 20 19 80% 29% 28%

State Large 2 2 2 2 100% 100% 100%

 Medium 1 1 1 1 100% 100% 100%

 Small 6 6 6 6 95% 100% 100%

 

Wholesaler 

or G&T 12 12 8 9 100% 67% 75%

State Total 21 21 17 18 99% 81% 86%

Federal Small 6 6 4 4 100% 67% 67%

 

Wholesaler 

or G&T 3 3 2 2 100% 67% 67%

Federal Total 9 9 6 6 100% 67% 67%

RTOs/ISOs Small 7 6 6 6 0% 86% 86%

RTOs/ISOsTotal 7 6 6 6 80% 86% 86%

Grand Total 3,366 2,656 1,886 1,860 79% 56% 55%

Source: FERC Survey 
Appendix F: The FERC Survey 

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F-11

Table F-4. Expected and Actual Response Rates by Strata: AMI

Ownership Size 

Nbr 

of 

Orgs 

Cell 

Response 

Goal 

AMI 

Survey 

Section 

Response 

Rate Goal 

AMI 

Response 

Rate 

Municipal Large 17 14 12 85% 71%

 Medium 18 14 13 80% 72%

 Small 58 47 42 82% 72%

 

Wholesaler or 

G&T 6 5 4 80% 67%

 XMultiRegion 0% 

Municipal Total 99 81 71 82% 72%

Cooperative Large 19 18 17 95% 89%

 Medium 20 16 15 80% 75%

 Small 18 14 12 80% 67%

 

Wholesaler or 

G&T 59 47 40 80% 68%

 XMultiRegion 

Cooperative Total 116 96 84 82% 72%

Investor Owned Large 109 98 103 90% 94%

 Medium 18 16 15 90% 83%

 Small 59 53 55 90% 93%

 

Wholesaler or 

G&T 33 30 30 90% 91%

Investor Owned 

Total 219 197 203 90% 93%

Power Marketer Large 10 6 6 60% 60%

 Medium 5 5 2 100% 40%

 Small 42 25 19 60% 45%

 

Wholesaler or 

G&T 49 29 20 60% 41%

 XMultiRegion 59 35 33 60% 56%

Power Marketer 

Total 165 101 80 61% 48%

Political 

Subdivision Large 7 7 6 100% 86%

 Medium 4 4 2 100% 50%

 Small 3 2 0 53% 0%

 

Wholesaler or 

G&T 25 20 15 80% 60%

Political 

Subdivision Total 39 33 23 84% 59%
Appendix F: The FERC Survey 

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F-12 

Ownership Size 

Nbr 

of 

Orgs 

Cell 

Response 

Goal 

AMI 

Survey 

Section 

Response 

Rate Goal 

AMI 

Response 

Rate 

Municipal 

Marketing 

Authority 

Wholesaler or 

G&T 19 15 11 80% 58%

Municipal 

Marketing 

Authority Total 19 15 11 80% 58% 58%

CSP Small 68 54 19 80% 28%

CSP Total 68 54 19 80% 28%

State Large 2 2 2 100% 100%

 Medium 1 1 1 100% 100%

 Small 6 6 6 95% 100%

 

Wholesaler or 

G&T 12 12 9 100% 75%

State Total 21 21 18 99% 86%

Federal Small 6 6 4 100% 67%

 

Wholesaler or 

G&T 3 3 2 100% 67%

Federal Total 9 9 6 100% 67%

RTOs/ISOs Small 7 6 6 80% 86%

RTOs/ISOs Total 7 6 6 80% 86%

Grand Total 762 612 521 80% 68% 

Source: FERC Survey 

Working with the Data 

By analyzing entities that responded to each survey, 125 entities were identified to have responded to the 

2004 EIA-861 survey, but not to the FERC Survey. In order to address the effect of this non-response, 

the demand response potential information provided by these 125 entities on their EIA Form 861 for the 

year 2004 was utilized to develop an estimate of the annual demand response resource contribution.9

Second, a number of respondents only provided information on a sub-set of the DR questions in the 

FERC Survey. These partial responses are particularly crucial in cases where respondents did not fill out 

the Potential Peak Reduction (PPR) and/or Annual Peak Reduction (APR) fields, thus omitting any 

estimate of existing demand response resource potential or actual performance in 2005. For example, a 

number of entities included only the number of customers enrolled in demand response programs or timebased tariffs and did not provide information on PPR. By comparing survey results for the EIA and 

FERC Survey, entities with about 3,500 MW of PPR (as reported in EIA-861 survey) reported only 

demand response program information on customer enrollment. This problem of partial response was 

particularly common for industrial customers enrolled in either time-of-use or real-time pricing tariffs. 

 9

 This assumes that all the demand response programs/tariffs included in the EIA-861 survey in 2004 were continued 

without any changes in enrollment in 2005. Commission staff acknowledges that it is possible that a few entities may have 

discontinued the demand response programs/tariffs offered in 2004 by the time this report was complete. 
Appendix F: The FERC Survey 

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F-13

To address this missing data issue, PPR values provided by an entity from the EIA Form 861 database 

were used to estimate resource contribution in cases where that entity did not report PPR values for a 

particular customer class in their FERC Survey response.10

Another notable data issue that Commission staff and Utilipoint addressed was the potential for overreporting and the double-counting of PPR and enrolled DR load. On the matter of over-reporting, a 

number of entities reported in their response to the FERC Survey the same PPR values for commercial 

and industrial customers enrolled in a demand response program or time-based tariff. In these cases, 

FERC Survey respondents may have erroneously entered the total demand response resource for each 

program in both customer classes instead of splitting it appropriately. Based on the comments provided 

by FERC Survey respondents, about 200 MW of PPR may have been counted twice for commercial and 

industrial customers.

On the matter of double-counting, the possibility of utilities that reported PPR values for customers 

enrolled in DR programs that were offered (and also reported) by wholesale market entities like RTOs 

and ISOs may have resulted in “double-counted” DR resources in the raw data. Specifically, a number of 

entities appear to have provided data about DR resources that were essentially a part of the DR programs 

operated by their respective RTOs or ISOs. In cases where utilities specifically indicated that a DR 

program or tariff was linked to an RTO/ISO DR program, the PPR values of the respondent were adjusted 

to avoid double-counting. Data quality checks were also performed on all utility responses in those 

regions with ISOs and RTOs, which involved comparisons of information reported in the FERC Survey 

by ISO/RTOs on their DR programs with utility responses to the FERC Survey. Through this process, 

3,222 MW of PPR is estimated to have been double-counted between utility and RTO/ISO DR programs. 

In developing an estimate of annual DR resource contribution, this “double-counting” resulted in demand 

response potential values being adjusted downward. 

A final notable issue that is always present in surveys is data quality. A number of data quality checks 

were developed to assess reasonableness of survey responses on demand response resource potential. For 

example, a number of respondents did not notice that data about PPR, APR, and maximum demand of 

enrolled customers was requested in terms of megawatts and provided data in kilowatts.11

 10 Entities report PPR values by customer class on the EIA Form 861; hence, FERC aggregated survey responses by 

each entity to the customer class level in addressing missing data values for PPR (i.e., partial non-response). 

11 For cases where an entity’s PPR value looked suspiciously high (e.g. because it may have been reported in kW, not 

MW), FERC compared the demand response resource estimates for an entity with their annual peak demand as reported in the 

EIA-861 survey. For example, an entity with annual peak demand of 25 MW cannot report a demand response resource of 1,000 

MW. Obviously, in this case, the demand response resource was reported in terms of kW instead of MW; and PPR values were 

adjusted accordingly. 
Appendix F: The FERC Survey 

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F-14 
Appendix G: FERC Survey Respondents 

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G-1

Appendix G: FERC Survey Respondents* 

Municipally Owned Utilities (986 Entities) 

Adrian Public Utilities Comm (MN) 

Aitkin Public Utilities Comm (MN) 

Albany Wtr Gas&Light Comm (GA) 

Algoma Utility Comm (WI) 

Anchorage Municipal Light and Power (AK) 

Atlantic Municipal Utilities (IA) 

Austin Energy (TX) 

Bancroft Municipal Utilities (IA) 

Barton Village, Inc (VT) 

Beaver City Corporation (UT) 

Town of Benson (NC) 

Bloomer Electric & Water Co (WI) 

Board of Water Elec & Comm (IA) 

Borough of Blakely (PA) 

Borough of Butler (NJ) 

Borough of Catawissa (PA) 

Borough of Chambersburg (PA) 

Borough of Duncannon (PA) 

Borough of Ellwood City (PA) 

Borough of Goldsboro (PA) 

Borough of Grove City (PA) 

Borough of Hatfield (PA) 

Borough of Lewisberry (PA) 

Borough of Milltown (NJ) 

Borough of New Wilmington (PA) 

Borough of Olyphant (PA) 

Borough of Pemberton (NJ) 

Borough of Perkasie (PA) 

Borough of Royalton (PA) 

Borough of Smethport (PA) 

Borough of St Clair (PA) 

Borough of Wampum (PA) 

Borough of Watsontown (PA) 

Borough of Zelienople (PA) 

Bozrah Light & Power Co (CT) 

Brainerd Public Utilities (MN) 

Bremen Elec Light & Power Co (IN) 

Bristol Virginia Utilities (VA) 

Brodhead Water & Light Comm (WI) 

Brownsville Pub Utilities Board (TX) 

Cairo Public Utility Company (IL) 

Canton Municipal Utilities (MS) 

Carrollton Board of Public Wks (MO) 

Cascade Municipal Utilities (IA) 

Cedar Falls Utilities (IA) 

Cedarburg Light & Wtr Comm (WI) 

Chillicothe Municipal Utils (MO) 

City & Cnty of San Francisco (CA) 

City of Abbeville (LA) 

City of Abbeville (SC) 

City of Acworth (GA) 

City of Adel (GA) 

City of Alameda (CA) 

City of Albany (MO) 

City of Albion (ID) 

City of Alexander City (AL) 

City of Alexandria (MN) 

City of Algona (IA) 

City of Alpha (MN) 

City of Alta (IA) 

City of Alta Vista (IA) 

City of Altamont (KS) 

City of Altamont (IL) 

City of Altus (OK) 

City of Ames (IA) 

City of Anaheim (CA) 

City of Anderson (IN) 

City of Anita (IA) 

City of Ansley (NE) 

City of Anthony (KS) 

City of Arcadia (WI) 

City of Arcanum (OH) 

City of Argyle (WI) 

City of Arlington (SD) 

City of Ashland (KS) 

City of Attica (KS) 

City of Auburn (IA) 

City of Augusta (KS) 

City of Aurora (SD) 

City of Axtell (KS) 

City of Aztec (NM) 

City of Azusa (CA) 

City of Baldwin City (KS) 

City of Bangor (WI) 

City of Bardwell (KY) 

City of Barnesville (MN) 

City of Barron (WI) 

City of Bastrop (TX) 

City of Battle Creek (NE) 

City of Baudette (MN) 

City of Bay City (MI) 

City of Bayard (NE) 

City of Beatrice (NE) 

City of Bedford (VA) 

City of Belleville (KS) 

city of Bellville (TX) 

City of Beloit (KS) 

City of Benkelman (NE) 

City of Benton (AR) 

City of Bentonville (AR) 

City of Berea Municipal Utilities (KY) 

City of Beresford (SD) 

City of Bethany (MO) 

City of Big Stone City (SD) 

City of Biggs (CA) 

City of Black River Falls (WI) 

City of Blackwell (OK) 

City of Blaine (WA) 

City of Blanding (UT) 

City of Blooming Prairie (MN) 

City of Blue Earth (MN) 

City of Blue Hill (NE) 

City of Bluffton (IN) 

City of Bonners Ferry (ID) 

City of Boscobel (WI) 

City of Bountiful (UT) 

City of Bowie (TX) 

City of Bowling Green (OH) 

City of Brady (TX) 

City of Breese (IL) 

City of Bristol (TN) 

City of Broken Bow (NE) 

City of Bronson (KS) 

City of Brookings (SD) 

City of Brooklyn (IA) 

City of Brownfield (TX) 

City of Brownton (MN) 

City of Brundidge (AL) 

City of Bryan (TX) 

City of Buffalo (MN) 

City of Buffalo (IA) 

City of Buford (GA) 

City of Burbank (CA) 

City of Burley (ID) 

City of Burlington (KS) 

City of Burlington (CO) 

City of Burwell (NE) 

City of Bushnell (IL) 

City of Bushnell (FL) 

City of Butler (MO) 

City of Caldwell (TX) 

City of Calhoun (GA) 

City of California (MO) 

City of Camden (SC) 
Appendix G: FERC Survey Respondents 

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G-2 

Municipally Owned Utilities (Cont’d) 

City of Cameron (MO) 

City of Campbell (MO) 

City of Carlyle (IL) 

City of Carmi (IL) 

City of Cartersville (GA) 

City of Carthage (MO) 

City of Casey (IL) 

City of Castroville (TX) 

City of Cavalier (ND) 

City of Celina (OH) 

City of Center (CO) 

City of Central City (NE) 

City of Centralia (MO) 

City of Centralia (WA) 

City of Chanute (KS) 

City of Chappell (NE) 

City of Charlevoix (MI) 

City of Chattahoochee (FL) 

City of Chefornak (AK) 

City of Cheney (WA) 

City of Chewelah (WA) 

City of Chicopee (MA) 

City of Chignik (AK) 

City of Claremore (OK) 

City of Clewiston (FL) 

City of Clintonville (WI) 

City of Coggon (IA) 

City of Colby (KS) 

City of Coleman (TX) 

City of College Station (TX) 

City of Collins (MS) 

City of Colorado Springs (CO) 

City of Columbia (MO) 

City of Columbia City (IN) 

City of Columbus (WI) 

City of Commerce (GA) 

City of Cornelius (NC) 

City of Cornell (WI) 

City of Corning (IA) 

City of Covington (IN) 

City of Crane (MO) 

City of Croswell (MI) 

City of Crystal Falls (MI) 

City of Cuba City (WI) 

City of Cuero (TX) 

City of Cumberland (WI) 

City of Curtis (NE) 

City of Cushing (OK) 

City of Cuyahoga Falls (OH) 

City of Danville (VA) 

City of David City (NE) 

City of Dayton (IA) 

City of Deaver (WY) 

City of Declo (ID) 

City of Denison (IA) 

City of Detroit (MI) 

City of Detroit Lakes (MN) 

City of Dighton (KS) 

City of Doerun (GA) 

City of Dothan (AL) 

City of Dover (DE) 

City of Dover (OH) 

City of Duncan (OK) 

City of Dunnell (MN) 

City of Dysart (IA) 

City of Eagle River (WI) 

City of Earlville (IA) 

City of Easton (MO) 

City of Eaton Rapids (MI) 

City of Edmond (OK) 

City of Eitzen (MN) 

City of El Dorado Springs (MO) 

City of Elba (AL) 

City of Electra (TX) 

City of Elfin Cove (AK) 

City of Elizabethton (TN) 

City of Elk Point (SD) 

City of Elk River (MN) 

City of Elkhorn (WI) 

City of Ellaville (GA) 

City of Ellensburg (WA) 

City of Ellsworth (IA) 

City of Elroy (WI) 

City of Elsmore (KS) 

City of Elwood (KS) 

City of Emerson (NE) 

City of Enterprise (UT) 

City of Enterprise (KS) 

City of Erie (KS) 

City of Escanaba (MI) 

City of Escondido (CA) 

City of Estelline (SD) 

City of Estherville (IA) 

City of Eudora (KS) 

City of Eugene (OR) 

City of Fairbury (NE) 

City of Fairfax (MN) 

City of Fairhope (AL) 

City of Faith (SD) 

City of Falls City (NE) 

City of Falmouth (KY) 

City of Farmer City (IL) 

City of Farmersville (TX) 

City of Farmington (NM) 

City of Farnhamville (IA) 

City of Fayette (MO) 

City of Fennimore (WI) 

City of Flandreau (SD) 

City of Floresville (TX) 

City of Floydada (TX) 

City of Fonda (IA) 

City of Forest Grove (OR) 

City of Fort Collins (CO) 

City of Fountain (CO) 

City of Franklin (VA) 

City of Fredericktown (MO) 

City of Fredonia (AZ) 

City of Gaffney (SC) 

City of Galion (OH) 

City of Gallup (NM) 

City of Galva (KS) 

City of Garden City (KS) 

City of Gardner (KS) 

City of Garnett (KS) 

City of Garrett (IN) 

City of Gas City (IN) 

City of Gastonia (NC) 

City of Geary (OK) 

City of Geneseo (IL) 

City of Georgetown (TX) 

City of Gering (NE) 

City of Giddings (TX) 

City of Gillette (WY) 

City of Gilman City (MO) 

City of Girard (KS) 

City of Gladstone (MI) 

City of Glasco (KS) 

City of Glen Elder (KS) 

City of Glenwood Springs (CO) 

City of Glidden (IA) 

City of Goldsmith (TX) 

City of Goldthwaite (TX) 

City of Goodland (KS) 

City of Gothenburg (NE) 

City of Grafton (ND) 

City of Granbury (TX) 

City of Grand Haven (MI) 

City of Grand Island (NE) 

