2012

Assessment of

Demand Response and Advanced Metering

Staff Report

Federal Energy Regulatory Commission

December 2012

The opinions and views expressed in this staff report do not necessarily represent those of the 

Federal Energy Regulatory Commission, its Chairman, or individual Commissioners, and are 

not binding on the Commission.
ACKNOWLEDGEMENTS

Federal Energy Regulatory Commission Staff Team

David Kathan, Team Lead

Robin Aldina

Michael P. Lee

Lisa Medearis

Pamela Sporborg

Michael Tita

Dean Wight

Andy Wilkerson

Z, INC. Team

French Kreger (Z, INC.)

Valerie Richardson (DNV-KEMA)

Will Gifford (DNV-KEMA)

Christopher Elsner (Z, INC.)
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission i

TABLE OF CONTENTS

Executive Summary.................................................................................................................. 1

Chapter 1. Introduction ............................................................................................................ 3

Preparation of This Year’s Report ........................................................................................ 3

Demand Response and Advanced Metering Survey............................................................. 4

Report Organization.............................................................................................................. 4

Regions in This Report ......................................................................................................... 5

Chapter 2. Advanced Metering Infrastructure ......................................................................... 7

Definition of Advanced Metering......................................................................................... 7

Advanced Metering Penetration ........................................................................................... 8

Analytical Approach ..........................................................................................................8

Survey Findings .................................................................................................................8

Customer Accessibility of Advanced Metering Data ......................................................... 13

Developments and Issues in Advanced Metering............................................................... 14

Status of the Advanced Metering Deployments Funded by the American Recovery 

and Reinvestment Act .................................................................................................15

Green Button Initiative ....................................................................................................15

Expanded Customer Service Offerings............................................................................15

Use of Advanced Metering Data for Non-Billing Applications......................................16

Opt-Out Programs............................................................................................................17

Chapter 3. Demand Response ................................................................................................ 21

Definition of Demand Response......................................................................................... 21

Survey Results .................................................................................................................... 22

Analytical Approach ........................................................................................................22

Summary of Report Findings...........................................................................................22

Demand Response Activities at the FERC ......................................................................... 36

Commission Demand Response Activities......................................................................36

Other Demand Response Developments and Issues........................................................... 42

National Forum on the National Action Plan on Demand Response...............................42

U.S. Department of Energy-Sponsored Consumer Behavior Studies..............................42

NERC Demand Response Data Collection......................................................................43

Summer 2012 Demand Response Deployments..............................................................44

Selected State Activities ..................................................................................................45

Barriers to Demand Response............................................................................................. 49

Chapter 4. Smart Grid Developments Supporting Demand Response .................................. 51

Demand Response-Related Smart Grid Standards Development....................................... 51

Demand Response Activities within the NIST/SGIP Process.........................................51

Smart Grid Demonstration Program................................................................................... 54

Appendix A: Section 1252 of the Energy Policy Act of 2005................................................ 57

Appendix B: Acronyms and Abbreviations........................................................................... 61

Appendix C: Glossary............................................................................................................. 63

Appendix D: 2012 FERC Survey Method.............................................................................. 73

Background......................................................................................................................... 73

Development of the FERC Survey and Sampling Design .................................................. 73

The Survey Population........................................................................................................ 75
ii Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

FERC Survey Methodology................................................................................................ 75

Working with the Data........................................................................................................ 76

Advanced Metering..........................................................................................................76

Demand Response............................................................................................................77

Eliminating Double-Counting in Wholesale Demand Response........................................ 78

Appendix E: FERC Survey Respondents ............................................................................... 81

Appendix F: Demand Response Programs and Services at Responding Entities................... 99

Appendix G: Data for Figures in Report............................................................................... 107

Advanced Metering........................................................................................................... 107

Demand Response............................................................................................................. 108

Appendix H: Adjustment Methodology for FERC-731 Survey ........................................... 115

Self-Selection Assessment Subsample ............................................................................. 116

Assessment of Past Designs.............................................................................................. 117

2012 Self-Selection Bias Assessment Design................................................................... 117

Survey Response Rates..................................................................................................... 118

Self-Selection Bias Assessment........................................................................................ 118

LIST OF TABLES

Table 2-1. Entities with the five largest 2010 to 2012 increases in reported advanced 

meters................................................................................................................ 9

Table 2-2. Estimated advanced metering penetration by region and customer class ............. 11

Table 2-3. Estimated penetration of advanced metering by state in 2008 – 2012.................. 12

Table 3-1. Demand response program types in the 2012 FERC Survey ................................ 21

Table 3-2. Reported potential peak reduction in Megawatts by program type and state........ 28

Table 3-3. Reported plans for new demand response programs and time-based 

rates/tariffs ...................................................................................................... 32

Table D-1. Survey Population for the 2012 FERC Survey..................................................... 75

LIST OF FIGURES

Figure 1-1. NERC regions. ....................................................................................................... 6

Figure 2-1. Estimated advanced metering penetration nationwide reported in FERC 

Surveys 2006, 2008, 2010, and 2012................................................................ 8

Figure 2-2. Estimated advanced metering penetration nationwide in 2006, 2008, 2010 

and 2012 FERC Surveys................................................................................. 10

Figure 2-3. Estimated advanced metering penetration by type of entity in 2006, 2008 

and 2010, and 2012 FERC Surveys................................................................ 14

Figure 2-4. Reported numbers of customers and communication methods for advanced 

metering by customer class............................................................................. 14

Figure 3-1. Total reported potential peak reduction in the 2006 through 2012 FERC 

Surveys............................................................................................................ 23

Figure 3-2. Reported potential peak reduction by customer class in 2006, 2008, 2010 

and 2012.......................................................................................................... 23

Figure 3-3. Reported potential peak reduction by Independent System Operators and 

Regional Transmission Operators in 2010 and 2012...................................... 25
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission iii

Figure 3-4. Reported potential peak reduction by region and customer class for the 

2010 and 2012 FERC Surveys........................................................................ 25

Figure 3-5. Reported potential peak reduction by program type and by customer class 

in 2012 FERC Survey ..................................................................................... 27

Figure 3-6. Reported actual peak reduction by NERC region between 2010 and 2012 

FERC Survey years......................................................................................... 30

Figure 3-7. 2012 FERC Survey reported potential and actual peak reduction by region....... 30

Figure 3-8. Estimated potential peak reduction by region and customer class in 2010 

and 2012.......................................................................................................... 31

Figure 3-9. Estimated potential peak reduction by entity type and customer class in 

2010 and 2012................................................................................................. 32

Figure 3-10. Number of entities reporting interruptible/curtailable rates by region and 

type of entity in 2010 and 2012 ...................................................................... 33

Figure 3-11. Reported number of customers enrolled in direct load control programs by 

region and type of entity in 2010 and 2012 .................................................... 34

Figure 3-12. Number of entities reporting residential time-of-use rates by region and 

type of entity in 2010 and 2012 ...................................................................... 35

Figure 3-13. Reported number of residential customers enrolled in time-of-use rates by 

region and entity type in 2010 and 2012......................................................... 35

Figure 3-14. Number of entities reporting retail real-time pricing by region and entity 

type in 2010 and 2012..................................................................................... 36

2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 1

EXECUTIVE SUMMARY

In the past year, significant progress has been achieved for both wholesale and retail 

electricity demand response and advanced metering, supported by the actions of state 

regulators, federal regulators and federal funding under the American Recovery and 

Reinvestment Act, the development of interoperability standards, and efforts of industry and 

customers. According to information provided by survey respondents to the Federal Energy 

Regulatory Commission (FERC) 2012 Demand Response and Advanced Metering Survey, 

the potential demand response resource contribution from all U.S. demand response 

programs is estimated to be nearly 72,000 megawatts (MW), or about 9.2 percent of U.S. 

peak demand. This is an increase of about 13,000 MW from the 2010 FERC Survey. The 

regions with the largest estimated demand response capability are the Midwest-to-MidAtlantic region, the Southeast, and the Upper Midwest. With regard to advanced metering, 

penetration reached approximately 22.9 percent in 2011 in the United States, compared to 

approximately 8.7 percent in the 2010 FERC Survey (covering calendar year 2009). Florida, 

Texas, and the West have advanced meter penetrations exceeding 30 percent. As in previous 

surveys, electric cooperatives have the largest penetration, nearly 31 percent, among 

categories of organizations.

More than 1,900 entities responded to the voluntary FERC survey and many made 

themselves available for follow-up questions. FERC staff greatly appreciates the responses 

and assistance in completing the information for this Report. 
2 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 3

CHAPTER 1. INTRODUCTION

The Energy Policy Act of 2005 (EPAct 2005) requires the FERC to prepare and publish an 

annual report on the penetration of advanced metering and demand response programs in the 

electric power industry in the United States. This data is to be divided and presented by 

region, and the information is to cover all types of electric consumers. 

EPAct 2005 expressly requires that the Commission’s annual report 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. 

This Report is the fourth annual comprehensive report based on a first-of-its-kind survey of 

demand response and advanced metering. The first report was published in August 2006, 

Assessment of Demand Response and Advanced Metering.

1

 Since 2006, Commission staff 

has published a series of annual reports assessing demand response and advanced metering in 

the U.S. In support of these reports, the FERC staff has conducted comprehensive 

nationwide surveys every other year. In intervening years reports consist of updates based on 

publicly-available information and discussions with market participants and industry experts. 

Commission staff published its most recent annual report in November 2011.2 

Preparation of This Year’s Report

In preparing this report, Commission staff undertook several activities, the most significant 

being the preparation and release of the Demand Response and Advanced Metering Survey 

(2012 FERC Survey). Commission staff also reviewed relevant literature and recent 

developments on advanced metering, demand response programs, and time-based rates. As 

with past surveys, the 2012 FERC Survey gathers data for the previous calendar year, 2011.

 

1

FERC, Assessment of Demand Response & Advanced Metering: Staff Report, Docket No. AD06-2, August 7, 

2006, available at http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-advmetering.asp. 

2

FERC, Assessment of Demand Response & Advanced Metering: Staff Report, November 2011. The annual 

reports are available at http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-advmetering.asp. 
4 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Demand Response and Advanced Metering Survey

The 2012 FERC Survey was conducted in the spring months of 2012 and requested 

information from 3,349 entities in all 50 states,

3

representing all aspects of the electricity

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

power marketers, state and federal agencies, and other demand response providers.4 The 

survey sought the following: (a) general information about the entity responding to the 

survey, including contact information, customer size, and electricity demand and 

consumption; (b) the number of advanced meters and their use; (c) existing demand response 

and time-based rate programs, including their current level of resource contribution; and (d) 

plans for future demand response program offerings. Like the 2010 Survey, the 2012 FERC 

Survey combined advanced metering and demand response questions into one survey form. 

The FERC staff also made efforts to enhance the clarity of instructions and definitions for the 

2012 FERC Survey.

More than 1,978 entities responded to the 2012 FERC Survey, representing a response rate of 

over 59 percent. This is an increase from the 2010 FERC Survey response rate of 52 percent. 

Information gathered through the 2012 FERC Survey serves as the basis for this report’s 

estimates of the market penetration5of advanced metering, demand response resource 

contributions, and current demand response and time-based rate programs. This report also 

utilizes results from the 2010, 2008 and 2006 FERC Surveys to assess trends in advanced 

metering deployment and demand response in the U.S.

Report Organization

The Introduction (Chapter 1) of this report describes the report’s structure, along with a 

brief overview of the 2012 Survey methodology and key findings. The following chapters 

provide the information required by EPAct 2005 section 1252(e)(3). 

Advanced Metering Infrastructure (Chapter 2) presents survey results on the penetration 

of advanced metering nationally, regionally, by type of utility, customer class, and by state. 

This chapter also discusses the key new developments, issues, and trends in the deployment 

and adoption of advanced metering. The chapter concludes with a description of major 

challenges and issues for advanced metering in the U.S.

Demand Response (Chapter 3) presents survey results on demand response programs

(including time-based rate programs), and provides the regional and national distribution of 

these programs. The chapter also includes estimates of the overall size of demand response 

resources in the U.S. Chapter 3 then reviews demand response trends and developments at 

the national and state level, and identifies several key trends in demand response. This 

chapter also reviews Commission demand response activities and steps that have been taken 

to ensure comparable treatment of demand response in regional transmission planning. 

 

3 Later in the process it was determined that 15 of these entities were either out of business or not in a relevant 

business.

4 Appendices D and H include detailed information on the survey and sample design. Appendix E lists the 

respondents to the survey.

5

Penetration, for the purposes of this report, refers to the ratio of advanced meters to all installed meters. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 5

Finally, Chapter 3 concludes with a summary of potential barriers to demand response, as 

identified by various sources. 

Smart Grid Standards Development (Chapter 4) is a new section in this report series, and 

provides an overview of work underway to develop and implement smart grid 

interoperability standards that help support demand response. 

This report also includes eight appendices that provide reference material and additional 

detail on the survey data and responses. Appendix A provides the statutory language in 

section 1252 of EPAct 2005. Appendix B lists the acronyms used in this report. Appendix 

C contains a glossary of the key terms used in this report and the 2012 survey. Appendix D

provides additional detail on the 2012 FERC Survey and survey response rates. Appendix E

lists the entities who responded to the 2012 FERC Survey. Appendix F lists the entities that 

reported operating demand response programs in the 2012 survey. Appendix G provides 

data tables associated with each of the figures in this report. Appendix H describes the 

estimation methods used in this report. 

Regions in This Report

As in past reports, Staff is presenting the results of the 2012 Survey by NERC region. NERC

(North American Electric Reliability Council) is an international nonprofit organization 

certified by the FERC as the electric reliability organization for the U.S. The 2012 FERC 

Survey uses NERC’s eight regional divisions to better identify trends and align regulatory 

and industry geographical units. The regional entities are:

 Florida Reliability Coordinating Council (FRCC)

 Midwest Reliability Organization (MRO)

 Northeast Power Coordinating Council (NPCC)

 ReliabilityFirst Corporation (RFC)

 SERC Reliability Corporation (SERC)

 Southwest Power Pool (SPP)

 Texas Reliability Entity (TRE)

 Western Electricity Coordinating Council (WECC)

The map in Figure 1.1 illustrates the boundaries of the NERC regions. Although some 

NERC regions include areas in Canada and Mexico, the Commission only requested data 

from the U.S. portions of these NERC regions. In this report, Hawaii and Alaska are not 

included in most regional data summaries, but are included in state-level data tables. 
6 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Figure 1-1. NERC regions.

FRCC - Florida Reliability Coordinating Council

MRO - Midwest Reliability Organization

NPCC - Northeast Power Coordinating Council

RFC - ReliabilityFirst Corporation

SERC - SERC Reliability Corporation

SPP - Southwest Power Pool

TRE - Texas Reliability Entity

WECC - Western Electricity Coordinating Council

Source: North American Electric Reliability Corporation, July 2012.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 7

CHAPTER 2. ADVANCED METERING INFRASTRUCTURE

This chapter reports on the first topic in EPAct 2005 section 1252(e)(3):

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

technologies, devices and systems.

The information presented is divided into the following three sections and is based on the 

2012 FERC Survey, with comparisons to previous FERC Surveys (as appropriate) to 

demonstrate trends in advanced metering deployment on a regional basis, by type of entity, 

and by customer type.6 

 Definition of Advanced Metering

 Advanced Metering Penetration

 Developments and Issues in Advanced Metering

All figures and tables are labeled “Estimated...” This indicates that additional information 

was used in conjunction with 2012 FERC Survey data to improve the accuracy of Staff’s 

estimates. A detailed description of these estimation methods can be found in Appendix H. 

Definition of Advanced Metering

For the 2012 FERC Survey, FERC staff used the following definition of advanced meters:

Advanced Meters: Meters that measure and record usage data at hourly intervals or 

more frequently, and provide usage data to both consumers and energy companies at 

least once daily. Data are used for billing and other purposes. Advanced meters 

include basic hourly interval meters, meters with one-way communication, and realtime meters with built-in two-way communication capable of recording and 

transmitting instantaneous data.

Several respondents to the 2012 FERC Survey provided lower advanced meter counts than in 

previous FERC Surveys. Respondents that reported large declines were contacted for 

explanation. During these calls, staff learned anecdotally that many of the reported declines 

were due to respondents reclassifying their responses based on a better understanding of the 

survey’s “advanced meter” definition. For example, many respondents had installed meters 

with advanced metering capability, but were still in the process of programming the software 

and establishing the infrastructure to allow for communication on a daily basis. 

Consequently, these installed meters did not meet the advanced meter definition.

 

6 A full database of survey responses is available at 

http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-adv-metering.asp.
8 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Advanced Metering Penetration

This section describes the analytical approach used in the 2012 FERC Survey and provides 

summary findings.

Analytical Approach

Commission Staff estimates of advanced metering penetration in the U.S. are primarily based 

on the 2012 FERC Survey data. However, the 2012 advanced metering data was 

supplemented by past FERC Survey data and survey data from the Energy Information 

Administration’s Annual Electric Power Industry Report (i.e., Form EIA-861 survey data)7

for this report. In contrast to previous years, the 2012 estimation methods both fill in missing 

data and correct for reporting errors. A detailed explanation of these estimation methods can 

be found in Appendix H.

Survey Findings

Results indicate significant growth in advanced metering deployment in the U.S. As Figure 

2-1 illustrates between 2006 and 2012, the number of advanced meters currently operating in 

the U.S. (38 million) as a percentage of total meters installed is estimated to be 23 percent. 

This represents a 14 percentage point increase from 2010 levels.

Figure 2-1. Estimated advanced metering penetration nationwide reported in

FERC Surveys 2006, 2008, 2010, and 2012

Secondary sources suggest that advanced metering deployment will continue to increase 

significantly past 2012. While as noted above the FERC Survey reports nearly 38 million 

advanced meters installed as of December 31, 2011, the Institute for Energy Efficiency (IEE) 

 

7 The Energy Information Administration collects information on advanced metering in its annual Form EIA861 (Annual Electric Power Industry Report). As Appendix H describes, EIA provided FERC staff with 

preliminary Form EIA-861 data to help improve estimation.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 9

projects that a total of 65 million advanced meters will be deployed by 2015.8 In addition, 

recipients of U.S. Department of Energy Smart Grid Investment Grants report adding almost 

1 million advanced meters over the first and second quarters of 2012.9 

The following tables and figures in this chapter provide detailed information on the estimated 

38 million advanced meters operating in the U.S. by geographic region, customer class, and 

ownership category. Table 2-1 below lists the respondents with the five largest increases in 

advanced meters from 2010 to 2012 (ranked by the size of the increase in reported advanced 

meters).

Table 2-1. Entities with the five largest 2010 to 2012 increases in reported 

advanced meters

The advanced metering deployments shown in Table 2-1 are currently in the middle to late 

stages of deployment. The funding for these advanced metering deployments were primarily 

subject to state commission-approved cost recovery. For example, the California Public 

Utility Commission authorized two of the state’s primary investor-owned utilities, Southern 

California Edison and Pacific Gas and Electric, to replace conventional meters with advanced 

meters.10 Southern California Edison expects to complete its deployment of approximately 5 

million advanced meters by the end of 2012, and reports that this deployment was 

approximately 78 percent complete as of January 2012.11 Pacific Gas and Electric reports 

installing nearly 4.7 million advanced meters as of November 2011, and expects to complete 

its advanced meter rollout by mid-2013.12 

 

8

Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans, & Proposals, May 2012, 

available at http://www.edisonfoundation.net/iee/Documents/IEE_SmartMeterRollouts_0512.pdf.

9

SmartGrid.gov, Advanced Metering Infrastructure and Customer Systems, available at

http://www.smartgrid.gov/recovery_act/deployment_status/ami_and_customer_systems.

10 California Public Utilities Commission, The Benefits of Smart Meters, available at

http://www.cpuc.ca.gov/PUC/energy/Demand+Response/benefits.htm.

11 California Public Utilities Commission, California Division of Ratepayer Advocates, Case Study of Smart 

Meter System Deployment: Recommendations for Ensuring Ratepayer Benefits, March 2012, available at

http://www.dra.ca.gov/uploadedFiles/Content/Energy/Management_and_Conservation/Smart_Meters/SmartMet

erSystemDeploymentReportMar2012FinalDraft_wcover_Public.pdf.

12 PG&E, SmartMeterTM Program Data, 12/13/2011, available at

http://www.pge.com/includes/docs/pdfs/myhome/customerservice/meter/smartmeter/SmartMeterProgramData_

12-13-11.pdf.

Entity Name

NERC 

Region State

2010 

Advanced 

Meters

2012 

Advanced 

Meters

Advanced Meter 

Increase

Advanced Metering 

Penetration

Southern California Edison WECC CA 147,645 3,740,640 3,592,995 75.2%

Florida Power & Light Company FRCC FL 202,510 2,675,479 2,472,969 58.8%

Pacific Gas and Electric Company WECC CA 2,085,712 4,508,036 2,422,324 88.7%

Oncor Electric Delivery Company TRE TX 662,774 2,664,462 2,001,688 83.5%

Puget Sound Energy, Inc. WECC WA 7,432 1,900,306 1,892,874 99.9%
10 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

2006 Survey 0.6% 0.5% 0.7% 3.0% 1.2% 0.4% 0.1% 0.0% 0.0% 0.1%

2008 Survey 3.7% 2.1% 9.0% 5.8% 5.8% 5.1% 10.4% 1.6% 0.0% 0.3%

2010 Survey 15.3% 14.1% 13.4% 8.9% 8.0% 6.7% 5.0% 2.1% 1.2% 0.7%

2012 Survey 14.6% 42.4% 38.6% 15.2% 22.0% 10.4% 32.5% 0.2% 0.0% 5.3%

Figure 2-2 illustrates how advanced metering penetration has increased in nearly every 

region in the continental U.S. between 2010 and 2012.13 In 2010, no NERC region had an 

advanced metering penetration rate over 20 percent; by contrast, Staff estimates that three 

regions (FRCC, TRE and WECC) now have an advanced metering penetration rate over 30 

percent. WECC has the highest advanced metering penetration rate of over 40 percent. This 

is primarily driven by investor-owned utility rollouts in California, Oregon, Nevada, Idaho, 

and Arizona. 

Figure 2-2. Estimated advanced metering penetration nationwide in 2006, 

2008, 2010 and 2012 FERC Surveys

Table 2-2 compares the estimated penetration of advanced meters by customer class across 

the 2008, 2010 and 2012 FERC Surveys. The increases in advanced metering penetration are 

generally driven by the residential sector. However, advanced metering penetration for 

nonresidential customers has also increased significantly in some regions, most notably 

WECC and TRE, where advanced metering penetration is estimated to be over 30 percent.

 

13 A notable departure from the trend of increasing advanced metering penetration between the 2010 and 2012 

Surveys is for the MRO region, where there was an apparent slight decrease in advanced metering penetration 

as compared to the 2010 FERC Survey estimate. Small decreases in penetration appeared in Hawaii and ASCC 

as well. In the MRO region, Wisconsin Public Service reported a decline in 375,000 advanced meters between 

survey years. Follow-up conversations revealed that in the 2010 FERC Survey Wisconsin Public Service had 

mistakenly reported automated meter reading (AMR) meters as advanced meters, and corrected for this in 2012. 

Most of the decline in Hawaii was due to suspected AMR entries as well, discovered through comparison 

analysis with the 2011 EIA-861 Survey preliminary database. In ASCC, no 2012 responses reporting advanced 

meters were received, but a small number of advanced meters were estimated for one entity in ASCC in 2010.

14.6%

42.4%

38.6%

15.2%

22.0%

10.4%

32.5%

0.2% 0.0%

5.3%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

MRO WECC TRE SPP SERC RFC FRCC Hawaii ASCC NPCC

Penetration

2006 Survey 2008 Survey 2010 Survey 2012 Survey
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 11

Table 2-2. Estimated advanced metering penetration by region and customer 

class

Table 2-3 lists estimated market penetration rates of advanced meters by state. The largest 

increase in advanced metering market penetration was in the District of Columbia; 

penetration in D.C. is estimated to increase from nearly zero percent in the 2010 survey to 

over 80 percent in the 2012 survey.14 This can be attributed to the Potomac Electric Power 

Company (Pepco) advanced metering rollout that began in 2011.15 

California has the second-highest market penetration rate in the country, 70 percent. This is 

primarily due to advanced metering rollouts by two utilities: Southern California Edison and 

Pacific Gas and Electric.16 There were also large advanced metering deployments in other 

Western states such as in Oregon, Nevada, Idaho, and Arizona. Each of these states has a 

market penetration rate over 50 percent and contains at least one investor-owned utility that 

deployed over 200,000 advanced meters between 2010 and 2012.17 

Georgia’s advanced metering market penetration rate increased by almost 54 percentage 

points from 2010 to 2012. The majority of this growth came from Cooperatives such as the 

Central Georgia Electric Membership Corp., which added over 140,000 advanced meters 

between 2010 and 2012.

 

14 As noted in the 2010 Assessment of Demand Response & Advanced Metering: Staff Report, the large apparent 

decrease in advanced meter count and total meter count for the District of Columbia from 2008 to 2010 was due 

to a correction in reporting that erroneously included Pepco’s meters in the Maryland suburbs in the District of 

Columbia estimate.

15 In July 2011, Pepco began a smart-meter rollout that was expected to include over 500,000 customers by the 

end of 2012, and complete their D.C. deployment by the end of 2011. Pepco smart-meter rollout announcement

is available at http://www.pepco.com/welcome/news/releases/archives/2011/article.aspx?cid=1787.

16 As highlighted in Table 2-1, Southern California Edison and Pacific Gas & Electric (both located in 

California) were the first and third largest entities adding AMI meters in the country, respectively. Pacific Gas 

& Electric is focused on installing advanced meters for all their customers by 2013, with over 9 million already

installed. See

http://www.pge.com/myhome/customerservice/smartmeter/installation/.

17 Arizona Public Service in Arizona, Idaho Power Company in Idaho, Nevada Power Company in Nevada, and 

Portland General Electric Company in Oregon. FERC Survey

Region

MRO 3.7% 15.3% 14.6% 4.0% 15.8% 15.3% 2.2% 11.9% 8.9%

WECC 2.1% 14.1% 42.4% 2.1% 14.9% 43.5% 2.0% 9.1% 33.5%

TRE 9.0% 13.4% 38.6% 8.5% 13.4% 39.0% 12.4% 13.1% 34.1%

SPP 5.8% 8.9% 15.2% 6.1% 9.2% 15.9% 4.2% 7.5% 11.6%

SERC 5.8% 8.0% 22.0% 6.1% 8.3% 24.6% 3.2% 5.9% 5.6%

RFC 5.1% 6.7% 10.4% 5.0% 6.7% 10.9% 6.1% 6.9% 6.2%

FRCC 10.4% 5.0% 32.5% 10.8% 5.2% 34.5% 7.8% 3.3% 17.1%

Hawaii 1.6% 2.1% 0.2% 1.6% 2.2% 0.1% 1.6% 1.8% 0.4%

ASCC 0.0% 1.2% 0.0% 0.0% 1.3% 0.0% 0.0% 0.6% 0.0%

NPCC 0.3% 0.7% 5.3% 0.3% 0.6% 5.3% 1.0% 1.1% 6.0%

United States 4.7% 8.7% 22.9% 4.7% 8.9% 23.9% 4.2% 7.0% 14.4%

Advanced Metering Penetration

2008 2010 2012 2008 2010 2012 2008 2010 2012

All Classes Residential Class Nonresidential Classes
12 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Table 2-3. Estimated penetration of advanced metering by state in 2008 –

201218

Several advanced metering rollouts occurred in tandem with new time-of-use demand 

response programs. For example, Oklahoma added over 450,000 advanced meters between 

the 2010 and 2012 FERC Surveys, largely from the advanced metering deployments by the 

 

18 As noted elsewhere in this Report, entities revised what meters they included as being consistent with the 

definition of AMI used for this report.

State AMI meters Total meters Penetration AMI meters Total meters Penetration AMI meters Total meters Penetration

DC 1,348 809,412 0.2% 2 275,554 0.0% 248,133 285,046 87.1%

CA 170,896 14,595,958 1.2% 2,475,896 14,837,434 16.7% 10,459,477 14,836,734 70.5%

ID 105,933 769,963 13.8% 198,370 803,576 24.7% 530,655 802,440 66.1%

GA 342,772 4,537,717 7.6% 514,403 4,401,623 11.7% 3,013,541 4,599,392 65.5%

A Z 96,727 2,810,224 3.4% 847,177 2,915,712 29.1% 1,646,410 2,977,092 55.3%

NV 10,835 1,292,331 0.8% 24,378 1,255,950 1.9% 717,220 1,299,632 55.2%

A L 139,972 2,774,764 5.0% 127,092 2,467,741 5.2% 1,397,672 2,604,431 53.7%

DE 0 438,020 0.0% 10,433 455,926 2.3% 310,890 593,583 52.4%

OR 39,797 1,890,423 2.1% 478,897 1,896,717 25.2% 960,151 1,874,339 51.2%

ME 426 780,748 0.1% 20,315 796,691 2.5% 671,036 1,372,735 48.9%

TX 868,204 10,870,895 8.0% 1,284,179 11,013,153 11.7% 5,948,975 16,987,336 35.0%

OK 161,795 1,875,325 8.6% 215,462 2,028,522 10.6% 703,091 2,071,552 33.9%

FL 765,406 9,591,363 8.0% 490,150 9,644,617 5.1% 3,052,570 9,771,192 31.2%

S D 41,191 475,477 8.7% 41,122 432,632 9.5% 109,586 440,774 24.9%

W Y 12,268 318,282 3.9% 14,437 303,272 4.8% 70,650 308,024 22.9%

P A 1,443,285 6,036,064 23.9% 1,493,201 6,152,994 24.3% 1,623,982 7,753,238 20.9%

TN 60,385 3,160,551 1.9% 252,341 2,761,758 9.1% 724,469 3,738,153 19.4%

W I 117,577 3,039,830 3.9% 757,688 3,418,498 22.2% 562,861 3,107,700 18.1%

MI 73,948 5,311,570 1.4% 269,933 4,865,396 5.5% 738,702 4,859,675 15.2%

ND 33,336 375,473 8.9% 42,875 445,164 9.6% 61,329 407,033 15.1%

NC 143,093 4,771,479 3.0% 385,884 4,847,336 8.0% 644,811 4,832,250 13.3%

MS 3 1,454,275 0.0% 97,344 1,511,958 6.4% 201,877 1,584,994 12.7%

A R 168,466 1,488,124 11.3% 14,578 1,529,065 1.0% 162,181 1,559,849 10.4%

NH 260 763,683 0.0% 391 755,770 0.1% 76,864 743,454 10.3%

S C 114,619 2,373,047 4.8% 312,894 2,445,044 12.8% 246,526 2,417,863 10.2%

MO 204,498 3,098,055 6.6% 506,416 3,072,893 16.5% 299,375 3,061,397 9.8%

K Y 105,460 2,161,142 4.9% 273,663 2,523,833 10.8% 313,094 3,353,259 9.3%

OH 28,042 5,544,353 0.5% 289,970 6,290,618 4.6% 638,167 7,267,087 8.8%

NE 8,630 970,774 0.9% 19,290 999,353 1.9% 83,342 977,513 8.5%

IN 61,551 3,115,205 2.0% 148,129 3,355,485 4.4% 275,821 3,342,734 8.3%

IA 46,407 1,714,774 2.7% 58,092 1,576,475 3.7% 124,975 1,623,036 7.7%

K S 61,423 1,426,832 4.3% 62,626 1,467,092 4.3% 110,628 1,452,858 7.6%

MN 37,071 2,542,113 1.5% 108,232 2,602,360 4.2% 203,717 2,709,254 7.5%

CO 39,873 2,246,184 1.8% 111,330 2,403,001 4.6% 183,658 2,446,657 7.5%

V A 6,448 3,965,584 0.2% 175478 3,663,525 4.8% 201,014 3,706,158 5.4%

CT 5,838 1,600,768 0.4% 1,967 1,625,758 0.1% 101,267 2,044,906 5.0%

MD 8 1,938,948 0.0% 4,189 2,483,628 0.2% 108,881 2,856,999 3.8%

MT 8,979 549,136 1.6% 27,470 577,745 4.8% 20,101 563,920 3.6%

IL 112,410 5,701,533 2.0% 286,568 6,099,158 4.7% 196,150 6,138,749 3.2%

MA 3,907 3,077,679 0.1% 20,831 3,150,098 0.7% 70,729 3,384,865 2.1%

W A 69,377 2,987,355 2.3% 128,857 3,298,781 3.9% 74,252 4,009,332 1.9%

UT 37 1,056,718 0.0% 20,046 1,083,069 1.9% 18,250 1,069,087 1.7%

LA 44,103 2,186,249 2.0% 53,848 2,245,066 2.4% 37,691 2,325,796 1.6%

NM 20,776 904,861 2.3% 54,250 1,015,058 5.3% 68,975 4,533,949 1.5%

A K 18 315,419 0.0% 3,835 316,289 1.2% 4,045 295,821 1.4%

NY 12,778 7,811,335 0.2% 28,664 9,313,776 0.3% 23,756 9,063,297 0.3%

NJ 9,866 3,900,716 0.3% 25,744 3,953,683 0.7% 13,768 6,062,487 0.2%

HI 6,550 405,228 1.6% 8,713 411,232 2.1% 737 484,479 0.2%

RI 148 480,135 0.0% 2,381 506,379 0.5% 210 477,183 0.0%

V T 20,755 375,202 5.5% 31,293 379,139 8.3% 128 398,300 0.0%

W V 10 1,183,513 0.0% 7,039 1,033,802 0.7% 280 1,051,585 0.0%

2008 2010 2012
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 13

Oklahoma Gas and Electric (OG&E). OG&E has stated that it is interested in delaying the 

need for constructing additional generation facilities until 2020; therefore, OG&E is working 

to combine smart grid technology (including advanced meters) with dynamic pricing to help 

manage demand and achieve this goal.19 OG&E is using a combination of state and federal 

funding to complete this dual advanced metering/demand response program.20

Figure 2-3 provides the estimated national penetration rate of advanced metering by entity 

type. Advanced metering penetration increased for each entity type between 2010 and 2012. 

Cooperatives still had the highest penetration with 31 percent. However, advanced metering 

penetration for other entity types, such as political subdivisions21 and investor-owned

utilities, are reaching similar levels, with 29 percent and 25 percent market penetration 

respectively. 

The growth in the political subdivision category was driven by Salt River Project, which was 

responsible for over 84 percent of the total advanced meters for this entity type. Salt River 

Project was the recipient of federal Smart Grid Investment Grant (SGIG) funding to help

double its advanced metering meter penetration rate between 2010 and 2012; the SGIG 

project also used time-of-day pricing to allow customers to better monitor and manage their 

energy consumption.

22

 

Customer Accessibility of Advanced Metering Data

The 2010 and 2012 FERC Surveys asked respondents with demand response or time-based

rate programs to categorize the ways in which their customers are capable of receiving 

detailed energy usage data: over the internet, on their bills or invoices, or via a display unit

(e.g., an in-home display). Figure 2-4 illustrates that internet-based access has become the 

dominant medium for customers to retrieve their energy usage data. In 2010, an estimated 

5.4 million customers (both residential and nonresidential) were capable of using the internet 

to access information on their energy use. That number increased significantly to 17.5 

million customers by 2012, becoming the dominant means of accessing energy usage 

information. 

 

19 Oklahoma Gas & Electric, Second Year Preliminary Results Confirm Smart Technology Helps Reduce Peak 

Energy Use, 1/24/2012 press release, available at http://phx.corporate-ir.net/phoenix.zhtml?c=106374&p=irolnewsArticle&ID=1652157&highlight=. 

20 Ibid.

21 Political Subdivisions include public utility districts, irrigation districts, and associations like the Salt River 

Project.

22 Salt River Project added over 300,000 AMI meters between 2010 and 2012, and was a significant contributor to 

the estimated penetration of 30 percent for its entity type. Its rollout was driven by funding from U.S. 

Department of Energy, and its plan to install one million meters for its customers. Salt River Project smart 

meter information is available at http://www.srpnet.com/electric/home/millionmeters.aspx.
14 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Figure 2-3. Estimated advanced metering penetration by type of entity in 

2006, 2008 and 2010, and 2012 FERC Surveys

Figure 2-4. Reported numbers of customers and communication methods for 

advanced metering by customer class

Developments and Issues in Advanced Metering

This section highlights developments in several key advanced metering policy areas: (1) the 

status of the advanced metering deployments funded by the American Recovery and 

Reinvestment Act (ARRA), (2) the Green Button initiative, (3) expanded customer offerings, 

(4) use of advanced metering data for non-billing applications, and (5) noteworthy state 

activities on consumer opt-out programs. Ownership Cooperatives Political Subdivision Investor Owned Utility Municipal Entities Federal and State Utility

2006 Survey 3.8% 0.1% 0.2% 0.3% 0.2%

2008 Survey 16.4% 2.2% 2.7% 4.9% 1.1%

2010 Survey 24.7% 20.3% 6.6% 3.6% 0.7%

2012 Survey 30.9% 29.4% 25.0% 12.4% 3.6%

0

3,000,000

6,000,000

9,000,000

12,000,000

15,000,000

18,000,000

Internet Bills Display Number of Customers

Communications Method

Nonresidential Residential
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 15

Status of the Advanced Metering Deployments Funded by the American 

Recovery and Reinvestment Act

The ARRA provided $4.5 billion in awards for smart grid deployment programs,

23 and a 

portion of that funding provided matching grants for advanced metering development. The 

SGIG program has funded investments in advanced meters, networks, and hardware that 

enable two-way communications between consumers and their electricity providers. 

According to U.S. Department of Energy data, it has invested $2.8 billion in advanced 

metering as of June 2012, and SGIG recipients have deployed and are operating 10.3 million 

advanced meters. A total of 15.5 million advanced meters are planned to be deployed under

the ARRA program, and over two-thirds of these planned meters have been installed as of 

September 30, 2012.

24

 

Green Button Initiative

The Green Button Initiative is an effort for utilities to voluntarily provide retail electricity 

customers with easily accessible and up-to-date data on their electricity usage. The initiative 

began in September 2011 when U.S. Chief Technology Officer Aneesh Chopra challenged

the electric industry to provide customers access to their energy usage information 

electronically in a user-friendly format.

25

 Since launching the Green Button Initiative in 

January 2012, 35 utilities have committed to participate,26 which will provide 27 million 

households in 17 states27 and the District of Columbia access to their energy usage 

information.28 In a statement of support, the National Association of Regulatory Utility 

Commissioners (NARUC) stated, “Voluntary efforts like the Green Button Initiative will 

have a positive impact on both our electricity prices and the environment, and we salute the 

States and utilities that are pursuing these developments.”29 

Expanded Customer Service Offerings 

Efforts to standardize the format of energy usage information and protect customer privacy30

have fostered the rapid development of new applications to further engage and inform

customers. Among these new offerings are home energy reports, customized alerts or 

notifications, and improved management software. Advanced metering data makes it 

possible for utilities and third-party service providers to offer customers these new and

 

23U.S. Department of Energy, 2010 Smart Grid System Report, February 2012, p. 7, available at

http://energy.gov/oe/downloads/2010-smart-grid-system-report-february-2012. 

24 Smartgrid.gov, Advanced Metering Infrastructure and Customer Systems, available at

http://www.smartgrid.gov/recovery_act/deployment_status/ami_and_customer_systems. 

25 Aneesh Chopra, “Modeling a Green Energy Challenge after a Blue Button,” Office of Science and 

Technology Policy, The White House, September 2011, available at

http://www.whitehouse.gov/blog/2011/09/15/modeling-green-energy-challenge-after-blue-button. 

26 See http://www.whitehouse.gov/sites/default/files/microsites/ostp/energy_datapalooza_fact_sheet.pdf for 

more information.

27 Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, North 

Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, and West Virginia, as well as the District 

of Columbia.

28 See: Green Button, Adopters, available at http://www.greenbuttondata.org/greenadopt.html. 

29 National Association of Regulatory Utility Commissioners, “NARUC Applauds States, Utilities for ‘Green 

Button’ Efforts,” March 23, 2012 press release, available at http://www.naruc.org/News/default.cfm?pr=306. 

30 See, e.g., the NAESB Energy Service Provide Interface (see Chapter 4).
16 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

innovative products and services which are designed to help customers save money, qualify 

for incentives, and consume electricity more efficiently. 

For example, the U.S. Department of Energy sponsored an “Apps for Energy” contest in 

April 2012 that offered $100,000 to software developers who created the best new apps to 

help customers utilize Green Button electricity usage data.31 The winning application was 

submitted by Leafully, which created a program that compares a customer’s energy usage to

the number of trees needed to offset the pollution created by that electricity consumption.32 

Other companies used social media and peer comparison/competition to promote awareness 

of energy consumption. For example, Opower recently partnered with Facebook and the 

National Resources Defense Council to launch an application that allows customers to post 

their electric usage data online and compare it to others with similarly-sized homes.33

Use of Advanced Metering Data for Non-Billing Applications

In addition to expanded service offerings, data derived from advanced metering allows 

utilities to help tackle long-standing issues such as outage management, power and voltage 

quality, overloaded customer services and overheating meter sockets. For example, 

advanced meters have the ability to provide “last gasp” messages. As soon as an advanced 

meter experiences an outage, an internal battery can provide enough power to transmit an 

outage message back to the utility. These messages can be actively monitored, or fed into an 

outage management system to determine the extent of outages and assist in dispatching the 

necessary resources. In addition to facilitating timely outage responses, advanced meters can 

reduce unnecessary service calls. For example, if a customer calls to report an outage, a call

center representative can attempt to contact the customer’s meter to determine immediately if

the customer has power. This ability of advanced meters to detect outages proved valuable 

for several utilities on the East Coast during the restoration efforts following Hurricane 

Sandy in October 2012.34 Many advanced meters also have the ability to sense the meter’s 

internal temperature, related to its ability to maintain accuracy over its operating temperature 

range. This can be used to detect overheating conditions within the meter. 

Advanced metering systems can also open up new ways of monitoring voltage throughout an 

electric distribution system; this can improve operational control and efficiency. Voltage 

typically varies across a distribution circuit, and to ensure that voltage is consistently within 

the allowable band (usually 114 to 126 volts), utilities have traditionally relied on 

engineering models to identify potential points in a circuit where voltage may fall outside the 

allowable range. Voltage levels outside allowable ranges can reduce customers’ service 

quality and compromise the reliability of grid components such as transformers. However, 

since advanced meters provide data more frequently than traditional meters, a utility can 

monitor voltage levels using actual data throughout the circuit, rather than using engineering 

 

31 U.S. DOE, Challenge.gov, Apps for Energy, available at http://appsforenergy.challenge.gov/.

32 Leafully, What is Leafully?, available at https://www.leafully.com/tour/.

33 Opower, Your electricity use vs Similar homes, available at https://social.opower.com/explore/

34 For example, see http://www.technologyreview.com/view/506711/smart-meters-help-utility-speed-sandyrestoration/ for a description of how advanced meters helped Potomac Electric Power, and see 

http://www.greentechmedia.com/articles/read/a-smart-meter-in-the-superstorm for a description of how 

advanced metering helped Philadelphia Electric.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 17

model estimates. Controlling voltage more precisely can also help utilities and consumers 

save energy; these conservation voltage reduction programs are also known as “Volt-Var.” 

Opt-Out Programs

Some consumers are concerned about the privacy of customer data, cybersecurity, failure 

rates, and overheating,35 as well as possible adverse health effects from radio frequency 

emissions if the communications method uses radio frequencies. Because of these concerns, 

many consumer groups endorse opportunity for individual customers to forgo, or “opt-out,”

of advanced meter installations at their own premises.

State regulatory bodies are considering whether to permit opt-out programs, and are coming 

to varying conclusions. When evaluating an opt-out program, a state typically balances

consumer concerns regarding advanced meters against the system cost-saving benefits of 

universal use in an area. Some groups argue that opt-out programs are not efficient, since 

having both analog and digital systems in one area could reduce a utility’s ability to automate 

functions such as meter reading, billing, and outage detection.36 Utilities also incur 

additional administrative costs to accommodate customers that opt out of advanced metering; 

for example, the utility might need to maintain meter reading trucks and additional staff to 

support the non-advanced metering customers.37 Therefore, to maximize the potential 

system benefits of advanced metering, and to avoid additional administrative costs, some 

states have been hesitant to allow opt-out provisions in advanced metering deployment 

programs. For example, the Idaho Public Utilities Commission recently dismissed a 

consumer request to allow opting out of advanced meter installations, citing the potential 

costs of an opt-out program.

38

 

Another issue concerning opt-out programs is how to allocate the extra cost of manually 

reading individual meters if some consumers choose not to use an advanced meter. The costs 

of an opt-out program could be allocated to (1) all rate payers in a service territory, (2) only 

the customers that choose to opt out, or (3) some combination of the two. For example, the 

Maine Public Utilities Commission39 and the California Public Utilities Commission40

 

35 See: Maryland Public Service Commission, Notice of Opportunity to Comment, To: Service List for Case 

Nos. 9207, 9208, 9294, available at http://webapp.psc.state.md.us/Intranet/Casenum/caseform_new.cfm? ;

Pennsylvania Public Utility Commission, Re: AMI Meter Deployment Inquiries: Commission staff August 24, 

2012 data request, and PECO’s September 7, 2012 responses; Gregory Karp, “ComEd confirms smart meters 

involved in ‘small fires’” Chicago Tribune, August 2012, available at http://articles.chicagotribune.com/2012-

08-30/business/chi-comed-confirms-smart-meters-involved-in-small-fires--20120830_1_smart-meters-comedcustomers-poor-connection.

36 See: “The Opt-Out Challenge,” Electric Light & Power, March/April 2012, available at

http://www.elp.com/index/current-issue/electric-light-power/volume--90/issue-02.html; Institute for Electric 

Efficiency, The Cost and Benefits of Smart Meters for Residential Customers, July 2011, p. 4, Available at: 

http://www.edisonfoundation.net/iee/Documents/IEE_BenefitsofSmartMeters_Final.pdf.

37 Ibid

38 Meters that opt-out need to be individually read by a meter reader. See Idaho Public Utilities Commission, 

Formal Complaint Objecting to Installation of AMI Meters, Case No. IPC-E-12- 04, Order No. 32500, available 

at 

http://www.puc.idaho.gov/internet/cases/elec/IPC/IPCE1204/ordnotc/20120327FINAL_ORDER_NO_32500.P

DF. 

39 Maine Public Utilities Commission, Docket No. 2010-345, et al., Request for Commission Investigation in 

Pursuing the Smart Meter Initiative, et al., Order (Part I), and Order (Part II), May 19, 2011 and June 22, 2011, 
18 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

recently approved opt-out programs where the costs were assigned only to customers 

choosing to opt out, on a tiered basis. The California and Maine programs offer differing

opt-out fees under a variety of options, ranging from maintaining a traditional analog meter 

to simply having the wireless capabilities removed from an advanced meter.41 Some other 

states do not permit utilities to charge opt-out fees. For example, Vermont enacted 

legislation eliminating opt-out fees in May 2012, and also required that any advanced meter 

already installed be removed without charge if the customer requests this option.

42

 

However, to date customer participation rates in opt-out programs have been low. For 

example, less than one percent of Pacific Gas and Electric customers have opted out of 

advanced meter deployments.

43

 Portland General Electric experienced an even lower opt-out 

rate; only 4 out of 720,000 customers chose to opt out.44 These early advanced metering 

deployment results indicate that opt-out provisions support individuals’ ability to make a 

choice, while only an insignificant number of customers have actually decided to opt out.45 

The debate surrounding opt-out programs continues, and several states continue to assess the 

feasibility of implementing opt-out programs. For example, the California Public Utilities 

Commission began a second phase of proceedings in June 2012 to reexamine the opt-out 

issue and may consider extending an opt-out option to customer groups such as local 

governments and residents of apartment buildings/condominiums.46 The second phase will 

also address the possibility that the Americans with Disabilities Act prohibits that

Commission from charging opt-out fees for customers who have an analog meter for medical 

reasons. In addition, the Maryland Public Service Commission issued an interim order in 

 

available at https://mpuc-cms.maine.gov/CQM.Public.WebUI/Common/CaseMaster.aspx?CaseNumber=2010-

00345. 

40 California Public Utilities Commission, Decision Modifying Decision 08-09-039 and Adopting an Opt-Out 

Program for Southern California Edison Company’s Edison SmartConnect Program, Decision 12-04-018, 

Issued April 30, 2012, available at http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/165307.htm.

41 On July 12, 2012, the Maine Law Court issued a decision that vacated the portion of Maine Public Utilities 

Commission’s dismissal of a complaint pertaining to health and safety concerns associated with advanced meter 

usage in the Central Maine Power Company (CMP) service territory. The Maine PUC subsequently issued an 

order staying disconnection of CMP customers until the conclusion of an investigation. See: Maine Public 

Utilities Commission, Docket No. 2010-345, et al., Request for Commission Investigation in Pursuing the 

Smart Meter Initiative, et al., Order Staying Disconnection of CMP Customers for Failure to Pay Opt-Out Fees, 

August 8, 2012

42 Vermont State Legislature, The Vermont Legislative Bill Tracking System, Senate Bill No. 214, An Act 

Relating to the Vermont Energy Act of 2012, Enacted May 18, 2012, available at

http://www.leg.state.vt.us/database/status/summary.cfm?Bill=S.0214&Session=2012. 

43 United Telecom Council, Smart Meter Opt-Out – The Policies and Impacts, 9/27/2012 Webinar, as reported 

by intelligentutility, Few and fewer opting out of smart meters, September 30, 2012, available at

http://www.intelligentutility.com/article/12/09/few-and-fewer-opting-out-smart-meters. 

44 ibid.

45 Eric Lightner, Director of the Federal Smart Grid Task Force, DOE Office of Electricity Delivery and Energy 

Reliability, Roundtable 2 – Policymakers Talk, June 26, 2012. 

46 California Public Utilities Commission, Application of Pacific Gas and Electric Company for Approval of 

Modifications to its SmartMeterTM Program and Increased Revenue Requirements to Recover the Costs of the 

Modifications: Assigned Commissioner’s Ruling Amending Scope of Proceeding to Add a Second Phase, 

Application No. 11-03-014, Enacted June 8, 2012, available at http://docs.cpuc.ca.gov/efile/RULC/168362.pdf. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 19

May 2012 directing utilities to refrain from installing or activating advanced meters until a 

permanent course of action is determined.47 Texas48 and Nevada49 have also been assessing 

the feasibility of opt-out programs. 

 

47Maryland Public Service Commission, Case No. 9207: In the Matter of Potomac Electric Power Company and 

Delmarva Power and Light Company Request for the Deployment of Advanced Meter Infrastructure, and Case 

No. 9208: In the Matter of Baltimore Gas and Electric Company for Authorization to deploy a Smart Grid 

Initiative and to Establish a Surcharge Mechanism for the Recovery of Costs, Order No. 84926: Interim Order 

Regarding “Opt-out” Option for Smart Meters, May 25, 2012, available at

http://webapp.psc.state.md.us/Intranet/Casenum/submit_new.cfm?DirPath=C:\Casenum\9200-

9299\9207\Item_203\&CaseN=9207\Item_203. 

48 Public Utilities Commission of Texas, Project, Control No. 40190, Item 382: PUC Proceeding to Evaluate the 

Feasibility of Instituting a Smart Meter Opt-Out Program, available at

http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pgControl.asp?TXT_UTILIT

Y_TYPE=A&TXT_CNTRL_NO=40190&TXT_ITEM_MATCH=1&TXT_ITEM_NO=&TXT_N_UTILITY=

&TXT_N_FILE_PARTY=&TXT_DOC_TYPE=ALL&TXT_D_FROM=&TXT_D_TO=&TXT_NEW=true.

49 Public Utilities Commission of Nevada, Application of Nevada Power Company d/b/a NV Energy and Sierra 

Pacific Power Company d/b/a NV for approval of proposed trial Non-Standard Metering Option riders and 

changes to existing rules and schedules associated with implementation of the NSMO riders, Docket No. 12-

05003, Filled May 2012.
20 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 21

CHAPTER 3. DEMAND RESPONSE

This chapter addresses the second and third topics in EPAct 2005 section 1252(e)(3):

(B) Existing demand response programs and time-based rate programs, and

(C) The annual resource contribution of demand resources.

This chapter presents results of the 2012 FERC Survey on demand response programs, 

including comparisons to previous FERC Survey results, and has three sections:

 Definition of Demand Response

 Survey Results 

 Demand Response Developments at the FERC, and Barriers to Demand Response

Definition of Demand Response 

The definition of demand response used in the survey and this report is:

Demand Response: Changes in electric use by demand-side resources from their 

normal consumption patterns in response to changes in the price of electricity, or to 

incentive payments designed to induce lower electricity use at times of high 

wholesale market prices or when system reliability is jeopardized.

The demand response program types and definitions in the 2012 FERC Survey conform to 

those used by NERC’s Demand Response Availability Data System (DADS). This common 

terminology allows for some comparison with the DADS data. Table 4.1 contains the 

program classifications included in the 2012 Survey. Definitions for each of the 

classifications can be found in the Appendix C glossary.

Table 3-1. Demand response program types in the 2012 FERC Survey

Incentive-Based Programs Time-Based Programs

 Demand Bidding and Buyback 

 Direct Load Control

 Emergency Demand Response

 Interruptible Load

 Load as Capacity Resource

 Non-Spinning Reserves

 Regulation Service

 Spinning Reserves

 Critical Peak Pricing with Control

 Critical Peak Pricing

 Peak Time Rebate

 Real-Time Pricing

 Time-of-Use Pricing

 System Peak Response Transmission 

Tariff

Note: The 2012 FERC Survey also included an “Other” category for demand response program types that 

were not classified in either the Incentive-based DR Programs or Time-based Programs classifications.
22 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Survey Results

Analytical Approach

Reported and estimated data on demand response and time-based rate programs are presented 

below. As with prior year Reports, the approach taken was to gather information via survey 

and to also supplement the data with Form EIA-861 data to report “annual resource 

contribution” as required in EPAct Section 1252(e)(3)(C). Values that are labeled as 

“reported” reflect the peak reduction (potential and actual) reported by entities in their survey 

responses. Values labeled as “estimated” represent an estimate of U.S. total peak reduction, 

and were derived using supplemental FERC and Form EIA-861 data, along with statistical 

methods, to fill in missing data. A detailed explanation of these estimation methods can be 

found in Appendix H.

Both reported and estimated demand response peak reduction are adjusted to minimize 

double-counting. Appendix D describes the methods Staff used to address double counting 

in the peak reduction data in more detail.

Summary of Report Findings

According to FERC Survey data, reported potential peak reduction in the U.S. increased from 

2010 to 2012 by more than 10,000 MW, from 53,062 to 66,351 MW in 2012. This 

represents a 25 percent increase in reported potential peak reductions from demand response. 

Figure 3-1 illustrates a steady national increase in demand response capability50 across all 

FERC survey years.

While demand response capability in the U.S. has steadily increased over the past few years, 

the key contributors to this trend vary across customer class, ownership type, and program 

type. The following sections summarize the 2012 FERC Survey findings on demand 

response.

Growth in Reported Potential Peak Reduction by Customer Class

Growth in reported potential peak reduction from 2006 to 2012 occurred among all customer 

classes, as illustrated in Figure 3-2. 

Growth in Commercial and Industrial Potential Peak Reduction

Reported potential peak reductions by commercial and industrial customers increased by 31 

percent, the largest increase of the three customer classes. This increase is due to new and 

expanded demand response programs, along with improved reporting of existing programs in 

the 2012 survey.51  The Oklahoma Gas and Electric (OG&E) time-of-use program is one

 

50 The terms “demand response capability” and “potential peak reduction” are used synonymously in this report.

51

 For example, the 2012 response for TVA indicates a significant increase in TVA’s potential peak reduction 

from 2010. The apparent increase is because certain potential peak reductions reported in 2012 existed in 2010 

but were not reported for TVA’s programs in the 2010 FERC Survey. Similarly, the large changes in potential 

peak reduction from 2010 to 2012 for The Detroit Edison Company and Progress Energy Florida can be 

attributed to unreported 2010 data, rather than new program offerings or increased enrollment. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 23

Figure 3-1. Total reported potential peak reduction in the 2006 through 2012 

FERC Surveys

Survey Year

Figure 3-2. Reported potential peak reduction by customer class in 2006, 

2008, 2010 and 2012

example of a significant demand response program expansion; the utility reported adding

nearly 900 MW of demand response capability between 2010 and 2012 from commercial and 

industrial consumers. OG&E’s demand response program was coordinated with an advanced 

29,653

37,335

53,062

66,351

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2006 Survey 2008 Survey 2010 Survey 2012 Survey

Reported Potential Peak Reduction (MW)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2006 Survey 2008 Survey 2010 Survey 2012 Survey

Reported Potential Peak 

Reduction (MW)

Commercial & Industrial Residential Wholesale
24 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

metering deployment (see Chapter 2), and as a result, OG&E reported over 1,700 new 

commercial and industrial participants in its time-of-use rate program.

52

Growth in Wholesale Potential Peak Reduction

Reported potential peak reduction for wholesale entities53 grew by 26 percent, from 22,884 

MW in 2010 to 28,807 MW in 2012. Increased enrollment of demand response resources in

PJM Interconnection, LLC (PJM) and Midwest Independent Transmission System Operator 

(Midwest ISO) largely drove this increase, as illustrated in Figure 3-3.

54

Figure 3-3 also shows a marked shift in the composition of wholesale demand response 

programs. Between 2010 and 2012, the reported potential peak reductions associated with 

emergency demand response programs decreased and load as a capacity resource increased, 

especially in the PJM and the Midwest ISO markets. 

Growth in Residential Potential Peak Reduction

Reported potential peak reduction associated with residential customers grew by 13 percent, 

from 7,189 MW in 2010 to 8,134 MW in 2012. Seventy percent of this increase is 

attributable to investor-owned utilities’ demand response programs. For residential 

customers, direct load control and time-based rates programs had the largest increases in 

reported potential peak reduction. For example, Baltimore Gas and Electric reported a 

significant increase in its residential direct load control program, from 272 MW of potential 

peak reduction in 2010 to 763 MW in 2012.55

Reported Potential Peak Reduction by Region

Nearly every region in the U.S. increased its reported potential peak reduction between 2010 

and 2012, as illustrated in Figure 3-4. ReliabilityFirst Corporation (RFC) remained the 

region with the most reported potential peak reduction; RFC reported of 24,381 MW of 

potential peak reduction in 2012, an increase of 8,517 MW from 2010. Most of this reported 

growth is due to increased participation by demand response resources in PJM’s forward 

capacity market.

 

52Smartgrid.gov: Recovery Act Smart Grid Programs, Case Studies, Reducing Peak Demand to Defer Power 

Plant Construction in Oklahoma, August 2011, available at

http://energy.gov/sites/prod/files/Case%20Study%20-%20Oklahoma%20Gas%20and%20Electric%20-

%20Reducing%20Peak%20Demand%20to%20Defer%20Power%20Plant%20Construction%20-

%20August%202011.pdf.

53 Wholesale entities include ISOs, RTOs, curtailment service providers, wholesale power marketing agencies 

such as the Bonneville Power Administration, the Tennessee Valley Authority, generation and transmission 

corporations and joint action agencies that serve member companies, and wholesale electric marketers.

54 Figure 3-3 shows the information provided by the ISOs and RTOs in 2010 and 2012 in their responses to the 

2012 FERC Survey. This figure does not reflect any adjustments to eliminate double counting of potential peak 

reductions reported by both retail entities and an ISO or RTO.

55 Baltimore Gas and Electric deployed its direct load control program during a PJM-initiated emergency on a 

very hot day in July of 2011 and later measured the impact at approximately 600 MW. See 

http://webapp.psc.state.md.us/Intranet/Casenum/submit_new.cfm?DirPath=C:\Casenum\9100-

9199\9154\Item_214\&CaseN=9154\Item_214.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 25

Figure 3-3. Reported potential peak reduction by Independent System 

Operators and Regional Transmission Operators in 2010 and 2012

 

 Note: This figure does not adjust for double-counting.

Figure 3-4. Reported potential peak reduction by region and customer class

for the 2010 and 2012 FERC Surveys
26 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

SERC Reliability Corporation became the second largest NERC region for reported potential 

peak reduction, by adding 3,655 MW; this represents a 40 percent increase from 2010. 

Combined, SERC and RFC account for over 55 percent of the total U.S. reported potential 

peak reduction in 2012. 

In the Northeast Power Coordinating Council (NPCC), the reported potential peak reduction

declined by 40 percent between 2010 and 2012. A key driver for this drop in the reported 

potential peak reduction is due to significant declines in the amount of potential peak 

reduction reported by several key entities in New York.

Demand Response Program Trends

Figure 3-5 illustrates reported potential peak reduction by demand response program type.56 

These program types are organized into two main groupings: incentive-based demand 

response and time-based demand response programs. Traditionally, demand response 

programs have used incentives to encourage electricity customers to modify their electricity 

consumption when system reliability was threatened or market opportunities arose. Timebased programs, on the other hand, send price signals to electricity customers who 

voluntarily choose to modify their electricity consumption in response to these signals. As in 

previous years, incentive-based demand response program types represent the bulk of 

reported demand response potential, but time-based program types also significantly 

increased in 2012. 