City of Grand Junction (IA) 

City of Grand Marais (MN) 

City of Granite (OK) 

City of Granite Falls (MN) 

City of Green Cove Springs (FL) 
Appendix G: FERC Survey Respondents 

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Municipally Owned Utilities (Cont’d) 

City of Greendale (IN) 

City of Greenfield (IA) 

City of Greensburg (KS) 

City of Groton (SD) 

City of Guttenberg (IA) 

City of Hallettsville (TX) 

City of Halstad (MN) 

City of Hannibal (MO) 

City of Harrisonburg (VA) 

City of Hart Hydro (MI) 

City of Hartley (IA) 

City of Hastings (NE) 

City of Haven (KS) 

City of Hawarden (IA) 

City of Hebron (NE) 

City of Hecla (SD) 

City of Helper (UT) 

City of Hempstead (TX) 

City of Henning (MN) 

City of Hermann (MO) 

City of Hermiston (OR) 

City of Heyburn (ID) 

City of Hickman (NE) 

City of Higginsville (MO) 

City of Highland (IL) 

City of Highlands (NC) 

City of Hill City (KS) 

City of Hinton (IA) 

City of Holland (MI) 

City of Holton (KS) 

City of Holyoke (MA) 

City of Holyrood (KS) 

City of Homestead (FL) 

City of Hominy (OK) 

City of Hope (AR) 

City of Hopkinton (IA) 

City of Horton (KS) 

City of Houston (MO) 

City of Howard (SD) 

City of Hubbard (OH) 

City of Hudson (OH) 

City of Hudson (IA) 

City of Hugoton (KS) 

City of Hunnewell (MO) 

City of Imperial (NE) 

City of Independence (MO) 

City of Independence (IA) 

City of Indianola (NE) 

City of Iola (KS) 

City of Jackson (MO) 

City of Jackson (MN) 

City of Jackson (GA) 

City of Jackson (TN) 

City of Jacksonville Beach (FL) 

City of Jasper (IN) 

City of Jetmore (KS) 

City of Jewett City (CT) 

City of Jonesville (LA) 

City of Kansas City (KS) 

City of Kaukauna (WI) 

City of Kiel (WI) 

City of Kimball (NE) 

City of Kimballton (IA) 

City of King Cove (AK) 

City of Kingman (KS) 

City of Kings Mountain (NC) 

City of Kinston (NC) 

City of Kirkwood (MO) 

City of Kotlik (AK) 

City of La Crosse (KS) 

City of La Grange (GA) 

City of La Junta (CO) 

City of Lafayette (AL) 

City of Lafayette (LA) 

City of LaFayette (GA) 

City of Lake Crystal (MN) 

City of Lake Mills (IA) 

City of Lake View (IA) 

City of Lake Worth (FL) 

City of Lakeland (FL) 

City of Lakin (KS) 

City of Lamar (MO) 

City of Lamar (CO) 

City of Lamoni (IA) 

City of Lampasas (TX) 

City of Lanett (AL) 

City of Lansing (MI) 

City of Las Animas (CO) 

City of Laurel (NE) 

City of Laurens (IA) 

City of Laurens (SC) 

City of Laurinburg (NC) 

City of Lawrenceville (GA) 

City of Lebanon (MO) 

City of Lebanon (IN) 

City of Lebanon (OH) 

City of Leesburg (FL) 

City of Lewes (DE) 

City of Lexington (OK) 

City of Lexington (NE) 

City of Lexington (TX) 

City of Liberal (MO) 

City of Lincoln Center (KS) 

City of Lindsborg (KS) 

City of Linton (IN) 

City of Livingston (TX) 

City of Lodi (CA) 

City of Lodi (WI) 

City of Logan (UT) 

City of Logansport (IN) 

City of Lompoc (CA) 

City of Long Grove (IA) 

City of Los Angeles (CA) 

City of Lowell (MI) 

City of Lubbock (TX) 

City of Luverne (MN) 

City of Mabel (MN) 

City of Macon (MO) 

City of Maddock (ND) 

City of Madelia (MN) 

City of Madison (NE) 

City of Madison (SD) 

City of Malden (MO) 

City of Mangum (OK) 

City of Manitou (OK) 

City of Mankato (KS) 

City of Mansfield (MO) 

City of Mansfield (GA) 

City of Manti (UT) 

City of Maquoketa (IA) 

City of Marietta (GA) 

City of Marion (KS) 

City of Marshall (MO) 

City of Marshall (IL) 

City of Marshall (MN) 

City of Marshall (MI) 

City of Martinsville (VA) 

City of Mascoutah (IL) 

City of Mason (TX) 

City of McCleary (WA) 

City of McGregor (IA) 

City of McLaughlin (SD) 

City of McLeansboro (IL) 

City of McPherson (KS) 

City of Medford (WI) 

City of Memphis (MO) 

City of Menasha (WI) 

City of Mendon (OH) 

City of Mesa (AZ) 

City of Metropolis (IL) 

City of Milford (DE) 

City of Milford (IA) 

City of Milton (WA) 
Appendix G: FERC Survey Respondents 

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G-4 

Municipally Owned Utilities (Cont’d)

City of Milton-Freewater (OR) 

City of Minden (LA) 

City of Mishawaka (IN) 

City of Mitchell (NE) 

City of Monroe (UT) 

City of Monroe (NC) 

City of Monroe City (MO) 

City of Montezuma (IA) 

City of Montezuma (KS) 

City of Moorhead (MN) 

City of Mora (MN) 

City of Moran (KS) 

City of Morgan City (UT) 

City of Morrill (KS) 

City of Mount Vernon (MO) 

City of Mountain Iron (MN) 

City of Mountain Lake (MN) 

City of Mountain View (MO) 

City of Mt Pleasant (IA) 

City of Mulberry (KS) 

City of Mulvane (KS) 

City of Murray (UT) 

City of Muscoda (WI) 

City of Muscotah (KS) 

City of Naperville (IL) 

City of Nebraska City (NE) 

City of Needles (CA) 

City of Neodesha (KS) 

City of Neola (IA) 

City of New Braunfels (TX) 

City of New Hampton (IA) 

City of New Holstein (WI) 

City of New Lisbon (WI) 

City of New Martinsville (WV) 

City of New Richmond (WI) 

City of New Smyrna Beach (FL) 

City of Newberry (FL) 

City of Newburg (MO) 

City of Newfolden (MN) 

City of Newkirk (OK) 

City of Newton (IL) 

City of Nielsville (MN) 

City of Niles (MI) 

City of Nixa (MO) 

City of North Little Rock (AR) 

City of North St Paul (MN) 

City of Northwood (ND) 

City of Norway (MI) 

City of Norwood (MA) 

City of Oakley (KS) 

City of Oberlin (KS) 

City of Odessa (MO) 

City of Ogden (IA) 

City of Oglesby (IL) 

City of Orange City (IA) 

City of Orangeburg (SC) 

City of Orrville (OH) 

City of Ortonville (MN) 

City of Osage (IA) 

City of Osborne (KS) 

City of Ouzinkie (AK) 

City of Owatonna (MN) 

City of Owensboro (KY) 

City of Oxford (KS) 

City of Painesville (OH) 

City of Palmetto (GA) 

City of Palmyra (MO) 

City of Palo Alto (CA) 

City of Paris (MO) 

City of Parker (SD) 

City of Paullina (IA) 

City of Pawhuska (OK) 

City of Peabody (MA) 

City of Pella (IA) 

City of Perry (MO) 

City of Perry (OK) 

City of Petoskey (MI) 

City of Piggott (AR) 

City of Piqua (OH) 

City of Plankinton (SD) 

City of Plattsburgh (NY) 

City of Plymouth (WI) 

City of Pocahontas (IA) 

City of Pomona (KS) 

City of Poplar Bluff (MO) 

City of Port Angeles (WA) 

City of Portland (MI) 

City of Powell (WY) 

City of Pratt (KS) 

City of Preston (IA) 

City of Princeton (IL) 

City of Pryor (OK) 

City of Radford (VA) 

City of Randall (MN) 

City of Rayne (LA) 

City of Red Bud (IL) 

City of Red Cloud (NE) 

City of Redding (CA) 

City of Remsen (IA) 

City of Rensselaer (IN) 

City of Renwick (IA) 

City of Rich Hill (MO) 

City of Richland (WA) 

City of Richland (MO) 

City of Richland Center (WI) 

City of Richmond (IN) 

City of Rising Sun (IN) 

City of River Falls (WI) 

City of Riverside (CA) 

City of Robertsdale (AL) 

City of Robinson (KS) 

City of Rockport (MO) 

City of Rocky Mount (NC) 

City of Rolla (MO) 

City of Roodhouse (IL) 

City of Roseville (CA) 

City of Rushmore (MN) 

City of Sabetha (KS) 

City of Saint Peter (MN) 

City of Salamanca (NY) 

City of Salem (VA) 

City of Salisbury (MO) 

City of Sallisaw (OK) 

City of San Antonio (TX) 

City of San Saba (TX) 

City of Sanborn (IA) 

City of Sandersville (GA) 

City of Sargent (NE) 

City of Savonburg (KS) 

City of Schuyler (NE) 

City of Scribner (NE) 

City of Seaford (DE) 

City of Seattle (WA) 

City of Seguin (TX) 

City of Seneca (KS) 

City of Sergeant Bluff (IA) 

City of Seward (NE) 

City of Seymour (TX) 

City of Shasta Lake (CA) 

City of Sheboygan Falls (WI) 

City of Shelby (OH) 

City of Shelly (MN) 

City of Shiner (TX) 

City of Shullsburg (WI) 

City of Sikeston (MO) 

City of Sioux Center (IA) 

City of Sioux Falls (SD) 

City of Slater (MO) 

City of Snyder (NE) 

City of Soda Springs (ID) 

City of South Norwalk (CT) 

City of Spencer (NE) 

City of Springfield (IL) 

City of Springfield (OR) 

City of Springville (UT) 

City of St Clairsville (OH) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

G-5

Municipally Owned Utilities (Cont’d) 

City of St George (UT) 

City of St James (MN) 

City of St James (MO) 

City of St John (KS) 

City of St Martinville (LA) 

City of St Marys (KS) 

City of St Marys (OH) 

City of St Paul (NE) 

City of Stanhope (IA) 

City of Stanton (IA) 

City of Staples (MN) 

City of Steelville (MO) 

City of Stephen (MN) 

City of Stephenson (MI) 

City of Stockton (KS) 

City of Story City (IA) 

City of Stoughton (WI) 

City of Strawberry Point (IA) 

City of Stromsburg (NE) 

City of Stroud (OK) 

City of Stuart (NE) 

City of Stuart (IA) 

City of Sturgeon Bay (WI) 

City of Sullivan (IL) 

City of Sutton (NE) 

City of Syracuse (NE) 

City of Tallahassee (FL) 

City of Taunton (MA) 

City of Tecumseh (NE) 

City of Thayer (MO) 

City of Thief River Falls (MN) 

City of Thorntown (IN) 

City of Tipton (IA) 

City of Toronto (KS) 

City of Traer (IA) 

City of Trinidad (CO) 

City of Truth or Consequences (NM) 

City of Tuskegee (AL) 

City of Tyler (MN) 

City of Tyndall (SD) 

City of Unalaska (AK) 

City of Union (SC) 

City of Unionville (MO) 

City of Vandalia (MO) 

City of Vermillion (SD) 

City of Vernon (CA) 

City of Vero Beach (FL) 

City of Vineland (NJ) 

City of Vinton (IA) 

City of Volga (SD) 

City of Wadena (MN) 

City of Wamego (KS) 

City of Waseca (MN) 

City of Washington (GA) 

City of Washington (NC) 

City of Washington (KS) 

City of Waterloo (IL) 

City of Watertown (NY) 

City of Wathena (KS) 

City of Watonga (OK) 

City of Waynetown (IN) 

City of Webster City (IA) 

City of Weimar (TX) 

City of Weiser (ID) 

City of Wellington (KS) 

City of Wells (MN) 

City of Wessington Springs (SD) 

City of West Bend (IA) 

City of West Liberty (IA) 

City of West Memphis (AR) 

City of West Point (NE) 

City of West Point (GA) 

City of Westby (WI) 

City of Westerville (OH) 

City of Whigham (GA) 

City of White (SD) 

City of Williamsport (IN) 

City of Williston (FL) 

City of Winfield (KS) 

City of Winthrop (MN) 

City of Wisner (NE) 

City of Wood River (NE) 

City of Worthington (MN) 

City of Wray (CO) 

City of Wynnewood (OK) 

City of Zeeland (MI) 

City Water and Light Plant (AR) 

Clarksdale Public Utilities (MS) 

Clarksville Light & Water Co (AR) 

Clinton Combined Utility Sys (SC) 

Coldwater Board of Public Util (MI) 

Conway Corporation (AR) 

Corbin City Utilities Comm (KY) 

Cozad Board of Public Works (NE) 

Crawfordsville Elec, Lgt & Pwr (IN) 

Delano Municipal Utilities (MN) 

East Bay Municipal Util Dist (CA) 

Easton Utilities Comm (MD) 

Fairmont Public Utilities Comm (MN) 

Fairview City Corporation (UT) 

Fillmore City Corporation (UT) 

Fitzgerald Wtr Lgt&Bond Com (GA) 

Flora Utilities (IN) 

Florence Utility Comm (WI) 

Foley Board of Utilities (AL) 

Fort Pierce Utilities Auth (FL) 

Glencoe Light & Power Comm (MN) 

Grafton Electric (IA) 

Grand Rapids Pub Util Comm (MN) 

Greenwood Utilities Comm (MS) 

Groton Dept of Utilities (CT) 

Grundy Center Mun Light & Power (IA) 

Hartford Electric (WI) 

Havana Power & Light Company (FL) 

Hawley Public Utilities Comm (MN) 

Heber Light & Power Company (UT) 

Henderson City Utility Comm (KY) 

Hillsdale Board of Public Wks (MI) 

Hooversville Boro Elec Lgt Co (PA) 

Hurricane Power Committee (UT) 

Hustisford Utilities (WI) 

Hutchinson Utilities Comm (MN) 

Indianola Municipal Utilities (IA) 

Jacksonville Electric Authority (FL) 

Jefferson Utilities (WI) 

Juneau Utility Comm (WI) 

Kaysville City Corporation (UT) 

Keewatin Public Utilities (MN) 

Kenyon Municipal Utilities (MN) 

Ketchikan Public Utilities (AK) 

Kissimmee Utility Authority (FL) 

La Farge Municipal Electric Co (WI) 

La Porte City Utilities (IA) 

Lake Mills Light & Water (WI) 

Lake Placid Village, Inc (NY) 

Lawrenceburg Municipal Utils (IN) 

Lehi City Corporation (UT) 

Lincoln Electric System (NE) 

Litchfield Public Utilities (MN) 

Manitowoc Public Utilities (WI) 

Melrose Public Utilities (MN) 

Mohawk Municipal Comm (NY) 

Monroe Water, Light & Gas Comm (GA) 

Mont Alto Borough (PA) 

Moose Lake Water & Light Comm (MN) 

Nashville Electric Service (TN) 

Nephi City Corporation (UT) 

New Castle Municipal Serv Comm (DE) 

New London Electric&Water Util (WI) 

New Prague Utilities Comm (MN) 

Newnan Wtr, Sewer & Light Comm (GA) 

Nome Joint Utility Systems (AK) 

North Branch Water & Light Comm (MN) 

North Slope Borough Power & Light (AK) 

Norwalk Third Taxing District (CT) 

Oconomowoc Utilities (WI) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

G-6 

Municipally Owned Utilities (Cont’d) 

Oconto Falls Water & Light Comm (WI) 

Orlando Utilities Comm (FL) 

Page Electric Utility (AZ) 

Paragould Light & Water Comm (AR) 

Parowan City Corporation (UT) 

Payson City Corporation (UT) 

Philippi Municipal Electric (WV) 

Precinct of Woodsville (NH) 

Princeton Public Utils Comm (MN) 

Proctor Public Utilities Comm (MN) 

Pub Wrks Comm-Fayetteville (NC) 

PUD No 1 of Asotin County (WA) 

Raton Public Service Com (NM) 

Redwood Falls Pub Util Comm (MN) 

Reedsburg Utility Comm (WI) 

Rice Lake Utilities (WI) 

Rochester Public Utilities (MN) 

Rock Rapids Municipal Utility (IA) 

Salem City Corporation (UT) 

Shawano Municipal Utilities (WI) 

Slinger Utilities (WI) 

South Vienna Corporation (OH) 

Spanish Fork City Corporation (UT) 

Spring City Corporation (UT) 

Spring Valley Pub Utils Comm (MN) 

Stillwater Utilities Authority (OK) 

Sun Prairie Wtr & Light Comm (WI) 

Tatitlek Electric Utility (AK) 

Terrebonne Parish Consol Gv't (LA) 

Texas Municipal Power Agency (TX) 

Tipton Municipal Electric Util (IN) 

Town of Advance (IN) 

Town of Apex (NC) 

Town of Argos (IN) 

Town of Ashburnham (MA) 

Town of Ashland (NH) 

Town of Avilla (IN) 

Town of Bainbridge (IN) 

Town of Basin (WY) 