Four demand response program types made up 80 percent of the total reported potential peak 

reduction in 2012. These programs were: 

 Load as a capacity resource: 29 percent of all reported demand response potential

peak reduction

 Interruptible load: 24 percent of all reported demand response potential peak 

reduction

 Direct load control: 15 percent of all reported demand response potential peak 

reduction

 Time-of-use: 12 percent of all reported demand response potential peak reduction 

The dominant program type in 2012 is load as a capacity resource (20,000 MW), a departure 

from the results of previous surveys. In 2010, the predominant program type was emergency 

demand response (13,000 MW); load as a capacity resource made up less than 9,000 MW of 

the total reported potential peak reduction. This change for load as a capacity resource and 

emergency demand response reflects the changes in wholesale market program offerings, 

along with changes in how PJM chose to categorize its Emergency Load Response – Full 

Option program. 

 

56 A significant challenge to developing program type classifications is linking retail programs to the 

classifications submitted by the ISO/RTO market operator, when a retail program is enrolled in a wholesale 

market program for demand response. FERC staff conducted a process to discern this linkage in order to 

eliminate double counting of programs in tabulations that include customer class. Further details on this 

process are explained in Appendix H.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 27

Figure 3-5. Reported potential peak reduction by program type and by 

customer class in 2012 FERC Survey

Table 3-2 lists reported peak reduction by program type and state.57 The five states reporting 

the highest potential peak reductions are:

 Michigan – Michigan reported the highest potential peak reduction: 5,835 MW. 

Detroit Edison’s time-of-use program for commercial and industrial customers 

accounts for 3,000 MW of this total. 

 Minnesota – Although Minnesota respondents reported a slight decrease in demand 

response capability from 2010 to 2012, the state had second the largest reported 

potential peak reduction in 2012: 4,392 MW. Midwest ISO’s “load as a capacity 

resource” demand response program consists largely of Minnesota’s reliance on this 

demand response program type. 

 

57 In Table 3-2, Time-Based Demand Response Programs are the following program types: Critical Peak 

Pricing, Critical Peak Pricing with Load Control, Time-of-Use, Real-Time Pricing, and Peak Time Rebate. 

Other Incentive-Based Demand Response Programs are the following program types: Load as a Capacity 

Resource, Spinning Reserves, Non-Spinning Reserves, Regulation, Demand Bidding and Buy-Back, and 

System Peak Response Transmission Tariff. 
28 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Table 3-2. Reported potential peak reduction in Megawatts by program type

and state

State

TimeBased

Direct 

Load 

Control

Other 

IncentiveBased

Emergency 

Demand 

Response

Interruptible 

Load Other

State 

Total

AK - - - - - - - 

AL 183 17 - - 1,647 - 1,847 

AR 160 199 - - 956 19 1,334 

AZ 158 13 190 - - - 361 

CA 381 612 1,112 256 660 - 3,020 

CO 26 193 44 - 56 - 320 

CT - - 48 339 5 - 392 

DC - 25 97 - 0 - 123 

DE 117 76 186 - 20 9 408 

FL 68 2,620 87 37 1,009 35 3,857 

GA 686 244 7 - 328 - 1,264 

HI 24 36 - - 5 - 65 

IA 3 136 346 154 605 - 1,244 

ID - 24 380 - 314 - 717 

IL 9 189 1,658 58 1,298 - 3,213 

IN 72 92 184 930 618 - 1,896 

KS 25 65 28 20 249 - 387 

KY 59 178 69 7 565 - 878 

LA - 67 - - - - 67 

MA 28 - 58 310 - - 396 

MD 232 822 1,357 - 66 - 2,478 

ME - - 25 195 - - 220 

MI 3,383 240 1,306 271 550 86 5,835 

MN 573 994 1,466 337 992 30 4,392 

MO 84 40 - - 83 - 207 

MS 282 - - - 674 - 955 

MT 3 - - - - - 3 

NC 59 315 93 - 574 - 1,040 

ND 116 295 18 6 - - 435 

NE 0 184 40 75 42 1,051 1,392 

NH - - 11 62 - - 73 

NJ - 112 786 9 3 - 910 

NM 3 2 90 - - - 95 

NV - 130 - 32 - - 162 

NY 1 45 1,829 258 299 0 2,432 

OH 3 88 2,536 44 475 - 3,145 

OK 1,939 56 623 - 63 3 2,683 

OR - 1 14 - 6 - 21 

PA 169 68 3,745 19 211 - 4,212 

RI 12 - 11 74 - - 96 

SC 105 107 - - 932 41 1,185 

SD 13 605 - 18 20 - 656 

TN 1,308 - 29 - 955 - 2,293 

TX 4 71 1,943 420 137 2 2,577 

UT 4 449 - - 4 - 457 

VA 85 118 1,988 10 82 - 2,283 

VT 3 0 19 50 46 - 117 

WA 1 1 1 - 20 - 23 

WI 139 250 1,785 344 712 - 3,231 

WV - - 560 4 364 - 929 

WY 25 - - - - - 25 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 29

 Pennsylvania -- Pennsylvania reported an increase in reported potential peak 

reduction in 2012 to 4,212 MW, largely from increased demand response 

participation in PJM’s forward capacity market through the Emergency Load 

Response program. 

 Florida – Florida continues to have a large reported potential peak reduction, and 

Florida’s demand response capability is provided primarily by utilities’ interruptible 

load and direct load control programs. 

 Wisconsin – Wisconsin’s reported potential peak reduction is primarily from a 

Midwest ISO program called “Load Modifying Resources.” 

Three other states had large increases in reported potential peak reduction between the 2010 

and 2012: Michigan, Tennessee, and Oklahoma. These increases were due primarily to the 

demand response programs of Detroit Edison, the Tennessee Valley Authority, and 

Oklahoma Gas and Electric, respectively. 

Actual Peak Reduction

In addition to providing information on reported potential peak reductions, survey 

respondents also provided information on actual (or realized) peak reductions that occurred 

in 2011 from demand response programs.

58

 The actual peak reductions from demand 

response resources for the 2010 and 2012 FERC Surveys are presented by region in Figure 3-

6 below. The 2012 FERC Survey respondents identified a total of 20,256 MW of actual peak 

reductions from demand response resources, representing use of 31 percent of the total 

reported potential peak reduction. This represents an increase from the 2010 Survey in actual 

peak reductions from demand response. 

Figure 3-7 compares the 2012 reported potential peak reduction to actual peak reduction by 

region. While RFC reported the highest potential peak reduction, it reported using only 15 

percent of this potential.

59 Every other NERC region used at least 25 percent of its potential 

demand response capability; NPCC realized 85 percent and TRE 90 percent of its reported 

potential peak reduction. 

Estimated Potential Peak Reduction by Region

The above values for reported potential peak reduction likely understate the total potential 

peak reduction capability in the U.S. because not all those surveyed responded and for other 

reasons. Therefore, staff took steps to estimate the potential peak reduction of nonresponding entities, using FERC Survey data and other sources of information, such as Form 

EIA-861 data.60 The result is called the estimated potential peak reduction, in contrast to the 

reported potential peak reduction presented above. 

 

58 As a means of confirming the data, if the actual demand response peak reduction was larger than the reported 

potential peak reduction, the reported potential peak reduction was set equal to the actual demand response peak 

reduction.

59 The ratio in RFC was low because no actual peak reductions from demand response resources were reported by the 

two of the largest programs in the RFC region – Detroit Edison’s commercial and industrial time-of-use 

program and Commonwealth Edison’s commercial and industrial interruptible load program. The RFC actualto-potential ratio for the remaining programs reported was 45 percent.

60 The estimation methodology is described in Appendices D and H.
30 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Figure 3-6. Reported actual peak reduction by NERC region between 2010 

and 2012 FERC Survey years

Figure 3-7. 2012 FERC Survey reported potential and actual peak reduction 

by region

Figure 3-8 compares the estimated potential peak reduction by NERC region and customer

class between 2010 and 2012. Total estimated potential peak reduction is 71,654 MW, an 

increase of almost 13,000 MW from 2010. RFC remained the region with highest estimate 

of potential peak reduction, with a total of 25,356 MW in 2012, an increase of 8,025 MW 

from the estimated 2010 potential peak reduction. 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

Reported Actual Peak

Reduction (MWs)

NERC Regions

2010 Actual peak Reduction 2012 Actual Peak Reduction
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 31

Figure 3-8. Estimated potential peak reduction by region and customer class 

in 2010 and 2012

Figure 3-9 presents the estimated potential peak reduction by entity type and customer 

class across the 2010 and 2012 surveys. Investor-owned utilities remained the entity type 

with the largest estimated potential peak reduction, 27,476 MW in 2012. Commercial and 

industrial customers accounted for 75 percent of the estimated potential peak reduction for 

investor-owned utility demand response programs. ISO and RTO programs’ estimated 

potential peak reduction increased by 20 percent to 25,489 MW in 2012.61 Federal and state 

entities added an estimated 4,600 MW of estimated potential peak reduction between 2010 

and 2012. 

Plans for New Demand Response Programs

FERC Survey respondents were asked to “Provide your entity’s near- and long-term plans for 

new demand response programs and time-based rates/tariffs.” Table 3-3 summarizes these 

responses for three time periods. Direct load control programs were the dominant planned 

program type, followed by time-of-use rates programs and interruptible programs for all 

three time periods. The three main and roughly equal contributors to new demand response 

planned for 2012 comes from direct load control, interruptible load, and load as a capacity 

resource. For programs beginning in 2013 and 2014, 80 percent of the planned demand 

response from new programs was reported to come from an interruptible program or load as 

a capacity resource program.

 

61 The estimated potential peak reductions attributed to RTO/ISO programs were reduced according to the 

methodology described in Appendix D to eliminate double-counting of retail demand response programs 

enrolled in wholesale market programs. 
32 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Figure 3-9. Estimated potential peak reduction by entity type and customer 

class in 2010 and 2012

Table 3-3. Reported plans for new demand response programs and time-based 

rates/tariffs

Participation in Demand Response Programs

This section discusses the reported participation of entities and customers in four specific 

types of demand response program: Interruptible Load, Direct Load Control, Time-of-Use, During Calendar Year 2012

During Calendar Years 

2013 and 2014

During Calendar Years 

2015 through 2017

Program Type

Number of 

Programs

Potential Peak 

Reduction (MW)

Number 

of 

Programs

Potential 

Peak 

Reduction 

(MW)

Number 

of 

Programs

Potential 

Peak 

Reduction 

(MW)

 Direct Load Control 489 4,579 38 884 18 291 

Interruptible Load 20 5,842 15 9,696 6 211 

Critical Peak Pricing with Controls 3 1 1 31 2 1 

Load as Capacity Resource 9 5,906 5 9,837 - - 

Spinning Reserves 3 370 4 747 2 350 

Non-Spinning Reserves 4 281 4 667 2 185 

Emergency Demand Response 9 1,243 8 1,658 - - 

Regulation Service 2 60 1 75 - - 

Demand Bidding and Buyback 4 - - - - - 

Time-of-Use Pricing 40 373 27 24 18 7 

Critical Peak Pricing 8 12 12 15 9 14 

Real-Time Pricing 3 - 5 125 6 1 

Peak Time Rebate 7 64 5 3 1 - 

System Peak Response Transmission Tariff 1 5 - - 3 5 

Other 7 222 6 691 2 101 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 33

and Real-Time Pricing. Information on how many entities offer these programs and how 

many customers participate can provide insights into trends and regional differences.

Interruptible Load Demand Response Programs

Figure 3-10 illustrates changes in the number of entities providing interruptible load demand 

response between 2010 and 2012 by NERC region and entity type. Overall, the total number 

of entities providing interruptible service decreased from 183 providers in 2010 to 158 in 

2012.62 Cooperatives reported the largest decrease between 2010 and 2012 in the number of 

entities that operate interruptible demand response programs; a lower FERC Survey response 

rate for cooperatives may explain the decrease.

Figure 3-10. Number of entities reporting interruptible/curtailable rates by 

region and type of entity in 2010 and 201263

Direct Load Control Demand Response Programs

The number of customers enrolled in a direct load control program by region is provided in 

Figure 3-11, along with the proportion of total retail customers by NERC region. The region 

with the most customers participating in direct load control programs in both 2010 and 2012 

is RFC; however, FRCC and MRO had the highest proportions of retail customers 

participating in these programs. Over 12 percent of MRO’s retail customers and almost 15 

percent of FRCC’s retail customers reportedly participated in direct load control programs in 

2012.

 

62 The 2010 Report contains the number of interruptible/curtailable rate programs, rather than the number of 

entities reporting one or more of these types of programs. Figure 3-10 reflects the number of entities offering 

these programs in the 2010 FERC Survey. 

63 For the following figures that summarize entity and customer participation in demand response, the category 

“Cooperative Entities” refers to cooperatives, generation and transmission cooperatives, and political 

subdivisions. Similarly, municipal utilities and municipal marketing authorities are combined into “Municipal 

Entities.” Federal entities, such as Southwestern Power Administration, and state utilities, such as the Arizona 

Power Authority, are combined into “Federal and State.” Unless specifically identified, “Other” refers to 

curtailment service providers, retail power marketers, regional transmission organizations and independent 

system operators.
34 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Figure 3-11. Reported number of customers enrolled in direct load control 

programs by region and type of entity in 2010 and 2012

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

Percent of total 

estimated 

customers in the 

region in a direct 

load control 

program

0.11% 14.54% 12.15% 0.25% 4.39% 2.28% 1.43% 3.09% 4.59%

Time-of-Use Demand Response Programs

Figure 3-12 illustrates the number of entities reporting residential time-of-use rates by NERC 

region and entity type. The number of entities offering residential time-of-use rate demand 

response programs increased slightly, from 144 in 2010 to 151 in 2012.64 MRO continued to 

be the highest: 52 entities in the region reported offering a time-of-use rate for residential 

customers; over half of these programs were offered by municipally owned utilities in 2012. 

While the number of entities offering residential time-of-use rates has been relatively 

constant from 2010 to 2012, Figure 3-13 indicates that the number of residential customers 

utilizing time-of-use rates is rising. The total number of residential customers on a time-ofuse rate increased from 1.1 million in 2010 to almost 2.1 million in 2012, with almost all of 

this growth occurring in RFC. Approximately 800,000 new residential customers began 

using time-of-use rates in RFC between 2010 and 2012, primarily under the Potomac Electric 

Power Company and Delmarva Power and Light program expansions. 

 

64 The 2010 Report contains the number of residential time-of-use programs, rather than the number of entities 

reporting one or more of these types of programs. Figure 3-12 reflects the number of entities offering these 

programs in the 2010 FERC Survey. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 35

Figure 3-12. Number of entities reporting residential time-of-use rates by 

region and type of entity in 2010 and 2012

Figure 3-13. Reported number of residential customers enrolled in time-ofuse rates by region and entity type in 2010 and 2012

The large increase in time-of-use participation in the RFC region illustrates a shift from 

previous FERC Survey trends. In previous years, WECC was the dominant time-of-use 

demand response region; however, residential time-of-use program customers in WECC 

increased only slightly between the two survey years, to just over 775,000 customers (about 

2.7 percent of all WECC customers).
36 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Real-Time Pricing Programs

The number of entities that reported offering real-time pricing programs is presented in

Figure 3-14, by region and entity type. Twenty-eight entities reported offering real-time 

pricing in 2012, a slight increase from the 25 entities reporting in 2010. Nearly all of the 

entities offering real-time pricing programs are investor-owned utilities.

65

Figure 3-14. Number of entities reporting retail real-time pricing by region 

and entity type in 2010 and 2012

Demand Response Activities at the FERC

Since the publication of the November 2011 Assessment of Demand Response and Advanced 

Metering, the Commission has continued to further the goal of comparable treatment of 

demand response resources in wholesale markets, as well as to follow the provisions of law 

requiring it to develop a plan to realize the national potential for demand response. 

This section summarizes the key demand response developments and actions undertaken by 

the Commission since the prior report, including several rulemakings and key demandresponse-related RTO/ISO orders. 

Commission Demand Response Activities

The Commission continues to assess and monitor the wholesale electric power markets under 

its jurisdiction, to ensure that resources that are technically capable of providing demand 

response services are treated comparably to supply-side resources. This section summarizes 

FERC actions taken in the past year that affect demand response resources in wholesale 

markets, including action the Commission has taken to address compensation and 

 

65 The 2010 Report contains the number of RTP programs, rather than the number of entities reporting one or 

more RTP program. Figure 3-14 reflects the number of entities offering these programs in the 2010 FERC 

Survey. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 37

measurement and verification as well as Commission actions in response to RTO and ISO 

proposals related to demand response. 

Commission Rulemakings on Demand Response Issues

NAESB Wholesale Demand Response Measurement and Verification NOPR

In April 2012, the Commission issued a Notice of Proposed Rulemaking (NOPR) to amend 

its regulations to incorporate by reference NAESB’s business practice standards on the 

measurement and verification of demand response and energy efficiency resources that 

participate in organized wholesale electricity markets. The proposed demand response 

measurement and verification standards would add specificity to existing standards in several 

areas, including meter data reporting, advanced notification, telemetry, and meter accuracy. 

The Commission requested comments on whether the proposed demand response 

measurement and verification standards are sufficiently detailed to provide transparent 

measurement and verification across regions, and whether greater detail or conformity across 

regions would be appropriate. By contrast, the proposed energy efficiency measurement and

verification standards would provide more substantial detail than the demand response

standards to ensure effective evaluation of the performance of energy efficiency products and 

services. The proposed wholesale energy efficiency standards include four measurement and

verification methodologies, as well as a mechanism for resource providers to propose, and 

organized markets to consider, alternative approaches.66 Comments on the NOPR were 

received on July 30, 2012 and the Commission is evaluating those comments. 

Order No. 745 Compliance Orders

Order No 745,67 issued in March 2011, requires that RTOs and ISOs pay demand response 

resources participating in the day-ahead and real-time wholesale energy markets the 

locational marginal price (LMP) when two conditions are met: demand response resource are 

capable of balancing supply and demand in the wholesale energy markets, and dispatching 

and paying LMP to demand response resources is cost-effective as determined by a net 

benefits test. All six ISOs and RTOs, have made filings to comply with Order No. 745. 

Commission orders approving the compliance filings of PJM, ISO-New England (ISO-NE), 

and the Midwest ISO are discussed below. Commission proceedings on the compliance 

filings for the California ISO (CAISO), New York ISO (NYISO), and SPP remain open at 

the time of this writing.

PJM Order No. 745 Compliance (Docket No. ER11-4106)

PJM submitted its Order No. 745 compliance filing in July 2011. In its compliance filing, 

PJM proposed to revise its existing compensation methods for participants in PJM’s 

Economic Load Response programs from LMP less applicable avoided generation and 

transmission charges in all hours to LMP in hours when a net benefits test is passed. PJM 

also proposed changes to (1) rules governing self-scheduling, (2) the customer baseline load 

methodology used to measure demand reductions in the energy and ancillary services 

 

66 Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041

(2012).

67 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 76 FR 16,658 

(Mar. 24, 2011), FERC Stats. & Regs. ¶ 31,322 (2011) (Order No. 745), order on reh’g, 137 FERC ¶ 61,215 

(2011).
38 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

markets, and (3) how the costs for demand response are allocated. On December 15, 2011, 

the Commission accepted PJM’s filing, subject to an additional compliance filing.

68

 The 

Commission found that PJM’s proposed tariff revisions went beyond what was required to 

comply with Order No. 745, which applies only if a demand response resource has the 

capability to balance supply and demand and if dispatch of the demand response resource is 

cost-effective as determined by a net benefits test. PJM submitted another compliance filing 

in March 2012 in response to the December order, which was accepted by the Commission in 

June 2012.69

ISO-New England Order No. 745 Compliance (Docket No. ER11-4336)

ISO-NE submitted its Order No. 745 compliance filing and proposed tariff revisions in 

August 2011. As part of its compliance filing, ISO-NE proposed (1) a net benefits test that 

established a threshold price for submitting demand response bids, (2) adjustments to its 

current baseline calculation methodology for measuring demand reductions, and (3)

allocating costs hourly in proportion to the ISO-NE Real-Time Load Obligation70 on a 

system-wide basis. ISO-NE proposed implementing these changes in two stages that would 

fully integrate demand response resources into its energy market by June 2016. The 

Commission accepted ISO-NE’s Order No. 745 compliance filing in January 2012,71 subject 

to a further compliance filing. ISO-NE submitted this second compliance filing in March 

2012, which was accepted by the Commission in May 2012.72

Midwest ISO Order No. 745 Compliance (Docket Nos. ER12-1266 and ER11-4337)

The Midwest ISO submitted its Order No. 745 compliance filing in August 2011. It 

proposed to establish a monthly Net Benefits Price Threshold. The Midwest ISO also 

proposed to pay the applicable LMP to cost-effective demand response resources that clear 

either the day-ahead or real-time energy market. Additionally, the Midwest ISO proposed to 

allocate the costs associated with compensating demand resources in the real-time energy 

market to market participants located within the reserve zone of demand response resources 

that either purchase energy and benefit from reduced LMPs or serve load and avoid selling 

energy to retail customers at a loss. The Midwest ISO proposed to allocate any remaining 

costs to all load-serving entities systemwide on a pro rata load ratio share basis. The 

Commission accepted this compliance filing in part and rejected it in part in December 

2011.73 The Midwest ISO submitted its second Order No. 745 compliance filing in March 

2012; d the Commission accepted the Midwest ISO’s Order No. 745 compliance filing in 

July 2012.74

Order No. 719 Compliance Orders

The Commission issued Order No. 719 in October 2008 to improve the operation of 

organized wholesale electric power markets in several areas: (1) demand response, including 

 

68 PJM Interconnection, L.L.C., 137 FERC ¶ 61,216 (2011).

69 PJM Interconnection, L.L.C., 139 FERC ¶ 61,256 (2012).

70 Real-Time Load Obligation refers to the total load serving entities’ MWh load obligation of market 

participants at each location during a given hour of operation. See ISO-NE Tariff, section III.3.2.1(b)(i).

71 ISO New England Inc., 138 FERC ¶ 61,042 (2012). 

72 ISO New England Inc., Docket No. ER11-4336-005 (May 29, 2012) (delegated letter order)

73 Midwest Indep. Transmission Sys. Operator, Inc., 137 FERC ¶ 61,212 (2011) (Order No. 745 Compliance 

Order).

74 Midwest ISO. 140 FERC 61,059 (2012).
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 39

pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) 

market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers 

and other stakeholders.75 Several compliance filings associated with Order No. 719 

implementation were submitted and approved in 2012, and details on PJM and Midwest 

ISO’s filings are provided below. 

PJM Order No. 719 Compliance—Scarcity Pricing (Docket No. ER09-1063-004)

PJM submitted an Order No. 71976 compliance filing and proposed tariff changes addressing 

shortage pricing requirements in June 2010, and the Commission accepted the changes in 

April 2012.77 PJM proposed numerous tariff changes, including changes to PJM’s demand 

response programs, based on its analysis that PJM’s existing shortage pricing provisions fail 

to satisfy the shortage pricing requirements of Order No. 719. The Commission accepted 

PJM’s tariff revisions and found that PJM’s proposed pricing reforms would encourage 

existing demand response and generation resources to continue to provide supplies during 

shortage conditions, because these resources will be eligible to receive the prevailing energy 

and reserve market clearing price. In addition, the Commission found that PJM’s proposal 

would (1) increase the accuracy of market clearing prices during shortage conditions, (2) 

minimize the need for out-of-market payments, and (3) provide clearer price signals to both 

demand response and generation resources.78

Midwest ISO Order No. 719 Compliance (Docket Nos. ER12-1265 and ER09-1049)

The Midwest ISO submitted its initial Order No. 719 compliance filing in April 2009. In this 

filing, MISO stated that its existing market design satisfied the requirements of Order No. 

719 regarding both (1) the participation of demand response resources in ancillary services 

markets,79 and (2) price formation during periods of operating reserve shortages.80 The 

Midwest ISO submitted an additional filing in October 2009 that proposed tariff revisions to 

allow the participation of aggregators of retail customers (ARCs) in Midwest ISO’s markets. 

The Commission accepted both Midwest ISO compliance filings in December 2011, subject 

to a further compliance filing. The Midwest ISO submitted its final Order No. 719 

compliance filing in March 2012,81 proposing tariff revisions regarding the provision of 

ancillary services by demand response resources, including measurement and verification 

protocols82 and tariff revisions regarding the registration, information sharing, credit, and 

 

75 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶ 

31,281 (2008) (Order No. 719), order on reh’g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order 

on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).

76 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 73 Fed. Reg. 64,100 

(Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281, at P 165, et seq. (2008), order on reh’g, Order No. 719-A, 

FERC Stats. & Reg. ¶ 31,292 (2009), FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B, 

129 FERC ¶ 61,252 (2009).

77 PJM Interconnection L.L.C., 139 FERC ¶ 61,057 (2012).

78 PJM Interconnection, L.L.C., 139 FERC ¶ 61,057 (2012).

79 MISO April 2009 Compliance Filing, Transmittal Letter at 6-9, 11-12.

80 Id. at 20-25.

81 MISO March 14, 2012 Compliance Filing, Docket No. ER12-1265-000 (March 2012 Compliance Filing); 

MISO March 23, 2012 Amended Compliance Filing, Docket No. ER12-1265-001 (March 2012 Amended 

Filing).

82 MISO March 2012 Compliance Filing, Transmittal Letter at 2-6.
40 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

other requirements for ARCs. The Midwest ISO proposed to compensate ARCs at the 

LMP.83 The Commission accepted these proposed changes in July 2012.

Other Commission Demand Response Orders

In addition to rulemakings, the Commission also approved several revisions to RTO/ISO 

tariffs related to demand response resources in regional organized wholesale markets. The 

follow briefly describes these revisions and Commission actions.

California ISO Flexible Ramping Constraint (Docket No. ER12-50)

The CAISO proposed tariff changes to implement a flexible ramping constraint in October 

2011 so as to provide CAISO with sufficient ramping capability to match real-time supply 

with real-time demand. The CAISO plans to procure this flexible ramping capability from 

committed, flexible generation resources, proxy demand resources, and participating load 

resources. The Commission accepted and suspended the proposed tariff changes in

December 2011 to establish hearing and settlement judge procedures.84 CAISO is continuing 

to work on developing a new flexible ramping product.

California ISO Regulation Energy Management (Docket No. ER11-4353)

In August 2011, CAISO submitted proposed revisions to its tariff to implement regulation 

energy management. Regulation energy management allows energy storage resources or 

demand response to provide regulation service. Under the proposal, scheduling coordinators 

for non-generator resources within CAISO’s balancing authority area may choose to use 

regulation energy management if they require regulation resources. The Commission 

accepted CAISO’s proposal in November 2011.85 

Midwest ISO’s Extended Locational Marginal Price Algorithm (Docket No. ER12-

668) 

The Midwest ISO filed proposed revisions to its tariff in December 2011 to improve the 

accuracy of pricing in its energy and operating reserve markets by allowing more resources, 

including emergency demand resources, to set the LMP in the day-ahead and real-time 

energy markets as well as the market clearing price in the day-ahead and real-time operating 

reserve markets. The Commission accepted Midwest ISO’s proposal in July 2012, subject to 

further compliance filings.86 

PJM Price Responsive Demand (Docket No. ER11-4628)

PJM filed proposed tariff changes in September 2011 to support the development of price 

responsive demand, an initiative for end-use customers to vary their load in response to 

wholesale electricity prices. PJM proposed to incorporate this demand responsiveness by 

allowing load serving entities (and other market participants), with the approval of their 

relevant regulatory authorities, to commit to reducing loads to specified levels when prices 

rise during emergency conditions. The mechanism is designed to allow the installed capacity 

requirement of load serving entities to be reduced to reflect the lowered need for peaking 

 

83 Id. at 7-16.

84 California Independent System Operator Corporation, 137 FERC ¶ 61,191 (2011).

85 California Independent System Operator Corporation, 137 FERC ¶ 61,165 (2011).

86 Midwest ISO., 140 FERC ¶ 61,067 (2012).
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 41

capacity due to price responsive demand commitments. Following a staff technical 

conference on this proposal, the Commission accepted PJM’s filing effective May 15, 2012, 

subject to further compliance.87

PJM Targeted Sub-Zonal Dispatch (Docket No. ER12-1372)

PJM filed tariff revisions in March 2012 to support sub-zonal dispatch, and recognize the 

expanded selection of demand resource products. Sub-zonal dispatch would allow PJM to 

dispatch a targeted set of demand response resources to address localized emergency events,

rather than calling on the full set of demand resources available within a zone. To implement 

sub-zonal dispatch, PJM also proposed requiring demand response providers to have the 

capability to receive electronic dispatch signals from PJM. PJM proposed that responses to 

sub-zonal dispatch be voluntary at first, with no penalty for non-performance. After a twoyear transition period, PJM proposed assessing compliance charges for inadequate response 

to sub-zonal dispatch only if the sub-zone is defined and posted the day before the Load 

Management event. The Commission accepted PJM’s proposed tariff revisions, which were 

effective June 1, 2012.

88

 

PJM Regulation-Only CSPs (Docket No. ER12-1430)

PJM filed proposed tariff changes in April 2012 to expand the opportunity for demand 

response providers and end-use customers to participate in PJM’s frequency regulation 

market. PJM’s proposed changes would create an “Economic Load Response Regulation 

Only Registration” to (1) simplify the aggregation process for regulation-only resources; (2) 

allow two different demand response providers in the PJM Economic Load Response 

Program to provide demand response services to the same end-use customer, where one 

demand response provider provides regulation service; and (3) allow equipment-specific load 

data, rather than load data for an entire facility, to be submitted to verify that the regulation 

service that cleared the market was actually provided. The Commission accepted these tariff 

revisions in June 2012.89 

PJM M&V Changes (Docket No. ER11-3322) 

PJM filed proposed changes to its tariff in April 2011 to clarify how the performance of 

demand response capacity resources is measured during emergency dispatch and 

performance verification testing. PJM stated that its current rules allowed curtailment 

service providers to offset some customers’ underperformance with the “excess” 

performance of other end-use customers in its portfolio, and argued that this type of 

aggregation gives the appearance of a greater supply of capacity. PJM proposed to modify 

the reference point of capacity demand response load reductions so that each end-use 

customer’s actual load reduction results in a metered load that is less than the customer’s 

peak demand (i.e., the peak contribution identified by PJM). After a technical conference on 

the subject, the Commission accepted PJM’s proposal in November 2011 requiring PJM to 

submit a compliance filing to modify and clarify its proposal.90 

 

87 PJM Interconnection L.L.C., 139 FERC ¶ 61,115 (2012).

88 PJM Interconnection L.L.C., 139 FERC ¶ 61,165 (2012).

89 PJM Interconnection L.L.C., 139 FERC ¶ 61,172 (2012).

90 PJM Interconnection L.L.C., 137 FERC ¶ 61,108 (2011).
42 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Other Demand Response Developments and Issues

In addition to FERC rulemakings and RTO/ISO demand response initiatives, several 

noteworthy developments and activities occurred within and outside government. The 

following summarizes (1) the National Forum on the National Action Plan on Demand 

Response, (2) ARRA-funded consumer behavior studies, (3) the NERC DADS program, (4) 

demand response events during the summer of 2012, and (5) selected state activities. 

National Forum on the National Action Plan on Demand Response

Over the past year, the U.S. Department of Energy, with support from Commission staff,

conducted a National Forum on the National Action Plan on Demand Response.91 Working 

groups comprised of national demand response experts and practitioners are preparing

reports that identified knowledge and research gaps in four areas (cost-effectiveness, 

measurement and verification, program design and delivery, and modeling and tools) and the 

actions needed to help implement the action items included in the National Action Plan on 

Demand Response. 

U.S. Department of Energy-Sponsored Consumer Behavior Studies

The ARRA includes funding and support for nine utility-sponsored consumer behavior 

studies as part of ARRA’s SGIG program. The SGIG studies are designed to assess 

customer acceptance and adoption of time-based electricity rates and enabling technologies, 

such as advanced metering.92 The studies, carried out in nine states and varying in size from 

500 to 60,000 participants, assess consumer usage of a variety of technologies, such as web 

portals, in-home displays, and programmable communicating thermostats. The SGIG studies 

also examine several rate structures, from simple time-of-use rates, to more complex critical 

peak pricing plans, with some combinations offered on either an opt-in or opt-out basis. The 

consumer behavior studies began in 2010 and are scheduled to end in 2014. SGIG recipients 

are required to publish mid-term and final reports on the findings of their studies. As of July 

2012, mid-term reports from Marblehead Municipal Light Department and Oklahoma Gas 

and Electric (OG&E) were published, along with a final SGIG consumer behavior report 

from OG&E. OG&E’s final SmartStudy Together report suggests that customers are open to 

the program’s new technology and time-based pricing schedules, especially programmable 

communicating thermostats and variable peak pricing with a critical peak component. Final 

results from the remaining SGIG consumer behavior studies are expected between 2012 and 

2014. 

 

91 For more information on the National Action Plan on Demand Response, see National Action Plan on 

Demand Response, Federal Energy Regulatory Commission, June 2010; 

http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential.asp, and FERC and DOE Staff, 

Implementation Proposal for the National Action Plan, July 2011, available at http://www.ferc.gov/legal/staffreports/07-11-dr-action-plan.pdf.

92 Smart Grid Investment Grant Program, Project Information: Consumer Behavior Studies, Information 

available at http://www.smartgrid.gov/recovery_act/project_information?keys=&project%5B%5D=15.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 43

NERC Demand Response Data Collection

NERC developed a regular data reporting system for demand response resources to measure 

their contribution to reliability more precisely. NERC’s Demand Response Availability Data 

System (DADS) collects and analyzes semiannual data from several categories of industry 

participants,93 and reporting entities are required to submit information for a specified 

reporting period about (1) individual demand response programs, and (2) each event for 

which demand response was deployed for reliability purposes. 

NERC is implementing DADS in four distinct phases: 

 Phase I was completed in 2010 and served as a pilot stage for establishing the 

mechanism of data collection and metrics for data analysis. It featured information 

on reliability-based programs that are dispatchable and controllable. 

 Phase II (the current phase of the DADS program) is mandatory94 for programs that 

have been in service for one year or longer and have 10 MW or more of enrolled 

resources.

 Phase III is expected to begin in the summer of 2013 and will add voluntary reporting 

of non-controllable economic demand response programs such as time-of-use rates 

and critical peak pricing. 

 Phase IV will require reporting of all demand response resources. It is projected to 

begin in 2014.

The first results of the DADS program were published in NERC’s 2012 State of Reliability 

Report. 95 The report featured Phase II DADS data collected over the summer 2011 reporting 

period (April 1 – September 30, 2011). From data reported by 133 entities, NERC estimates 

an average of 53,005 MW of reliability demand response capacity throughout all the NERC 

regions of the United States and Canada.96 NERC also reports there were 664 demand 

response events called during the summer 2011 reporting period, with an average sustained 

response period of 2 hours and 51 minutes. 

The NERC State of Reliability Report also summarized DADS data by NERC region and 

program type. The ReliabilityFirst Corporation (RFC) region had the largest demand 

response capacity, with 24,386 MW registered. NERC also reported that the Interruptible 

Load and Direct Load Control were the most prevalent program types, accounting for 32 

percent and 26 percent of all programs respectively.

 

93 Responsible Entities include: Balancing Authorities, Distribution Providers, Load-Serving Entities, and 

Purchasing-Selling Entities that are Registered NERC Entities. See the NERC Reliability Functional Model for 

more detail, available at http://www.nerc.com/page.php?cid=2%7C247%7C108.

94 DADS data reporting is mandatory for all entities on the NERC Compliance Registry, through Section 1600 

data requests. See http://www.nerc.com/files/DADS%20Quick%20Facts.pdf for more information. See also 

https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/DRWG/2011/20111003/201

11003%20DRWG%20Item%2005%20DADS%20September%20Training%20Presentation.pdf for a discussion 

of NERC’s authority under 18 C.F.R. Section 39.2(d).

95 North American Electric Reliability Corporation, 2012 State of Reliability Report, May 2012, available at 

http://www.nerc.com/files/2012_SOR.pdf.

96 The Western Electricity Coordinating Council, the Midwest Reliability Organization, and the Northeast 

Power Coordinating Council cover areas of the U.S. and Canada. 
44 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Summer 2012 Demand Response Deployments

This section provides a brief overview of major summer 2012 demand response deployments 

by region, along with links to additional data on summer 2012 demand response events. 

According to the National Oceanic Atmospheric Administration (NOAA), summer 2012 was 

one of the hottest summers on record for the U.S.97 Above-average temperatures drove high 

peak electricity loads and large deployments of demand response resources across the 

country. 

PJM reported several large deployments of demand response resources in June and July 

2012. It estimated 17,148 MW in reductions from its economic demand response program 

over the month of June,98 and PJM also issued hot weather alerts for June 20-21 instructing

generators and transmission owners to defer unnecessary maintenance on plants and power 

lines.99 In July, PJM reported large demand response deployments from July 2-8 and July 

16-18. PJM deployed economic demand response resources from July 2-8; however, no 

emergency demand response was dispatched over this one-week period.100 PJM again 

utilized economic demand response resources on July 16, and a mix of economic and 

emergency demand response resources from July 17-18. In the largest deployment on July 

18, PJM estimates that over 2,500 MW of economic and emergency demand response 

resources was deployed.101 The largest overall economic demand response responses in PJM 

primarily came from Virginia, Pennsylvania, and New Jersey in June-July 2012.102 PJM did 

not report any large demand response deployments during August.

New York ISO (NYISO) called upon demand response resources in June and July 2012. 

NYISO called upon reliability demand response resources several times during June 20-

22.103 The New York Power Authority (NYPA) also deployed demand resources 

participating in its Peak Reduction program for the first time on June 20, reducing hourly 

peak loads in New York City up to 30 MW.104 In July, NYISO utilized reliability demand 

response resources on July 18, and a mix of economic and reliability demand response 

 

97 State of the Climate Report, July 2012, available at http://www.ncdc.noaa.gov/sotc/.

98 Load Response Activity Report, August 2012, available at http://pjm.com/markets-and-operations/demandresponse/~/media/markets-ops/dsr/2012-dsr-activity-report-20120810.ashx.

99 Energy Assurance Daily, June 20, 2012, available at http://www.oe.netl.doe.gov/docs/eads/ead062012.pdf.

100 PJM Estimated Demand Response Activity July 2 – 8, 2012 Report, available at http://pjm.com/markets-andoperations/demand-response/~/media/markets-ops/demand-response/pjm-hot-days-report-for-july-2-july-8-

2012.ashx.

101 PJM Estimated Demand Response Activity July 16 – 18, 2012 Report, available at http://pjm.com/marketsand-operations/demand-response/~/media/markets-ops/demand-response/pjm-hot-days-report-july-16-18-

2012.ashx.

102 Load Response Activity Report, August 2012, available at http://pjm.com/markets-and-operations/demandresponse/~/media/markets-ops/dsr/2012-dsr-activity-report-20120810.ashx.

103 NYISO-Called Events & Tests, August 2, 2012, available at 

http://www.nyiso.com/public/webdocs/products/demand_response/general_info/Historic_EDRP_and_SCR_Act

ivation_Information.pdf.

104 NYPA press release, June 20, 2012, available at 

http://www.nypa.gov/NYPAPressCenter/PressRelease/News/Hot%20Weather%20Leads%20to%20NYPAs%20

Activation%20of%20Demand%20Response%20Program%20to%20Lower%20Electricity%20Use%20in%20N

YC.html.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 45

resources on July 17.105 NYISO did not report any large demand response deployments 

during August.

In contrast to the Mid-Atlantic region, operators in the Midwest and New England primarily 

met summer heat wave loads through non-demand resources. For example, the Midwest ISO 

declared an emergency event on July 17 (which gave the Midwest ISO the option to utilize 

emergency demand response resources), but wind generation unexpectedly increased by 

about 200 MW shortly afterwards. As a result of this increase in supply, combined with 

changing weather conditions and voluntary conservation efforts, the Midwest ISO did not 

have to turn to emergency demand response resources.106 ISO New England also did not 

report calling on demand response resources from June to August 2012, although the ISO 

called upon Real-Time Price Response Loads several times in late May.107

While the California ISO (CAISO) did not have any demand response deployments during 

summer 2012, the ISO did issue several Flex Alerts in August 2012. Flex Alert is a CAISO 

program that encourages California consumers to voluntarily conserve electricity and shift 

demand to off-peak hours when the ISO issues an alert. CAISO reports that its Flex Alert 

program led to significant voluntary reductions. For example, CAISO estimates that a Flex 

Alert issued on August 10 resulted in nearly 1,000 MW in load reductions. PG&E, one of 

the three large investor-owned utilities in California, estimates that over half of these 

reductions came from PG&E’s voluntary demand response programs.108

Selected State Activities

State-regulated demand response activities over the past year have primarily focused on 

evaluating applications for large-scale rollouts of new time-based electricity pricing 

programs. States such as Arizona, California, and Maryland, as well as Arkansas, Oklahoma, 

Illinois, Idaho, Colorado, and Connecticut, have examined the issue of time-based rates, and 

many customers in these states are having their first experiences with these time-varying 

rates. The following section details developments in program rollouts in these nine states, 

and provides a spotlight on retail demand response programs in Texas.

Time-Based Pricing

Time-based pricing programs provide customers with economic incentives to shift 

consumption away from periods of increased demand,109 giving an opportunity to save 

energy expenditures. In addition, shifts in consumption may reduce the need to construct 

 

105 NYISO-Called Events & Tests, August 2, 2012, available at 

http://www.nyiso.com/public/webdocs/products/demand_response/general_info/Historic_EDRP_and_SCR_Act

ivation_Information.pdf.

106 Summer Heat Wave, MISO Market Subcommittee Presentation, August 7, 2012, available at 

https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/MSC/2012/20120807/20120

807%20MSC%20Item%2002b%202012%20Summer%20Heat%20Wave.pdf.

107 See http://www.isone.com/calendar/month.action?date=20120501&cats=18,19,20&type=2&link=yes&filter=off

108 PG&E press release, available at http://www.pgecurrents.com/2012/08/17/pge-customers-heed-the-call-toconserve/.

109Incentives include actual incurred electricity prices, a pre-specified incentive payment, or the customer’s 

response to an emergency alert. 
46 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

new power plants to meet increasing peak demand periods. Time-based pricing programs 

include a range of rate structures, such as critical peak pricing, critical peak rebates, real-time 

pricing, and variable peak pricing. A number of states and utilities took actions to implement 

time-based pricing programs in the past year. The Energy Information Administration (EIA) 

reports that twenty-nine states have adopted time-based pricing requirements, have 

requirements pending, or are studying these rate structures.

110

 

In Arizona, an estimated one-third of the residential customers of Arizona Public Service and 

Salt River Project have voluntarily chosen to participate in one of their utility’s time-of-use

programs.

111

 Both Arizona Public Service and Salt River Project offer web portals with userfriendly language to assist customers in making rate decisions, and offer features that allow 

residential customers to compare their rate options so that interested customers may choose 

the most cost-efficient rate program.112 Arizona Public Service provides graphical 

comparisons of amounts paid under each available rate,113 and Salt River Project provides 

customers with a web-based interactive tool that asks a series of questions so customers can 

choose a plan that fits their lifestyles.114

California is another state facilitating customer participation in dynamic pricing programs: all 

three investor-owned utilities in California plan to offer a dynamic pricing option to all 

customers by the end of 2012.115 The California investor-owned utilities have had default 

time-of-use and critical peak pricing rates for their large commercial and industrial customers 

for several years, and while a law referred to as Senate Bill 645 currently prevents defaulting 

residential customers to these rates, efforts are being made to expedite the transition of 

residential customers to dynamic pricing plans “subject to resolution of pending proceedings 

and legal resolution of SB 695 provisions.”116 The California Public Utilities Commission

 

110 EIA, Table 3 Existing or Pending Legislative or Regulatory Activity for Demand Response, available at 

http://www.eia.gov/analysis/studies/electricity/pdf/smartggrid.pdf.

111 King, Chris, “Why energy consumers love VOLUNTARY dynamic pricing,” eMeter: Smart Grid Watch, 

March 18, 2011, available at http://www.emeter.com/smart-grid-watch/2011/why-energy-consumers-lovevoluntary-dynamic-pricing/. 

112 See: APS, Residential Rate Comparison, available at 

https://www.aps.com/main/services/demos/RateComparisonAudio.htm; SPR, Choose your price plan & save on 

electric bills, available at http://www.srpnet.com/prices/home/ChooseYourPricePlan.aspx. 

113 Ibid

114 Schwartz, Judith, “Salt River Project: The Persistence of Choice,” A National Town Meeting on Demand 

Response and Smart Grid, ADS Conference Presentation, June 28, 2012, available at 

http://www.demandresponsetownmeeting.com/presentations/. 

115 California Public Utilities Commission, Public Utilities Code Section 748 Report to the Governor and 

Legislature on Actions to Limit Utility Cost and Rate Increases, May 2012, available at 

http://www.cpuc.ca.gov/NR/rdonlyres/339C0DD6-0298-4BC7-AAD9-

A27779AA43D4/0/2012SB695ReporttoGovernorandLegislatureFinalv2.pdf.

116 For example, see California Public Utilities Commission, Proceeding A.10-08-005: Application of Pacific 

Gas and Electric Company for Approval to Defer Consideration of Default Residential Time-Variant Pricing 

until Its Next General Rate Case Phase 2 Proceeding, or in the Alternative for Approval of its Proposal for 

Default Residential Time-Variant Pricing and For Recovery of Incremental Expenditures Required for 

Implementation (U39E), available at 

http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:392034754001701::NO:RP:: Proceeding A.10-

07-009: In the Matter of the Application of San Diego Gas & Electric Company (U902E) for Approval of its 

Proposals for Dynamic Pricing and Recovery of Incremental Expenditures Required for Implementation; 

available at http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:1372938263824701::NO:RP:

Proceeding A.11-06-007: Application of Southern California Edison Company (U338E) To Establish Marginal 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 47

recently authorized portions of the investor-owned utilities’ programs’ dynamic pricing 

requests for 2012 through 2014 as part of the utilities’ demand response programs and budget 

proposals.117 

Maryland is also active in implementing dynamic pricing programs. The Maryland Public 

Service Commission approved applications from Baltimore Gas and Electric and Potomac 

Electric Power Company to offer peak time rebate programs. The Baltimore Gas and 

Electric program was approved for rollout in June 2013, while Potomac Electric Power 

Company planned to offer its program to over 5,000 customers in July 2012.118 Both 

programs will be available on an opt-in basis to customers who have advanced meters 

installed. 

Several other states also examined and approved dynamic pricing programs and rates. These 

include:

 Arkansas and Oklahoma. The Arkansas Public Service Commission and the 

Oklahoma Corporation Commission have each allowed the Oklahoma Gas and 

Electric Company to offer residential customers variable peak pricing rates on an optin basis.119, 120

 

 Illinois. In Illinois, both Ameren Utilities and Commonwealth Edison Company have 

received approval from the Illinois Commerce Commission to establish residential 

real-time pricing programs.121 

 Idaho. The Idaho Public Utilities Commission approved a voluntary Idaho Power 

dynamic pricing program, initially proposed for 1,200 customers. After Idaho Power 

submits a report on its 2012 results, the program may be expanded to additional 

customers in 2013.122 

 

Costs, Allocate Revenues, Design Rates, and Implement Additional Dynamic Pricing Rates, available at 

http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:1372938263824701::NO:RP:.

117 The decision authorized thee-year budgets of approximately $191.9 million for PG&E, $196.3 million for 

SCE and $65.8 million for SDG&E.

118 Maryland Public Service Commission, In the Matter of Baltimore Gas and Electric Company for 

Authorization to Deploy a Smart Grid Initiative and To Establish a Surcharge for the Recovery of Cost, Case 

No. 9208, Order No. 84925, Item 143, Issued May 24, 2012, available at: 

http://webapp.psc.state.md.us/Intranet/home.cfm; and Maryland Public Service Commission, In the Matter of 

Potomac Electric Power Company and Delmarva Power and Light Company Request for the Deployment of 

Advanced Metering Infrastructure, Case No. 9207, Item 207, Order No. 84966, Issued June 8, 2012, available 

at: http://webapp.psc.state.md.us/Intranet/home.cfm. 

119 Oklahoma Corporation Commission, Standard Pricing Schedule: R-VPP Residential Variable Peak Pricing 

Program, Docket No. PUD 201000016, Order No. 575500, Approved May 2010, available at 

http://www.oge.com/Documents/OK/3.50%20R-VPP.pdf.

120 Arkansas Public Service Commission, Oklahoma Gas and Electric Company Residential Variable Peak 

Pricing, Docket No. 10-067-U. Order No. 6, Approved June 2011, available at 

http://www.oge.com/Documents/ARK/2011%20Arkansas%20Docket%2010-067-U/R-VPP%206-6-2011.pdf.

121 Illinois Commerce Commission, Real Time Pricing, available at 

http://www.icc.illinois.gov/Electricity/RTP.aspx. 

122 Idaho Public Utilities Commission, Case No. IPC-E-12-05: In the Matter of the Application of Idaho Power 

Company for Approval of Modifications to Schedules 1, 4, and 5 Implementing a Time Variant Pricing Plan, 
48 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

 Colorado. In April 2011, the Colorado Public Utilities Commission (CPUC) closed a 

docket on exploring the issues related to smart grid and advanced metering by issuing 

a decision that included conclusions and next steps for the state.123 In this document,

the CPUC noted that one of the primary benefits of advanced meters is to provide a 

platform for dynamic pricing.

 Connecticut. In Connecticut, all electric distribution companies must offer voluntary 

critical peak pricing or real-time pricing programs for all customer classes.124 As a 

result, the Connecticut Public Utilities Regulatory Authority has approved variable 

peak pricing rates for customers of both the Connecticut Light and Power 

Company125 and the United Illuminating Company.126 

Texas Retail Demand Response

The Public Utility Commission of Texas has developed a process to integrate the deployment 

of advanced metering with competitive demand response retail service markets. After an

electric utility installs an advanced meter, residential customers in Texas have the option to 

choose demand response services and compatible technologies from a number of competing 

companies. Eligible demand response service providers include both retail energy providers 

and vendors of third-party products and services.127 Third-party providers that participate in 

Texas’ program have noted that they must engage and educate consumers on the benefits of 

demand response technology.

The Public Utility Commission of Texas, ERCOT, and interested stakeholders are also 

working on reducing barriers to increased demand response participation among advanced 

metering customers.128,129 Through a series of workshops, stakeholders are examining a 

 

Order No 32499, March 27, 2012, available at: 

http://www.puc.idaho.gov/orders/recent/Final_Order_No_32499.pdf. 

123 Colorado Public Utilities Commission, In the Matter of the Investigation of the Issues Related to Smart Grid 

and Advanced Metering Technologies: Order Stating Conclusions and Next Steps, Adopted March 2011, 

available at https://www.dora.state.co.us/pls/efi/EFI_Search_UI.Show_Decision?p_session_id=&p_dec=13836.

124 See: Connecticut Public Utilities Regulatory Authority, Docket No. 03-07-02RE11: Application of the 

Connecticut Light and Power Company to Amend its Rate Schedule – Review of VPP Tariffs, September 21, 

2011 Decision, available at 

http://www.dpuc.state.ct.us/dockhist.nsf/8e6fc37a54110e3e852576190052b64d/d72d04fcf84696c18525795800

5bd05a?OpenDocument. 

125 Ibid.

126 Connecticut Public Utilities Regulatory Authority, Docket No. 05-06-04RE04: Application of The United 

Illuminating Company To Increase Its Rates and Charges, – Public Act 07-242, Seasonal Rates, Non 

Generation-Related Time-of-Use Pricing and Related Rate Design Issues, September 28, 2008, Final Decision, 

available at 

http://www.dpuc.state.ct.us/dockhist.nsf/8e6fc37a54110e3e852576190052b64d/17989d79124999ea852575230

0524e43?OpenDocument.

127 See: ERCOT, Demand Side Working Group (DSWG), AMI’s Next Frontier Workshop, Agenda Item 

#6:Technology/Product Providers Perspectives, August 30, 2011, available at

http://ercot.com/calendar/2011/08/20110830-DSWG.

128 ERCOT, Demand Side Working Group (DSWG), AMIT-DSWG Workshop, ‘AMI’s Next Frontier: Demand 

Response Part 2’, December 16, 2011, available at http://ercot.com/calendar/2011/12/20111216-DSWG.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 49

broad variety of potential barriers, including (1) the short duration of retail contracts (e.g., 12 

or 24 months) that may not allow retail demand response providers to recover product and 

service costs, (2) the lack of regulatory requirements for retail energy providers to offer 

specific products, (3) limited third-party access to data, and (4) the reliability of 

communication networks.

Barriers to Demand Response 

Demand-response can be accomplished through a variety of means and ways. As evidenced 

by the activities described above, the federal government, the Commission, and state and 

local governments have made progress on removing barriers to customer participation in 

demand response. Nevertheless, and depending on the type of demand-response to be 

pursued, several outstanding barriers remain. 

 Limited Number of Retail Customers on Time-Based Rates. Previous 

Commission staff annual reports highlighted the low number of retail customers who 

purchase electricity based on time-based rates. While there is progress, without an 

expanded implementation of time-based rates across the U.S., the development of 

new technologies and programs and the fulfillment of the nation’s demand response 

potential may be slowed.

 Measurement and Cost-Effectiveness of Reductions. While the lack of 

consistency in the measurement and verification of demand reductions and the lack of 

demand responsive-specific cost-effectiveness tools remain as barriers, significant 

progress to reduce these barriers occurred in the past year. NAESB completed some 

work on measurement and verification and the Commission issued a Notice of 

Proposed Rulemaking in April proposing to adopt the Phase II wholesale demand 

response measurement and verification standards. Furthermore, changes to the 

measurement and verification of demand response in organized wholesale energy and 

ancillary markets indicate movement toward more consistency across the various 

RTOs. Finally, focused review of these two issues is occurring within the National 

Forum on the National Action Plan on Demand Response. 

 Lack of Uniform Standards for Communicating Demand Response Pricing, 

Signals and Usage Information. Communications to and interactions with demand 

response resources and end-use devices are typically based on company- and 

technology-specific proprietary protocols and techniques. The lack of common 

information models and protocols resulted in the potential for duplicative systems and 

inefficient transfer of pricing and usage information between parties. As discussed in 

Chapter 4, recent standards development work being led by the National Institute of 

Standards and Technology and the Smart Grid Interoperability Panel should help 

remove this barrier, if industry embraces and utilities these standards. 

 Lack of Customer Engagement. Customers need to be effectively educated and 

informed about demand response and smart grid opportunities. Effective outreach 

 

129 Public Utility Commission of Texas, PUCT Project 34610: Implementation Project Relating to Advanced 

Metering, available at http://www.puc.state.tx.us/industry/projects/electric/34610/34610.aspx. 
50 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

and communication are needed to explain demand response, time-based pricing and 

smart grid investments and the impacts of these at the customer level. Otherwise, 

customers may respond negatively to actions taken by their electric providers, e.g., 

the deployment of advanced meters. As the experiences of Oklahoma Gas and 

Electric and Arizona Public Service demonstrate, successful customer engagement 

efforts can be used to support smart grid investments, thereby promoting customer 

support. The efforts of the Smart Grid Consumer Collaborative to draw upon best 

practices may prove helpful.130

 Lack of Demand Response Forecasting and Estimation Tools. As the National 

Action Plan on Demand Response identified, “new tools and methods should be 

developed to directly incorporate demand response into dispatch algorithms and 

resource planning models,” and “to forecast and model the capability of demand 

resources to adjust consumption in near real-time.”131 Current planning and 

forecasting tools are not sufficiently robust to model adequately the capability of 

demand response to serve as an alternative to building new generation and 

transmission and to act as a resource to alleviate transmission congestion. The efforts 

sponsored by U.S. Department of Energy to develop interconnection-wide plans that 

include demand side resources may help address this need. In addition, the National 

Forum on the National Action Plan on Demand Response is examining other 

modeling needs. The National Forum effort is inventorying existing demand 

response tools and models, and is identifying needed modeling and tools.

 

130 Consumer engagement is a key topic for the Smart Grid Consumer Collaborative (SGCC). See SGCC, 

Consumer Engagement, available at http://smartgridcc.org/category/consumer-engagement.

131 FERC, National Action Plan on Demand Response, June 2010, pp. 75-76.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 51

CHAPTER 4. SMART GRID DEVELOPMENTS SUPPORTING DEMAND 

RESPONSE

This chapter reports on two key smart grid developments that support the further 

development of demand response resources: (1) the development of new communications 

and demand response standards by the National Institute of Standards and Technology’s 

Smart Grid Interoperability Panel, and (2) the Smart Grid Demonstration Program sponsored 

by the U.S. Department of Energy.

Demand Response-Related Smart Grid Standards Development

In Title XIII of the Energy Independence and Security Act of 2007 (EISA), Congress 

addressed the need for standards for communication and interoperability of the grid to 

enable, among other things, the incorporation of demand response and demand-side 

resources into grid operations.

132

 EISA directed the National Institute of Standards and 

Technology (NIST) to coordinate the development of a framework to achieve 

interoperability of smart grid devices and systems, including protocols and model 

standards for information management.

133

 In turn, NIST set up the Smart Grid 

Interoperability Panel (SGIP), a public-private consensus-based organization, to coordinate 

standards development with input from a broad range of smart grid stakeholders.134 

In 2009, the Commission issued a Smart Grid Policy Statement that identified demand 

response as one of four key functional priorities for smart grid interoperability standards 

development.135 In the Policy Statement, the Commission reiterated that demand response 

can play a important role in integrating variable sources of renewable generation, and in 

maintaining system security in constrained areas.136 NIST agreed that demand response is a 

priority for interoperability standards development, and has devoted considerable resources 

to this effort.137 The following section reviews the progress of the SGIP efforts.

Demand Response Activities within the NIST/SGIP Process

The NIST Framework and Roadmap for Smart Grid Interoperability, Release 2.0 states the 

following:

“...the SGIP focuses on two principal areas where value can be added: 

 Analysis of cross-functional area applications. Such applications often require 

coordination between one or more technologies, and this coordination introduces 

 

132 Public Law No. 110-140, 121 Stat. 1492, 1783-84, codified at 15 U.S.C. 17381 et seq. (2007).

133 EISA sec. 1305(a), codified at 15 U.S.C. 17385(a).

134 NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 2.0, at page 142.

135 Federal Energy Regulatory Commission, Smart Grid Policy, 128 FERC ¶ 61,060 (2009). The other three 

functional priorities are wide-area situational awareness, energy storage, and electric transportation. The 

Commission also identifies two cross-cutting priorities, namely cyber security and communication and 

coordination across inter-system interfaces.

136 Id., at P 74.

137 NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 1.0.
52 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

issues and requirements beyond the original scope of the technology or 

technologies. 

 Coordination among all groups which must complement each other on the 

resolution of a gap or overlap in Smart Grid technologies. 

The first of these focus areas, Analysis, is provided by the SGIP through the working group 

structure, primarily through the Domain Expert Working Groups. The second of these focus 

areas, Coordination, is provided by the SGIP through the origination and oversight of the 

Priority Action Plan (PAP) groups.”138

NIST and the SGIP established the following Priority Action Plans for demand response. As

the name suggests PAPs are created when the SGIP determines there is a need for 

interoperability coordination on some urgent issue.”139

 Standardized demand response information and signals;

 Standardized energy usage information;

 Wholesale demand response communication protocols; and

 Facility-level communication standards.

A number of standards related to demand response have received supermajority support 

within the SGIP,

140 or have made major strides to develop new standards, as described in the 

following sections.

Standardized demand response information and signals

Recognizing the need for electricity providers to be able to communicate demand response 

and distributed energy resources signals (e.g., price, information on system conditions, and 

dispatch instructions) with each other and with customers, the SGIP sponsored several PAPs 

to develop common protocols for communicating (1) price information, (2) demand response 

signals, and (3) equipment status for demand response and distributed energy resources.

141

 

Two standards development organizations, the Organization for the Advancement of 

Structured Information Standards (OASIS) and NAESB, did much of the standards 

development work, in collaboration with the PAP working groups. 

The OpenADR Alliance, a diverse group of utilities, independent system operators, 

regulators, demand response providers, and controls suppliers is currently testing various 

forms of the OpenADR 2.0 standard.

 

138 Supra at page 143.

139 Id., at page 150.

140 When smart grid standards are supported by a supermajority, they are included in SGIP’s Catalog of 

Standards. The Catalog of Standards is a compendium of standards and practices considered to be relevant for 

the development and deployment of an interoperable Smart Grid, Information on the Catalog of Standards is 

available at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/SGIPCatalogOfStandards. 

141 PAP 3 (Develop Common Specification for Price and Product Definition) facilitated the development of the 

OASIS Energy Market Information Exchange (eMIX) standard. PAP 4 (Develop Common Schedule 

Communication Mechanism for Energy Transactions) helped produce the OASIS WS-Calendar standard. PAP 

9 (Standard Demand Response and Distributed Energy Resources Signals) facilitated the development of the 

OASIS Energy Interoperation standard and OpenADR 2.0. For more information on the SGIP PAP process, see

http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/WebHome.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 53

Standardized energy usage information

In recognition of the importance of energy usage information to the smart grid, and the lack 

of a common, standardized approach, the SGIP established PAP 10 (Standard Energy Usage 

Information). The associated working group had the mission to develop a standardized 

information model for energy usage and to develop business rules for authorizing access to 

this usage information. Without these efforts, software developers and utilities would each 

need to develop customized, one-off solutions. Much of the work for this PAP has been led

by NAESB. The result of NAESB’s work (the Energy Usage Information standard) has been 

included in the Catalog of Standards. NAESB has also developed an Energy Service 

Provider Interface (ESPI) that provides a way for Energy Usage Information to be shared, in 

a controlled manner to ensure confidentiality, between participants in the energy services 

markets. 