Town of Belhaven (MD) 

Town of Belmont (MA) 

Town of Black Creek (NC) 

Town of Bostic (NC) 

Town of Boyce (LA) 

Town of Braintree (MA) 

Town of Braman (OK) 

Town of Brooklyn (IN) 

Town of Brookston (IN) 

Town of Centerville (IN) 

Town of Chalmers (IN) 

Town of Chester (MA) 

Town of Coatesville (IN) 

Town of Concord (MA) 

Town of Culpeper (VA) 

Town of Enfield (NC) 

Town of Etna Green (IN) 

Town of Ferdinand (IN) 

Town of Fleming (CO) 

Town of Forest City (NC) 

Town of Frederick (CO) 

Town of Front Royal (VA) 

Town of Groveland (MA) 

Town of Guernsey (WY) 

Town of Gueydan (LA) 

Town of Hardwick (VT) 

Town of Haxtun (CO) 

Town of High Point (NC) 

Town of Hudson (MA) 

Town of Hull (MA) 

Town of Huntersville (NC) 

Town of Jamestown (IN) 

Town of Knightstown (IN) 

Town of Laverne (OK) 

Town of Littleton (NH) 

Town of Louisburg (NC) 

Town of Lusk (WY) 

Town of Lyons (CO) 

Town of Madison (ME) 

Town of Maiden (NC) 

Town of Mannford (OK) 

Town of Mansfield (MA) 

Town of Massena (NY) 

Town of McCormick (SC) 

Town of Merrimac (MA) 

Town of Middleborough (MA) 

Town of Middletown (IN) 

Town of Middletown (DE) 

Town of Montezuma (IN) 

Town of North Attleborough (MA) 

Town of Oak City (UT) 

Town of Oak Creek (CO) 

Town of Paragonah (UT) 

Town of Pendleton (IN) 

Town of Pinetops (NC) 

Town of Pineville (NC) 

Town of Reading (MA) 

Town of Readsboro (VT) 

Town of Rowley (MA) 

Town of Shrewsbury (MA) 

Town of Smyrna (DE) 

Town of South Hadley (MA) 

Town of South Whitley (IN) 

Town of Spiceland (IN) 

Town of Spiro (OK) 

Town of Sterling (MA) 

Town of Stowe (VT) 

Town of Straughn (IN) 

Town of Summerfield (KS) 

Town of Veedersburg (IN) 

Town of Wakefield (MA) 

Town of Wakefield (VA) 

Town of Walstonburg (NC) 

Town of Waynesville (NC) 

Town of Welsh (LA) 

Town of Winamac (IN) 

Town of Winnsboro (SC) 

Turlock Irrigation District (CA) 

Two Rivers Water & Light (WI) 

Van Buren Light & Power Dist (ME) 

Village of Andover (NY) 

Village of Angelica (NY) 

Village of Arcadia (OH) 

Village of Arnold (NE) 

Village of Baraga (MI) 

Village of Bartley (NE) 

Village of Belmont (WI) 

Village of Benton (WI) 

Village of Bergen (NY) 

Village of Bethany (IL) 

Village of Bethel (OH) 

Village of Black Earth (WI) 

Village of Boonville (NY) 

Village of Bradshaw (NE) 

Village of Brocton (NY) 

Village of Callaway (NE) 

Village of Carey (OH) 

Village of Castile (NY) 

Village of Chatham (IL) 

Village of Chelsea (MI) 

Village of Chester (NE) 

Village of Clinton (MI) 

Village of Davenport (NE) 

Village of Decatur (NE) 

Village of Deshler (OH) 

Village of Endicott (NY) 

Village of Endicott (NE) 

Village of Enosburg Falls (VT) 

Village of Fairport (NY) 

Village of Freeburg (IL) 

Village of Grafton (OH) 

Village of Greene (NY) 

Village of Greenup (IL) 

Village of Gresham (WI) 

Village of Hamilton (NY) 

Village of Hampton (NE) 

Village of Hazel Green (WI) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

G-7

Municipally Owned Utilities (Cont’d) 

Village of Hemingford (NE) 

Village of Hildreth (NE) 

Village of Holbrook (NE) 

Village of Holley (NY) 

Village of Hyde Park (VT) 

Village of Jacksonville (VT) 

Village of Johnson (VT) 

Village of Lakeview (OH) 

Village of L'Anse (MI) 

Village of Little Valley (NY) 

Village of Lodi (OH) 

Village of Ludlow (VT) 

Village of Lyman (NE) 

Village of Lyndonville (VT) 

Village of Marshallville (OH) 

Village of Mayville (NY) 

Village of Mazomanie (WI) 

Village of Merrillan (WI) 

Village of Milan (OH) 

Village of Minster (OH) 

Village of Morrisville (VT) 

Village of Mt Horeb (WI) 

Village of New Glarus (WI) 

Village of Northfield (VT) 

Village of Orleans (VT) 

Village of Oxford (NE) 

Village of Pardeeville (WI) 

Village of Paw Paw (MI) 

Village of Pemberville (OH) 

Village of Philadelphia (NY) 

Village of Prairie Du Sac (WI) 

Village of Rantoul (IL) 

Village of Reynolds (NE) 

Village of Richmondville (NY) 

Village of Rockville Centre (NY) 

Village of Rouses Point (NY) 

Village of Sauk City (WI) 

Village of Sherburne (NY) 

Village of Shickley (NE) 

Village of Shiloh (OH) 

Village of Silver Springs (NY) 

Village of Skaneateles (NY) 

Village of Spencerport (NY) 

Village of Springville (NY) 

Village of Stratford (WI) 

Village of Swanton (VT) 

Village of Talmage (NE) 

Village of Tontogany (OH) 

Village of Trempealeau (WI) 

Village of Tupper Lake (NY) 

Village of Versailles (OH) 

Village of Walthill (NE) 

Village of Waunakee (WI) 

Village of Wauneta (NE) 

Village of Waynesfield (OH) 

Village of Wellsville (NY) 

Village of Yellow Springs (OH) 

Wagoner Public Works Authority (OK) 

Waterloo Light & Water Comm (WI) 

Watertown Municipal Utilities (SD) 

Waupun Utilities (WI) 

Waverly Municipal Elec Utility (IA) 

Weatherford Mun Utility System (TX) 

West Point Utility System (IA) 

Whitehall Electric Utility (WI) 

Williamstown Utility Comm (KY) 

Winner Municipal Utility (SD) 

Wonewoc Electric & Water Util (WI) 

Cooperative Utilities (537 Entities) 

A & N Electric Coop (VA) 

Adams Electric Coop (IL) 

Adams Electric Cooperative Inc (PA) 

Adams Rural Elec Coop, Inc (OH) 

Adams-Columbia Electric Coop (WI) 

Aiken Electric Coop Inc (SC) 

Alabama Electric Coop Inc (AL) 

Alfalfa Electric Coop, Inc (OK) 

Alger-Delta Coop Electric Assn (MI) 

Allamakee-Clayton El Coop, Inc (IA) 

Allegheny Electric Coop Inc (PA) 

Altamaha Elec Member Corp (GA) 

Amicalola Elec Member Corp (GA) 

Anoka Electric Coop (MN) 

Appalachian Electric Coop (TN) 

Arizona Electric Pwr Coop Inc (AZ) 

Ark Valley Elec Coop Assn, Inc (KS) 

Arkansas Electric Coop Corp (AR) 

Arkansas Valley E C Corp (AR) 

Arrowhead Electric Coop, Inc (MN) 

Ashley Chicot Elec Coop, Inc (AR) 

Associated Electric Coop, Inc (MO) 

Atchison-Holt Electric Coop (MO) 

Bailey County Elec Coop Assn (TX) 

Bartholomew Cnty Rural E M C (IN) 

Bartlett Electric Coop, Inc (TX) 

Basin Electric Power Coop (ND) 

Bayfield Electric Coop, Inc (WI) 

Beartooth Electric Coop, Inc (MT) 

Beauregard Electric Coop, Inc (LA) 

Bedford Rural Elec Coop, Inc (PA) 

Belfalls Electric Coop, Inc (TX) 

Beltrami Electric Coop, Inc (MN) 

Big Bend Electric Coop, Inc (WA) 

Big Country Electric Coop, Inc (TX) 

Big Flat Electric Coop Inc (MT) 

Big Horn Cnty Elec Coop, Inc (MT) 

Big Horn Rural Electric Co (WY) 

Big Rivers Electric Corp (KY) 

Big Sandy REC Corp (KY) 

Black Hills Electric Coop, Inc (SD) 

Black River Electric Coop, Inc (SC) 

Black Warrior Elec Mem Corp (AL) 

Blue Grass Energy Coop Corp (KY) 

Blue Ridge Electric Coop Inc (SC) 

Bluestem Electric Coop Inc (KS) 

Boone County Rural EMC (IN) 

Boone Electric Coop (MO) 

Bowie-Cass Electric Coop, Inc (TX) 

Brazos Electric Power Coop Inc (TX) 

Bridger Valley Elec Assn, Inc (WY) 

Broad River Electric Coop, Inc (SC) 

Brown County Rural Elec Assn (MN) 

Brown-Atchison E C A Inc (KS) 

Brunswick Electric Member Corp (NC) 

Buckeye Power, Inc (OH) 

Buckeye Rural Elec Coop, Inc (OH) 

Burke-Divide Electric Coop Inc (ND) 

Butler County Rural Elec Coop (IA) 

Butler Rural El Coop Assn, Inc (KS) 

Butler Rural Electric Coop Inc (OH) 

Butte Electric Coop, Inc (SD) 

C & L Electric Coop Corp (AR) 

Caddo Electric Coop, Inc (OK) 

Calhoun County Elec Coop Assn (IA) 

Callaway Electric Cooperative (MO) 

Cam Wal Electric Coop, Inc (SD) 

Canadian Valley Elec Coop, Inc (OK) 

Canoochee Electric Member Corp (GA) 

Cape Hatteras Elec Member Corp (NC) 

Capital Electric Coop, Inc (ND) 

Carbon Power & Light, Inc (WY) 

Carroll Electric Coop, Inc (OH) 

Carroll Electric Member Corp (GA) 

Carteret-Craven El Member Corp (NC) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

G-8 

Cooperative Utilities (Cont’d)

Cass County Electric Coop Inc (ND) 

Cass Electric Coop (IA) 

Central Alabama Electric Coop (AL) 

Central Electric Coop Inc (OR) 

Central Electric Coop, Inc (PA) 

Central Electric Coop, Inc (SD) 

Central Electric Mem Corp (NC) 

Central Electric Power Coop (MO) 

Central Electric Pwr Coop, Inc (SC) 

Central Florida Elec Coop, Inc (FL) 

Central Iowa Power Cooperative (IA) 

Central New Mexico EC, Inc (NM) 

Central Rural Elec Coop, Inc (OK) 

Central Valley Elec Coop, Inc (NM) 

Central Virginia Electric Coop (VA) 

Chariton Valley Elec Coop, Inc (IA) 

Charles Mix Electric Assn, Inc (SD) 

Cherryland Electric Coop Inc (MI) 

Chippewa Valley Electric Coop (WI) 

Choctawhatche Elec Coop, Inc (FL) 

Choptank Electric Coop, Inc (MD) 

Chugach Electric Assn Inc (AK) 

City of Salem (OR) 

Clark County Rural E M C (IN) 

Clark Energy Coop Inc (KY) 

Clarke Electric Coop Inc (IA) 

Claverack Rural Elec Coop Inc (PA) 

Clay County Elec Coop Corp (AR) 

Clay Electric Cooperative, Inc (FL) 

Clearwater Power Company (ID) 

Clearwater-Polk Elec Coop Inc (MN) 

Cloverland Electric Co-op (MI) 

Coahoma Electric Power Assn (MS) 

Coastal Electric Coop, Inc (SC) 

Coastal Electric Member Corp (GA) 

Cobb Electric Membership Corp (GA) 

Codington-Clark Elec Coop, Inc (SD) 

Coleman County E C, Inc (TX) 

Coles-Moultrie Electric Coop (IL) 

Colquitt Electric Mem Corp (GA) 

Columbia Basin Elec Coop., Inc (OR) 

Columbia Power Coop Assn Inc (OR) 

Columbus Electric Coop, Inc (NM) 

Comanche Cnty E C Assn (TX) 

Community Electric Coop (VA) 

Co-Mo Electric Coop Inc (MO) 

Concho Valley Elec Coop Inc (TX) 

Consolidated Electric Coop (MO) 

Consolidated Electric Coop Inc (OH) 

Consumers Energy (IA) 

Consumers Power, Inc (OR) 

Continental Divide El Coop Inc (NM) 

Cooke County Elec Coop Assn (TX) 

Cookson Hills Elec Coop, Inc (OK) 

Coop L&P Assn Lake Cnty (MN) 

Coosa Valley Electric Coop Inc (AL) 

Coos-Curry Electric Coop, Inc (OR) 

Copper Valley Elec Assn, Inc (AK) 

Cordova Electric Coop, Inc (AK) 

Corn Belt Energy Corporation (IL) 

Corn Belt Power Coop (IA) 

Coweta-Fayette El Mem Corp (GA) 

Craig-Botetourt Electric Coop (VA) 

Crow Wing Coop Pwr&Lght Co (MN) 

Cuivre River Electric Coop Inc (MO) 

Cumberland Valley Rural E C C (KY) 

Dairyland Power Coop (WI) 

Dakota Electric Association (MN) 

Dakota Energy Coop Inc (SD) 

Dakota Valley Elec Coop Inc (ND) 

Daviess Martin County R E M C (IN) 

Deaf Smith Electric Coop, Inc (TX) 

Decatur County Rural E M C (IN) 

Delaware Cnty Elec Coop Inc (NY) 

Delaware Electric Cooperative (DE) 

Denton County Elec Coop, Inc (TX) 

Deseret Gen & Tran Coop (UT) 

Diverse Power Incorporated (GA) 

Dixie Electric Coop (AL) 

Dixie Electric Power Assn (MS) 

Dixie Escalante R E A, Inc (UT) 

Douglas Electric Coop, Inc (SD) 

Douglas Electric Coop, Inc (OR) 

Dubois Rural Electric Coop Inc (IN) 

Duncan Valley Elec Coop, Inc (AZ) 

East Central OK Elec Coop Inc (OK) 

East Kentucky Power Coop, Inc (KY) 

East River Elec Pwr Coop, Inc (SD) 

East Texas Electric Coop, Inc (TX) 

East-Central Iowa REC (IA) 

Eastern Illinois Elec Coop (IL) 

Eastern Iowa Light & Pwr Coop (IA) 

Eau Claire Electric Coop (WI) 

Edisto Electric Coop, Inc (SC) 

Egyptian Electric Coop Assn (IL) 

Elmhurst Mutual Pwr&Light Co (WA) 

EnergyUnited EMC (NC) 

Excelsior Electric Mem Corp (GA) 

Fairfield Electric Coop, Inc (SC) 

Fannin County Electric Coop (TX) 

Farmers Electric Company, Ltd (ID) 

Farmers Electric Coop Corp (AR) 

Farmers Electric Coop, Inc (IA) 

Farmers Electric Coop, Inc (TX) 

Farmers' Electric Coop, Inc (NM) 

Farmers' Electric Coop, Inc (MO) 

Farmers Mutual Electric Co (IL) 

Farmers Rural Electric Coop Corp (KY) 

Federated Rural Electric Assn (MN) 

First Electric Coop Corp (AR) 

Flathead Electric Coop Inc (MT) 

Fleming-Mason Energy Coop Inc (KY) 

Flint Electric Membership Corp (GA) 

Flint Hills Rural E C A, Inc (KS) 

Florida Keys El Coop Assn, Inc (FL) 

Fort Belknap Electric Coop Inc (TX) 

Fox Islands Electric Coop, Inc (ME) 

Franklin Rural Electric Cooperative (IA) 

French Broad Elec Member Corp (NC) 

Frontier Power Company (OH) 

Fulton County Rural E M C (IN) 

Garkane Energy Coop, Inc (UT) 

Gascosage Electric Coop (MO) 

Georgia Transmission Corp (GA) 

Glidden Rural Electric Coop (IA) 

Golden Spread Elec Coop, Inc (TX) 

Golden Valley Elec Assn Inc (AK) 

Goldenwest Electric Coop, Inc (MT) 

Graham County Electric Coop Inc (AZ) 

Grand Electric Coop, Inc (SD) 

Grand Valley Rrl Pwr Line, Inc (CO) 

Grayson Rural Electric Coop Corp (KY) 

Great Lakes Energy Coop (MI) 

Great River Energy (MN) 

GreyStone Power Corporation (GA) 

Grundy County Rural Elec Coop (IA) 

Grundy Electric Coop, Inc (MO) 

Guernsey-Muskingum El Coop Inc (OH) 

Gunnison County Elec Assn. (CO) 

Guthrie County Rural E C A (IA) 

Habersham Electric Membership Corp (GA) 

Hamilton County Elec Coop Assn (TX) 

Hancock County Rural E M C (IN) 

Harkers Island El Member Corp (NC) 

Harrison County Rrl Elec Coop (IA) 

Hart Electric Member Corp (GA) 

Haywood Electric Member Corp (NC) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