The Green Button initiative is also based on the framework created by the NAESB Energy 

Usage Information and ESPI standards. As discussed in Chapter 2, Green Button is an 

industry-led effort to provide electricity customers with easy access to their energy usage 

data in a consumer-friendly and computer-friendly format. To further develop the Green 

Button effort, the SGIP recently approved the creation of a new PAP 20 (Green Button ESPI 

Evolution). 

There were several national-scale efforts over the past two years that have focused on 

providing privacy protection for consumer energy usage information. The SGIP Cyber 

Security Working Group devoted an entire chapter of the NIST IR 7628142 to privacy 

principles. NAESB has also developed a set of guidelines143 with respect to customer data 

being shared between utilities and third-party service providers.

Wholesale demand response communication protocols

The SGIP recently formed the PAP 19 working group (Wholesale Demand Response 

Communication Protocol) to develop and enhance data exchange between RTOs and demand 

response aggregators, which may include utilities.

144

 The new effort is not intended to 

compete with standards for communicating with end-use customers, but rather is designed to 

create a seamless transfer of information and signals from wholesale system operators to 

demand response aggregators and then to end-use customers. 

The PAP 19 working group is in the process of identifying electricity market requirements 

and gaps within current standards frameworks (including but not limited to Energy 

Interoperation, OpenADR 2.0 and the IEC Common Information Modeling), to adequately 

address demand response wholesale market interfaces.145 

 

142 NISTIR 7628, Guidelines for Smart Grid Cyber Security: Vol. 2, Privacy and the Smart Grid, available 

at http://nist.gov/smartgrid/upload/nistir-7628_total.pdf.

143 North American Energy Standards Board, REQ.22 Third Party Access to Smart Meter-Based Information

(2011)

144 PAP 19 began its deliberations in March 2012. 

145 PAP 19 developed a Wholesale Demand Response Communication Protocol that was out for comment in 

Autumn 2012. See http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/PAP19WholesaleDR for more 

information.
54 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Facility-level standards

The standards discussed in the preceding sections focus on the interchange of information 

and data among parties and across domains, and are not directly focused on the transfer of 

information or communications at the facility level. To address facility-level 

communications, the SGIP created two additional PAPs focused on communication and 

information exchange within buildings and premises.

One PAP deals with the Smart Energy Profile, which originally was a proprietary protocol 

developed for residential end users by the Zigbee Alliance, a collaboration of vendors and 

utilities. The Smart Energy Profile has since changed into an open standard that is 

harmonized with several previously competing communications standards. A new version 

2.0 that communicates with home area networks is expected to be published by the end of 

2012. It however is not compatible with the older Smart Energy Profile 1.0 and successor 

versions already installed in many meters. This lack of compatibility has troubled state 

commissions in Texas and California. In response, the SGIP established PAP 18 to focus on 

the technical issues associated with migration and the coexistence of two Smart Energy 

Profile versions. PAP 18 succeeded in identifying best practices and means to allow 

continued use of Smart Energy Profile 1.x and transition towards the use of Smart Energy 

Profile 2.0.146

A second PAP (PAP 17) focuses on interoperability among building energy management 

systems for primarily commercial buildings, although the standard could also be used in 

industrial facilities and residences. The standard is being developed through a partnership 

between ASHRAE and NEMA. This standard enables communications of demand response 

signals from system operators and aggregators, through building energy management 

systems, to equipment within facilities. It also can allow communications about electrical 

loads within the facility back to the utility and other electrical service providers. 

Smart Grid Demonstration Program

The Smart Grid Demonstration Program147 operated by the U.S. Department of Energy aims 

to demonstrate how a suite of existing and emerging smart grid concepts can be innovatively 

applied and integrated to prove technical, operational, and business model feasibility. The 

goal of the program is to demonstrate new and more cost-effective smart grid technologies, 

tools, techniques, and system configurations that significantly improve on the ones 

commonly used today. This program is currently funding 16 smart grid regional 

demonstration projects and 16 energy storage projects.148 Most of these support advanced 

metering or demand response programs.

The regional smart grid demonstration projects were selected to verify smart grid viability, 

quantify smart grid costs and benefits, and validate new smart grid business models at scales 

that can be readily replicated across the country. Of these 16 projects, the nine that employ 

 

146 A white paper on this transition received supermajority support within the SGIP and is available at 

http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/PAP18SEP1To2TransitionAndCoexistence.

147 This program was authorized by the Energy Independence and Security Act of 2007, Section 1304, and

amended by the Recovery Act.

148 The total budget for the 32 projects is about $1.6 billion; the federal share is about $600 million.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 55

demand response technologies or otherwise enhance demand response are described 

below.

149

 

 AEP’s gridSMART Demonstration Project demonstrates the ability to maximize 

distribution system efficiency and reliability, and consumer use of demand response 

programs to reduce energy consumption, peak demand costs, and fossil fuel 

emissions. 

 Battelle Memorial Institute’s Pacific Northwest Smart Grid Demonstration 

Project is a collaboration between utilities, universities, and technology partners 

across five states More than 20 types of responsive Smart Grid assets, including 

demand response, storage, and direct load control, will be tested across six regional 

and utility operational objectives at 15 unique distribution sites operated by 12 

utilities. 

 Kansas City Power and Light’s Green Impact Zone SmartGrid Demonstration is 

built around a SmartSubstation with a local distributed control system that includes 

advanced generation, distribution, and customer technologies. 

 Long Island Power Authority’s Long Island Smart Energy Corridor will 

integrate advanced metering technology with automated substation and distribution 

systems to reduce peak demand and energy costs, while improving the ability to 

identify and respond to outages. 

 Los Angeles Department of Water and Power’s Smart Grid Regional 

Demonstration is a collaboration between a consortium of research institutions to 

develop new Smart Grid technologies, quantify costs and benefits, validate new 

models, and create prototypes to be adapted nationally. The project consists of four 

broad initiatives: demand response, electric vehicle integration, customer behavior, 

and cyber security.

 National Rural Electric Cooperative Association’s Enhanced Demand and 

Distribution Management Regional Demonstration demonstrates Smart Grid 

technologies with 27 cooperatives in 11 states. The project will conduct studies in 

advanced volt/volt-ampere reactive for total demand; demand response; critical peak 

pricing; water heater and air conditioning load control; thermal storage; energy usage 

portal pilots; consumer in-home energy display pilots; AMI integration; distribution 

co-op meter data management system applications; and self-healing feeders for 

improved reliability.

 NSTAR Electric and Gas Corporation’s Automated Meter Reading-Based 

Dynamic Pricing will enable residential dynamic pricing (time-of-use, critical peak 

rates, and peak time rebates) and two-way direct load control by capturing automated 

meter reading (AMR) data transmissions and communicating through existing 

customer-sited broadband connections in conjunction with home area networks. 

 

149 SmartGrid.gov, Smart Grid Demonstration Program, available at

http://www.smartgrid.gov/recovery_act/overview/smart_grid_demonstration_program. 
56 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

 Pecan Street Project’s Energy Internet Demonstration is developing and 

implementing an Energy Internet in Austin, Texas. Smart Grid technologies include 

advanced metering, energy control gateways, advanced billing software, and smart 

thermostats, distributed generation, thermal storage, battery storage, and smart 

irrigation systems. 

 Southern California Edison Company’s Irvine Smart Grid Demonstration will 

deploy advanced Smart Grid technologies in an integrated system to be more reliable, 

secure, economic, efficient, safe, and environmentally friendly. The technology 

demonstrations will include three main areas: (1) Energy Smart Customer Devices; 

(2) Year 2020 Distribution System including distribution automation with looped 

circuit topology, advanced voltage/VAR control, advanced distribution equipment, 

smart metering, utility-scale storage, and dispatched renewable distributed generation; 

and (3) a Secure Energy Network to demonstrate end-to-end management of a 

complex high performance telecommunication system.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 57

APPENDIX A: SECTION 1252 OF THE ENERGY POLICY ACT OF 

2005

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 pre-established 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 time-based 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.
58 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

‘‘(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

(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 ratemaking 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
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 59

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.

(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.
60 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

(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 

non-regulated 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 non-regulated 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).’
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 61

APPENDIX B: ACRONYMS AND ABBREVIATIONS

AMI Advanced Metering Infrastructure

AMR Automated Meter Reading OR Automatic Meter Reading

ARRA American Recovery and Reinvestment Act of 2009

ASCC Alaska Systems Coordinating Council

CAISO California Independent System Operator

EIA Energy Information Administration

EISA 2007 Energy Independence and Security Act of 2007

EPAct 2005 Energy Policy Act of 2005

ERCOT Electric Reliability Council of Texas, Inc.

FERC Federal Energy Regulatory Commission 

FRCC Florida Reliability Coordinating Council

kW Kilowatt

ISO Independent system operator

ISO-NE Independent System Operator of New England

LMP Locational Marginal Price

Midwest ISO Midwest Independent Transmission System Operator

MRO Midwest Reliability Organization

MW Megawatt

MWh Megawatt-hour

NAESB North American Energy Standards Board

NERC North American Electric Reliability Corporation

NIST National Institute of Standards and Technology

NPCC Northeast Power Coordinating Council

NYISO New York Independent System Operator

OATT Open Access Transmission Tariff

PJM PJM Interconnection, L.L.C

RFC ReliabilityFirst Corporation

RTO Regional transmission organization

SERC SERC Reliability Corporation

SGIG Smart Grid Investment Grant

SGIP Smart Grid Interoperability Panel

SPP Southwest Power Pool, Inc.

TRE Texas Regional Entity

WECC Western Electricity Coordinating Council
62 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 63

APPENDIX C: GLOSSARY

Note: The terms and definitions provided in this glossary were provided to survey 

respondents and are for the limited purpose of the survey.

Actual MWh Change: The total change in energy consumption (measured in MWh) that 

resulted from the deployment of demand response programs during the year. 

Advanced Meters: Meters that measure and record usage data at hourly intervals or more 

frequently, and provide usage data to both consumers and energy companies at least once 

daily. Data are used for billing and other purposes. Advanced meters include basic hourly 

interval meters, meters with one-way communication, and real-time meters with built-in twoway communication capable of recording and transmitting instantaneous data. 

Aggregator: See “Curtailment Service Provider” 

Ancillary Services: Services that ensure reliability and support the transmission of electricity 

to customer loads. Such services may include: energy imbalance, operating reserves, 

contingency reserves, spinning (also known as synchronized, ten-minute spinning, 

responsive) reserves, supplemental (also known as non-spinning, non-synchronized, tenminute non-synchronous, thirty-minute operating) reserves, reactive supply and voltage 

control, and regulation and frequency response (also known as regulation reserves, regulation 

service, up-regulation and down-regulation). 

Bid Limit: The maximum bid, in $/MWh, that can be submitted by a demand response 

program participant. If there is no bid limit, leave blank. 

Capacity (program type): Displacement or augmentation of generation for planning and/or 

operating resource adequacy; penalties are assessed for nonperformance. 

Capacity Market Programs: Arrangements in which customers offer load reductions as 

system capacity to replace conventional generation or delivery resources. Participating 

customers typically receive notice of events requiring a load reduction and face penalties 

when failing to curtail load. Incentives usually consist of up-front reservation payments. 

Capacity Service: A type of demand response service in which demand resources are 

obligated over a defined period of time to be an available resource for the system operator. 

Commercial and Industrial: Belonging to either of the energy-consuming sectors that 

consist of (a) a broad range of facility types including office buildings, retail establishments, 

hospitals, universities, the facilities of federal, state, and local governments and non-profit 

organizations, institutional living quarters, master-metered apartment buildings, and homes 

on military bases; and (b) manufacturing facilities and equipment used for producing, 

processing, or assembling goods and encompassing the following types of activities: 

manufacturing; processing; agriculture, forestry and fisheries; mining; and construction. 

Also, a business labeled as “industrial” by the North American Industry Classification 
64 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

System or by the energy provider on the basis of energy demand or annual usage exceeding 

some specified limit set by the energy provider.

Coincident Reduction Capability: The amount of demand response curtailments that would 

be realized if all demand response products were called simultaneously and all responded by 

curtailing load at prearranged levels or at their enrolled quantity. 

Critical Peak Pricing with Load Control: Demand-side management that combines direct 

load control with a pre-specified high price for use during designated critical peak periods, 

triggered by system contingencies or high wholesale market prices. 

Critical Peak Pricing: Rate and/or price structure designed to encourage reduced 

consumption during periods of high wholesale market prices or system contingencies by 

imposing a pre-specified high rate or price for a limited number of days or hours. 

Curtailment Service Provider: Businesses that sponsor demand response programs that 

recruit and contract with end users, and sell the aggregated demand response to utilities, 

RTOs and ISOs. A Curtailment Service Provider is sometimes called an Aggregator and is 

not necessarily a load-serving entity. 

Customer Sector: A group of customers: residential, commercial and industrial, and 

other (for example, transportation, agricultural). 

Demand Bidding & Buy-Back: A program which allows a demand resource in retail and 

wholesale markets to offer load reductions at a price, or to identify how much load it is 

willing to curtail at a specific price. 

Demand Resource or Demand-Side Resource: An electricity consumer that can decrease 

its power consumption in response to a price signal or direction from a system operator. 

Demand Response: Changes in electric use by demand-side resources from their normal 

consumption patterns in response to changes in the price of electricity, or to incentive 

payments designed to induce lower electricity use at times of high wholesale market prices or 

when system reliability is jeopardized. 

Demand Response Program: A company's service/program/tariff related to demand 

response, or the change in customer electric usage from normal consumption patterns in 

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

designed to induce lower electricity use at times of high wholesale market prices, or a change 

in electric usage by end-use customers at the direction of a system operator or an automated 

preprogrammed control system when system reliability is jeopardized. Includes both timebased rate programs and incentive-based programs. 

Demand Response Program/Tariff and Program/Tariff Types: A company or utility's 

service/product/compilation of all effective rate schedules, general terms and conditions and 

standard forms related to demand response and/or AMI services and classification thereof. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 65

Direct Load Control: A demand response activity by which the program sponsor 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. Also known as direct control load management.

Display Unit/In-home Display: Customer on-site device that receives (from a service 

provider or from a smart meter) and displays for the customer information such as usage and 

pricing data, messages, and alerts. 

Duration of Event: The length of an Emergency or Economic Demand Response Event, in 

hours. 

Economic Demand Response Event: An 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. 

Electric Utility: A corporation, person, agency, authority, or other legal entity or 

instrumentality producing, transmitting, or distributing electricity for use primarily by the 

public. This includes: 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 owning distribution facilities are also included in this definition. 

Emergency Event: An abnormal system condition (for example, system constraints and 

local capacity constraints) that requires automatic or immediate manual action to prevent or 

limit the failure of transmission facilities or generation supply that could adversely affect the 

reliability of the Bulk Electric System. 

Emergency Demand Response Event: The period of time during which participants in a 

Demand Response Program must reduce load. The Emergency Demand Response Event is 

announced by the program sponsor in response to an Emergency Event declared by it or by 

another entity such as a utility or RTO/ISO. Demand Response Program sponsors, utilities 

and RTO/ISOs typically declare these emergency events. 

Emergency Demand Response Program: A demand response program that provides 

incentive payments to customers for load reductions achieved during an Emergency Demand 

Response Event. 

End-Use Customer: A firm or individual that purchases electricity for its own consumption 

and not for resale; an ultimate consumer of electricity. 

Energy Payment for MWh Curtailed ($/MWh): Compensation paid or received for 

reductions in electric energy consumption. 

Energy Service Providers: See Power Marketers. 

Entity: The organization that is (1) responding to the survey, (2) offering demand response 

programs, time-based rates and/or tariffs, or (3) using advanced or smart meters. 
66 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Entity ID Number: The respondent should enter the ID number which appears on the survey 

transmittal e-mail, or the ID number used for the entity’s response to the Form EIA-861 

Survey. 

Event Limits: The maximum number of times a demand response resource may be called 

during a specified period of time (typically one year or one season). 

Federal Electric Utility: A utility that is either owned or financed by the Federal 

Government.

Generation and Transmission Company (G&T Company): A company that provides both 

energy production and facilities for transmitting energy to wholesale customers. G&T 

companies are usually formed by rural electric cooperatives and electric utilities to pool the 

costs and risks of constructing and managing the generation facilities and high-voltage 

transmission infrastructure which are needed to deliver energy to their customers. 

Hourly Pricing: A pricing plan in which energy prices vary by the hour, usually based in 

part on a wholesale market price for energy. 

In-home Display: See Display Unit/In-home Display. 

Industrial Sector: The energy-consuming sector that consists of manufacturing facilities and 

equipment used for producing, processing, or assembling goods. The Industrial Sector 

encompasses the following types of activities: manufacturing; processing; agriculture, 

forestry and fisheries; mining; and construction. The term Industrial Sector may also 

designate a business labeled as “industrial” by the North American Industry Classification 

System or by the energy provider on the basis of energy demand or annual usage exceeding 

some specified limit set by the energy provider. See Commercial and Industrial sector. 

Internet: The worldwide, publicly accessible series of interconnected computer networks 

that transmit data by packet switching using the standard Internet Protocol. 

Interruptible Load: Electric consumption subject to curtailment or interruption under tariffs 

or contracts that provide a rate discount or bill credit for agreeing to reduce load during 

system contingencies. In some instances, the demand reduction may be effected by action of 

the System Operator (remote tripping) after notice to the customer in accordance with 

contractual provisions. 

Interval: The period of time for which advanced meters measure energy usage (and possibly 

other data). Increments are typically in minutes, and may consist of five-minute intervals, 15-

minute intervals, or hourly intervals. 

Interval Meter: An electric meter that measures energy use in increments of one hour or 

less. 

Interval Usage: The amount of energy, measured in kWh, consumed during a period of time, 

typically five minutes, 15 minutes, or an hour. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 67

Investor-Owned Electric Utility: A privately-owned electric utility whose stock is publicly 

traded. It is rate regulated and authorized to achieve an allowed rate of return. 

Joint Action Agency: A body consisting of utility companies, municipalities who own 

public utilities, and/or municipalities who purchase energy from private utilities, which acts 

as a committee for making decisions regarding the acquisition and delivery of energy 

resources or related services. 

Load as a Capacity Resource: Demand-side resources that commit to make pre-specified 

load reductions when system contingencies arise. 

Load Serving Entity: Entities that provide electric service to end-users, wholesale 

customers, or both. 

Mandatory Participation: Participation in the demand response program is required based 

on the customer’s size or rate class. Customers are not offered the option of refusing to 

respond to requests for load reduction. 

Maximum Demand: The highest level of demand in MWs as tracked by an entity, such as 

an hourly demand, 30-minute demand, 15-minute demand or 5-minute demand. 

Maximum Demand of Customers: The highest level of total demand, in MW, for 

customers participating in a demand response program, excluding any demand reduction that 

results from the program. The maximum non-coincident demand of the participating 

customers that would occur without the program. 

Maximum Duration of Event: A specified maximum length of time a particular demand 

response event will continue, usually defined by 30-minute or hourly increments. 

Megawatt (MW): One thousand kilowatts or one million watts of electric power. 

Megawatt-hour (MWh): One thousand kilowatt-hours or one million watt-hours of electric 

energy. 

Member Company: Member of a joint action agency or generation and transmission 

company that supplies wholesale electricity and energy services. 

Minimum Payment Rate: The smallest amount of money, in dollars per megawatt-hour, 

that a program sponsor will pay a demand response program participant for reduced energy 

consumption. 

Minimum Reduction: A level established by the demand response program sponsor as the 

least amount of demand reduction, in megawatts, a participant must achieve during a demand 

response event to be considered as participating in that event or to qualify for the demand 

response program. 

Minimum Term: The shortest period of time that customers are obligated to participate in a 

demand response program. 
68 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipality: A village, town, city, county, or other political subdivision of a state. 

NERC Regional Entity: One of the eight groups listed below (formerly known as Reliability 

Councils) organized within the major interconnections in the North American bulk power 

system. They work with the North American Electric Reliability Corporation to improve the 

reliability of the bulk power system. Florida Reliability Coordinating Council (FRCC), 

Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), 

ReliabilityFirst Corporation (RFC), SERC Reliability Corporation (SERC), Southwest Power 

Pool RE (SPP), Texas Regional Entity (TRE), Western Electricity Coordinating Council 

(WECC). The states of Alaska and Hawaii are not within a NERC Regional Entity, but for 

purposes of this survey appear as a choice in NERC Regional Entity fields. 

Non-Spinning Reserves: Demand-side resource that may not be immediately available, but 

may provide solutions for energy supply and demand imbalance after a delay of ten minutes 

or more. 

Opt-In: A Time-Based Rate/Tariff or demand response program in which a customer will be 

enrolled only if the customer chooses to enroll. 

Opt-Out: A Time-Based Rate/Tariff or demand response program in which a customer will 

be enrolled unless the customer chooses not to enroll; a program that is the default for a class 

of customers but that allows individual customers to choose an alternative rate/tariff or 

program. 

Other (as shown in Q3, Q5 & Q6): Customers who are in a customer class that is not listed. 

Other Demand Response Program/Tariff: A company or utility's 

service/product/compilation of all effective rate schedules, general terms and conditions and 

standard forms related to demand response/AMI services for customers that are not 

Residential, Commercial and Industrial, or Other. 

Peak Time Rebate: Peak time rebates allow customers to earn a rebate by reducing energy 

use from a baseline during a specified number of hours on critical peak days. Like Critical 

Peak Pricing, the number of critical peak days is usually capped for a calendar year and is 

linked to conditions such as system reliability concerns or very high supply prices. 

Penalties: Fines or reductions in payments that result when a demand response program 

participant fails to meet targeted reductions in power demand or chooses to not reduce 

consumption during a demand response event. 

Potential Peak Reduction: The sum of the load reduction capabilities (measured in 

megawatts) of the demand response program participants, within the specified customer 

sector, whether reductions are made through the direct control of the utility system operator 

or by the participant in response to price signals or a utility request to curtail load. It reflects 

the demand reduction capability, as opposed to the actual peak reduction achieved by 

participants. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 69

Power Marketers: Business entities, including energy service providers, which are engaged 

in buying and selling electricity, but which do not necessarily own generating or transmission 

facilities. Power marketers and energy service providers take ownership (title) of the 

electricity, unlike power brokers, who do not take title to electricity. Power marketers are 

involved in interstate commerce and must file with the FERC for authority to make 

wholesale sales. Energy service providers will not file with the FERC but may file with the 

states if they undertake only retail transactions. 

Program Type: The category of demand response arrangements between retail or wholesale 

entities and their retail or wholesale customers. Examples of these arrangements include: 

critical peak pricing, critical peak pricing with load control, direct load control, interruptible 

load, load as a capacity resource, regulation, non-spinning reserves, spinning reserves, 

demand bidding and buy-back, time of use pricing, real-time pricing, system peak response 

transmission tariff, peak time rebate, and emergency demand response, all of which are 

defined in this glossary. 

Program End Date: A date specified when the demand response and/or time-based rate 

program is no longer in effect.

Program Start Date: A date specified when a demand response and/or time-based rate 

program began. 

Public Utility District: Municipal corporations organized to provide electric service to both 

incorporated cities and towns and unincorporated rural areas. 

Publicly Owned Electric Utility: Utilities operated by municipalities, political subdivisions, 

and state and federal power agencies (such as the Bonneville Power Administration and the 

Tennessee Valley Authority). 

Realized Demand Reduction: The largest hourly demand reduction (in megawatts) that 

occurred when the demand response program was called, or that was attributable to the 

demand response program, during the 2011 calendar year. 

Real Time Meters: Meters that measure energy as used, with built-in two-way 

communication capable of recording and transmitting instantaneous data. 

Real Time Pricing: Rate and price structure in which the retail price for electricity typically 

fluctuates hourly or more often, to reflect changes in the wholesale price of electricity on 

either a day-ahead or hour-ahead basis. 

Regulation Service: A type of Demand Response service in which a Demand Resource 

increases and decreases load in response to real-time signals from the system operator. 

Demand Resources providing Regulation Service are subject to dispatch continuously during 

a commitment period. This service is usually responsive to Automatic Generation Control 

(AGC) to provide normal regulating margin. Also known as regulation or regulating reserves, 

up-regulation and down-regulation. 
70 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Reliability: A measure of the ability of the electric system to withstand sudden disturbances 

such as electric short circuits or unanticipated loss of system components. 

Reliability Event: An event, such as the loss of a line or generator, or imbalance between 

supply and demand, which threatens the safe operation of the grid. 

Reserve: A service in which demand resources are obligated to be available to provide 

demand reduction upon deployment by the system operator, based on reserve capacity 

requirements that are established to meet reliability standards. 

Residential: The energy-consuming sector consisting of 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 electric-powered devices. The 

residential sector excludes institutional living quarters. This sector excludes deliveries or 

sales to master-metered apartment buildings or homes on military bases (these buildings or 

homes are included in the commercial sector).

Response Time: The maximum time allowed in a demand response program for a program 

participant to react to the program sponsor’s notification, in hours.

Retail: Sales covering electrical energy supplied for residential, commercial, industrial, and 

other (e.g., agricultural) end-use purposes. Electricity supplied at retail cannot be offered for 

resale. 

Retail Customer: A purchaser of energy that consumes electricity for residential, 

commercial, or industrial use, or a variety of other end-uses. 

Retail Electric Customer: See Retail Customer. 

Rural Electric Cooperative: A member-owned electric utility company serving retail 

electricity customers. Electric cooperatives may be engaged in the generation, wholesale 

purchasing, transmission, and/or distribution of electric power to serve the demands of their 

members on a not-for-profit basis. 

Specific Event Limits: The maximum number of times that a participant in a demand 

response program may be called to reduce energy consumption during a year. 

Spinning/Responsive Reserves: Demand-side resource that is synchronized and ready to 

provide solutions for energy supply and demand imbalance within the first few minutes of an 

Emergency Event. 

System Peak Response Transmission Tariff: The terms, conditions, and rates and/or prices

for customers with interval meters who reduce load during peaks as a way of reducing 

transmission charges. 

Tariff: A published volume of all effective rate schedules, terms and conditions under which 

a product or service will be supplied to customers. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 71

Time-Based Rate/Tariff: A retail rate or Tariff in which customers are charged different 

prices for using electricity at different times during the day. Examples are time-of-use rates, 

real time pricing, hourly pricing, and critical peak pricing. Time-based rates do not include

seasonal rates, inverted block, or declining block rates. 

Time-of-Use: A rate where usage unit prices vary by time period, and where the time periods 

are typically longer than one hour within a 24-hour day. Time-of-use rates reflect the average 

cost of generating and delivering power during those time periods. 

Transportation: An energy consuming sector that consists of electricity supplied and 

services rendered to railroads and inter-urban and street railways, for general railroad use 

including the propulsion of cars or locomotives, where such electricity is supplied under 

separate and distinct rate schedules. In this survey, transportation customers should be 

counted in the Other category. 

Transportation Program/Tariff: A company or utility's service/product/compilation of all 

effective rate schedules, general terms and conditions and standard forms related to demand 

response/AMI services for transportation customers. 

Type of Entity: The category of organization that best represents the energy market 

participant. The available options include: investor-owned utility, municipal utility, 

cooperative utility, state-owned utility, federally-owned utility, independent system operator, 

retail power marketer, wholesale power marketer, regional transmission operator, curtailment 

service provider, transmission, or other. 

Voluntary: Customers have the option of participating or not participating. This would 

include opt-out programs where customers are automatically enrolled but are allowed to 

discontinue their participation. 

Wholesale: Pertaining to a sale of electric energy for resale. 

Wholesale Customer: An entity that purchases electric energy for resale.
72 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 73

APPENDIX D: 2012 FERC SURVEY METHOD

Background

The Energy Policy Act of 2005 (EPAct 2005) requires that the Federal Energy Regulatory

Commission prepare and publish an annual report, by appropriate region, that assesses 

electricity demand response resources. Commission staff determined that a survey of a full 

set of private and public entities that provide electric power and could provide demand 

response to customers would help fulfill the requirement.

In the first half of 2012 Commission staff:

 Identified survey respondents, i.e., the “survey population;” and

 Developed a voluntary survey based on a PDF vehicle.

Beginning in February of 2012 Z, INC. and their subcontractor DNV KEMA 

 Developed a sampling design based on the 2010 FERC Demand Response and 

Advanced Metering Survey;

 Revised a custom survey processing system in Microsoft Access to interface with the 

FERC provided PDF Survey;

 Reviewed the list of survey respondents and removed companies who are out 

business or do are not appropriate recipients of the survey150;

 Distributed the 2012 FERC Survey, collected the data, and followed-up with 

respondents where necessary; and

 Conducted data analysis of the survey responses.

Responses to the survey were originally requested from all 3,349 entities from all 50 states 

representing all aspects of the electricity delivery industry: investor-owned utilities, 

municipally owned utilities, wholesale and retail power marketers, state and federal agencies, 

and (rural electric) cooperatives. The 2012 FERC Survey respondent list was based on the

list of entities that the Energy Information Administration (EIA) uses for their Form EIA-861 

Survey Form. The FERC staff added three categories of respondents to the base set of EIA 

contacts – Regional Transmission Organizations (RTOs)/Independent System Operators 

(ISOs), curtailment service providers, and transmission companies.

During the survey processing period it was determined fifteen entities were no longer in 

operation or should not have received the survey. These entities were removed from the 

survey respondent list, resulting in a list of 3,334 active respondents. Out of this active 

group, 1,978 entities responded to the 2012 FERC Survey (a response rate of 59.3 percent), 

an increase from the 2010 FERC Survey response rate of 52 percent. 

Development of the FERC Survey and Sampling Design

The 2012 FERC Survey was conducted subject to the same Office of Management and 

Budget (OMB) authorization that was provided to the Commission for similar surveys 

 

150 A surveyed company may have been acquired by another company, for example.
74 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

previously. The 2010 authorization of March 31, 2013 was used.151 As was done in the 

previous three surveys, Commission staff fielded the survey on a voluntary rather than a 

mandatory basis. Commission staff designed the survey to collect the needed information 

using nine questions organized in three sections. The three sections include one parent 

section containing questions one through seven and two child sections covering retail and 

wholesale demand response programs:

Parent record (only one record per Utility) 

Question 1: Company and contact information including utility ID, company name and 

ownership type. Primary contact information along with their supervisor’s 

information.

Question 2: Advanced and total meter counts by State and customer class

Question 3: Number of retail customers and meters by NERC region and customer class. 

(optional, skip if there are demand response programs)

Question 4: Number of retail customers that can access the amount and frequency of their 

electricity use by method and by customer sector.

Question 5: Plans for demand response programs over next 5 years by number of 

programs and potential peak reduction.

Question 6: NERC regions and states in which you operate

Question 7: Number of retail customers for each NERC and State combination in Question 

6, 

by customer class.

Child 1 Record (Add additional pages as needed)

Question 8: Detailed retail demand response program information by NERC region, State, 

Customer class, and Program type.

Child 2 Record (Add additional pages as needed)

Question 9: Detailed wholesale demand response program information by NERC region, 

State, and Program type.

By shifting the detailed Demand Response program information to the end of the survey, the 

burden on small utilities without demand response programs was lessened because they were 

only asked to complete Questions 1 through 3. Also, by having all the information relative to 

one demand response program on one page (Child record), respondents could as many pages 

as required to cover each of their programs. The content of the 2012 FERC Survey mirrored 

 

151 Links to the 2012 FERC Survey documents can be found at http://www.ferc.gov/industries/electric/indusact/demand-response/2012/survey.asp. 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 75

the 2010 FERC Survey collected. The structure of the survey was duplicative of the 2010 

survey.

The Survey Population 

To analyze the survey data and calculate statistics for this report, Commission staff reviewed 

the composition of the survey population, and found that there were 3,349 organizations as 

listed in Table D-1.

The region definition used in the FERC Survey was based on that used by the North 

American Electric Reliability Corporation (NERC). Using NERC regions allows collection 

of data based on how energy is traded and managed. It provides the most useful regional 

grouping for the consideration of demand response resources and advanced metering 

deployment that would potentially reduce barriers for participation in demand response and 

time-based rate programs and/or tariffs.

Table D-1. Survey Population for the 2012 FERC Survey 

Group Name 2012 N0. 2010 No.

Municipally Owned Utility 1,834 1,840

Cooperatively Owned Utility 874 878

Investor-Owned Utility 194 207

Retail Power Marketer 135 128

Wholesale Power Marketer 42 46

Political Subdivision 127 127

Municipal Power Agency 19 21

Federal and State 35 29

Regional Transmission Organization/

Independent System Operator 7 7

Curtailment Service Provider 11 11 

Transmission 9 7

Total Classified 3,287 3,301

Unclassified 47 57

Active Total 3,334 3358

Inactive (removed from survey population) 15 96

Grand Total 3,349 3,454

FERC Survey Methodology

On March 23, 2012, the survey was distributed through a mass e-mailing. This message 

included an introduction to the survey as well as directions and the glossary (see Appendix 

C). The survey itself was attached to the e-mail. The survey form was in PDF format, 

programmed such that the respondents could respond directly on the PDF form. They then 

would e-mail their surveys to a main collecting point, an e-mail account set up specifically 

for the collection of the surveys. For any inquiries or questions the respondents might have, 

they could reach out to the FERC staff for help at DRSurvey@ferc.gov and DRSurveyHelp@ferc.gov. 
76 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Z, INC., in collaboration with the FERC staff, strove to maximize the response rate through 

various means. If respondents required specific information, a phone hotline was 

established, open daily between 9 am and 6 pm. FERC staff also initiated its own 

dissemination of the survey through postal mail, to capture any respondents that might not 

have internet access or a functional e-mail account. Additionally, Z, INC assisted in the 

sending out of a reminder e-mail to all those who had not responded as of April 25, 2012. Z, 

INC. also contacted all companies that were statistically significant (i.e., large companies and 

those selected for the sample), as well as all medium-sized companies, reaching more than 

1,200 companies individually. Finally, FERC Chairman Jon Wellinghoff sent out a letter to 

all cooperating organizations, including members and representatives of the National 

Association of Regulatory Commissioners, American Public Power Association, Edison

Electric Institute, and the National Rural Electric Cooperative Association, asking them to 

reach out to members and the industry to encourage submission of the survey.

As responses were returned to us, Z, INC. employed a rigorous system of verification and 

due diligence. Beyond the software used to collect the submissions to the e-mail account 

established by the FERC staff, Z, INC. also searched through the e-mail account looking for 

attachments that had not been included in the data upload or other related problems. 

Anomalies and seemingly incorrect information received a flag, indicating the necessity for 

personal follow-up. 

Continuous efforts were also made to ensure the optimal structure and processing of the 

incoming data. Z, INC. created a specialized database for the 2010 FERC-731 Survey. This 

database included all available information for on each entity in the survey population, This 

data base allowed for a more efficient process overall, reducing the labor involved with 

cleaning data. 

Working with the Data

As discussed in Chapters 2 and 3, the FERC staff used the 2012 FERC Survey to estimate 

advanced metering penetration rate and potential peak reduction. The following discussion 

describes the analysis undertaken by the FERC staff and Z, Inc.’s subcontractor DNV 

KEMA, who was responsible for the analysis.

Advanced Metering

The FERC staff developed estimates of the penetration rate of national and regional 

advanced metering required by Congress at the national, regional, and state levels, as well as 

by load serving entity type. These estimates were to reflect the full universe of entities in the 

United States that own electricity meters for retail. The FERC Survey population

encompasses all such entities. As such, the primary data source of the estimates produced is 

the set of respondent data from the 2012 FERC Survey. Some entities in the FERC Survey 

did not respond, requiring statistical estimation of advanced metering penetration in their 

retail service territories so that the estimates account for the whole survey population. 

The approach taken by DNV KEMA was to make statistically informed imputations of the 

number of customers, advanced meters, and total meters for non-responding entities 

leveraging related published information from the 2011 preliminary Form EIA-861 Survey 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 77

and FERC Survey. The Form EIA-861 Survey file 2 contains customer counts at the entity 

level by customer class, which is highly correlated with total meter counts, a FERC Survey 

item. Other FERC Survey items – customer counts and advanced meters – have direct 

counterparts in the Form EIA-861 Survey. For the “other” customer class (i.e., retail 

customers not classified as residential, commercial, or industrial), there is not a comparable 

field in the Form EIA-861 Survey from which to link to the 2012 FERC Survey. For this 

customer class balance group, the 2010 FERC Survey was used as the source of missing 

data.152 

When an entity did not respond to the 2012 FERC Survey at all, or responded but did not 

provide a valid entry for the number of advanced meters for a customer class, DNV KEMA 

used direct substitution of an entity’s advanced meters by sector from the reported value by 

that entity in the 2011 Form EIA-861 Survey. Having the 2011 Form EIA-861 Survey 

preliminary database available for comparison was valuable because both surveys collected 

2011 summary information. If the sector-level advanced meter count for an entity was not 

available in the preliminary 2011 Form EIA-861 Survey database made available to DNV 

KEMA for this analysis, the imputation methodology from the 2010 FERC Survey analysis 

was used, with updated databases supporting it. 

Having access to the preliminary 2011 Form EIA-861 Survey database was valuable also 

because it contains fields for both advanced and AMR meters. DNV KEMA developed an 

editing procedure to identify instances where it appeared likely that the respondent was 

misreporting AMR meters as advanced meters in the 2012 FERC Survey. 

The logic used in the editing procedure started with computing the percent difference in 

advanced meters between the 2012 FERC Survey and the 2011 Form EIA-861 Survey and 

the percent difference between the meters in the 2012 FERC Survey advanced metering and 

the Form EIA-861 Survey AMR meter count. If an entity did not provide an advanced meter 

count on the Form EIA-861 Survey but did provide a count for AMR meters, and the AMR 

meter count was within 50 percent of the reported advanced meter count on the 2012 FERC 

Survey, DNV KEMA edited the advanced metering value. The 2012 FERC survey was set 

to zero since the entity likely misreported an AMR meter count which does not meet the 

FERC definition of advanced metering. 

If the entity reported meter counts for both AMI and AMR on the Form EIA-861 Survey, and 

the 2012 FERC Survey advanced meter count was found to be significantly closer to the sum 

of the AMR and AMI meter totals than just the AMI meters on the Form EIA-861, the 

determination was that the respondent likely included both AMI and AMR meters on the 

2012 FERC Survey, when it should have only included AMI meters. In these instances, the 

Form EIA-861 total AMI meters were used in the analysis.

Demand Response

The FERC Survey responses were extrapolated to estimate the demand response for the 

entire FERC Survey population by imputing survey answers for nonrespondents using an 

 

152 A secondary data source field that is used directly or following a statistical modification, in place of a 

missing value on the FERC Survey, is referred to as a “donor variable”.
78 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

imputation method that limits the bias introduced. The DNV KEMA approach for 

imputation utilized direct substitution of responses by the entity for comparable survey items 

(same survey year and identical or nearly identical wording and/or response categorization) 

from related surveys when such responses are available. When direct substitution was not 

available, responses from identical or closely related questions of past survey years were

utilized, with a class-level growth rate multiplier applied. Classes were defined according to 

customer sector and size exactly as is documented in the 2010 report.

For potential peak reduction, the imputation process below was implemented for the tables 

supporting figures 4.12 and 4.13, which give estimated potential MW by entity type, NERC 

region, and customer sector.

If an entity did not provide potential peak reduction in the 2012 FERC Survey, data on 

potential peak reduction from the 2011 Form EIA-861 was used. However, since the Form 

EIA-861 data only contains potential peak reduction at the entity/sector level, but not by state 

or demand response program type, imputations were made at this entity/sector level, not at 

the state or program type level. If there was no response for potential peak reduction in the 

2012 FERC survey response and an imputation was made with the EIA data, the potential 

peak reduction value was assigned to the entity’s primary NERC region. 

If an entity did not provide potential peak reduction either the 2012 FERC Survey or the 

2011 Form EIA-861, but provided a response to the 2010 Form EIA-861 for this item, it was 

multiplied by a the class-level growth rate between 2010 and 2011 and used as the imputed 

value. If the customer sector for the demand response program was listed as “Other”, and the 

entity did not provide potential peak reduction in the 2012 FERC Survey, the 2010 FERC 

Survey response value multiplied by a class-level growth rate factor was used as the imputed

value. No imputation was used for wholesale potential peak reduction.

Eliminating Double-Counting in Wholesale Demand Response

The methodology used for tabulating wholesale potential peak reduction was designed to 

identify and separate potential peak reduction that is solely wholesale in nature and is not 

associated with any programs offered by retail entities (such as an investor-owned utility). If 

a retail entity reported that 50 MW of potential peak reduction was enrolled in an ISO or 

RTO wholesale market demand response program, the 50 MW may have also been included 

in the ISO or RTO’s survey response. The 50 MW could be counted as both retail demand 

response, since it was reported by a retail entity in Q8, and as wholesale demand response, 

since it was reported by the ISO or RTO in its Q9 submission for wholesale entities. The 50 

MW should be counted only once as either retail or wholesale. The FERC staff decision rule 

for this and each prior survey has been to count it as retail demand response. 

To accomplish this, DNV KEMA merged the enrolled potential demand response reported by 

retail entities in Q8 with the Q9 reports by wholesale entities as negative values of the same 

magnitude. In principle, the tabulation of the combined values would give the final 

wholesale potential demand response. This, however, does not work because ISO/RTOs 

classify their demand response programs by purpose, such as load as a capacity resource or 

emergency demand response, while retail entities generally classify programs according to 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 79

the mechanism employed for reducing load, such as an air conditioner or water heater direct 

load control program, or according to the contract agreement with a large commercial or 

industrial customer. To align the programs to reduce double counting, DNV KEMA 

reclassified the program type listed for retail entities to match the program type listed by the 

ISO or RTO market program that the retail program was enrolled in. Note that the retail 

program types were only recategorized in this step for the enrolled potential demand 

response for the purpose of eliminating double counting. The entity’s response for potential 

peak reduction by sector was according to the original program type in their response.
80 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 81

APPENDIX E: FERC SURVEY RESPONDENTS

Appendix E lists the entities that responded to the 2012 FERC Survey, organized by entity type.

Cooperatively Owned Utility

Calhoun County Electric Cooperative Association IA

Cam Wal Electric Cooperative, Inc SD

4-County Electric Power Assn MS Canadian Valley Electric Cooperative OK

A & N Electric Cooperative MD,VA Caney Fork Electric Cooperative, Inc. TN

Adams Electric Cooperative IL Capital Electric Cooperative, Inc. ND

Adams Electric Cooperative, Inc. PA Carbon Power & Light Inc WY

Adams Rural Electric Cooperative, Inc. OH Carroll County REMC IN

Adams-Columbia Electric Cooperative WI Carroll Electric Cooperative Corporation AR,MO

Alaska Village Elec. Coop. Inc. AK Carroll Electric Cooperative, Inc OH

Albemarle Electric Member Corp. NC Carroll Electric Membership Corporation GA

Alder Mutual Light Co., Inc. WA Carteret-Craven Electric Membership Corporation NC

Alger-Delta Cooperative Electric Association MI Cass County Electric Cooperative ND

Allamakee- Clayton El Coop, Inc IA Cass Electric Cooperative IA

Allegheny Electric Cooperative, Inc. PA Cavalier Rural Electric Coop, Inc. ND

Amicalola Electric Membership Corp GA Central Alabama Electric Cooperative AL

Anza Electric Cooperative, Inc. CA Central Electric Cooperative SD

Appalachian Electric Cooperative TN Central Electric Cooperative, Inc. PA

Arizona Electric Power Cooperative, Inc. AZ Central Electric Power Cooperative MO

Arkansas Electric Cooperative Corporation AR Central Electric Power Cooperative, Inc. SC

Arkansas Valley Electric Cooperative Corporation AR,OK Central Georgia Electric Membership Corp. GA

Ashley-Chicot Electric Cooperative, Incorporated AR Central Iowa Power Cooperative IA

Atchison-Holt Electric Coop IA,MO Central Valley Electric Coop., Inc. NM

Bailey County Electric Cooperative TX Charles Mix Electric SD

BARC Electric Coop Inc VA Cherryland Electric Coop Inc MI

Barron Electric Coop WI Chippewa Valley Electric Coop WI

Barrow Utilities & Electric Coop., Inc. AK Choctawhatchee Electric Cooperative, Inc. FL

Barry Electric Cooperative MO Clark County REMC IN

Bartlett Electric Cooperative Inc TX Clark Electric Coop WI

Basin Electric Power Coop ND Claverack REC PA

Bayfield Electric Cooperative WI Clay County Electric Cooperative Corporation AR

Bedford Rural Elec Coop, Inc PA Clay Electric Cooperative, Inc. FL

Beltrami Electric Cooperative, Inc MN Clay-Union Electric Corporation SD

Benton Rural Electric Association WA Clearwater Power Company ID,OR,WA

Big Bend Electric Cooperative, Inc WA Clearwater-Polk Electric Cooperative, Inc. MN

Big Country Electric Cooperative, Inc. TX Cloverland Electric Cooperative MI

Big Flat Electric Co-op., Inc. MT Coahoma electric Power Association MS

Big Horn County Elec Coop, Inc MT Coastal Electric Cooperative GA

Big River Electric Coop KY Codington-Clark Electric Cooperative, Inc. SD

Black Hills Electric Cooperative, Inc SD Coles-Moultrie Electric Cooperative IL

Black River Electric Cooperative MO Colquitt Electric Membership Corporation GA

Blue Grass Energy Cooperative Corporation KY Columbia Power Cooperative Association OR

Blue Ridge Electric Coop Inc - (SC) SC Concordia Electric Cooperative, Inc. LA

Blue Ridge Mountain EMC - (GA) GA Connexus Energy MN

Bluebonnet Electric Cooperative Inc. TX Consolidated Electric Cooperative MO

Bon Homme Yankton Electric Association, Inc. SD Consumers Energy IA

Boone Valley Electric Coop IA Consumers Power Inc. OR

Brazos Electric Power Cooperative, Inc. TX Cookson Hills Electric Cooperative OK

Broad River Electric Cooperative, Inc. NC,SC Cooperative Light and Power MN

Brunswick Electric Membership Corporation NC Coosa Valley Electric Cooperative AL

Buckeye Power, Inc. OH Coos-Curry Electric Cooperative, Inc. OR

Buckeye Rural Electric Cooperative, Inc. OH Cordva Electric Cooperative, Inc. AK

Butler County Rural Elec Coop - (IA) IA Corn Belt Energy Corporation IL

Butler Rural Electric Cooperative Association, Inc. KS Corn Belt Power Cooperative IA

Butler Rural Electric Cooperative, Inc. OH Craig-Botetourt Electric Cooperative VA,WV

Butte Electric Cooperative SD Craighead Electric Cooperative Corporation AR

C&L Electric Cooperative Corporation AR Crow Wing Cooperative Power & Light Company MN

Caddo Electric Cooperative, Inc. OK Cumberland Electric Membership Corporation TN

Dairyland Power Cooperative IA,MN,WI
82 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Cooperatively Owned Utility (Continued)

Dakota Electric Association MN H-D Electric Cooperative, Inc MN,SD

Darke Rural Electric Coop, Inc OH Heart of Texas Electric Cooperative, Inc. TX

Deep East Texas Electric Coop Inc TX Heartland Power Coop IA

Delaware Electric Cooperative, Inc. DE Heartland Rural Electric Cooperative Inc KS

Dixie Electric Cooperative AL Hendricks County Rural Electric Membership IN

Dixie Electric Membership Corporation LA Henry County REMC IN

Dixie Electric Power Association MS High Plains Power, Inc. WY

Dixie Escalante REA Inc. AZ,UT Highline Electric Association CO,NE

Doniphan Elec Coop Assn, Inc KS HILCO Electric Cooperative, Inc. TX

Douglas Electric Cooperative, Inc OR Hill County Electric Cooperative, Inc. MT

Douglas Electric Cooperative, Inc. SD Holmes-Wayne Electric Cooperative, Inc. OH

Dubois Rural Electric Cooperative, Inc. IN Holy Cross Electric Assn, Inc CO

Duck River Electric Membership Corporation TN Hood River Electric Cooperative OR

Dunn County Electric Cooperative WI Houston County Electric Cooperative, Inc. TX

East End Mutual Elec Co Ltd ID Humboldt County R E C IA

East River Electric Power Cooperative, Inc. SD Idaho County Light & Power Cooperative Assoc., Inc. ID

East-Central Iowa Rural Electric Cooperative IA Illinois Rural Electric Cooperative IL

Eastern Maine Electric Cooperative, Inc ME Indian Electric Cooperative, Inc. OK

Eau Claire Electric Coop WI Inter-County Energy Cooperative KY

Edgecombe-Martin County Electric Membership Corp. NC Intercounty Electric Cooperative Assn. MO

Edisto Electric, Cooperative, Inc. SC Iowa Lakes Electric Coop IA

Egyptian Electric Cooperative Association IL Irwin Electric Membership Corp GA

Empire Electric Association, Inc. CO Itasca-Mantrap Cooperative Electrical Association MN

Energy United Electric Membership Corp NC J-A-C Electric Cooperative Inc TX

Excelsior Electric Membership Corporation GA Jackson County Rural electric Membership Corporation IN

Fairfield Electric Cooperative Inc. SC Jackson Electric Cooperative WI

Farmers Electric ID Jackson Electric Membership Corporation GA

Farmers Electric Cooperative TX Jackson Energy Cooperative Corp - (KY) KY

Farmers Electric Cooperative Corporation AR Jackson Purchase Energy Corporation KY

Farmers Electric Cooperative, Inc IA Jasper County REMC IN

Farmers' Electric Cooperative, Inc. MO Jasper-Newton Electric Cooperative TX

Farmers' Electric Cooperative, Inc. NM Jefferson Energy Cooperative GA

Federated Rural Electric IA,MN Jemez Mountains Electric Cooperative, Inc. NM

Fergus Electric Cooperative, Inc. MT Jo-Carroll Energy, Inc. (NFP) IL

First Electric Cooperative Corporation AR Jones-Onslow Electric Membership Corporation NC

Flathead Electric Cooperative, Inc. MT Jump River Electric Cooperative, Inc. WI

Flint Electric Membership Corporation GA KAMO Electric Cooperative, Inc OK

Florida Keys Electric Cooperative FL Kankakee Valley Rural Electric Membership Corp IN

Four County EMC NC Kansas Electric Power Cooperative, Inc. KS

Fox Islands Electric Cooperative, Inc. ME Kauai Island Utility Cooperative HI

Franklin Electric Cooperative AL KC Electric Association, Inc. CO

Franklin Rural Electric Cooperative- (IA) IA KEM Electric Cooperative, Inc. ND

Freeborn-Mower Coop Services MN Kingsbury Electric Cooperative, Inc. SD

French Broad Electric Membership Corporation NC,TN Kodiak Electric Association, Inc. AK

Fulton County REMC IN Kosciusko REMC IN

Gascosage Electric Cooperative MO La Plata Electric Assn. Inc. CO

Gibson Electric Membership Corporation TN Laclede Electric Cooperative MO

Golden Spread Electric Cooperative, Inc. TX Lacreek Electric Association, Inc. NE,SD

Goldenwest Electric Cooperative, Inc. MT,ND Lagrange County Rural E M C IN

Graham County Electric Cooperative, Inc AZ Lake Country Power MN

Grundy County Rural Electric Coop IA Lake Region Electric Cooperative MN

Grundy Electric Cooperative, Inc. MO Lamb County Electric Cooperative TX

Guernsey-Muskingum Electric Cooperative, Inc. OH Lane Electric Cooperative Inc OR

Habersham Electric Membership Corporation GA Lee County Electric Cooperative, Incorporated FL

Halifax Electric Membership Corporation NC,VA Lewis County Rural Electric Coop Association MO

Hart Electric Membership Corporation GA Licking Valley RECC KY

Hawkeye Tri-County El Coop Inc IA Lincoln Electric Cooperative MT

Haywood Electric membership Corp. GA,NC,SC Linn County Rural Electric Cooperative Association IA
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 83

Cooperatively Owned Utility (Continued)

Los Alamos County NM Northern Virginia Electric Cooperative VA

Lower Yellowstone REA Inc., MT,ND Northwestern Electric Cooperative, Inc. OK

Lumbee River Electric Membership Corporation NC Northwestern REC PA

Lynches River Electric Cooperative, Inc. SC NorVal Electric Cooperative MT

Lyntegar Electric Cooperative, Inc. TX Nueces Electric Cooperative TX

Lyon-Coffey Electric Cooperative, Inc. KS Oahe Electric Cooperative Inc. SD

M & A Electric Power Cooperative MO Oakdale Electric Coop WI

M.J.M. Electric Cooperative, Inc. IL Ocmulgee Electric Membership Corporation GA

Magic Valley Electric Cooperative, Inc. TX Oglethorpe Power Corporation GA

Maquoketa Valley Rural Electric Cooperative IA Okanogan County Electric Cooperative Inc WA

Marshall County REMC IN Okefenoke Rural El Member Corp GA

McCone Electric Co-op., Inc. MT Oklahoma Electric Cooperative OK

McDonough Power Cooperative IL Osceola Electric Cooperative, Inc. IA

McKenzie Electric Cooperative, Inc. ND Otero County Electric Cooperative, Inc. NM

McLean Electric Coop ND Ouachita Electric Cooperative Corporation AR

McLeod Cooperative Power Association MN Ozark Border Electric Cooperative MO

Meade County RECC KY Ozark Electric Cooperative, Inc. MO

Mecklenburg Electric Cooperative NC,VA Ozarks Electric Cooperative Corporation AR,OK

Menard Electric Cooperative IL Panola-Harrison Electric Cooperative, Inc. LA,TX

Middle Kuskokwim Electric Cooperative, Inc AK Parke County Rural E M C IN

Midland Power Coop IA Peace River Electric Cooperative, Inc. FL

Mid-Ohio Energy Cooperative, Inc. OH Pearl River Valley Electric Power Association MS

Mid-South Electric Cooperative TX Pee Dee Electric Membership Corp. NC

Midwest Electric, Inc. OH Peninsula Light Company WA

Midwest Energy Cooperative IN,MI,OH Pennyrile Rural Electric Coop KY

Midwest Energy, Inc. KS People's Cooperative Services MN

Minnesota Valley Electric Cooperative MN People's Electric Cooperative OK

Minnkota Power Cooperative, Inc. ND Petit Jean Electric Cooperative Corporation AR

Mississippi County Electric Cooperative, Inc. AR Pickwick Electric Cooperative TN

Missouri Rural Electric Cooperative MO Piedmont Electric Membership Corporation NC

Modern Electric Water Company WA Pierce-Pepin Coop Services WI

Monroe County Electric Co-Operative, Inc. IL Pioneer Electric Cooperative, Inc. AL

Moreau-Grand Electric Cooperative, Inc. SD Pitt and Greene Electric Membership Corporation NC

Mountain Parks Electric, Inc. CO PKM Electric Coop, Inc MN

Mountain View Electric Association, Inc. CO Planters Electric Membership Corporation GA

Navasota Valley Electric Cooperative TX Polk-Burnett Electric Coop WI

Navopache Electric Cooperative, Inc. AZ,NM Poudre Valley Rural Electric Association, Inc. CO

Nemaha-Marshall Electric Cooperative Association, Inc KS Powder River Energy Corporation MT,WY

New-Mac Electric Cooperative, Inc. MO Prairie Energy Coop IA

NineStar Connect IN Prentiss County Electric Power Association MS

Niobrara Electric Association NE,SD,WY Price Electric Coop Inc WI

Noble County REMC IN Prince George Electric Cooperative VA

Nobles Cooperative Electric MN Raccoon Valley Electric Power Cooperative IA

Nodak Electric Coop Inc ND Raft River Rural Electric Cooperative, Inc. ID

Nolin Rural Electric Cooperative Corporation KY Ralls County Electric Cooperative MO

North Alabama Electric Cooperative AL Rappahannock Electric Cooperative VA

North Arkansas Electric Cooperative, Incorporated AR Ravalli County Electric Cooperative, Inc. MT

North Carolina Electric Membership Corp NC Rayburn Country Electric Cooperative, Inc.; TX

North Central Electric Coop ND Rayle Electric Membership Corporation GA

North East Mississippi E P A MS REA Energy Cooperative, Inc. PA

North Georgia Electric Membership Corporation GA Red Lake Electric Cooperative, Inc. MN

North Plains Electric Coop Inc TX Red River Valley MN

North Star Electric Cooperative, Inc. MN Red River Valley Rural Electric Association OK

North Western Electric Cooperative, Inc. OH Renville-Sibley Cooperative Power Association MN

Northeast Oklahoma Electric Cooperative OK Rich Mountain Electric Cooperative, Inc. AR

Northeastern REMC IN Richland Electric Coop WI

Northern Lights, Inc. ID,MT,WA Rita Blanca Electric Cooperative, Inc. TX

Northern Neck Electric Cooperative VA Riverland Energy Cooperative WI
84 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Cooperatively Owned Utility (Continued)

Rock Energy Cooperative IL,WI The Midwest Electric Cooperative Corporation NE

Rolling Hills Electric Cooperative, Inc. KS The Radiant Electric Cooperative, Inc. KS

Roseau Electric Coop MN The Satilla Rural Electric Membership Corporation GA

Rosebud Electric Cooperative SD Three Notch Electric Membership Corporation GA

Roughrider Electric Cooperative, Inc ND Tippah Electric Power Association MS

Rural Electric Cooperative, Inc. OK Traverse Electric Cooperative, Inc. MN,ND,SD

Rushmore Electric Power Cooperative, Inc SD Tri-County Electric Coop MN

Rusk County Electric Cooperative, Inc. TX Tri-County Electric Cooperative, Inc TX

Sac Osage Electric Coop, Inc Mo Tri-County Electric Cooperative, Inc. OK

Salem Electric OR Tri-County Electric Membership Corporation NC

Salmon River Electric Cooperative, Inc. ID Trinity Valley Electric Cooperative, Inc. TX

Salt River Electric Coop. Corp. KY Turlock Irrigation District CA

Sam Houston Electric Cooperative, Inc. TX Twin County Electric Power Association MS

Sangre de Cristo Electric Association CO Twin Valley Electric Cooperative KS

Santee Electric Cooperative, Inc. SC Union County Electric Cooperative, Inc. SD

Scenic Rivers Energy Coop WI Union Electric Membership Corp NC

Se-Ma-No Electric Cooperative MO Union Rural Electric Coop, Inc. OH

Sequachee Valley Electric Coop TN United Electric Cooperative IA,MO

Shelby Electric Cooperative IL United Electric Cooperative Services, Inc. TX

Shelby Energy Cooperative KY United Power CO

Shenandoah Valley Electric Cooperative VA Upper Cumberland Electric Membership Corporation TN

Sheridan Electric Co-op., Inc. MT Upper Missouri G & T Electric Cooperative, Inc. MT,ND

Sho-Me Power Electric Cooperative MO Upshur Rural Electric Cooperative Corp TX

Sierra Electric Cooperative, Inc. NM Upson Electric Membership Cooperation GA

Sioux Valley SW Elec Coop MN,SD Valley Electric Association, Inc. CA,NV

Slash Pine Electric Membership Corporation GA Valley Rural Electric Cooperative, Inc. PA

Smarr EMC GA Verdigris Valley Electric Cooperative OK

Snapping Shoals El Member Corp GA Vermont Electric Cooperative, Inc. VT

South Central Arkansas Electric Cooperative, AR Vernon Electric Coop WI

South Central Electric Association MN Victoria Electric Coop., Inc. TX

South Central Power Company OH Vigilante Electric Cooperative, Inc MT

South Kentucky Rural Electric Coop Corp KY,TN Volunteer Electric Coop TN

South Mississippi Electric Power Association MS Wabash County REMC IN

South Plains Electric Cooperative TX Wake Electric NC

South Side Electric ID Warren Electric Cooperative, Inc PA

Southeast Electric Cooperative, Inc. MT,SD,WY Warren Rural Electric Coop Corp KY

Southeastern Electric Cooperative, Inc. OK Washington Electric Co-Op Inc. VT

Southern Illinois Power Cooperative IL Washington Electric Membership Corporation GA

Southern Indiana REC, Inc. IN Wayne-White Counties Electric Cooperative IL

Southern Maryland Electric Cooperative, Inc. MD Webster Electric Cooperative MO

Southwest Arkansas Electric Cooperative Corporation AR Wells Rural Electric Company NV,UT

Southwest Electric Cooperative MO West Central Electric Cooperative, Inc. MO

Southwest Texas Elec Coop, Inc TX West Oregon Electric Cooperative, Inc. OR

Southwestern Electric Cooperative, Inc. IL Western Cooperative Electric Association, Inc. KS

Square Butte Electric Cooperative ND Western Illinois Electrical Coop IL

St Croix Electric Coop WI Western Indiana Energy REMC IN

Steuben Rural Electric Cooperative, Inc. NY Western Iowa Power Cooperative IA

Sumter Electric Cooperative, Inc. FL Wheatland Electric Cooperative, Inc. KS

Sumter Electric Membership Corporation GA Wheatland Rural Electric Cooperative WY

Surry-Yadkin Elec Member Corp NC Whetstone valley electric cooperative, Inc SD

Suwannee Valley Electric Cooperative, Inc. FL White County Rural Electric Membership Corporation IN