G-9

Cooperative Utilities (Cont’d)

H-D Electric Coop Inc (SD) 

Heartland Power Coop (IA) 

Heartland Rural Elec Coop, Inc (KS) 

Henry County Rural E M C (IN) 

High Plains Power Inc (WY) 

High West Energy, Inc (WY) 

Highline Electric Assn (CO) 

HILCO Electric Coop, Inc. (TX) 

Hill County Electric Coop, Inc (MT) 

Holmes-Wayne Elec Coop Inc (OH) 

Hood River Electric Coop (OR) 

Hoosier Energy R E C, Inc (IN) 

Horry Electric Coop Inc (SC) 

Houston County Elec Coop Inc (TX) 

Howell-Oregon Elec Coop, Inc (MO) 

Humboldt County R E C (IA) 

Idaho Cnty L&P Coop Assn, Inc (ID) 

Illinois Rural Electric Coop (IL) 

Inland Power & Light Company (WA) 

Inter County Energy Coop Corp (KY) 

Intercounty Electric Coop Assn (MO) 

Intermountain Rural Elec Assn (CO) 

Iowa Lakes Electric Coop (IA) 

Irwin Electric Membership Corp (GA) 

Jackson County Rural E M C (IN) 

Jackson Electric Coop, Inc (WI) 

Jackson Electric Member Corp (GA) 

Jackson Energy Coop Corp (KY) 

Jackson Purchase Energy Corp (KY) 

Jasper County Rural E M C (IN) 

Jasper-Newton Elec Coop, Inc (TX) 

Jefferson Davis Elec Coop, Inc (LA) 

Jefferson Electric Mem Corp (GA) 

Jemez Mountains E C, Inc (NM) 

Johnson County Rural E M C (IN) 

Jump River Electric Coop Inc (WI) 

K C Electric Association (CO) 

KAMO Electric Coop Inc (OK) 

Kansas Electric Pwr Coop Inc (KS) 

Karnes Electric Coop Inc (TX) 

Kauai Island Utility Cooperative (HI) 

Kay Electric Coop (OK) 

KEM Electric Coop Inc (ND) 

Kenergy Corp (KY) 

Kiamichi Electric Coop, Inc (OK) 

Kingsbury Electric Coop, Inc (SD) 

Kiwash Electric Coop, Inc (OK) 

Kodiak Electric Assn Inc (AK) 

Kootenai Electric Coop Inc (ID) 

Kotzebue Electric Assn Inc (AK) 

L & O Power Co-operative (IA) 

La Plata Electric Assn, Inc (CO) 

Laclede Electric Coop, Inc (MO) 

LaCreek Electric Assn, Inc (SD) 

Lake Region Coop Elec Assn (MN) 

Lake Region Electric Assn, Inc (SD) 

Lakeview Light & Power (WA) 

Lamar County Elec Coop Assn (TX) 

Lamar Elec Membership Corp (GA) 

Lane Electric Coop Inc (OR) 

Lane-Scott Electric Coop, Inc (KS) 

Laurens Electric Coop, Inc (SC) 

Lea County Electric Coop, Inc (NM) 

Leavenworth-Jefferson E C, Inc (KS) 

Lee County Electric Coop, Inc (FL) 

Licking Rural Electric Inc (OH) 

Lighthouse Electric Coop, Inc (TX) 

Lincoln Electric Coop, Inc (MT) 

Linn County Rural E C A (IA) 

Little Ocmulgee El Mem Corp (GA) 

Lower Yellowstone R E A, Inc (MT) 

Lumbee River Elec Mem Corp (NC) 

Lynches River Elec Coop, Inc (SC) 

Lyon-Coffey Electric Coop, Inc (KS) 

Lyon-Lincoln Electric Coop Inc (MN) 

Macon Electric Coop (MO) 

Magic Valley Electric Coop Inc (TX) 

Magnolia Electric Power Assn (MS) 

Maquoketa Valley Rrl Elec Coop (IA) 

Marias River Electric Coop Inc (MT) 

Marlboro Electric Coop, Inc (SC) 

McCone Electric Coop Inc (MT) 

McDonough Power Coop (IL) 

McKenzie Electric Coop Inc (ND) 

McLean Electric Coop, Inc (ND) 

McLeod Cooperative Pwr Assn (MN) 

Meade County Rural E C C (KY) 

Mecklenburg Electric Coop, Inc (VA) 

Medina Electric Coop, Inc (TX) 

Menard Electric Coop (IL) 

Miami-Cass County Rural EMC (IN) 

Mid-Carolina Electric Coop Inc (SC) 

Middle Georgia El Mem Corp (GA) 

Middle Kuskokwim E C Inc (AK) 

Middle Tennessee E M C (TN) 

Midland Power Coop (IA) 

Mid-Ohio Energy Coop, Inc (OH) 

Midstate Electric Coop, Inc (OR) 

Midwest Electric, Inc (OH) 

Midwest Energy Cooperative (MI) 

Midwest Energy Inc (KS) 

Mid-Yellowstone Elec Coop, Inc (MT) 

Mille Lacs Electric Coop (MN) 

Minn Valley Coop L&P Assn (MN) 

Minnesota Valley Electric Coop (MN) 

Minnkota Power Coop, Inc (ND) 

Missouri Rural Electric Coop (MO) 

Modern Electric Water Company (WA) 

Monroe County Elec Coop, Inc (IL) 

Moon Lake Electric Assn Inc (UT) 

Mora-San Miguel Elec Coop, Inc (NM) 

Morgan County Rural Elec Assn (CO) 

Mt Wheeler Power, Inc (NV) 

N W Electric Power Coop, Inc (MO) 

Navasota Valley Elec Coop, Inc (TX) 

Navopache Electric Coop, Inc (AZ) 

Nemaha-Marshall E C A, Inc (KS) 

Nespelem Valley Elec Coop, Inc (WA) 

New Enterprise R E C, Inc (PA) 

New Horizon Electric Coop, Inc (SC) 

Newberry Electric Coop, Inc (SC) 

NewCorp Resources El Coop Inc (TX) 

New-Mac Electric Coop, Inc (MO) 

Ninnescah Rural E C A Inc (KS) 

Niobrara Electric Assn, Inc (WY) 

Noble County R E M C (IN) 

Nobles Cooperative Electric (MN) 

Nodak Electric Coop Inc (ND) 

Nolin Rural Electric Coop Corp (KY) 

Norris Electric Coop (IL) 

North Arkansas Elec Coop, Inc (AR) 

North Carolina El Member Corp (NC) 

North Central Elec Coop, Inc (ND) 

North Plains Electric Coop Inc (TX) 

North Star Electric Coop, Inc (MN) 

North West Rural Electric Coop (IA) 

Northeast Missouri El Pwr Coop (MO) 

Northeast Oklahoma Electric Coop, Inc (OK) 

Northern Electric Coop, Inc (MT) 

Northern Neck Elec Coop, Inc (VA) 

Northern Rio Arriba E Coop Inc (NM) 

Northern Virginia Elec Coop (VA) 

Northwest Iowa Power Coop (IA) 

Northwestern Rural E C A, Inc (PA) 

Oakdale Electric Coop (WI) 

Ocmulgee Electric Member Corp (GA) 

Oglethorpe Power Corporation (GA) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

G-10 

Cooperative Utilities (Cont’d)

Ohop Mutual Light Company, Inc (WA) 

Okanogan County Elec Coop, Inc (WA) 

Okefenoke Rural El Member Corp (GA) 

Oklahoma Electric Coop Inc (OK) 

Oliver-Mercer Elec Coop Inc (ND) 

Oneida-Madison Elec Coop, Inc (NY) 

Ontonagon County R E A (MI) 

Oregon Trail El Cons Coop,Inc (OR) 

Osceola Electric Coop, Inc (IA) 

Otsego Electric Coop, Inc (NY) 

Owen Electric Coop Inc (KY) 

Ozark Electric Coop Inc (MO) 

Ozarks Electric Coop Corp (AR) 

P K M Electric Coop, Inc (MN) 

Park Electric Coop Inc (MT) 

Parke County Rural E M C (IN) 

Parkland Light & Water Co (WA) 

Peace River Electric Coop, Inc (FL) 

Pedernales Electric Coop, Inc (TX) 

Pee Dee Electric Coop, Inc (SC) 

Pee Dee Elec Member Corp (NC) 

Pella Cooperative Elec Assn (IA) 

Pemiscot-Dunklin E C Inc (MO) 

Peninsula Light Company (WA) 

People's Cooperative Services (MN) 

People's Electric Cooperative (OK) 

Petit Jean Electric Coop Corp (AR) 

Piedmont Elec Member Corp (NC) 

Pierce-Pepin Coop Services (WI) 

Pioneer Electric Coop, Inc (KS) 

Pioneer Rural Elec Coop, Inc (OH) 

Planters Electric Member Corp (GA) 

Pointe Coupee Elec Mem Corp (LA) 

Polk-Burnett Electric Coop (WI) 

Poudre Valley R E A, Inc (CO) 

Powder River Energy Corp (WY) 

Prairie Land Electric Coop Inc (KS) 

Presque Isle Elec & Gas Coop (MI) 

Price Electric Coop Inc (WI) 

Radiant Electric Coop, Inc (KS) 

Ralls County Electric Coop (MO) 

Randolph Elec Member Corp (NC) 

Rappahannock Electric Coop (VA) 

Ravalli County Elec Coop, Inc (MT) 

Rayburn Cntry Elec Coop, Inc (TX) 

REA Energy Coop Inc (PA) 

Redwood Electric Coop (MN) 

Rich Mountain Elec Coop, Inc (AR) 

Richland Electric Coop (WI) 

Rita Blanca Electric Coop, Inc (TX) 

Rolling Hills Electric Coop (KS) 

Roosevelt Cnty Elec Coop Inc (NM) 

Rosebud Electric Coop Inc (SD) 

Runestone Electric Assn (MN) 

Rusk County Electric Coop, Inc (TX) 

Sac County Rural Electric Coop (IA) 

Sac-Osage Electric Coop Inc (MO) 

Salt River Electric Coop Corp (KY) 

Saluda River Electric Coop Inc (SC) 

Sam Rayburn G&T E C Inc (TX) 

San Luis Valley R E C, Inc (CO) 

San Miguel Electric Coop, Inc (TX) 

San Miguel Power Assn, Inc (CO) 

Sand Mountain Electric Coop (AL) 

Satilla Rural Elec Mem Corp (GA) 

SE-MA-NO Electric Coop (MO) 

Seminole Electric Coop, Inc (FL) 

SEMO Electric Cooperative (MO) 

Shelby Electric Coop, Inc (IL) 

Shelby Energy Co-op, Inc (KY) 

Sheridan Electric Coop, Inc (MT) 

Sho-Me Power Electric Coop (MO) 

Singing River Elec Pwr Assn (MS) 

Slash Pine Elec Member Corp (GA) 

Smarr EMC (GA) 

Snapping Shoals El Mem Corp (GA) 

Somerset Rural Elec Coop, Inc (PA) 

South Central Ark El Coop, Inc (AR) 

South Central Indiana REMC (IN) 

South Kentucky R E C Corp (KY) 

Southeast Colorado Pwr Assn (CO) 

Southeastern IL Elec Coop, Inc (IL) 

Southern Illinois Elec Coop (IL) 

Southern Iowa Elec Coop, Inc (IA) 

Southern Maryland E C Inc (MD) 

Southern Pine Elec Coop, Inc (AL) 

Southside Electric Coop, Inc (VA) 

Southwest Electric Coop, Inc (MO) 

Southwest Louisiana E M C (LA) 

Southwest Texas E C, Inc (TX) 

Southwestern Electric Coop Inc (IL) 

Southwestern Elec Coop Inc (NM) 

Square Butte Electric Coop (ND) 

Steuben Rural Elec Coop, Inc (NY) 

Sullivan County R E C, Inc (PA) 

Sumter Electric Coop, Inc (FL) 

Sumter Electric Member Corp (GA) 

Sun River Electric Coop, Inc (MT) 

Sussex Rural Electric Coop Inc (NJ) 

Suwannee Valley E C Inc (FL) 

Swans Island Electric Coop Inc (ME) 

Swisher Electric Coop, Inc (TX) 

T I P Rural Electric Coop (IA) 

Tallapoosa River Elec Coop Inc (AL) 

Taylor County Rural E C C (KY) 

Taylor Electric Coop (WI) 

Tex-La Electric Coop-Texas Inc (TX) 

The Energy Cooperative (PA) 

Three Notch Elec Member Corp (GA) 

Tipmont Rural Elec Mem Corp (IN) 

Traverse Electric Coop, Inc (MN) 

Trico Electric Cooperative Inc (AZ) 

Tri-County Electric Coop (MN) 

Tri-County Electric Coop Assn (MO) 

Tri-County Electric Coop, Inc (FL) 

Tri-County Electric Coop, Inc (IL) 

Tri-County Electric Coop, Inc (TX) 

Tri-County Rural Elec Coop Inc (PA) 

Twin Valley Electric Coop Inc (KS) 

Umatilla Electric Coop Assn (OR) 

Unalakleet Valley Elec Coop (AK) 

United Electric Coop Service Inc (TX) 

United Electric Coop, Inc (MO) 

United Electric Coop, Inc (PA) 

United Electric Co-op, Inc (ID) 

Upper Missouri G&T El Coop Inc (MT) 

Upshur Rural Elec Coop Corp (TX) 

Upson Elec Member Corp (GA) 

Valley Electric Assn, Inc (NV) 

Valley Electric Coop, Inc (MT) 

Valley Rural Electric Coop Inc (PA) 

Verdigris Valley Elec Coop Inc (OK) 

Verendrye Electric Coop Inc (ND) 

Vermont Electric Cooperative, Inc. (VT) 

Vigilante Electric Coop, Inc (MT) 

Wabash County Rural E M C (IN) 

Walton Electric Member Corp (GA) 

Warren County Rural E M C (IN) 

Warren Electric Coop Inc (PA) 

Washington Elec Member Corp (GA) 

Washington Electric Coop Inc (VT) 

Washington-St Tammany E C, Inc (LA) 

Webster Electric Coop (MO) 

West Central Electric Coop Inc (SD) 

West Florida El Coop Assn, Inc (FL) 

West Oregon Electric Coop Inc (OR) 

West River Electric Assn Inc (SD) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

G-11

Cooperative Utilities (Cont’d)

Western Coop Electric Assn Inc (KS) 

Western Farmers Elec Coop, Inc (OK) 

Western Illinois Elec Coop (IL) 

Western Indiana Energy REMC (IN) 

Western Iowa Power Coop (IA) 

Wheatland Electric Coop, Inc (KS) 

Wheatland R E A, Inc (WY) 

White County Rural E M C (IN) 

White River Electric Assn, Inc (CO) 

White River Valley El Coop Inc (MO) 

Whitewater Valley Rural EMC (IN) 

Wild Rice Electric Coop, Inc (MN) 

Willwood Light & Power Co (WY) 

Withlacoochee River Elec Coop (FL) 

Wolverine Pwr Supply Coop,Inc (MI) 

Wood County Elec Coop, Inc (TX) 

Woodruff Electric Coop Corp (AR) 

Wyrulec Company (WY) 

Yazoo Valley Elec Power Assn (MS) 

Yellowstone Valley Elec Co-op Inc. (MT) 

York Electric Coop Inc (SC) 

Investor Owned Utilities (203 Entities)

AEP Generating Company (OH) 

AEP Texas Central Company (OH) 

AEP Texas North Company (OH) 

AGC Division of APG Inc (IN) 

Ajo Improvement Co (AZ) 

Alabama Power Co (AL) 

Alaska Electric Light&Pwr Co (AK) 

Alaska Power Co (WA) 

Allegheny Generating Co (PA) 

Alpena Power Co (MI) 

Amana Society Service Co (IA) 

Andreanof Electric Corp (AK) 

Aniak Light & Power Co Inc (AK) 

Appalachian Power Co (OH) 

Aquila Inc (MO) 

Arizona Public Service Co (AZ) 

Atlantic City Electric Co (DE) 

Avista Corp (WA) 

Baltimore Gas & Electric Co (MD) 

Bangor Hydro-Electric Co (ME) 

Bethel Utilities Corp (AK) 

Black Diamond Power Co (WV) 

Black Hills Power Inc (SD) 

Block Island Power Co (RI) 

Boston Edison Co (MA) 

Cambridge Electric Light Co (MA) 

CenterPointEnrgy HoustonElec (TX) 

Central Electric Inc (AK) 

Central Hudson G&E Corp (NY) 

Central Illinois Light Co (MO) 

Central Illinois Pub Serv Co (IL) 

Central Maine Power Co (ME) 

Central Vermont PubServ Corp (VT) 

Chitina Electric Inc (AK) 

Cincinnati Gas & Electric Co (OH) 

Citizens Electric Co (PA) 

Cleco Power LLC (LA) 

Cleveland Electric Illum Co (OH) 

Columbus Southern Power Co (OH) 

Commonwealth Edison Co (IL) 

Commonwealth Electric Co (MA) 

Connecticut Light & Power Co (CT) 

Consolidated Edison Co-NYInc (NY) 

Consolidated Water Power Co (WI) 

Consumers Energy Co (MI) 

Dahlberg Light & Power Co (WI) 

Dayton Power & Light Co (OH) 

Delmarva Power (DE) 

Detroit Edison Co (MI) 

Duke Power Co (NC) 

Duquesne Light Co (PA) 

Edison Sault Electric Co (MI) 

Egegik Light & Power Co (AK) 

El Paso Electric Co (TX) 

Electric Energy Inc (IL) 

Elk Power Co (WV) 

Elkhorn Public Service Co (WV) 

Empire District Electric Co (MO) 

Entergy Arkansas Inc (AR) 

Entergy Gulf States Inc (TX) 

Entergy Louisiana Inc (LA) 

Entergy Mississippi Inc (MS) 

Entergy New Orleans Inc (LA) 

Entergy Power, Inc (AR) 

Fale-Safe, Inc (OR) 

Fishers Island Utility Co Inc (NY) 

Fitchburg Gas & Elec Light Co (NH) 

Florida Power & Light Co (FL) 

Florida Public Utilities Co (FL) 

Georgia Power Co (GA) 

Granite State Electric Co (NH) 

Green Mountain Power Corp (VT) 

Gulf Power Co (FL) 

Gustavus Electric Inc (AK) 

Gwitchyaa Zhee Utility Co (AK) 

Hawaii Electric Light Co Inc (HI) 

Hawaiian Electric Co Inc (HI) 

Holyoke Power & Electric Co (MA) 

Holyoke Water Power Co (MA) 

Idaho Power Co (ID) 

Illinois Power Co (MO) 

Indiana Michigan Power Co (OH) 

Indiana-Kentucky Elec Corp (OH) 

Indianapolis Power & Light Co (IN) 

Interstate Power and Light Co (IA) 

Jersey Central Power & Lt Co (OH) 

Kansas City Power & Light Co (MO) 

Kansas Gas & Electric Co (KS) 

Kentucky Power Co (OH) 

Kentucky Utilities Co (KY) 

KeySpan Generation LLC (NY) 

Kimball Light and Water Co (WV) 

Kingsport Power Co (OH) 

Kuiggluum Kallugvia (AK) 

Lockhart Power Co (SC) 

Louisville Gas & Electric Co (KY) 

Madison Gas & Electric Co (WI) 

Maine Public Service Co (ME) 

Manley Utility Co Inc (AK) 

Massachusetts Electric Co (MA) 

Maui Electric Co Ltd (HI) 

MDU Resources Group Inc (ND) 

Metropolitan Edison Co (OH) 

Miami Power Corporation (OH) 

MidAmerican Energy Co (IA) 

Minnesota Power Inc (MN) 

Mississippi Power Co (MS) 

Monongahela Power Co (PA) 

Morenci Water and Electric Co (AZ) 

Mt Carmel Public Utility Co (IL) 

Nantucket Electric Co (MA) 

Napakiak Ircinraq Power Co (AK) 

Nevada Power Co (NV) 

New England Elec Transm'n Corp (NH) 

New England Hydro-Tran Elec Co (MA) 

New England Hydro-Trans Corp (NH) 

New England Power Company (MA) 

New York State Elec & Gas Corp (NY) 

Niagara Mohawk Power Corp. (NY) 

North Central Power Co Inc (WI) 

Northern Indiana Pub Serv Co (IN) 

Northern States Power Co (WI) 

Northern States Power Co (MN) 

NorthWestern Energy (SD) 

NorthWestern Energy LLC (MT) 

Northwestern Wisconsin Elec Co (WI) 

Ohio Edison Co (OH) 

Ohio Power Co (OH) 

Ohio Valley Electric Corp (OH) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

G-12 

Investor Owned Utilities (Cont’d)

Oklahoma Gas & Electric Co (OK) 

Omya Inc (VT) 

Orange & Rockland Utils Inc (NY) 

Otter Tail Power Co (MN) 

Pacific Gas & Electric Co (CA) 

PacifiCorp (OR) 

PECO Energy Co (PA) 

Pelican Utility (AK) 

Pennsylvania Electric Co (OH) 

Pennsylvania Power Co (OH) 

Pike County Light & Power Co (PA) 

Pioneer Power and Light Co (WI) 

Portland General Electric Co (OR) 

Potomac Electric Power Co (DC) 

PPL Electric Utilities Corp (PA) 

Progress Energy Carolinas (NC) 

Progress Energy Florida (FL) 

PSI Energy Inc (IN) 

Public Service Co of NH (NH) 

Public Service Co of NM (NM) 

PublicService Co of Oklahoma (OH) 

Public Service Elec & Gas Co (NJ) 

Puget Sound Energy Inc (WA) 

Redlands Water & Power Co (CO) 

Rochester Elec Lgt and Power (VT) 

Rochester Gas & Electric Corp (NY) 

Rockland Electric Co (NY) 

Safe Harbor Water Power Corp (PA) 

San Diego Gas & Electric Co (CA) 

Savannah Electric & Power Co (GA) 

Sharyland Utilities LP (TX) 

Sierra Pacific Power Co (NV) 

South Beloit Wtr Gas & Elec (WI) 

South Carolina Gen Co, Inc (SC) 

Southern California Edison Co (CA) 

Southern California Water Co (CA) 

Southern Electric Gen Co (AL) 

Southern Indiana Gas&Elec Co (IN) 

Southwestern Elec Power Co (OH) 

Strawberry Water Users Assn (UT) 

Superior Water, Light & Pwr Co (WI) 

System Energy Resources, Inc (MS) 

Tampa Electric Co (FL) 

Tanana Power Co Inc (AK) 

The Narragansett Electric Co (RI) 

The Potomac Edison Co (PA) 

The Toledo Edison Co (OH) 

TransCanadaPwr Div-Engy Ltd (CN) 

Tucson Electric Power Co (AZ) 

TXU Electric Delivery Company (TX) 

UGI Utilities, Inc (PA) 

Union Electric Co (MO) 

Union Light, Heat & Power Co (OH) 

Union Power Co (WV) 

United Illuminating Co (CT) 

United Light and Power Co (WV) 

Unitil Energy Systems (NH) 

Upper Peninsula Power Co (MI) 

Vermont Electric Power Co, Inc (VT) 

Vermont Electric Trans Co Inc (VT) 

Vermont Yankee Nucl Pwr Corp (VT) 

Virginia Electric & Power Co (VA) 

War Light and Power Co (WV) 

Wellsborough Electric Co (PA) 

West Penn Power Co (PA) 

Westar Energy Inc (KS) 

Western Massachusetts Elec Co (MA) 

Westfield Electric Co (WI) 

Wheeling Power Co (OH) 

Wisconsin Electric Power Co (WI) 

Wisconsin Power & Light Co (WI) 

Wisconsin Public Service Corp (WI) 

Wisconsin River Power Company (WI) 

York Haven Power Company (OH) 

Power Marketers (74 Entities) 

Agway Energy Services, LLC (NY) 

Ameren Energy Marketing (MO) 

APS Energy Services (AZ) 

Aquila Energy Marketing Corp (MO) 

Cargill Power Markets LLC (MN) 

CECG Maine, LLC (MD) 

Cirro Corporation (TX) 

CL Power Sales Eight LLC (CA) 

CL Power Sales Nine LLC (CA) 

CL Power Sales Seven LLC (MA) 

CL Power Sales Ten LLC (CA) 

CL Power Sales Two LLC (CA) 

CMS Marketing, Serv&Trd Co (MI) 

Competitive Engy Serv, LLC (ME) 

ConocoPhillips Company (TX) 

Consolidated Edison Sol Inc (NY) 

Constellation NewEnergy, Inc (MD) 

Constellation Enrgy Comdties (MD) 

Coral Power LLC (TX) 

CP Pwr Sales Seventeen LLC (MA) 

CPL Retail Energy, LP (TX) 

Direct Energy, LP (TX) 

Dominion Energy Marketing (VA) 

Dominion Retail Inc (VA) 

Duke Energy Trdg&Mrktg LLC (TX) 

Duke Energy Trdg & Mktg, LLC (TX) 

Edison Mission Mktg&Trdg Inc (MA) 

El Paso Merchant Energy LP (TX) 

Empire Natural Gas Corp (NY) 

Energy Coop of New York, Inc (NY) 

Energy West Resources Inc (MT) 

Engage Energy America LLC (TX) 

Exelon Energy Company (IL) 

First Energy Solutions Corp. (OH) 

GEN-SYS Energy (WI) 

Granite Peak Energy (ND) 

Great Bay Pwr Marketing, Inc. (NH) 

Hinson Power Company LLC (WA) 

Independence Pwr Marketing (NY) 

Merrill Lynch Commodities (TX) 

Mirant Americas EngyMrktg LP (GA) 

Mpower Retail Energy LP (TX) 

Neumin Production Company (TX) 

OGE Energy Resources, Inc (OK) 

People's Electric Corporation (OK) 

Peoples Energy Services (IL) 

PEPCO Energy Services (VA) 

Pilot Power Group Inc (CA) 

Powerex Corporation (CN) 

PPL EnergyPlus LLC (PA) 

PPM Energy Inc (OR) 

Quest Energy, LLC (MI) 

Rainbow Energy Marketing Corp (ND) 

Reliant Energy Electric Solutions (TX) 

Reliant Energy Retail Services, Inc (TX) 

Reliant Energy Services Inc (TX) 

Reliant Energy Solutions East, LLC (TX) 

Spark Energy, LP (TX) 

Split Rock Energy LLC (MN) 

Strategic Energy LLC (PA) 

Stream Energy (TX) 

Suez Enrgy Resources North America (TX) 

Tara Energy, Inc (TX) 

TDX North Slope Generating Co (AK) 

Texas Retail Energy, LLC (AR) 

Tractebel Energy Marketing Inc (TX) 

TransAlta Enrgy Marketing (U.S.) Inc. (CN) 

TXU Energy Retail Co LP (TX) 

TXU ET Services Co (TX) 

TXU SESCO Energy Services Co (TX) 

UNS Electric, Inc (AZ) 

Williams Energy Mktg & Trdg Co (OK) 

WPS Energy Services (WI) 

WTU Energy, LP (TX) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

G-13

Political Subdivisions (77 Entities) 

Arkansas River Power Authority (CO) 

Burt County Public Power Dist (NE) 

Butler County Rural P P D (NE) 

Central Lincoln People's Ut Dt (OR) 

Central Nebraska Pub P&I Dist (NE) 

Chimney Rock Public Power Dist (NE) 

Clatskanie Peoples Util Dist (OR) 

Cornhusker Public Power Dist (NE) 

Crisp County Power Comm (GA) 

Cuming Cnty Public Pwr Dist (NE) 

Custer Public Power District (NE) 

Dawson Power District (NE) 

Electrical Dist No2 Pinal Cnty (AZ) 

Electrical Dist No4 Pinal Cnty (AZ) 

Electrical Dist No6 Pinal Cnty (AZ) 

Elkhorn Rural Public Pwr Dist (NE) 

Emerald People's Utility Dist (OR) 

Heartland Consumers Pwr Dist (SD) 

Hohokam Irr & Drain Dist (AZ) 

Imperial Irrigation District (CA) 

Intermountain Power Agency (CA) 

KBR Rural Public Power District (NE) 

Kings River Conservation Dist (CA) 

Kokhanok Village Council (AK) 

Lincoln County Pwr Dist No 1 (NV) 

Louisiana Energy & Pwr Auth (LA) 

Loup River Public Power Dist (NE) 

McCook Public Power District (NE) 

Merced Irrigation District (CA) 

Midvale Irrigation District (WY) 

Modesto Irrigation District (CA) 

Mohegan Tribal Utility Auth (CT) 

MSR Public Power Agency (CA) 

Municipal Enrgy Agency of NE (NE) 

Nebraska Public Power District (NE) 

North Central Public Pwr Dist (NE) 

Northern Wasco County PUD (OR) 

Northwest Rural Pub Pwr Dist (NE) 

Oakdale& S SanJoaquin Irrign (CA) 

Omaha Public Power District (NE) 

Oroville-Wyandotte Irrig Dist (CA) 

Perennial Public Power Dist (NE) 

Piedmont Municipal Pwr Agny (SC) 

Placer County Water Agency (CA) 

Polk Cnty Rural Pub Pwr Dist (NE) 

PSC of Yazoo City (MS) 

Public Utility District No 1 (WA) 

Public Utility District No 2 (WA) 

PUD No 1 of Benton County (WA) 

PUD No 1 of Chelan County (WA) 

PUD No 1 of Clallam County (WA) 

PUD No 1 of Clark County (WA) 

PUD No 1 of Cowlitz County (WA) 

PUD No 1 of Douglas County (WA) 

PUD No 1 of Ferry County (WA) 

PUD No 1 of Grays Harbor Cnty (WA) 

PUD No 1 of Kittitas County (WA) 

PUD No 1 of Klickitat County (WA) 

PUD No 1 of Okanogan County (WA) 

PUD No 1 of Pend Oreille Cnty (WA) 

Roosevelt Public Power Dist (NE) 

Sacramento Municipal Util Dist (CA) 

Salt River Project (AZ) 

Seward County Rrl Pub Pwr Dist (NE) 

Snohomish County PUD No 1 (WA) 

Southern California P P A (CA) 

Southwest Public Power Dist (NE) 

Stanton County Public Pwr Dist (NE) 

Tonopah Irrigation District (AZ) 

Truckee Donner P U D (CA) 

Tuolumne County Pub Power Agny (CA) 

Twin Valleys Public Power Dist (NE) 

Utah Associated Mun Power Sys (UT) 

Vermont Public Pwr Supply Auth (VT) 

Wellton-Mohawk Irr & Drain Dist (AZ) 

Western Minnesota Mun Pwr Agny (SD) 

Yakutat Power Inc (AK) 

Municipal Marketing Authorities (11 Entities) 

CT Muni Elec Engy Coop (CT) 

Florida Municipal Pwr Agency (FL) 

Illinois Municipal Elec Agency (IL) 

Indiana Municipal Pwr Agency (IN) 

Mass Mun Wholesale Elec Co (MA) 

Minnesota Municipal Pwr Agny (MN) 

Municipal Electric Authority (GA) 

Municipal Enrgy Agency of MS (MS) 

Northern Municipal Power Agency (MN) 

Utah Municipal Power Agency (UT) 

Wisconsin Public Power Inc Sys (WI) 

Curtailment Service Providers (19 Entities) 

A&C Management Group LLC (NJ) 

Allied Utility Network (GA) 

Baltimore Gas & Electric (MD) 

Celerity Energy Partners, LLC (WA) 

Commercial Utility Consultants, Inc. (PA) 

Constellation Energy Source (MA) 

Consumer Powerline Company (NY) 

Crucible Metals (NY) 

Downes Associates, Inc. (MD) 

ECONnergy Energy Co, Inc. (NY) 

Enrgy Investment Systms, Inc. (NY) 

EnerNOC, Inc (MA) 

FirstEnergy (PA) 

Galt Power (DE) 

MWN Energy Group (PA) 

Onsite Energy Corporation (CA) 

State University of NY at Buffalo (NY) 

The Legacy Energy Group (VA) 

WebGen Systems (MA) 

State Utilities (20 Entities)

Ak-Chin Electric Utility Authority (AZ) 

Alaska Energy Authority (AK) 

American Samoa Power Authority (AS) 

Arizona Power Authority (AZ) 

Brazos River Authority (TX) 

California Dept of Wtr Res (CA) 

Colorado River Comm of NV (NV) 

Electric Fund (CDWR) (CA) 

Energy Northwest (WA) 

Grand River Dam Authority (OK) 

Guadalupe Blanco River Auth (TX) 

Long Island Power Authority (NY) 

Metropolitan Water District of S CA (CA) 

Navajo Tribal Utility Authority (AZ) 

New River Light & Power Co (NC) 

New York Power Authority (NY) 

Oklahoma Municipal Power Auth (OK) 

South Carolina Pub Serv Auth (SC) 

Virgin Islands Wtr&Pwr Auth (VI) 

Virginia Tech Electric Service (VA) 
Appendix G: FERC Survey Respondents 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

G-14 

Federal (6 Entities)

Bonneville Power Admin (OR) 

Southeastern Power Admin (GA) 

Southwestern Power Admin (OK) 

Tennessee Valley Authority (TN) 

USBIA-Mission Valley Power (MT) 

Western Area Pwr Admin (CO) 

RTOs/ISOs (6 Entities) 

CAISO 

ERCOT 

ISONE 

MISO 

NYISO 

PJM 

* Commission staff received a total of 1,939 responses to the 3,366 surveys it sent out. Some respondents (1,886) completed the

Demand Response section of the survey, others (1,860) completed the AMI section of the survey. The difference among the 

1,886, 1,860 and 1,939 numbers stems from some respondents filling out only the general information section of the survey or 

otherwise reporting to Commission staff that they had no programs or activities to report.
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-1

Appendix H: Demand Response (DR) Programs and Services at 

Responding Utilities 

Ancillary Services 

TXU Energy Retail Company LP 

Capacity Market Programs 

Allied Utility Network 

Celerity Energy Partners, LLC 

City of Waseca Electric Utility 

Commonwealth Edison Co. 

ConEdison Solutions 

Consumers Energy Co. 