T.I.P. Rural Electric Cooperative IA Whitewater Valley REMC IN

Tallapoosa River Electric Cooperative, Inc. AL Wild Rice Electric Coop, Inc MN

Talquin Electric Cooperative, Inc, FL Wiregrass Electric Cooperative, Inc. AL

Taylor Electric Cooperative WI Withlacoochee River Electric Cooperative, Inc. FL

Tennessee Valley Electric Coop TN Woodruff Electric Cooperative Corporation AR

The Brown Atchison Electric Cooperative Assn., Inc. KS Yazoo Valley Electric Power Association MS

The Frontier Power Company OH York Electric Cooperative, Inc. SC
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 85

Curtailment Service Provider

Duke Energy Indiana, Inc IN

Duke Energy Kentucky, Inc KY

Energy Curtailment Specialists, Inc. CA,DC,DE,IL,IN,MD, Duquesne Light Company PA

NJ,NY,OH,PA,TX,VA, Entergy Arkansas Inc AR

WV Entergy Gulf States Louisiana, LLC LA

Energy Investment Systems, Inc. NY Entergy Louisiana Inc. LA

Energy spectrum, Inc NJ,NY Entergy Mississippi, Inc. MS

EnerNOC, Inc MD Entergy New Orleans, Inc. LA

Galt Power, Inc PA Entergy Texas, Inc. TX

KEYTEX Energy LLC PA Fale-Safe, Inc OR

Richards Energy Group, Inc. PA Fishers Island Electric company NY

Fitchburg Gas and Electric Light Company MA

Federal Utility Florida Power & Light Company FL

Colorado River Indian Irrigation Project AZ Florida Public Utilities Co. FL

Mission Valley Power MT Georgia Power GA

Southeastern Power Administration GA Granite State Electric Company NH

Southwestern Power Administration AR,MO,OK Green Mountain Power Corporation VT

Tennessee Valley Authority AL,GA,KY,MS,NC,TN, Gulf Power Company FL

VA

Western Area Power Administration AZ,CA,CO,IA,KS,MN, Gustavus Electric Company AK

MT,ND,NE,NJ Hawaii Electric Light Company, Inc. HI

Hawaiian Electric Company, Inc. HI

Investor-Owned Utility Hughes Power & Light Co. AK

Black Hills Power, Inc. MT,SD,WY Idaho Power Company ID,OR

AEP Texas Central Company TX Indiana Michigan Power Company IN,MI

AEP Texas North Company TX Indiana-Kentucky Electric Corp IN

Alabama Power Company AL Interstate Power and Light Company IA

Alaska Power & Telephone Co AK Jersey Central Power & Light Co NJ

Alpena Power Company MI Kansas City Power & Light Company KS,MO

Amana Society Service Co. IA Kansas Gas & Electric Company KS

Aniak Light & Power Co., Inc. AK KCP&L Greater Missouri Operations Company MO

Appalachian Power Company VA,WV Kentucky Power Company KY

Arizona Public Service AZ Kentucky Utilities KY

Atlantic City Electric Company NJ Kingsport Power Company TN

Avista Corporation, dba Avista Utilities WA Louisville Gas & Electric and Kentucky Utilities KY,VA

Baltimore Gas and Electric Company MD Luminant ET Services Company TX

Bangor Hydro Electric Company ME Massachusetts Electric Company MA

Bear Valley Electric Service CA Maui Electric Company, Limited HI

Black Hills/Colorado Electric Utility Co. LP CO McGrath Light and Power AK

Block Island Power Co RI Metropolitan Edison Co PA

Central Hudson Gas & Electric Corporation NY Miami Power Corporation OH

Central Maine Power Co ME MidAmerican Energy Company IA,IL,SD

Central Vermont Public Service Corporation VT Minnesota Power, Inc. MN

Cheyenne Light, Fuel and Power Company WY Mississippi Power MS

Chitina Electric, Inc. AK Monongahela Power Co WV

Citizens' Electric Company PA Mt Carmel Public Utility Company IL

Cleco Power LLC LA Nantucket Electric Company MA

Cleveland Electric Illuminating Co OH Nevada Power Company NV

Columbus Southern Power Company OH New York State Electric & Gas NY

Commonwealth Edison Company IL Niagara Mohawk Power Corporation NY

Competitive Energy Services, LLC ME Northern Indiana Public Service Company IN

Connecticut Light and Power Company CT NorthWestern Energy MT

Consolidated Edison Company of New York NY NSTAR Electric Company MA

Consumers Energy Company MI OGE Energy Corporation AR,OK

Dahlberg Light and Power Company WI Ohio Edison Co OH

Delmarva Power and Light Company DE,MD Ohio Power Company OH

Duke Energy Carolinas, LLC NC,SC Ohio Valley Electric Corporation OH

Duke Energy Corporation OH Oncor Electric Delivery Company LLC TX

Orange & Rockland Utilities Inc NY
86 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Investor-Owned Utility (Continued)

Otter Tail Power Company MN,ND,SD City of New Roads LA

Pacific Gas and Electric Company CA City of Starke FL

PacifiCorp CA,ID,OR,UT,WA,WY City of Vermillion SD

PECO Energy Company PA Eugene Water & Electric Board OR

Pennsylvania Electric Co PA Fillmore City Electric Department UT

Pennsylvania Power Co PA Indiana Municipal Power Agency IN

Portland General Electric Company OR Intermountain Power Agency CA

Potomac Electric Power Company DC,MD Ipnatchiaq Electric Company AK

PPL Electric Utilities PA Massachusetts Municipal Wholes Electric Co MA

Progress Energy Carolinas NC,SC Missouri Basin Municipal Power Agency SD

Progress Energy Florida FL Municipal Electric Authority of Georgia GA

Public Service Company of New Hampshire NH Municipal Energy Agency of Mississippi MS

Public Service Company of New Mexico (PNM) NM New York Municipal Power Agency NY

Public Service Company of Oklahoma OK Northern Municipal Power Agency MN

Public Service Electric & Gas Company NJ Oklahoma Municipal Power Authority OK

Puget Sound Energy, Inc. WA Pocahontas Municipal Utilities IA

Rochester Gas & Electric NY Public Utility District No.1 of Grays Harbor County WA

Rockland Electric Co NY Sacramento Municipal Utility Dist CA

Safe Harbor Water Power Corporation PA Texas Municipal Power Agency TX

San Diego Gas & Electric CA Town of Pendleton IN

Sharyland Utilities, L.P. TX Utah Municipal Power Agency UT

Sierra Pacific Power Company NV Village of Trenton NE

South Carolina Electric & Gas Company SC Vinton Public Power Authority LA

Southern California Edison (SCE) CA Wyoming Municipal Power Agency WY

Southern Indiana Gas & Elec Co IN

Southwestern Electric Power Company AR,LA,TX Municipally Owned Utility

Superior Water, Light and Power Company WI Adrian Public Utilities MN

Tampa Electric Company FL Aitkin Public Utilities MN 

The Dayton Power and Light Company OH Albany Water, Gas & Light Commission GA

The Detroit Edison Company MI Algoma Utility Commission WI

The Empire District Electric Company AR,KS,MO,OK Alta Vista Municipal Utilities IA

The Narragansett Electric Company RI Ames, City of IA

The Potomac Edison Company MD,WV Anita Municipal Utilities IA 

The Toledo Edison Co OH Atlantic Municipal Utilities IA

The United Illuminating Company CT Auburn Board of Public NE

Tucson Electric Power AZ Austin Utilities MN

Union Electric Company MO Bagley Public Utilities MN

Unitil Energy Systems, Inc. NH Bainbridge Municipal Electric Utility IN

Upper Peninsula Power Corporation MI,WI Bamberg Board of Public Works SC

Virginia Electric & Power Co NC,VA Bancroft Municipal Utilities IA

West Penn Power Company PA Baraga Electric Utility MI

Westar Energy, Inc. KS Barnesville Municipal Electric MN

Western Massachusetts Electric Company CT Barton Village, Inc. VT

Wheeling Power Company WV Bath Electric Gas & Water System NY

Wisconsin Electric Power Company MI,WI Beaver City Corporation UT

Wisconsin Public Service Corporation WI Benton County Electric System TN

Wisconsin River Power Company MI,WI Biwabik Public Utilities MN

Wisconsin Power and Light Company WI Bloomer Electric & Water Co WI

Xcel Energy MI,WI Blooming Prairie Public Utility Commission MN

Board of Public Works of The City of Lewes DE

Board of Water, Electric & Communications IA

Municipal Power Agency

Alabama Municipal Electric Authority AL

Centralia City Light WA

City of Alton IA

City of Anthony KS

City of Bentonville - (AR) AR

City of Drain OR

City of Mooreland - (OK) OK
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 87

Municipally Owned Utility (Continued)

Bolivar Energy Authority TN City of California MO

Borough of Berlin (PA) PA City of Abbeville LA

Borough of Butler- (NJ) NJ City of Abbeville- SC SC

Borough of Ellwood City PA City of Aberdeen MS

Borough of Ephrata PA City of Acworth GA

Borough of Goldsboro PA City of Ada MN

Borough of Grove City PA City of Adel GA

Borough of Hatfield PA City of Afton IA

Borough of Kutztown - (PA) PA City of Akron (IA) IA

Borough of Lansdale PA City of Akutan AK

Borough of Lavallette- (NJ) NJ City of Albany - (IL) IL

Borough Of Lehighton PA City of Albany- (MO) MO

Borough of Middletown PA City of Albemarle NC

Borough of Mifflinburg PA City of Albion ID

Borough of Mont Alto PA City of Alcoa Electric Department TN

Borough of Olyphant- (PA) PA City of Alexander City AL

Borough of Park Ridge - (NJ) NJ City of Alexandria MN

Borough of Pemberton NJ City of Algona IA

Borough of Perkasie PA City Of Alma KS

Borough of Pitcairn - (PA) PA City of Alpha MN

Borough of Quakertown- (PA) PA City of Altamont IL

Borough of Royalton PA City of Altamont - (KS) KS

Borough of Schuylkill Haven - (PA) PA City of Anaheim Public Utilities Department CA

Borough of Smethport PA City of Anoka MN

Borough of South River (NJ) NJ City of Ansley NE

Borough of St Clair- (PA) PA City of Anthon IA

Borough of Tarentum (PA) PA City of Aplington IA

Borough of Wampum PA City of Arapahoe NE

Borough Watsontown (PA) PA City of Arcadia WI

Boscobel Municipal Utilities WI City of Arcadia - (KS) KS

Borough of Catawissa PA CITY OF ARLINGTON MN

Borough of Duncannon PA City of Arma KS

Bowling Green Municipal Utilities KY City of Ashland KS

Boylston Municipal Light Department MA City of Athens AL

Brainerd Public Utilities MN City of Atka AK

Braintree Electric Light Department (BELD) MA City of Auburn (IA) IA

Bremen Electric Light & Power Co IN City of Auburn Electric Utility IN

Brigham City Corporation UT City of Augusta KS

Bristol Virginia Utilities VA City of Ava (MO) MO

Brodhead Water & Light Commission WI City of Axtell KS

Brooklyn Municipal Utilities IA City of Azusa CA

Brownfield Power & Light TX City of Blackwell OK

Brownsville Public Utilities Board TX City of Baldwin City Kansas KS

Brownsville Utility Department TN City of Bandon OR

Burlington Electric Department VT City of Banning CA

Cairo Public Utility Company IL City oF Bartlett, Texas TX

Canby Utility Board OR City of Bartow FL

Canton Municipal Utilities MS City of Bastrop TX

Carrollton Board of Public Works MO City of Batavia IL

Cascade Municipal Utilities IA City of Baudette MN

Cedarburg Light & Water Commission WI City of Beaver City NE

Centerville Municipal Power & Light IN City of Bedford, Virginia VA

Centuria Municipal Electric Utility WI City of Bellville (TX) TX

Chicopee Municipal Lighting Plant MA City of Benham KY

Chillicothe Municipal Utility MO City of Benkelman NE

City & Borough of Sitka, Electric Department AK City of Benton - (AR) AR

City & County of San Francisco CA City of Berea Municipal Utility KY

City of Hickman KY City Of Beresford SD
88 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipally Owned Utility (Continued)

City of Bethany MO City of Chetopa KS

City of Big Stone City SD City of Chewelah WA

City of Bloomfield IA City of Chignik AK

City of Blountstown FL City of Cimarron KS

City of Blue Earth MN City of Claremore OK

City of Blue Mound KS City of Cleveland - (OH) OH

City of Bluffton/Bluffton Utilities IN City of Clewiston FL

City of Boerne TX City of Clinton- (TN) TN

City of Boulder City NV City of Clinton, Combined Utility System SC

City of Bountiful UT City of Cody WY

City of Bowie TX City of Coffeyville, Kansas KS

City of Brady TX City of Colby KS

City of Breckenridge- (MN) MN City of Coleman TX

City of Breda IA City of Collins MS

City of Breese IL City of Collinsville OK

City of Brenham TX City of Columbia MO

City of Brewster (MN) MN City of Columbia City IN

City of Bridgeport Ne NE City of Columbiana OH

City of Bristol - (TN) TN City of Columbus MS

City of Broken Bow NE City of Columbus, Ohio OH

City of Bronson KS City of Comanche OK

City of Brookings SD City of Commerce, GA GA

City of Brownton MN City of Coon Rapids IA

City of Bryan (OH) OH City of Corona CA

City of Buffalo (IA) IA City of Covington GA

City of Buffalo, Minnesota MN City of Covington - (TN) TN

City of Buford GA City of Cozad / Board of Public Works NE

City of Buhl MN City of Crane (MO) MO

City of Burke SD City of Crete NE

City of Burley - (ID) ID City of Crystal Falls MI

City of Burlingame KS City of Cuba MO

City of Burlington CO City of Cushing OK

City of Burt IA City of Danville IA

City of Burwell NE City of David City NE

CITY OF BUSHNELL FL City of Dayton (IA) IA

City of Butler (MO) MO City of Denver (IA) IA

City of Cabool MO City of Detroit Lakes MN

City of Calhoun GA City of Dighton KS

City of Cambridge NE City of Dike IA

City of Camden, SC SC City of Doerun GA

City of Cameron MO City of Dothan AL

City of Camilla GA City of Douglas GA

City of Carlyle, Illinois IL City of Dover Public Utilities DE

City of Carmi, Illinois IL City of Dowagiac MI

City of Cartersville, Georgia GA City of Due West SC

City of Cascade Locks OR City of Duncan OK

City of Casey IL City of Durant (IA) IA

City of Castroville TX City of Dysart IA

City of Cawker City KS City of Earlville IA

City of Celina OH City of East Grand Forks - (MN) MN

City of Central City NE City Of East Point Power East Point Georgia GA

City of Centralia (KS) KS City of Eaton Rapids MI

City of Centralia, Missouri MO City of Edgar (NE) NE

City of Ceylon MN City of Edmond OK

City of Chapman KS City of Egegik AK

City of Chattanooga - (TN) TN City of Elberton GA

City of Chelsea MI City of Elfin Cove AK

City of Cheney WA City of Elizabethton TN
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 89

Municipally Owned Utility (Continued)

City of Elk Point SD City of Gladstone MI

City of Ellaville GA City of Glasco KS

City of Ellensburg WA City of Glen Elder KS

City of Ellsworth IA City of Glendale CA

City of Elroy WI City of Glenwood Springs - CO CO

City of Elwood KS City of Goldthwaite TX

City of Emerson NE City of Gonzales TX

City of Enterprise UT City of Goodland KS

City of Erie (KS) KS City of Gothenburg NE

City of Escanaba MI City of Graettinger IA

City of Escondido CA City of Grafton - (ND) ND

City of Estherville IA City of Grand Island NE

City of Eudora KS City of Grand Junction (IA) IA

City of Evergreen AL City of Granite OK

City of Fairbank IA City of Grant NE

City of Fairbury NE City of Grantville GA

City of Fairfax MN City of Greendale IN

City of Fairhope AL City of Greensburg (KS) KS

City of Fairview OK City of Gridley CA

City of Faith SD City of Griffin GA

City of Fallon (NV) NV City of Groton SD

City of Falls City NE City of Grove City MN

City of Farmersville TX City of Guttenberg IA

City of Farmington NM City of Hagerstown, IN IN

City of Fayetteville TN City of Hallettsville TX

City of Flandreau SD City of Halstad MN

City of Flora IL City of Hampton GA

City of Florence (AL) AL City of Harbor Springs MI

City of Floresville TX City of Harrisonville MO

City of Fonda IA City of Hart Hydro MI

City of Fontanelle IA City of Hartford (AL) AL

City of Forest Grove Light and Power OR City of Hartley IA

City of Fort Meade FL City of Hastings NE

City of Fort Morgan CO City of Haven KS

City of Fort Pierre - (SD) SD City of Hawarden IA

City of Fosston MN City of Healdsburg (CA) CA

City of Fountain CO City of Hebron NE

City of Franklin (NE) NE City of Hecla SD

City of Franklin Power & Light VA City of Hemphill TX

City of Frederick OK City of Henning MN

City of Fredonia KS City of Herington KS

City of Fulton MO City of Hermann MO

City of Galion OH City of Herndon KS

City of Gallatin MO City of Hertford (NC) NC

City of Gallup NM City of Higginsville MO

City Of Galt MO City of Highland IL

City of Galva KS City of Hill City KS

City of Garden City KS City of Hillsboro KS

City Of Garland TX City of Holdrege NE

City Of Gas City IN City of Hominy (OK) OK

City of Gastonia NC City of Hope ND

City of Geary OK City of Hopkinton IA

City of Geneseo IL City of Horton KS

City of Geneva IL City of Houston MO

City of Georgetown TX City of Howard SD

City of Giddings TX City of Hubbard OH

City of Gilbert MN City of Hubbell NE

City of Giltner NE City of Hudson OH

City of Hugoton KS
90 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipally Owned Utility (Continued)

City of Hunnewell MO City of Liberty TX

City of Huntingburg - (IN) IN City of Lincoln Center KS

City of Imperial NE City of Lincoln Electric System NE

City of Indianola NE CITY OF LINDSAY OK

City of Isabel (KS) KS City of Lindsborg KS

City of Itta Bena MS City of Linneus (MO) MO

City of Iuka KS City of Litchfield Public Utilities MN

City of Jackson GA City of Livermore IA

City of Jackson (OH) OH City of Livingston TX

City of Jacksonville Beach FL City of Lockhart TX

City of Janesville MN City of Lodgepole (NE) NE

City of Jasper, TX TX City of Lodi CA

City of Jetmore KS City of Lompoc CA

City of Jonesville (LA) LA City of Long Grove (IA) IA

City of Kahoka MO City of Lowell MI

City of Kandiyohi MN City of Lucas KS

City of Kansas City KS City of Luray (KS) KS

City of Kasson MN City of Luverne MN

City of Kennett MO CITY OF LYONS NE

City of Kiel WI City of Mabel (MN) MN

City of Kimball NE City of Maddock ND

City of Kingfisher OK City of Madison (MN) MN

City of Kings Mountain NC City of Madison (NE) NE

City of Kiowa (KS) KS City of Malden (MO) Board of Public Works MO

City of Kirkwood (MO) MO City of Mangum (OK) OK

City of La Crosse KS City of Manitou (OK) OK

City of La Grange TX City of Mankato KS

City of La Grange (GA) GA City of Manokotak AK

City of La Plata MO City of Mansfield MO

City of Lafayette AL City of Mansfield (GA) GA

City of Lake City Electric Utility MN City of Mapleton IA

City of Lake Crystal (MN) MN City of Marathon IA

City of Lake Mills IA City of Marietta (GA) GA

City of Lake Park- (IA) IA City of Marion KS

City of Lake View IA City of Marshall IL

City of Lake Worth Utilities FL City of Marshall, Michigan MI

City of Lakefield MN City of Marshfield WI

City of Lakeland, Lakeland Electric FL City of Martinsville Electric Department VA

City of Lakota ND City of Mascoutah IL

City of Lamar MO City of Mason TX

City of Lamar- (Colorado) CO City of McLeansboro IL

City of Lampasas (TX) TX City of McMinnville (OR) OR

City of Lanett AL City of Meade KS

City of Larchwood IA City of Meadville MO

City of Larned KS City of Memphis (MO) MO

City of Larsen Bay AK City of Mendon - (OH) OH

City of Las Animas Municipal Light & Power CO City of Mesa AZ

City of Laurel (NE) NE City of Milan TN

City of Laurens IA City of Milan (MO) MO

City of Laurinburg NC City of Milford DE

City of Lawler (IA) IA City of Milford (IA) IA

City of Lawrenceville GA City of Miller (SD) SD

City of Le Sueur (MN) MN City of Milton WA

City of Lebanon OH City of Minden LA

City of Lehigh IA City of Minden (NE) NE

City of Lenox (IA) IA City of Mindenmines (MO) MO

City of Lexington NE City of Mindoka (ID) ID

City of Liberal MO City of Minneapolis (KS) KS
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 91

Municipally Owned Utility (Continued)

City of Mishawaka IN City of Osawatomie KS

City of Monmouth OR City of Osborne KS

City of Monroe GA City of Osceola MO

City of Montezuma (IA) IA City of Osceola (AR) AR

City of Montezuma (KS) KS City of Osford KS

City of Monticello GA City of Oxford (GA) GA

City of Moore Haven (FL) FL City of Painesville OH

City of Mora (MN) MN City of Palo Alto Utilities CA

City of Moran KS City of Paris (AR) AR

City of Moreno Valley (CA) CA City of Paris (KY) KY

City of Morrill KS City of Park River - (ND) ND

City of Moultrie GA City of Pasadena CA

City of Mount Dora FL City of Paton - (IA) IA

City of Mount Hope (KS) KS City of Perry, MO. MO

City of Mount Vernon MO City of Peterson MN

City of Mountain Iron MN City of Petoskey MI

City of Mountain Lake MN City of Piedmont AL

City of Mountain View MO City of Pierce NE

City of Mt Pleasant UT City of Pierre SD

City of Mulberry (KS) KS City of Pierz MN

City of Mulvane - - (KS) KS City of Piqua (OH) OH

City of Murray UT City of Plainview (NE) NE

City of Nashwauk MN City of Plaquemine (LA) LA

City of Natchitoches LA City of Plattsburgh - (NY) NY

City of Nebraska City NE City of Pomona (KS) KS

City of Needles CA City of Poplar Bluff MO

City of Neligh NE City of Port Angeles WA

City of Neodesha (KS) KS City of Pratt (KS) KS

City of Neola (IA) IA City of Preston IA

City of New Braunfels - (TX) TX City of Princeton IL

City of New Hampton (IA) IA City of Princeton (WI) WI

City of New Lisbon Municipal Electric & Water Dept. WI City of Pryor (OK) OK

City of New Madrid (MO) MO City of Purcell OK

City of New Ross IN City of Quitman GA

City of Newberry, Florida FL City of Radford - Electric Department VA

City of Newburg (MO) MO City of Radium KS

City of Newkirk OK City of Rancho Cucamonga CA

City of Newton IL City of Randall MN

City of Nicholasville KY City of Randolph (NE) NE

City of Nielsville MN City of Rayne LA

City of Niles (MI) MI City of Readlyn (IA) IA

City of Nixa Utilities MO City of Red Cloud NE

City of North Saint Paul MN City of Redding CA

City of Northwood ND City of Renwick (IA) IA

City Of Norton Kansas KS City of Richland WA

City of Norway Dept. of Power & Light MI City of Rising Sun (IN) IN

City of Oberlin (KS) KS City of Riverdale ND

City of Ocala Utility Services FL City of Robertsdale AL

City of Odessa MO City of Robinson KS

City of Oglesby (IL) IL City of Rock Hill SC

City of Olivia (MN) MN City of Rockwood TN

City of Onawa IA City of Roodhouse IL

City of Onida (SD) SD City of Roseau MN

City of Opelika AL City of Roseville CA

City of Ord NE City of Round Lake MN

City of Orient (IA) IA City of Rupert ID

City of Ortonsville - (MN) MI City of Rushford MN

City of Osage City KS City of Rushmore - (MN) MN
92 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipally Owned Utility (Continued)

City of Russell KS City of Strawberry Point IA

City of Russell (MA) MA City of Stroud (OK) OK

City of Ruston (LA) LA City of Stuart (NE) NE

City of Sabula IA City of Sullivan MO

City of Saint Peter MN City of Sumas WA

City of Salamanca NY City of Superior (NE) NE

City of Salem VA City of Sutton NE

City of Sanborn IA City of Sylvania (GA) GA

City of Sauk Centre MN City of Syracuse NE

City of Schuyler (NE) NE City of Tallahassee Utilities FL

City of Scranton KS City of Taunton MA

City of Scribner NE City of Tecumseh NE

City of Seaford DE City of Tenakee Springs AK

City of Sebewaing (MI) MI City of Thayer MO

City of Seguin TX City of Thief River Falls MN

City of Seneca SC City of Timpson (TX) TX

City of Seward (AK) AK City of Toronto (KS) KS

City of Seymour (TX) TX City of Traverse City MI

City of Shasta Lake CA City of Trenton (TN) TN

City of Sheboygan Falls WI City of Trinidad CO

City of Shelbina MO City of Troy KS

City of Shelby (NC) NC City of Troy - (IN) IN

City of Shelby (OH) OH City of Troy AL

City of Sherrill Power & Light NY City of Tulia TX

City of Shiner TX City of Tupelo - (MS) MS

City of Shullsburg (WI) WI City of Tuskegee AL

City of Sibley IA City of Two Harbors MN

City of Sidney NE City of Tyler MN

City of Siloam Springs (AR) AR City of Tyndall SD

City of Sioux Falls (SD) SD City of Udall KS

City of Slater MO City of Unalaska AK

City of Smithville TX City of Union City TN

City of Snyder NE City of Union SC

City of Soda Springs ID City of Unionville MO

City of South Sioux City NE City of Valentine NE

City of Spring Grove MN City of Valley City ND

City of Springfield CO City of Vandalia MO

City of Springfield, IL IL City of Vermillion (KS) KS

City of St Charles IL City of Versailles OH

City of St Louis MI City of Virginia MN

City Of St Marys KS City of Wadena Electric & Water MN

City of St Robert (MO) MO City of Wakefield (NE) NE

City of St. Charles MN City of Wall Lake IA

City of St. Clairsville OH City of Wamego KS

City of St. George UT City of Warren - (MN) MN

City of St. James MN City Of Warroad MN

City Of St. John KS City of Washington (IN) IN

City of St. Marys OH City of Washington (KS) KS

City of Stafford (KS) KS City of Washington GA

City of Stanhope IA City of Waterloo IL

City of Stanton ND City of Watertown NY

City of Stanton (IA) IA City of Wathena KS

City of Starkville MS City of Wauchula FL

City of State Center IA City of Weiser ID

City of Statesville (NC) NC City of Wellington KS

City of Stephen - (MN) MN City of West Liberty IA

City of Stephenson MI City of West Plains MO

City of Stockton KS City of Westbrook MN
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 93

Municipally Owned Utility (Continued)

City of Westfield MA Gaffney Board of Public Works SC

City of Whalan MN Gainesville Regional Utilities FL

City of Whigham GA Galena Electric Utility AK

City of White SD Gallatin Department of Electricity TN

City of Whittemore IA Glasgow Electric Plant Board KY

City of Wilber NE Glencoe Light and Power Commission MN

City of Willow Springs MO Gold Country Energy AK

City of Windom MN Goltry Public Works Authority OK

City of Winfield (KS) KS Grafton Electric IA

City of Winner SD Grand Haven Board of Light and Power MI

City of Winnfield LA Green Cove Springs Electric Utility FL

City of Winona MO Greenfield Municipal Utilities IA

City of Winterset (IA) IA Greenwood Commissioners Public Works SC

City of Winterville NC Greenwood Utilities MS

City of Winthrop (MN) MN Groton Electric Light Dept. MA

City of Wisner NE Grundy Center Mun. Light & Power IA

City of Woolstock IA Harriman Utility Board TN

City of Wrangell AK Harrisonburg Electric Commission VA

City of Wray CO Hartford Utilities WI

City of Wymore (NE) NE Havana Power & Light Company FL

City of Yoakum, Texas TX Hawley Public Utilities MN

City Utilities of Springfield, MO MO Heber Light & Power Company UT

City Water & Light Plant of the City of Jonesboro AR Helper City UT

City of Girard KS Henderson Power and Light KY

Clarksdale Public Utilities MS Hermiston Energy Services OR

Clarksville Light & Water Co AR Hibbing Public Utilities MN

Clintonville Utilities WI Hingham Municipal Light Plant MA

Colorado Springs Utilities CO Holland Board of Public Works MI

Columbia Power & Water Systems TN Holy Springs Utility Department MS

Columbus Water & Light Dept. WI Hooversville Electric Light Co PA

Conway Corporation AR Hope Water and Light Commission AR

Corbin City Utilities Commission KY Hopkinsville Electric System KY

Corwith Municipal Utilities IA Hudson Light & Power Department MA

Crawfordsville Electric Light & Power IN Hudson Municipal Electric Utility IA

Cuba City Electric & Water Utility WI Hurricane City Power UT

Cumberland, City of WI Hustisford Utilities WI

Cuyahoga Falls Electric System OH Hutchinson Utilities Commission MN

D.G. Hunter Power Station LA Hyrum City Corp. UT

Darlington Light & Power Co IN Idaho Falls Power ID

Delano Municipal Utilities MN Illinois Municipal Electric Agency IL

Delta Municipal Light and Power CO Independence Light & Power IA

Dublin Municipal Electric Utilities IN Indianola Municipal Utilities IA

Eagle River Light & Water Commission WI Jamestown Board of Public Utilities NY

Easley Combined Utility System SC JEA FL

East Bay Municipal Utility District CA Jefferson Water & Light Dept. WI

Easton Utilities Commission MD Jewett City Department of Public Utilities CT

Ediburg Municipal Utilities IN Juneau Utility Commission WI

Electric and Water Plant Board of the City of Frankfort KY Kaukauna Utilities WI

Elk River Municipal Utilities MN Kaysville City Corporation UT

Evansville Water & Light WI Keewatin Public Utilities MN

Fairburn Utilities GA Kennebunk Light & Power District ME

Fitzgerald Wtr Lgt GA Kenyon Municipal Utility MN

Florence Utility Commission WI Kerrville Public Utility Board TX

Foley Board of Utilities AL Ketchikan Public Utilities AK

Forest City Municipal Utilities IA Kimballton Municipal Utilities IA

Fort Collins Utilities CO Kirbyville Light & Power Co TX

Fort Pierce Utilities Authority FL Kissimmee Utility Authority FL

Fremont Department of Utilities NE Knoxville Utilities Board TN
94 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipally Owned Utility (Continued)