EnerNOC, Inc. 

New York Power Authority 

Northern States Power Co 

Orange & Rockland Utils, Inc. 

Pacific Gas & Electric Company 

PacifiCorp 

PECO Energy Company 

Pioneer Electric Cooperative, 

 Inc. 

Portland General Electric Co 

Wisconsin Public Power, Inc. 

Critical Peak Pricing 

Arrowhead Electric Coop, Inc. 

Austin Energy 

Butler Rural Electric Coop, Inc. 

 (OH) 

Cass County Elec Coop Inc. 

 (ND) 

Cherryland Electric Cooperative 

Choptank Electric Cooperative, 

 Inc. 

City of Gastonia 

City of Grafton 

City of High Point Electric 

 Department 

City of LaGrange 

City of Laurinburg, North 

 Carolina 

Clay County Electric Coop Corp 

Consumers Energy 

Gulf Power Company 

High Plains Power, Inc. 

Idaho Power Company 

Jackson Electric Membership 

 Corporation 

Oakdale Electric Cooperative 

OGE Electric Services (DBA 

 Oklahoma Gas and Electric) 

Pacific Gas & Electric Co 

Pioneer Rural Electric 

 Coop, Inc. (OH) 

Rappahannock Electric Coop 

San Diego Gas & Electric Co 

Southern California Edison 

 Company 

Wisconsin Public Service Corp

Demand Bidding 

Alliant Energy 

City of Lafayette Electric 

 Department 

Entergy Arkansas, Inc. 

Gaffney Board of Public Works 

Groton Dept of Utilities 

New Braunfels Utilities 

Niagara Mohawk 

Otter Tail Power Company 

Pacific Gas & Electric Co 

Polk County Rural Public Power 

 District 

Portland General Electric Co 

PSI Energy Inc 

Sacramento Municipal Utility 

 District 

San Diego Gas & Electric Co 

Snohomish County PUD No 1 

Southern California Edison 

 Co 

Wisconsin Electric Power Co 

Wisconsin Public Service Corp

Direct Load Control 

A & N Electric Coop 

Adams Electric Coop 

Adams-Columbia Electric 

 Cooperative 

Alabama Power Company 

Alaska Electric Light and Power 

 Company 

Allamakee-Clayton Electric Coop 

Altamaha EMC 

Anderson Municipal Light and 

 Power 

Austin Energy 

Baltimore Gas & Electric Co 

Barnesville Municipal Utility 

Black River Electric Coop Inc. 

Blue Earth Light & Water Dept 

Bluestem Electric Coop, Inc. 

Board of Public Works 

Boone Electric Coop 

Bristol Tennessee Essential 

Services 

Buckeye Power, Inc 

Butler Rural Electric Coop Ass’n 

 Inc. 

Butler Rural Electric Coop, Inc. 

C & L Electric Coop Corporation 

Caddo Electric Coop 

Capital Electric Coop, Inc. 

Cass County Electric Coop, Inc 

Central Electric Membership 

 Corp (NC) 

Central Florida Electric Coop, 

 Inc. 

Central Maine Power Company 

Central Rural Electric Coop 

Central Vermont Public Service 

 Corporation 

City of Ames 

City of Arlington 

City of Aurora 

City of Big Stone City 

City of Bowling Green, OH 

City of Camden 

City of Central City 

City of Detroit Lakes 

City of Fort Collins Colorado 

City of Gothenburg 

City of Grafton 

City of Groton 

City of Hecla 

City of Kinston 
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-2 

Direct Load Control (Cont’d) 

City of Laurinburg (NC) 

City of Milford 

City of Moorhead 

City of New Smyrna Beach 

City of Northwood 

City of Parker 

City of Saint Peter 

City of Seward 

City of Staples 

City of Stromsburg 

City of Waseca Electric Utility 

City of White 

City of Wood River 

Clay County Electric Coop Corp 

Coastal Electric Cooperative, Inc 

Coles-Moultrie Electric Coop 

Colorado Springs Utilities 

Columbia Water & Light Dept 

Commonwealth Edison Co. 

Community Electric Coop 

Con Edison 

Concord Municipal Light Plant 

Connexus Energy 

Consolidated Electric Coop 

Continental Cooperative 

 Services 

Cooperative Light & Power 

Corn Belt Energy Corp 

Cornhusker Public Power District 

Coweta-Fayette EMC 

CPS Energy 

Crowning Power 

Cuivre River Electric Coop, Inc. 

Cuming County Public Power 

 District 

Dahlberg Light & Power Co. 

Dairyland Power Coop 

Dakota Electric Association 

Dakota Energy Coop, Inc. 

David City Utilities 

Delaware County Electric Coop, 

 Inc. 

Delmarva Power & Light 

 Company 

Detroit Edison Company 

Dominion North Carolina Power 

Dominion Virginia Power 

Dubois Rural Electric Coop, Inc. 

Duke Power 

Duquesne Light Company 

East River Electric Power Coop 

Elk River Municipal Utilities 

Elkhorn Rural Public Power 

 District 

EnergyUnited EMC 

Excelsior EMC 

Farmers Electric Coop Corp 

Farmers' Electric Coop 

First Electric Cooperative Corp 

Flint Electric Membership 

 Corporation 

Florida Power & Light Co 

Frontier Power Company 

Georgia Power Company 

Grand Rapids Public Utilities 

 Commission 

Great Lakes Energy Cooperative 

Grundy Electric Cooperative, 

 Inc. 

Guernsey-Muskingum Electric 

 Coop, Inc. 

Hart Electric Membership 

 Corporation 

Hawaiian Electric Company, Inc. 

Hawley Public Utilities 

Highline Electric Association 

Horry Electric Coop, Inc 

Idaho Power Company 

Illinois Rural Electric Coop 

Indianapolis Power & Light Co 

Jackson Electric Cooperative 

Jackson E M C 

Jamestown (Indiana) Municipal 

 Electric Utility 

Jefferson Energy Coop 

Jersey Central Power & Light Co 

Kansas City Power & Light Co 

KBR Rural Public Power District 

KEM Electric Coop, Inc. 

Kentucky Utilities Company 

Lake Region Electric Coop 

Lee County Electric Coop, Inc 

Licking Rural Electrification 

Lighthouse Electric Coop, Inc. 

Linton Municipal Electric Utility 

Litchfield Public Utilities 

Long Island Power Authority 

Louisville Gas & Electric Co 

Loup River Public Power District 

Lynches River Electric Coop, Inc 

Madison Gas and Electric Co 

Marshall Municipal Utilities 

McLean Electric Cooperative 

McLeod Cooperative Power 

 Assn 

Mecklenburg Electric Coop 

Menard Electric Coop 

MidAmerican Energy Company 

Midwest Electric, Inc 

Midwest Energy Coop 

Mille Lacs Electric Coop 

Modesto Irrigation District 

Montana-Dakota Utilities Co. 

Moose Lake Water & Light 

 Commission 

Morgan County rural Electric 

 Assn 

Municipal Commission of 

 Boonville 

Navopache Electric Coop, Inc. 

Nevada Power Company 

New Prague Utilities Comm. 

Nobles Cooperative Electric 

Nodak Electric Cooperative, Inc. 

North Arkansas Electric Coop, 

 Inc 

North Central Electric Coop, Inc. 

North Central Public Power 

 District 

North West Rural Electric Coop 

Northern States Power Co 

Northern States Power 

Company(Wisconsin) 

Northern Virginia Electric Coop 

Northwest Rural Public Power 

 District 

Oakdale Electric Cooperative 

Oliver-Mercer Electric Coop, Inc. 

Osceola Electric Coop, Inc 

Otter Tail Power Company 

Owatonna Public Utilities 

PacifiCorp 

PECO Energy Company 

Pee Dee Electric Member Corp 

 (NC) 

People's Electric Coop 

Perennial Public Power District 

Pierce Pepin Cooperative 

 Services, Inc. 

Pioneer Rural Electric Coop, INC 

Polk County Rural Public Power 

 District 

Price Electric Coop, Inc. 

Progress Energy Carolinas, Inc. 

Progress Energy Florida, Inc. 

PSI Energy Inc 

Public Service Electric & Gas 

 Company 

Randolph Electric Membership 

 Corporation 

Rappahannock Electric Coop 

Rice Lake Utilities 

Richland Electric Coop 

Runestone Electric Association 

Sacramento Municipal Utility 

 District 

San Diego Gas and Electric 

Seward County Public Power 

 District 

Shelby Electric Coop, INC 

Sioux Center Municipal Utilities 

Southeastern Electric Coop, Inc. 

Southern California Edison 

 Company 

Southern Indiana Gas & Elec Co 

Southern Maryland Electric 

 Coop, Inc. 

Southside Electric Cooperative 

Southwest Public Power District 

Southwestern Electric Coop, Inc 

Stanton County Public Power 

 District 
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-3

Direct Load Control (Cont’d) 

Steuben Rural Electric Coop, 

 Inc. 

Sumter Electric Coop, Inc. 

Superior Water, Light & Power 

 Co 

Taylor Electric Coop 

Third Taxing District Electrical 

 Dept 

Tipmont REMC 

Tipton Municipal Utilities 

Town of Maiden 

Town of Massena Electric Dept 

Town of Reading Municipal Light 

 Dept 

Town of Norwood Light Dept 

Union Light, Heat & Power Co 

Village of Hamilton 

Village of Sherburne Electric 

Volga Municipal Utilities 

Waynetown Utilities 

Wells Public Utilities 

Wild Rice Electric Coop Inc. 

Wisconsin Electric Power Co 

Wisconsin Power and Light Co 

Wisconsin Public Service Corp 

Woodruff Electric Coop Corp

Emergency Demand Response Program 

A&C Management Group LLC 

AGC 

Anaheim Public Utilities 

APS Energy Services Company, 

 Inc. 

Central Hudson Gas & Electric 

 Corp 

Central Vermont Public Service 

 Corp 

City of Westerville 

Commonwealth Edison Co. 

Con Edison 

Connecticut Light and Power Co 

Eugene Water & Electric Board 

Fitchburg Gas and Electric Light 

 Co 

Long Island Power Authority 

Mass Electric Co 

New York Power Authority 

Niagara Mohawk 

NSTAR Electric 

Orange & Rockand Utilities, Inc. 

Otter Tail Power Company 

Pacific Gas & Electric Co 

Sacramento Municipal Utility 

 District 

The Legacy Energy Group 

The Narragansett Electric Co 

Unitil Energy Systems, Inc. 

Western Massachusetts Electric 

 Company 

Wisconsin Public Service 

 Corporation 

Interruptible and Curtailable 

Adams Electric Cooperative 

Adams-Columbia Electric Coop 

Alabama Power Company 

Alaska Electric Light and Power 

 Company 

Alaska Power Company 

Alfalfa Electric Cooperative, Inc. 

Allegheny Power 

Bainbridge Municipal Electric 

Utiltiy 

Barton Village, Inc. 

Bear Valley Electric 

Blue Grass Energy Cooperative 

 Corporation 

Bluestem Electric Cooperative, 

Inc. 

Boone Electric Cooperative 

Buckeye Power, Inc 

Butler Rural Electric Coop Ass’n, 

 Inc. 

Carteret-Craven Electric Coop 

Cavalier Municipal Utilities 

Centerville Municipal Power & 

 Light 

Central Electric Membership 

 Corp 

Central Indiana Power 

Central Valley Electric Coop, Inc. 

Central Vermont Public Service 

 Corp 

Central Virginia Electric Coop 

Cherryland Electric Coop 

Cincinnati Gas & Electric Co 

City of Ashland 

City of Elroy 

City of Farmington 

City of Franklin 

City of Independence (MO) 

City of McPherson 

City of Saint Peter 

City of Seward 

Clay Electric Coop, Inc. 

Cleveland Electric Illuminating 

 Co 

Coastal Electric Coop, Inc 

Coles-Moultrie Electric Coop 

Colorado Springs Utilities 

Columbus Southern Company 

Commonwealth Edison Co. 

Community Electric Coop 

Con Edison 

Connecticut Light and Power 

Connexus Energy 

Consolidated Electric Coop 

Consumers Energy Co. 

Continental Cooperative 

 Services 

Cookson Hills Electric Coop, Inc 

Cooperative Light & Power 

Corn Belt Energy Corporation 

CPS Energy 

Crowning Power 

Cuivre River Electric 

Cooperative, Inc. 

Cuming County Public Power 

 District 

Dakota Electric Association 

Dawson Public Power District 

Denison Municipal Utilities 

Detroit Edison Company 

Dominion North Carolina Power 

Dominion Virginia Power 

Duquesne Light Company 

East River Electric Power Coop 

El Paso Electric Company 

Elk River Municipal Utilities 

Elkhorn Light and Water 

Empire District Electric Company 

EnergyUnited Electric 

 Membership Corp 

Entergy Arkansas, Inc. 

Entergy New Orleans, Inc. 

First Electric Cooperative Corp 

Flint Electric Membership Corp 

Flint Hills Rural E C A Inc. 

Florida Power & Light Co 

Franklin Rural Electric Coop 

Georgia Power Company 

Glidden Rural Electric Coop 

Grayson Rural Electric Coop 

Harrisonburg Electric 

Commission 

Hawaii Electric Light Company, 

 Inc. 

Hawaiian Electric Company, Inc. 

Hoory Electric Coop, Inc. 

Indiana Michigan Power Co. 

Indianapolis Power & Light 

 Company 

Inter-County Energy Cooperative 

 Corporation 

Iowa Lakes Electric Coop 
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-4 

 

Interruptible and Curtailable (Cont’d) 

Jackson Energy Coop Corp 

JEA 

Jefferson Energy Coop 

Kansas City Power & Light 

 Company 

Kansas gas and Electric 

 Company 

Kauai Island Utility Cooperative 

Kentucky Power Co. 

Kentucky Utilities Co 

Kiamichi Electric Cooperative, 

 Inc. 

Kissimmee Utility Authority 

Kiwash Electric Cooperative, Inc. 

Leavenworth Jefferson Electric 

 Coop 

Lee County Electric Cooperative, 

 Incorporated 

Lincoln Electric System 

Louisville Gas & Electric 

 Company 

Lumbee River Electric 

Membership Corporation 

Madison Gas and Electric 

 Company 

Manitowoc Public Utilities 

Marshall Municipal Utilities 

Mass Electric Co 

Maui Electric Company, Ltd 

McLeod Cooperative Power 

 Association 

Mecklenburg Electric Coop 

Menard Electric Coop 

Metropolitan Edison Co 

MidAmerican Energy Company 

Midwest Electric, Inc 

Midwest Energy, Inc. 

Narragansett Electric Co 

Navopache Electric Cooperative, 

 Inc. 

Nebraska Public Power District 

New Prague Utilities 

Commission 

New York Power Authority 

Ninnescah Rural Electric 

 Cooperative Assn., Inc. 

Nobles Cooperative Electric 

Nolin Rural Electric Coop Corp 

North Arkansas Electric Coop, 

 Inc 

North Central Power Co., Inc. 

North Plains Electric Coop Inc. 

Northern Neck Electric Coop 

Northern States Power Co 

Northern States Power 

 Company (WI) 

Northern Virginia Electric Coop 

Northwestern Wisconsin Electric 

 Company 

NSTAR Electric 

Oakdale Electric Cooperative 

Ohio Edison Co 

Ohio Power Company 

Omaha Public Power District 

Orlando Utilities Commission 

Otter Tail Power Company 

Owatonna Public Utilities 

Owen Electric Cooperative 

Paragould Light and Water 

 Commission 

PECO Energy Company 

Pee Dee Electric Member Corp 

 (NC) 

Pennsylvania Electric Co 

Pennsylvania Power Co 

Pepco Energy Services, Inc. 

Perennial Public Power District 

Pioneer Electric Cooperative, 

 Inc. 

Progress Energy Carolinas, Inc. 

Progress Energy Florida, Inc. 

PSI Energy Inc 

Public Service Company of New 

 Hampshire 

Public Service Company of New 

 Mexico 

Public Service Electric & Gas 

 Company 

Randolph Electric Membership 

 Corporation 

Rappahannock Electric Coop 

Richmond Power and Light 

Roosevelt Public Power District 

Runestone Electric Association 

Salamanca Board of Public 

 Utilities 

Salt River Electric Cooperative 

 Corporation 

San Diego Gas and Electric 

Satilla Rural Elec Member 

 Corporation 

Shelby Electric Coop, Inc 

Shelby Energy Cooperative 

 Incorporated 

South Carolina Public Service 

 Authority 

South Kentucky Rural Electric 

 Cooperative Corporation 

Southeastern Electric Coop, Inc. 

Southern California Edison Co 

Southern Indiana Gas & Elec Co 

Southside Electric Coop, Inc. 

Southwestern Electric Coop, Inc 

SRP 

Sterling Municipal Light Dept 

Sumter Electric Cooperative, Inc. 

Superior Water, Light & Power 

 Company 

Swanton Village, Inc. 

T.I.P. Rural Electric Cooperative 

Tennessee Valley Authority 

Thief River Falls Municipal 

 Utilities 

Toledo Edison Co 

Town of Hardwick Electric 

 Department 

Town of Stowe Electric 

 Department 

Trico Electric Cooperative, Inc 

Tucson Electric Power Company 

Union Electric Company 

Union Light, Heat & Power Co 

UniSource Electric 

United Electric Cooperative 

 Services, Inc. 

Village of Enosburg 

Village of Hyde Park, Inc. 

Village of Jacksonville 

Village of Johnson, Inc. 

Village of Ludlow Electric Light 

 Dept. 

Village of Lyndonville Electric 

 Dept 

Village of Morrisville Water & 

 Light Dept. 

Village of Northfield 

Village of Orleans, Inc. 

Waverly Light and Power 

Webster Electric Coop 

Westar Energy, Inc. 

Wheeling Power Co.(WPCO) 

White River Valley Electric Coop 

 Inc. 

Wisconsin Electric Power 

Company 

Wisconsin Power and Light 

 Company 

Wisconsin Public Power, Inc. 

Wisconsin Public Service 

 Corporation 

Real-Time Pricing 

Alabama Power Company 

Alpena Power Company 

Atlantic City Electric Company 

Baltimore Gas and Electric 

Butler County Rural Electric 

 Cooperative 

Central Hudson Gas & Electric 

 Corporation 
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-5

Real-Time Pricing (Cont’d) 

Chicopee Municipal Lighting 

 Plant 

Cincinnati Gas & Electric Co 

Cleveland Electric Illuminating 

 Co 

Con Edison 

Connecticut Light and Power 

Delmarva Power & Light 

 Company 

Dominion Virginia Power 

Duquesne Light Company 

Georgia Power Company 

Hill County Electric Cooperative, 

 Inc 

JEA 

Jersey Central Power & Light Co 

Kansas City Power & Light 

 Company 

Maui Electric Co Ltd 

MidAmerican Energy Company 

New York Power Authority 

Niagara Mohawk 

Northern States Power Co (MN) 

Northern States Power Co (WI) 

Northern Rio Arriba Electric 

 Coop 

Ohio Edison Co 

Orange & Rockland Utilities, Inc. 

Otter Tail Power Company 

Pennsylvania Power Co 

Pepco 

Pepco Energy Services, Inc. 

Portland General Electric 

 Company 

Progress Energy Carolinas, Inc. 

PSI Energy Inc 

Public Service Electric & Gas 

 Company 

Reliant Energy, Inc. 

Seattle City Light 

South Beloit Water Gas and 

 Electric Company 

South Carolina Public Service 

 Authority 

Tennessee Valley Authority 

Toledo Edison Co 

Union Light, Heat & Power Co 

Vermont Electric Cooperative 

Western Massachusetts Electric 

 Company 

Wisconsin Electric Power 

 Company 

Time-of-Use 

Adams-Columbia Electric Coop 

Ak-Chin Energy Services 

Alabama Power Co 

Alliant Energy 

Arizona Public Service Co 

Baltimore Gas and Electric Co 

Bangor Hydro-Electric 

Barron Light & Water 

Big Horn Rural Electric Co 

Blue Grass Energy Cooperative 

 Corp 

Blue Ridge Electric Coop 

Broad River Electric Coop 

Butler County Rural Electric 

 Coop 

Butler Rural Electric 

 Cooperative, Inc. 

Carbon Power and Light Inc. 

Carteret-Craven Electric Coop 

Cedarburg Light & Water Utility 

Central Alabama Electric Coop 

Central Electric Membership 

 Corp 

Central Hudson Gas & Electric 

 Corp 

Central Illinois Light Co 

Central Illinois Public Service Co 

Central Maine Power Co 

Central NM Electric Coop 

Central Vermont Public Service 

 Corp 

Choptank Electric Cooperative, 

 Inc. 

Cincinnati Gas & Electric Co 

City of Kiel Utilities 

City of Kinston 

City of Laurinburg, (NC) 

City of Mountain Iron 

Clark County Rural EMC 

Clark Energy Coop, Inc. 

Clay Electric Coop, Inc. 

Cleveland Electric Illuminating 

 Co 

Colorado Springs Utilities 

Columbia Water & Light 

 Department 

Columbus Southern Company 

Columbus Water & Light 

Concord Municipal Light Plant 

Consumers Energy 

Connecticut Light and Power 

Continental Cooperative 

 Services 

CPS Energy 

Crisp County Power 

 Commission 

Cumberland Valley Electric 

Decatur County Rural E M C 

Delmarva Power & Light Co 

Dominion North Carolina Power 

Dominion Virginia Power 

Duke Power 

Duquesne Light Co 

East-Central Iowa Rural Electric 

 Coop 

Econnergy Energy Co, Inc. 

El Paso Electric Co 

Elkhorn Light and Water 

Energy Investment Systems, Inc. 

Entergy Arkansas, Inc. 

Entergy Gulf States, Inc. 

Farmers Electric Coop, Inc. 

Farmers RECC 

Fleming-Mason Energy Coop 

 Inc. 

Florence Utilities 

Florida Power & Light Co 

Georgia Power Co 

Grand Valley Rural Power Lines, 

 Inc. 

Grayson Rural Electric Coop 

Green Mountain Power Corp 

Gunnison C E A Inc. 

Hartford Electric 

Hawaiian Electric Company, Inc. 

High Plains Power, Inc. 

Highline Electric Association 

Idaho Power Company 

Illinois Power Company 

Indiana Michigan Power Co 

Inter-County Energy Coop Corp 

Iowa Lakes Electric Cooperative 

Jackson Electric Membership 

 Corp 

Jackson Energy Cooperative 

 Corp 

JEA 

Jefferson Utilities 

Jemez Mountain Electric Coop, 

 Inc. 

Jersey Central Power & Light Co 

Johnson County REMC 

Kansas City Power & Light Co 

Kentucky Power Co 

Kentucky Utilities Co 

Kingsport Power Co 

La Plata Electric Association 

Laurens Electric Coop, Inc 

Long Island Power Authority 

Los Angeles Department of 

 Water and Power 

Lumbee River Electric 

Membership Corporation 

Madison Gas and Electric 

 Company 

Medford Electric Utility 

Menasha Utilities 

Metropolitan Edison Co 

MidAmerican Energy Company 

Montana-Dakota Utilities Co. 
Appendix H: DR Programs and Services at Responding Utilities 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

H-6 

Time-of-Use (Cont’d) 

Morgan County rural Elec Assn 

Navopache Electric Cooperative, 

 Inc. 

Nevada Power Company 

New Holstein Utilities 

New Richmond Utilities 

Niagara Mohawk 

Niobrara Electric Assn Inc 

North Central Power Co., Inc. 

Northern Indiana Public Service 

 Company 

Northern States Power Co (MN) 

Northern States Power Co (WI) 

Northwest Rural Public Power 

 District 

Northwestern Wisconsin Electric 

 Company 

Northern Rio Arriba Elec Coop 

NSTAR Electric 

Oconomowoc Utilities 

OGE Electric Services (DBA 

Oklahoma Gas and Electric) 

Ohio Power Company (OPCO) 

Oklahoma Electric Coo 

Orange & Rockland Utilities, Inc. 

Orlando Utilities Commission 

Owen Electric Cooperative 

Pacific Gas & Electric Co 

PacifiCorp 

PECO Energy Company 

Pee Dee Elect Mem Corp (NC) 

Pennsylvania Electric Co 

Pennsylvania Power Co 

Piedmont Electric Membership 

 Corporation 

Pioneer Electric Cooperative, 

 Inc. 

Portland General Electric 

 Company 

Poudre Valley R E A, Inc. 

Powder River Energy Corp 

Progress Energy Carolinas, Inc. 

Progress Energy Florida, Inc. 

PSI Energy Inc 

Public Service Co. of Oklahoma 

Public Service Company of New 

 Hampshire 

Public Service Company of New 

 Mexico 

Public Service Electric & Gas 

 Company 

Randolph Electric Membership 

 Corporation 

Rice Lake Utilities 

River Falls Municipal Utilities 

Riverside Public Utilities 

Rochester Gas & Electric Corp 

Roosevelt Public Power District 

Sacramento Municipal Utility 

District 

San Diego Gas and Electric 

San Luis Valley R E C 

Seattle City Light 

Shelby Energy Coop Inc 

Sierra Pacific Power Co 

Slinger Utilities 

South Beloit Water Gas and 

 Electric Co 

South Carolina Public Service 

 Authority 

South Central Indiana R E M C 

South Kentucky Rural Electric 

 Coop Corp 

Southeast Colorado Power Assn 

Southwestern Electric Power Co 

SRP 

Sterling Municipal Light 

Department 

Stoughton Utilities 

Sun Prairie Water & Light 

Taylor County RECC 

Texas North Company 

Toledo Edison Co 

Town of Reading Municipal Light 

Department 

Trico Electric Cooperative, Inc 

Tucson Electric Power Company 

Turlock Irrigation District 

TXU Energy Retail Company LP 

UGI Utilities, Inc. 

UIL 

Umatilla Electric Coop 

Union Electric Company 

Union Light, Heat & Power Co 

United Electric Cooperative 

Services, Inc. 

Unitil Energy Systems, Inc. 

Vermont Electric Coop 

Waverly Light and Power 

Westby Utilities 

Western Massachusetts Electric 

 Co 

Wheatland REA 

Wheeling Power Co 

Wisconsin Power and Light Co 

Wisconsin Public Service Corp
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-1

Appendix I. Data and Sources for Figures 

Executive Summary 

Figure ES-1. Penetration of advanced metering by region 

 *See Figure III-7 

Figure ES-2. Existing demand response resource contribution by NERC region and customer type 

 *See Figure V-6 

Figure ES-3. Demand response resource contributions by entity type and customer class 

 *See Figure V-3 

Chapter II 

Figure II-3. Elasticity of substitution varies by customer market segment 

Market Segment Elasticity

Commercial / Retail 0.05 

Gov't / Education 0.11 

Health Care 0.03 

Manufacturing 0.17 

Public Works 0.01 

All Accounts 0.11 

Source: Goldman, et al., Customer Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing: LBNL-57128, August 2005.

Chapter III 

 Figure III-4. United States penetration of advanced metering 

Penetration Rate Advanced Metering Non-Advanced Metering 

Total 5.9% 94.1% 

Source: FERC Survey 

Figure III-5. Penetration of advanced metering by customer class 

Customer Class Advanced Metering 

Residential 6.0%

Commercial 5.0%

Industrial 5.7%

Transportation 8.0%

Other 2.6%

Source: FERC Survey 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-2 

Figure III-6. Penetration of advanced metering by ownership 

Ownership Advanced Metering 

Cooperative 12.9% 

Investor Owned 5.7% 

Municipal Marketing Authority 2.0% 

Municipal 1.3% 

Political Subdivision 1.3% 

Power Marketer 0.5% 

Federal 0.4% 

CSP 0.3% 

State 0.1% 

ISO 0.0% 

Source: FERC Survey 

Figure III-7. Penetration of advanced metering by NERC region 

Region Advanced Metering 

RFC 14.7%

SPP 14.0%

SERC 5.2%

MRO 4.2%

NPCC 2.8%

FRCC 2.5%

WECC 1.0%

Other 0.2%

Source: FERC Survey 

Figure III-8. Advanced metering data interval and collection 

frequency penetration estimates 

Total meters Percent 

Daily Collection, Interval < 15 minutes 2.10%

Daily Collection, 15 minutes < Interval <= Hourly 5.04%

Advanced Metering 5.88%

Daily Collection, TOU 2.33%

Daily Collection, Interval <= Hourly or TOU 5.89%

Daily or Monthly Collection, Interval <= Hourly or TOU 7.01%

Monthly Collection, Interval <= Hourly or TOU 4.47%

Monthly Collection, TOU 2.79%

Monthly Collection, Interval <= Hourly 2.66%

Monthly Collection, 15 minutes < Interval <= Hourly 2.39%

Monthly Collection, Interval <= 15 minutes 1.25%

Source: FERC Survey 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-3

Figure III-9. Reported uses of AMI system by entities that use AMI 

Feature Yes, Entity Uses Capability 

Pricing event notification capability 3%

Interface with water or gas meters 6%

Price responsive DR 15%

Remotely change metering parameters 16%

Premise device - load control interface or capability 18%

Reduce line losses 19%

Asset mgmt, including transformer sizing 25%

Load forecasting 32%

Outage mgmt 40%

Power quality monitoring 41%

Tamper detection 52%

Enhanced customer service 73%

Source: FERC Survey 

Figure III-10. Large AMI deployments 

Year Fixed RF Power Line Comm Broadband Over 

Power Lines 

Pending Grand Total 

1994 450,000 450,000

1995 1,950,000 1,950,000

1996 1,900,000 1,900,000

1997 2,190,000 2,190,000

1999 2,420,000 650,000 3,070,000

2000 200,000 200,000

2001 450,000 450,000

2002 1,000,000 1,300,000 2,300,000

2004 125,000 125,000

2005 2,050,000 265,000 2,000,000 4,315,000

2006 4,100,000 5,100,000 4,300,000 13,500,000

2007 8,775,000 8,775,000

2008 4,475,000 4,475,000

Source: UtiliPoint International 

Figure III-11. Total AMI capital and hardware costs per meter 

Year Hardware Per Meter Total Capital per Meter 

1996 $99.23 

1997 $97.78 

1998 $100.00 

2000 $89.10 

2001 $86.15 $214.49 

2002 $86.15 $123.08 

2004 $68.18 $136.36 

2005 $75.60 $150.00 

2005 $73.57 $135.48 

2006 $86.43 $143.04 

Source: UtiliPoint International 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-4 

Figure III-12. AMI System Cost Breakdown 

Cost Component Cost 

Endpoint Hardware 0.45 

Network Hardware 0.2 

Installation 0.15 

Project Management 0.11 

IT 0.09 

Source: David Prins et. al. (CRA International), “Interval Metering Advanced Communications Study,” August 2005 

Figure III-14. Number of customers receiving interval usage information by customer class and 

source of information 

Source Residential Commercial Industrial Transportation Other TOTAL 

Via the internet 24,789 69,021 16,123 3 2,628 112,564

On their bills 75,836 24,421 3,708 4 2,914 106,883

Via the AMI network 5,641 789 249 0 35 6,714

TOTAL 106,266 94,231 20,080 7 5,577 226,161

Source: FERC Survey 

Chapter IV 

Figure IV-3. California CPP: Residential CPP Response by Attribute 

High vs. Low User 

200% Average Use 17.2%

50% Average Use 9.8%

Income 

>$100,000 15.1%

<$40,000 12.1%

Single vs. Multi-Family 

Single Family 13.5%

Multi-Family 9.8%

Central AC Ownership 

YES 12.8%

NO 12.3%

Pool Ownership 

YES 19.2%

NO 12.1%

State-wide Average 12.5%

Source: Roger Levy, Joint California Workshop, “Advanced Metering Results and Issues” September 2004. 

Figure IV-4. Average Residential Critical Peak Impacts by Rate Treatment 

Rate Type Peak Load Reduction 

Time of Use 4.1%

CPP-Fixed 12.5%

CPP-Variable 34.5%

Hottest CPP-Variable 47.4%

Source: Roger Levy, Joint California Workshop, “Advanced Metering Results and Issues” September 2004. 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-5

Figure IV-6. Direct Load Control programs offered by region and entity type 

Region Cooperative Utilities and 

Political Sub-divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 2

FRCC 3 2 1

MRO 43 1 14 33

NPCC 1 1 4 9

RFC 23 12 5

SERC 28 6 6

SPP 12 2 

WECC 5 5 2

Other 5 1 4

Source: FERC Survey 

Figure IV-7. Number of customers enrolled in DLC programs

Region Cooperative Utilities and 

Political Sub-divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 48,624

FRCC 68,482 1,142,290 3,079

MRO 432,817 347,750 468,569 39,678

NPCC 1,500 31,887 93,067 4,904

RFC 129,710 841,731 1042

SERC 222,791 334,551 31,828

SPP 29,113 17,147 

WECC 204,949 231,334 2,093

Other 20,797 7,837 2,219 1,161

Source: FERC Survey 

Figure IV-8. Number of entities offering interruptible/curtailable tariffs by region and entity 

type 

Region Cooperative Utilities and 

Political Sub-divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 1 1

FRCC 3 2 3

MRO 24 1 15 17

NPCC 1 7 16

RFC 15 22 2

SERC 31 2 8 2

SPP 16 2 2 4

WECC 2 7 2

Other 3 1 3 

Source: FERC Survey 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-6 

Figure IV-9. Number of entities offering capacity, demand bidding, and 

emergency programs by region 

Region Capacity Programs Demand Bidding Emergency 

ERCOT 0 1 0 

FRCC 0 0 0 

MRO 3 4 4 

NPCC 4 2 15 

RFC 3 1 3 

SERC 0 3 0 

SPP 1 0 0 

WECC 5 7 5 

Other 0 0 0 

Source: FERC Survey 

Figure IV-10. TOU tariffs offered to residential customers by entity type 

Region Cooperative Utilities and 

Political Sub-Divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 1 1 1

FRCC 1 2 2

MRO 7 12 21

NPCC 1 15 3

RFC 6 15 

SERC 23 1 12 2

SPP 4 5 

WECC 19 1 10 3

Other 1 

Source: FERC Survey 

Figure IV-11. Residential customers on TOU tariffs by region and entity type 

Region Cooperative Utilities and 

Political Sub-divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 60 1

FRCC 250 2

MRO 736 44003 215

NPCC 10818 55827 104

RFC 2424 681317 

SERC 5777 4 8107 58

SPP 6091 143870 

WECC 157483 3 447745 1845

Other 148 

Source: FERC Survey 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-7

Figure IV-12. RTP tariffs offered by region and entity type 

Region Cooperative Utilities and 

Political Sub-divisions 

Federal and 

State Utilities 

Investor-Owned 

Utilities 

Municipal 

Entities 

ERCOT 0 0 0 0

FRCC 0 0 0 1

MRO 1 0 8 0

NPCC 1 1 9 1

RFC 0 0 11 0

SERC 0 2 4 0

SPP 1 0 1 0

WECC 1 0 1 1

Other 0 0 1 0

Source: FERC Survey 

Figure IV-13. Drivers for developing or expanding demand response programs 

Drivers Percentage 

Less Pollution 18% 

Genreation Shortage 22% 

Add'l Power to Sell 22% 

Reduce Local Congestion 26% 

Fewer Brownouts/Blackouts 28% 

Reduce Energy Costs 30% 

Lower Energy Bills for Participants 36% 

Reliability 52% 

Regulatory 55% 

Reduce Utility Costs 55% 

Source: FERC Survey 

Chapter V 

Figure V-2. Demand response potential peak reduction 

by region and customer class

Region Residential Commercial Industrial Other (Agriculture) Wholesale 

ERCOT 53 9 315 0 1,485

FRCC 1,513 616 251 0 244

MRO 1,307 317 2,804 176 275

NPCC 236 822 591 33 1,618

RFC 1,033 1,502 660 8 3,962

SERC 758 243 3,586 51 248

SPP 84 168 99 17 635

WECC 807 1,054 1,251 304 431

Other 12 71 3 0 1

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-8 

Figure V-3. Demand response potential peak load reduction by type 

of entity and customer class 

Utility Type Residential Commercial Industrial Other 

(Agriculture) 

Wholesale

Investor-Owned Utility 3,927 3,377 5,158 246 395

Cooperative Utility and 

Political Sub-division 

1,232 406 930 306 941

Municipal Utility and 

Municipal Marketing Authority 

227 333 538 3 61

Curtailment Service Provider and 

Power Marketer 

0 162 387 0 0

Federal and State Utilities 416 517 2,541 33 367

ISO/RTO 0 0 0 0 7,134

Source: FERC Survey 

Figure V-4. Resource potential of various types of 

demand response programs and time-based tariffs

Program Residential Commercial Industrial Other 

(Agriculture) 

ISO/RTO 

Interruptible 82 1,103 6,266 58 

Direct Load Control 5,541 768 62 257 

Emergency Demand Response 62 892 252 12 1760

Capacity 350 150 2,091

Ancillary Services 10 1,547

Demand Bidding 104 250 2,414

Multiple 35 1,218 1,358 25 

Other 6 162 439 236 

Real-Time Pricing 0 445 659 

Critical Peak Pricing 16 39 57 0 

Time-of-Use 63 10 95 

Source: FERC Survey 

Figure V-5. Demand response resource potential versus actual deployed demand response 

resources by region

Region Potential Peak Reduction Actual Peak Reduction 

ERCOT 1,862 62 

FRCC 2,624 1,297 

MRO 4,878 2,227 

NPCC 3,301 447 

RFC 7,165 1,212 

SERC 4,887 1,606 

SPP 1,003 136 

WECC 3,847 1,675 

Other 88 55 

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-9

Figure V-6. FERC staff estimate of existing demand response 

resource contribution 

Region Residential Commercial Industrial Other (Agriculture) Wholesale 

ERCOT 55 24 327 0 1,485

FRCC 1,681 635 277 0 244

MRO 1,722 577 3,441 176 275

NPCC 267 859 690 33 1618

RFC 1,170 1,586 1,664 8 3,962

SERC 1,417 537 5,567 51 248

SPP 134 265 590 17 635

WECC 962 1,106 2,384 304 431

Other 12 72 41 0 1

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 

Figure V-7. FERC estimate of existing demand response resource contribution using old NERC 

region definitions 

Region Residential Commercial Industrial Other (Agriculture) Wholesale 

ERCOT 55 24 327 0 1,485

FRCC 1,666 635 256 0 244

MAPP 1,200 408 1,691 149 143

NPCC 226 814 680 33 1,619

MAIN 294 609 1,720 5 2,147

ECAR 819 272 2,174 28 745

MAAC 678 934 158 0 1,370

SERC 1,377 558 4,967 55 81

SPP 123 221 578 11 635

WECC 971 1,121 2,391 307 431

Other 11 66 38 0 0

Source: FERC Survey 

Notes: Other reliability region includes Alaska and Hawaii 
Appendix I: Data and Sources for Figures

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

I-10 

Figure V-8. FERC staff estimate of existing demand response resource contribution by entity 

type and customer class 

Utility Type Residential Commercial Industrial Other 

(Agriculture) 

Wholesale

Investor-Owned Utility 4,235 3,626 9,029 246 395

Cooperative Utility and 

Political Sub-division 

2,360 915 1,899 306 941

Municipal Utility and 

Municipal Marketing Authority 

338 433 903 3 61

Curtailment Service Provider and 

Power Marketer 

0 162 387 0 0

Federal and State Utilities 486 518 2,757 33 367

ISO/RTO 7,134

Source: FERC Survey 

Chapter VII

Figure VII-1. Regulator treatment of 

AMI and Demand Response 

Regulator Response Percent 

Yes - some recovery of prudent expenses 39% 

Yes - full recovery of prudent expenses 35% 

No 17% 

No reply 9% 

Source: Patti Harper-Slaboszewicz, UtiliPoint, “Regulator Interest in AMI and Demand Response,” written remarks submitted as panelist, 

FERC Technical Conference, 5
Appendix J: Acknowledgements 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

J-1

Appendix J: Acknowledgements 

Federal Energy Regulatory Commission

Team 

David Kathan, Team Lead 

Michael Goldenberg 

Norma McOmber 

Eileen Merrigan 

Aileen Roder 

Carol Brotman White 

Information Clearance Officer 

Michael P. Miller 

Editor 

John Jennrich 

Graphics 

Judy Eastwood 

Production and Logistics 

Commission Publishing Services Staff 

Valerie Mersier, Team Lead for Publishing 

 Services 

Michael Brown 

Kevin Wormley 

Technical Support and Advice 

UtiliPoint International, Inc 

Patti Harper-Slaboszewicz, Project Manager 

Ethan Cohen 

J. Christopher Purdue 

Maria Elena West 

Lawrence Berkeley National Laboratory 

Chuck Goldman 

Ranjit Bharvirkar 

Oak Ridge National Laboratory 

Brendan Kirby 

Demand Response and Advanced 

Metering Coalition (DRAM) 

Dan Delurey 

Mid-Atlantic Demand Response Initiative 

(MADRI) 

Richard E. Morgan

Survey Authorization 

Office of Management and Budget 

John A. Asalone, Desk Officer (FERC) 

Coordination of Efforts 

Government 

Energy Information Administration 

Robert Schnapp, Director Electric Power 

Division 

National Association of Regulatory 

Commissioners 

Grace D. Soderberg, Assistant General Counsel 

Industry 

American Public Power Association 

John Kelly 

Edison Electric Institute 

Richard Tempchin 

National Rural Electric Cooperative 

Association 

Jay Morrison 

Richard Meyer 
Appendix J: Acknowledgements

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

J-2 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-1

Errata: Corrected Advanced Metering and Demand 

Response Figures and Tables 

During the analysis of the 2008 FERC Survey, Commission staff identified several errors in the 

reported 2006 FERC Survey findings. The figures and tables below represent the corrected data for 

2006. Please use the figures and tables below in place of those similarly named in the Executive 

Summary and Chapters III and IV of the 2006 FERC Demand Response report.
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-2 

Table ES-1. States with the highest penetration of advanced metering 

Source: FERC Survey 

Revised December 2008 

Figure ES-1. Penetration of advanced metering by region 

3.0%

1.2%

0.7%

0.6% 0.5% 0.4%

0.1% 0.1% 0.0%

0%

1%

1%

2%

2%

3%

3%

4%

SPP SERC ERCOT MRO WECC RFC NPCC FRCC Other

NERC Region

Advanced Metering Penetration

Source: FERC Survey 

Revised December 2008 

State Advanced Metering 

Penetration 

Arkansas 5.0%

Idaho 3.9%

Alabama 3.3%

Oklahoma 3.0%

Colorado 1.7%

Georgia 1.7%

Kansas 1.3%

Kentucky 1.2%

South Carolina 1.0%

Illinois 0.8%
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-3

Figure III-4. United States penetration of advanced metering 

Non-Advanced 

Metering, 99.3%

Advanced 

Metering, 0.7%

Advanced Metering

Non-Advanced Metering

Source: FERC Survey 

Revised December 2008 

Figure III-5. Penetration of advanced metering by customer class 

2.2%

4.5%

3.7%

0.8%

0.6%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

5.0%

Other Transportation Industrial Commercial Residential

Customer Class

Advanced Metering Penetration

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-4 

Figure III-6. Penetration of advanced metering by ownership

3.8%

2.0%

0.3% 0.2% 0.2% 0.1% 0.1% 0.0%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

Cooperative Municipal

Marketing

Authority

Municipal Investor

Owned

Federal State Public Utility

District

ISO

Ownership

Advanced Metering Penetration

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-5

Figure III-7. Penetration of advanced metering by NERC region 

1.1%

15.5%

3.0% 2.5%

0.0%

4.1% 4.0%

16.4%

4.8%

0.4% 0.1% 0.1%

0.7%

1.2%

3.0%

0.6% 0.0% 0.5%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

SPP SERC ERCOT MRO WECC RFC NPCC FRCC Other

NERC Region

Advanced Metering Penetration

Capable of AMI Used for AMI

Source: FERC Survey 

Revised December 2008 

Table III-1. Penetration of AMI by region and customer class

Region Residential Commercial Industrial Transportation Other 

RFC 0.3% 0.5% 6.1% 89.8% 0.4% 

SPP 3.3% 1.4% 0.5% 48.6% 5.5% 

SERC 1.3% 0.8% 1.5% 6.5% 2.9% 

ERCOT 0.7% 0.7% 0.6% 0.0% 0.0% 

MRO 0.5% 0.7% 10.0% 0.0% 0.2% 

NPCC 0.1% 0.6% 4.8% 1.4% 3.4% 

FRCC 0.1% 0.2% 35.0% 0.0% 0.0% 

WECC 0.3% 1.2% 6.4% 0.5% 4.6% 

Other 0.0% 0.0% 0.1% 0.0% 0.1% 

Total 0.6% 0.8% 3.7% 4.5% 2.2% 

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-6 

Table III-2. Penetration of advanced metering by state

State Advanced Meters Total Meters Penetration 

Alabama 89,702 2,738,519 3.3% 

Alaska 6 305,949 0.0% 

Arizona 5,521 2,783,083 0.2% 

Arkansas 75,118 1,494,383 5.0% 

California 40,153 14,253,873 0.3% 

Colorado 39,274 2,263,873 1.7% 

Connecticut 3,862 1,580,365 0.2% 

Delaware 16 421,331 0.0% 

District of Columbia 0 809,412 0.0% 

Florida 8,479 9,679,565 0.1% 

Georgia 73,312 4,404,447 1.7% 

Hawaii 45 465,314 0.0% 

Idaho 29,062 739,199 3.9% 

Illinois 43,043 5,510,470 0.8% 

Indiana 13,137 3,217,359 0.4% 

Iowa 110 1,591,985 0.0% 

Kansas 18,913 1,430,953 1.3% 

Kentucky 27,501 2,225,485 1.2% 

Louisiana 44 1,037,355 0.0% 

Maine 716 773,164 0.1% 

Maryland 130 1,972,886 0.0% 

Massachusetts 6,940 3,244,778 0.2% 

Michigan 31,254 4,877,345 0.6% 

Minnesota 11,780 2,537,414 0.5% 

Mississippi 82 1,015,493 0.0% 

Missouri 8,986 3,087,821 0.3% 

Montana 162 529,135 0.0% 

Nebraska 1,520 937,148 0.2% 

Nevada 17 1,193,873 0.0% 

New Hampshire 306 759,514 0.0% 

New Jersey 25,222 3,884,140 0.6% 

New Mexico 1 875,393 0.0% 

New York 3,071 7,906,309 0.0% 

North Carolina 29,411 4,681,178 0.6% 

North Dakota 29 367,776 0.0% 

Ohio 1,958 6,307,050 0.0% 

Oklahoma 60,273 2,024,592 3.0% 

Oregon 2,960 1,821,710 0.2% 

Pennsylvania 18,200 6,053,110 0.3% 

Rhode Island 398 480,275 0.1% 

South Carolina 19,655 2,007,339 1.0% 

South Dakota 7 484,728 0.0% 

Tennessee 426 3,165,211 0.0% 

Texas 28,200 10,195,134 0.3% 

Utah 1 1,036,605 0.0% 

Vermont 1 331,161 0.0% 

Virginia 5,016 3,412,011 0.1% 

Washington 477 3,061,233 0.0% 

West Virginia 17 1,234,035 0.0% 

Wisconsin 19,882 2,983,075 0.7% 

Wyoming 0 272,033 0.0% 

Source: FERC Survey – Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-7

Figure IV-6. Direct Load Control programs offered by region and entity 

type 

0

20

40

60

80

100

120

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities offering DLC programs

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political Sub-divisions

Source: FERC Survey 

Revised December 2008 

Figure IV-7. Number of customers enrolled in DLC programs 

(Number of responding entities = 229) 

-

300,000

600,000

900,000

1,200,000

1,500,000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Customers Enrolled in DLC

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political

Sub-divisions

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-8 

Table IV-1. Number of entities offering incentive-based demand response 

programs in the United States

Type of Program Number of Entities 

Direct Load Control 245 

Interruptible/Curtailable 253 

Emergency Demand Response Program 59 

Capacity Market Program 34 

Demand Bidding/Buyback 30 

Ancillary Services 19 

Source: FERC Survey 

Revised December 2008 

Table IV-2. Top 10 entities by customers enrolled in DLC programs 

Name of Utility Number of Customers 

Enrolled in DLC 

Florida Power and Light 721,728 

Progress Energy Florida 401,392 

Detroit Edison 347,750 

Baltimore Gas and Electric 322,190 

Northern States Power 271,744 

Duke Power 207,772 

Southern California Edison 163,545 

Public Service Electric & Gas 119,310 

Buckeye Power 114,500 

Dairyland Power Cooperative 112,000 

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-9

Figure IV-8. Number of entities offering interruptible / curtailable tariffs 

by region and entity type 

0

10

20

30

40

50

60

70

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities offering I/C Programs

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and

Political Sub-divisions

Source: FERC Survey 

Revised December 2008 

Figure IV-9. Number of entities offering capacity, demand bidding, and 

emergency programs by region 

0

5

10

15

20

25

30

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities

Capacity Programs

Demand Bidding

Emergency

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-10 

Table IV-3. Number of entities offering time-based rates in the United 

States

Type of Program Number of Entities 

Time-of-Use Rates 366 

Real-time Pricing 60 

Critical Peak Pricing 36 

Source: FERC Survey 

Revised December 2008 

Figure IV-10. TOU tariffs offered to residential customers by entity type 

-

20

40

60

80

100

120

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities that offer TOU

 Tarrifs to Residential Customers

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political Subdivisions

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-11

Figure IV-11. Residential customers on TOU tariffs by region and entity 

type

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Residential Customers Enrolled in TOU

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and

Political Sub-divisions

Source: FERC Survey 

Revised December 2008 

Table IV-4. Top 10 entities by residential customers enrolled in TOU 

programs

Name of Utility Number of Residential 

Customers enrolled in TOU 

Columbus Southern Power Co 635,836 

Public Service Co of Oklahoma 429,737 

Arizona Public Service Company 378,841 

Salt River Project 151,000 

Southwestern Electric Power Co 135,816 

Pacific Gas and Electric Company 82,182 

Baltimore Gas and Electric Company 81,072 

Ohio Power Company 38,524 

FirstEnergy Corporation 35,640 

United Illuminating Company 35,041 

Source: FERC Survey 

Revised December 2008 
Errata to the 2006 Report 

1⁄2 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

Errata-12 

Table IV-5. Top five entities by number of customers enrolled in CPP 

programs 

Name of Utility Number of Customers 

enrolled in CPP 

Constellation NewEnergy 63,500 

Gulf Power Company 6,878 

Cass County Electric Cooperative 2,892 

San Diego Gas and Electric 1,410 

Source: FERC Survey 

Revised December 2008 

Figure IV-12. RTP tariffs offered by region and entity type 

-

5

10

15

20

ERCOT FRCC MRO NPCC RFC SERC SPP WECC Other

Number of Entities

Offering RTP rates

Federal and State Utilities

Investor-Owned Utilities

Municipal Entities

Cooperative Utilities and Political

Sub-divisions

Source: FERC Survey 

Revised December 2008