Kokhanok Village Council AK North Little Rock Electric Department AR

Kosciusko Water & Light Plant MS Norwich Public Utility CT

La Farge Municipal Electric Co. WI Oconto Falls Water & Light Commission WI

La Porte City Utilities IA Okeene Public Works Authority OK

Lafayette Utilities System LA Orlando Utilities Commission FL

Lake Mills Light & Water Dept. WI Orrville Utilities OH

Lake Placid Village, Inc. NY Osage Municipal Utilities IA

L'anse Electric Utility MI Owatonna Public Utilities MN

Lansing Board of Water & Light MI Owensboro Municipal Utilities KY

Lassen Municipal Utility District CA Page Electric Utility AZ

Lawrenceburg Municipal Utilities IN Palmrya Board of Public Works MO

Lebanon Utilities IN Paragould Light Water and Cable AR

Levan Town Corporation UT Parowan City Corporation UT

Lexington Electric System TN Pascoag Utility District RI

Littleton Water and Light Department NH Payson City Corporation UT

Lockwood Water & Light Company MO Pella City of IA

Lodi Municipal Light & Water Utility WI Pend Oreille PUD WA

Logan City Light and Power UT Piggott Light and Water AR

Logansport Municipal Utilities IN Plymouth Utilities WI

Longmont Power & Communications CO Prague Public Works Authority OK

Los Angeles Department of Water and Power CA Prairie du Sac Municipal Electric & Water WI

Louisville Electric System MS Precinct of Woodsville NH

Madelia Municipal Light & Power MN Price Municipal Corporation UT

Manitowoc Public Utilities WI Princeton Public Utilities Commission MN

Manti City UT Proctor Public Utilities Commission MN

Maquoketa Municipal Electric Utility IA Prospect Corporation OH

Marquette Board of Light and Power MI Provo City Corporation UT

Marshall Municipal Utilities MN Public Works Commission of the City of Fayetteville NC

Matinicus Plantation Electric Co ME PUD No 1 of Asotin County WA

Mayor & Council of Middletown DE PUD No 1 of Skamania Co WA

McMinnville Electric System TN Raton Public Service Company NM

Meadow Town Corp. UT Redwood Falls Public Utility Commission MN

Memphis Light, Gas & Water Division TNI Reedsburg Utility Commission WI

Menasha Electric & Water Utilities WI Reedy Creek Improvement District FL

Merrimac Municipal Light Department MA Rensselaer Municipal Electric Utility IN

Metlakatla Power & Light AK Reynolds, Village of NE

Monroe City UT Rice Lake Utilities WI

Moorhead Public Service MN Richland Center Electric Utility WI

Morgan City (LA) LA Richmond Power and Light IN

Morgan City Corporation UT River Falls Municipal Utility WI

Morristown Utilities Commission TN Riverside Public Utilities CA

Mount Horeb Electric Utility WI Rochelle Municipal Utilities IL

Mount Pleasant Municipal Utilities IA Rock Port Municipal Utilities MO

Municipal Commission of Boonville NY Rock Rapids Municipal Utilities IA

Municipal Electric Utility of the City of Cedar Falls IA Rockford Municipal Light Plan IA

Municipal Services Commission DE Sallisaw Municipal Authority OK

Muscoda Light & Water Utility WI Santa Clara City UT

Negaunee Electric Department MI Second Taxing District of Norwalk CT

New Glarus Light & Water Works WI Sevier County Electric System TN

New Hampton Village Precinct NH Shakopee Public Utilities Commission MN

New Holstein Public Utility WI Shawano Municipal Utilities WI

New London Electric & Water Utility WI Sikeston Board of Municipal Utilities MO

New Martinsville Municipal Electric Utility WV Silicon Valley Power, City of Santa Clara CA

New Richmond Municipal Electric Utility WI Sioux Center Municipal Electric Utility IA

New Ulm Public Utilities Comm MN Sleepy Eye Public Utilities MN

Newberry Water & Light Board MI Slinger Utilities WI

Nome Joint Utility System AK Smithville Electric System TN

North Branch Water & Light Comm. MN Snohomish County PUD No 1 WA
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 95

Municipally Owned Utility (Continued)

South Hadley Electric Light Department MA Town of Hobgood NC

South Vienna Corporation OH Town of Ipswich MA

Spanish Fork City Corporation UT Town of Julesburg CO

Spencer Municipal Utilities IA Town of Kingsford Heights IN

Spencerport Electric NY Town of Knightstown (Municipal Electric Utility) IN

Spooner Municipal Utilities WI Town of Ladoga (IN) IN

Spring Valley Public Utilities MN Town of Landis NC

Springville Light & Power UT Town of Laverne- (OK) OK

Stoughton Electric Utility WI Town of Lewisville IN

Straughn Municipal Electric IN Town of Lucama NC

Stuart Municipal Utilities IA Town of Lyons CO

Sturgeon Bay Utilities WI Town of MacClesfield NC

Sumner Municipal Light Plant IA Town of Madison (ME) ME

Sun Prairie Water & Light Commission WI Town of Maiden (NC) NC

Sylacauga Utilities Board AL Town of Manilla (IA) IA

Tacoma Public Utilities WA Town of Mansfield (MA) MA

TDX Manley Generating LLC AK Town of Massena Electric Department NY

Tell City Electric Department IN Town of Middleborough (MA) MA

The City of Holyoke Gas and Electric Department MA Town of Middletown-(IN) IN

The Hagerstown Light Department MD Town of Montezuma IN

Third Taxing District Electric Dept. CT Town of New Carlisle (IN) IN

Tipton Municipal Electric Utility IN Town of Oak City UT

Tipton Municipal Utilities IA Town of Paxton Municipal Light Department MA

Town of Argos Utilities IN Town of Pinetops NC

Town of Ashburnham MA Town of Pineville (NC) NC

Town of Avilla IN Town of Princeton (MA) MA

Town of Bargersville IN Town of Prosperity, SC SC

Town of Belmont MA Town of Rowley (MA) MA

Town of Black Creek NC Town of Ruston (WA) WA

Town of Blackstone VA Town of Ryan (OK) OK

Town of Bostic NC Town of Scotland Neck (NC) NC

Town of Boyce LA Town of Sharpsburg NC

Town of Brinson GA Town of South Whitley IN

Town of Brooklyn IN Town of Spiceland IN

Town of Clayton (NC) NC Town of Spiro OK

Town of Coatesville IN Town of Stantonsburg NC

Town of Coulee Dam WA Town of Stowe VT

Town of Crane IN Town of Templeton (MA) MA

Town of Culpeper Light & Power VA Town of Veedersburg IN

Town of Dallas NC Town of Vidalia LA

Town of Eatonville WA Town of Wakefield (VA) VA

Town of Etna Green IN Town of Walkerton IN

Town of Ferdinand IN Town of Wallingford, Department of Public Utilities CT

Town of Forest City NC Town of Walstonburg NC

Town of Fountain NC Town of Waynesville NC

Town of Frankton IN Town of Winamac IN

Town of Frederick CO Town of Winnsboro SC

Town of Fredonia AZ Town of Wolfeboro NH

Town of Front Royal VA Traer Municipal Utilities IA

Town of Granada CO Trenton Municipal Utilities MO

Town of Granite Falls NC Tullahoma Board of Public Utilities TN

Town of Groveland MA Two Rivers Water & Light Utility WI

Town of Guernsey WY Van Buren Light & Power District ME

Town of Gueydan LA Village of Akron NY

Town of Hardwick VT Village of Angelica NY

Town of Haxtun CO Village of Arcade NY

Town of High Point NC Village of Arcadia OH

Town of Highlands NC Village of Arnold NE
96 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Municipally Owned Utility (Continued)

Village of Bartley NE Village of Silver Springs Municipal Electric NY

Village of Belmont WI Village of Skaneateles (NY) NY

Village of Bergen NY Village of Spalding NE

Village of Bethany Illinois IL Village of Spencer NE

Village of Black Earth WI Village of Springville NY

Village of Blanchester OH Village of Stratford WI

Village of Brainard NE Village of Stratton NE

Village of Brocton NY Village of Swanton VT

Village of Callaway NE Village of Talmage NE

Village of Campbell (NE) NE Village of Theresa NY

Village of Carey OH Village of Tontogany OH

Village of Castile NY Village of Tupper Lake NY

Village of Chester NE Village of Viola WI

Village of Churchville NY Village of Watkins Glen NY

Village of Clinton MI Village of Wellington OH

Village of Daggett MI Village of Westfield NY

Village of Davenport NE Village of Wharton OH

Village of De Witt NE Village of Winnetka IL

Village of Deshler OH Vinton Municipal Electric Utility IA

Village of Dorchester NE Bowling Green OH

Village of Endicott Municipal Light NY Wadsworth Utilities OH

Village of Fairport NY Wagoner Public Works Authority OK

Village of Frankfort (NY) NY Walters Public Works Authority OK

Village of Freeburg IL Washington City Power UT

Village of Freeport NY Waterloo Water & Light Commission WI

Village of Glouster OH Waunakee Water & Light Commission WI

Village of Grafton OH Waupun Utilities WI

Village of Greene NY Waverly Municipal Elec Utility IA

Village of Greenport NY Weakley County Municipal Electric System TN

Village of Hampton NE Weatherford Municipal Utility System TX

Village of Haskins OH West Boylston Lighting Plant MA

Village of Hazel Green WI West Point Municipal Utility IA

Village of Hemingford/Hemingford Municipal Utilities NE Westby Municipal Electric Utility WI

Village of Holbrook NE Williamstown Utility Commission KY

Village of Holley Municipal Electric Department NY Wilton Municipal Light and Power IA

Village of Jackson Center - (OH) OH Wisconsin Dells Electric Utility WI

Village of Lakeview (OH) OH Wonewoc Municipal Water & Light Dept WI

Village of Little Valley NY Wyandotte Municipal Service Commission MI

Village of Lodi (OH) OH Wynnewood City Utilities Authority OK

Village of Lucas OH

Village of Lyndonville VT Political Subdivision

Village of Marshallville OH Alamo Power District #3 NV

Village of Mayville NY Arkansas River Power Authority CO

Village of Merrillan (WI) WI Butler Public Power District NE

Village of Morrill (NE) NE Cedar-Knox PPD NE

Village of New Bremen (OH) OH Chimney Rock Public Power District NE

Village of New Knoxville (OH) OH City of El Dorado Springs MO

Village of Oak Harbor (OH) OH City of Steelville MO

Village Of Oxford NE Clatskanie PUD OR

Village of Paw Paw MI Cornhusker Public Power District NE

Village of Pemberville (OH) OH Dawson Public Power District NE

Village of Philadelphia NY Eastside Power Authority CA

Village of Polk - (NE) NE Electrical District # 2 AZ

Village of Rantoul IL Electrical District No. 4 Pinal County AZ

Village of Rockville Centre NY Electrical District No. 5 Pinal County AZ

Village of Seville Board of Public Affairs OH Elkhorn Rural Public Power District NE

Village of Sherburn NY Emerald People's Utility District OR

Village of Shickley NE Howard Greeley Rural Public Power District NE
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 97

Political Subdivision (Continued)

Kings River Conservation District CA Direct Energy Services, LLC CT,DC,DE,IL,MA,MD,

Kwig Power Company AK ME,NJ,NY,OH,PA,RI

Louisiana Energy and Power Authority LA Direct Energy, LP TX

Loup River Public Power District NE Dow Hydrocarbons and Resources LLC. TX

Loup Valleys Rural Public Power District NE Energy Plus Holdings LLC CT,IL,MD,NJ,NY,PA,

McCook Public Power District NE TX

Merced Irrigation District CA En-Toucn Systems, Inc. d/b/a En-Touch Energy TX

Midvale Irrigation District WY First Choice Power TX

North Central Public Power District NE Gateway Energy Services Corporation MD,NJ,NY,PA

Northeast Nebraska Public Power District NE Integrys Energy Services of New York, Inc. NY

Oakdale & South San Joaquin Irrigation D. CA Integrys Energy Services, Inc. CT,DC,DE,IL,MA,MD,

ME

Overton Power District No. 5 NV MxEnergy Electric, Inc. TX

Perennial Public Power District NE Power Choice/ Pepco Energy Serv DC,DE,IL,MA,MD,NJ,

Placer County Water Agency CA NY,PA,TX

Platte River Power Authority CO Shell Energy North America, LP TX

Polk County Rural Public Power District NE South Jersey Energy NJ

Public Service Commission of Yazoo City MS Spartan Renewable Energy, Inc. MI

Public Utility District #1 of Ferry County WA Tara Energy, LLC TX

Public Utility District No. 1 of Wahkiakum County WA Texas Retail Energy, LLC TX

PUD #1 of Clallam County WA TXU Energy Retail Company LLC TX

PUD No 1 of Clark County WA U.S. Energy Partners LLC NY

PUD No 1 of Klickitat County WA UGI Energy Services, Inc. DC,DE,MD,NJ,NY,PA

PUD No 3 of Mason County WA Wolverine Power Marketing Cooperative MI

PUD No. 1 of Whatcom County WA WTU Retail Energy, LP TX

Roosevelt Public Power District NE

Salt River Project Agricultural Improvement & Power AZ State Utility

South Feather Water and Power Agency CA Alaska Energy Authority AK

Southern California PPA CA Commonwealth Utilities Corporation MP

Southern Public Power District NE Energy Northwest WA

Southwest Public Power District NE Grand River Dam Authority OK

The Central Nebraska Public Power and Irrigation NE Nebraska Public Power District NE,SD

Tillamook People's Utility District OR New York Power Authority NY

Tohono O'odham Utility Authority AZ South Carolina Public Service Authority SC

Tonopah Irrigation District AZ The Metropolitan Water District of Southern Calif CA

Village of Endicott NE Toledo Bend Project Joint Operations TX

WPPI Energy WI Virginia Tech Electric Service VA

Regional Transmission Organization/ ITC Great Plains KS,OK

Independent Transmission Operator ITC Midwest LLC IA,IL,MN,MO

California Independent System Operator CA ITC Transmission MI

Electric Reliability Council of Texas TX Michigan Electric Transmission Company MI

ISO New England MA Swans Island Electric Coop Inc ME

Midwest ISO IN Vermont Electric Power Co, Inc VT

New York Independent System Operator NY Vermont Electric Trans Co Inc VT

PJM Interconnection, LLC PA

Southwest Power Pool AR

Retail Power Marketer

3 Phases Renewables CA

Accent Energy Holdings, LLC NY,TX

Agway Energy Services, LLC NY

Ameren Energy Marketing IL

Amigo Energy TX

Anthracite Power & Light PA

AP Holdings, LLC NY,PA,TX

APN Starfirst, L.P. PA

APNA Holdings LLC dba APNA Energy TX

CPL Retail Energy, LP TX

Wholesale Power Marketer

AES Eastern Energy LP NV 

Badger Power Marketing Auth WI

CL Power Sales Eight LLC CA

CP Power Sales Seventeen LLC MA

Dynegy Power Marketing, LLC TX
98 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Edison Mission Marketing & Trading, Inc. - WSPP MA

GenOn Energy Management, LLC FL,IL,MA,MD,MS,NJ,NY,OH,PA,TX,VA

Great Bay Power Marketing, Inc. MA,ME,NH,NJ,NY,VT

Guthrie County Rural Electric Cooperative IA

H.Q. Energy Services (U.S.) Inc. CT

JP Morgan TX

Luminant Energy Company LLC TX

Macquarie Energy LLC TX

NextEra Energy Power Marketing, LLC FL

PPL EnergyPlus LLC MT

PSEG Energry Resources & Trade LLC NJ

Rainbow Energy Marketing Corporation ND

RRI Energy Services, LLC TX

Select Energy, Inc. TX

Sunflower Electric Power Corporation KS

TransAlta Energy Marketing NY
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 99

APPENDIX F: DEMAND RESPONSE PROGRAMS AND SERVICES AT 

RESPONDING ENTITIES

Appendix F lists entities that responded to the 2012 FERC Survey and indicated that they offer one or more 

demand response programs, organized by demand response program type.

Entergy Gulf States Louisiana, L.L.C.

Critical Peak Pricing ISO New England

Butler Rural Electric Cooperative, Inc. Niagara Mohawk Power Corporation

Canadian Valley Electric Cooperative PJM Interconnection, LLC

City of Algona Southern California Edison (SCE)

City of Palo Alto Utilities

Clay Electric Cooperative, Inc. Direct Load Control

Fairfield Electric Cooperative Inc. A & N Electric Cooperative

Flint Electric Membership Corporation Adams Electric Cooperative

Green Mountain Power Corporation Adams Electric Cooperative, Inc.

High Plains Power, Inc. Adams-Columbia Electric Cooperative

Jackson Electric Membership Corporation Alabama Municipal Electric Authority

JEA Alabama Power Company

OGE Energy Corporation Allegheny Electric Cooperative, Inc.

Rayle Electric Membership Corporation Ames, City of

Red River Valley Rural Electric Association Ashley-Chicot Electric Cooperative, Incorporated

Richmond Power and Light Austin Utilities

Rural Electric Cooperative, Inc. Baltimore Gas and Electric Company

Sacramento Municipal Util Dist BARC Electric Coop Inc

San Diego Gas & Electric Barnesville Municipal Electric

Sioux Valley SW Elec Coop Bedford Rural Elec Coop, Inc

Southern California Edison (SCE) Black Hills Electric Cooperative, Inc

Tampa Electric Company Blooming Prairie Public Utility Commission

The Detroit Edison Company Bon Homme Yankton Electric Association, Inc.

Town of High Point Brunswick Electric Membership Corporation

United Power Burlington Electric Department

Wisconsin Public Service Corporation Butler Public Power District

Wynnewood City Utilities Authority Butler Rural Electric Cooperative, Inc.

Butte Electric Cooperative

Critical Peak Pricing with Load Control C&L Electric Cooperative Corporation

Adams Electric Cooperative, Inc. Caddo Electric Cooperative, Inc.

Arizona Public Service Capital Electric Cooperative, Inc.

Cass County Electric Cooperative Carroll Electric Cooperative Corporation

City of Monroe Carroll Electric Membership Corporation

Coles-Moultrie Electric Cooperative Cass County Electric Cooperative

Dairyland Power Cooperative Central Alabama Electric Cooperative

Flathead Electric Cooperative, Inc. Central Electric Cooperative

Municipal Services Commission Central Electric Cooperative, Inc.

Northwestern Electric Cooperative, Inc. Central Georgia Electric Membership Corp.

Otter Tail Power Company Central Vermont Public Service Corporation

Sacramento Municipal Utility District Charles Mix Electric

Salt River Project Agricultural Improvement & Power District Citizens' Electric Company

San Diego Gas & Electric City of Big Stone City

Sioux Valley SW Elec Coop City of East Grand Forks - (MN)

Town of High Point City of Gothenburg

Warren Electric Cooperative, Inc City of Groton

City of Halstad

Demand Bidding & Buy-Back City of Hawarden City of Milford

City of Glendale City of Milford

City of Milford City of Olivia (MN)

Connecticut Light and Power Company City of Port Angeles

Duke Energy Carolinas, LLC City of Rock Hill

Duke Energy Corporation City of Roseau

Duke Energy Indiana, Inc. City of Roseville

City of Saint Peter City of St. James
100 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Direct Load Control (Continued)

City of Valley City Jefferson Energy Cooperative

City of Vermillion Jersey Central Power & Light Co

City of Wadena Electric & Water Kansas City Power & Light Company

City of Winner Kansas Gas & Electric Company

Claverack REC KCP&L Greater Missouri Operations Company

Clay County Electric Cooperative Corporation Kingsbury Electric Cooperative, Inc.

Clay-Union Electric Corporation Lake Region Electric Cooperative

Cleveland Electric Illuminating Co Lee County Electric Cooperative, Incorporated

Coles-Moultrie Electric Cooperative Louisville Gas & Electric and Kentucky Utilities

Commonwealth Edison Company Marshall Municipal Utilities

Connexus Energy McLean Electric Coop

Consolidated Edison Company of New York McLeod Cooperative Power Association

Cooperative Light and Power Mecklenburg Electric Cooperative

Corn Belt Energy Corporation Menard Electric Cooperative

Corn Belt Power Cooperative Metropolitan Edison Co

Craighead Electric Cooperative Corporation MidAmerican Energy Company

Crow Wing Cooperative Power & Light Company Midwest Electric, Inc.

Dairyland Power Cooperative Midwest Energy Cooperative

Dakota Electric Association Midwest Energy, Inc.

Delaware Electric Cooperative, Inc. Midwest ISO

Delmarva Power and Light Company Minnesota Valley Electric Cooperative

Dixie Electric Membership Corporation Minnkota Power Cooperative, Inc.

Douglas Electric Cooperative, Inc. Mississippi County Electric Cooperative, Inc.

Duke Energy Carolinas, LLC Moorhead Public Service

Duke Energy Corporation Mountain View Electric Association, Inc.

Duke Energy Indiana Inc Municipal Commission of Boonville

Duke Energy Kentucky, Inc. Nevada Power Company

East River Electric Power Cooperative, inc. Nobles Cooperative Electric

Elk River Municipal Utilities North Arkansas Electric Cooperative, Incorporated

Elkhorn Rural Public Power District North Carolina Electric Membership Corp

Emerald People's Utility District North Central Electric Coop

EnergyUnited Electric Membership Corporation Northeastern REMC

Entergy New Orleans, Inc. Northern Municipal Power Agency

Excelsior Electric Membership Corporation Northern Virginia Electric Cooperative

Fairfield Electric Cooperative Inc. Oahe Electric Cooperative Inc.

Farmers Electric Cooperative Corporation Ohio Edison Co

Farmers' Electric Cooperative, Inc. Osceola Electric Cooperative, Inc.

Federated Rural Electric Otter Tail Power Company

First Electric Cooperative Corporation Pacific Gas and Electric Company

Flint Electric Membership Corporation PacifiCorp

Florida Power & Light Company Pee Dee Electric Membership Corp.

Fort Collins Utilities Pennsylvania Electric Co

Georgia Power Pennsylvania Power Co

Grundy Electric Cooperative, Inc. People's Electric Cooperative

Hawaiian Electric Company, Inc. Perennial Public Power District

Haywood Electric membership Corp. Piedmont Electric Membership Corporation

H-D Electric Cooperative, Inc Pocahontas Municipal Utilities

Henry County REMC Potomac Electric Power Company

Highline Electric Association Power Choice/ Pepco Energy Services

Idaho Power Company Prince George Electric Cooperative

Illinois Rural Electric Cooperative Princeton Public Utilities Commission

Indiana Michigan Power Company Progress Energy Carolinas

Interstate Power and Light Company Progress Energy Florida

Itasca-Mantrap Cooperative Electrical Association Public Service Electric & Gas Company

Jackson Electric Membership Corporation Puget Sound Energy, Inc.

Jackson Energy Cooperative Corp - (KY) Rappahannock Electric Cooperative
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 101

Direct Load Control (Continued)

Renville-Sibley Cooperative Power Association Manitowoc Public Utilities

Rolling Hills Electric Cooperative, Inc. Midwest ISO

Sacramento Municipal Utility District Monongahela Power Co

San Diego Gas & Electric Nebraska Public Power District

Santee Electric Cooperative, Inc. New York Independent System Operator

Shakopee Public Utilities Commission New York State Electric & Gas

Shelby Electric Cooperative Niagara Mohawk Power Corporation

Shenandoah Valley Electric Cooperative Northern Virginia Electric Cooperative

Sioux Center Municipal Electric Utility Pacific Gas and Electric Company

Sioux Valley SW Elec Coop Rochester Gas & Electric

South Central Electric Association Sacramento Municipal Utility District

South Central Power Company Sierra Pacific Power Company

Southeastern Electric Cooperative, Inc. Southern California Edison (SCE)

Southern California Edison (SCE) Tampa Electric Company

Southern Indiana Gas & Elec The United Illuminating Company

Southern Indiana REC, Inc. West Penn Power Company

Southern Maryland Electric Cooperative, Inc.

Southwest Public Power District Interruptible Load

Southwestern Electric Power Company Adams Electric Cooperative

Spring Valley Public Utilities Adams Electric Cooperative, Inc.

Steuben Rural Electric Cooperative, Inc. Alabama Power Company

Sumter Electric Cooperative, Inc. APN Starfirst, L.P.

Superior Water, Light and Power Company Appalachian Power Company

Tampa Electric Company Arkansas Electric Cooperative Corporation

The Detroit Edison Company Atchison-Holt Electric Coop

The Frontier Power Company Austin Utilities

The Midwest Electric Cooperative Corporation Baltimore Gas and Electric Company

The Toledo Edison Co Blooming Prairie Public Utility Commission

Town of Massena Electric Department Board of Public Utilities, City of McPherson

Tucson Electric Power Bon Homme Yankton Electric Association, Inc.

TXU Energy Retail Company LLC Borough of Lansdale

Union County Electric Cooperative, Inc. Brunswick Electric Membership Corporation

United Electric Cooperative C&L Electric Cooperative Corporation

United Power Carroll Electric Cooperative Corporation

Virginia Electric & Power Co Carroll Electric Membership Corporation

Westar Energy, Inc. Central Electric Cooperative

Whetstone valley electric cooperative, Inc Central Iowa Power Cooperative

Wiregrass Electric Cooperative, Inc. Central Vermont Public Service Corporation

Wisconsin Public Service Corporation City of Cartersville, Georgia

Wisconsin Power and Light Company City of Elroy

Woodruff Electric Cooperative Corporation City of Halstad

Xcel Energy City of Lakeland, Lakeland Electric

York Electric Cooperative, Inc. City of Lincoln Electric System

City of Port Angeles

Emergency Demand Response City of Rock Hill

Central Hudson Gas & Electric Corporation City of Saint Peter

City of Columbus, Ohio City of Sheboygan Falls

Electric Reliability Council of Texas City of Tallahassee Utilities

Energy spectrum, Inc City Utilities of Springfield, MO

EnerNOC, Inc Clay Electric Cooperative, Inc.

ISO New England Columbus Southern Power Company

Kansas City Power & Light Company Commonwealth Edison Company

Keytex Energy LLC Connecticut Light and Power Company

Connexus Energy

Consolidated Edison Company of New York

Consumers Energy Company
102 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Interruptible Load (Continued)

Corn Belt Energy Corporation Moorhead Public Service

Crow Wing Cooperative Power & Light Company Mountain View Electric Association, Inc.

Dairyland Power Cooperative Municipal Electric Utility of the City of Cedar Falls, Iowa

Dakota Electric Association New York Power Authority

Delaware Electric Cooperative, Inc. Nobles Cooperative Electric

Dixie Escalante REA Inc. North Carolina Electric Membership Corp

Duke Energy Carolinas, LLC Northern Virginia Electric Cooperative

Duke Energy Corporation NorthWestern Energy

Duke Energy Indiana Inc Ocmulgee Electric Membership Corporation

Duke Energy Kentucky, Inc. Ohio Power Company

Elk River Municipal Utilities OSCEOLA ELECTRIC COOPERATIVE, INC.

EnergyUnited Electric Membership Corporation Ouachita Electric Cooperative Corporation

Entergy Arkansas Inc Ozarks Electric Cooperative Corporation

Entergy Gulf States Louisiana, L.L.C. Pacific Gas and Electric Company

Entergy Louisiana Inc PECO Energy Company

Entergy New Orleans, Inc. Prince George Electric Cooperative

Entergy Texas, Inc. Progress Energy Carolinas

Federated Rural Electric Progress Energy Florida

First Electric Cooperative Corporation Public Service Company of Oklahoma

Florida Power & Light Company Public Service Electric & Gas Company

Fort Collins Utilities Rappahannock Electric Cooperative

Four County EMC Richards Energy Group, Inc.

Georgia Power Sacramento Municipal Utility District

Green Mountain Power Corporation Salt River Project Agricultural Improvement & Power 

 District

Hawaiian Electric Company, Inc. San Diego Gas & Electric

Howard Greeley Rural Public Power District Shelby Electric Cooperative

Idaho Power Company Shenandoah Valley Electric Cooperative

Illinois Rural Electric Cooperative South Carolina Electric & Gas Company

Indiana Michigan Power Company South Carolina Public Service Authority

Interstate Power and Light Company South Central Arkansas Electric Cooperative, Incorporated

Itasca-Mantrap Cooperative Electrical Association South Central Electric Association

JEA South Kentucky Rural Electric Cooperative Corp

Jefferson Energy Cooperative Southern California Edison (SCE)

Kansas City Power & Light Company Southern Indiana Gas & Electric Co 

Kansas Gas & Electric Company Southern Maryland Electric Cooperative, Inc.

KCP&L Greater Missouri Operations Company Southwest Arkansas Electric Cooperative Corporation

Kentucky Power Company Southwestern Electric Power Company

Lake Country Power Spencer Municipal Utilities

Lake Region Electric Cooperative Sumter Electric Cooperative, Inc.

Lamb County Electric Cooperative T.I.P. Rural Electric Cooperative

Lee County Electric Cooperative, Incorporated Tampa Electric Company

Linn County Rural Electric Cooperative Association Tennessee Valley Authority

Louisville Gas & Electric and Kentucky Utilities The Detroit Edison Company

Loup River Public Power District The Empire District Electric Company

Loup Valleys Rural Public Power District The Potomac Edison Company

Marshall Municipal Utilities The Satilla Rural Electric Membership Corporation

Mecklenburg Electric Cooperative Tucson Electric Power

Menard Electric Cooperative Union County Electric Cooperative, Inc.

MidAmerican Energy Company Upper Peninsula Power Corporation

Midwest Energy Cooperative Virginia Electric & Power Co

Midwest Energy, Inc. Warren Electric Cooperative, Inc

Midwest ISO Webster Electric Cooperative

Minnesota Power, Inc. West Penn Power Company

Minnesota Valley Electric Cooperative Westar Energy, Inc.

Mississippi County Electric Cooperative, Inc. Wheeling Power Company

Mississippi Power Whetstone Valley Electric Cooperative, Inc
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 103

Interruptible Load (Continued)

Wisconsin Electric Power Company Northwestern REC

Wisconsin Public Service Corporation Oklahoma Electric Cooperative

Wisconsin Power and Light Company Orange & Rockland Utilities Inc

Woodruff Electric Cooperative Corporation Puget Sound Energy, Inc.

WPPI Energy Rockland Electric Co

Xcel Energy Salt River Project Agricultural Improvement & Power

District

Sierra Electric Cooperative, Inc.

South Carolina Electric & Gas Company

Southern California Edison (SCE)

Southwest Power Pool

Load as a Capacity Resource Spring Valley Public Utilities

Arizona Public Service United Electric Cooperative Services, Inc.

Brazos Electric Power Cooperative, Inc. United Power

Cass County Electric Cooperative Western Massachusetts Electric Company

City of Radford - Electric Department Wisconsin Electric Power Company

Cooperative Light and Power Withlacoochee River Electric Cooperative, Inc.

EnerNOC, Inc

Idaho Power Company Peak Time Rebate

Memphis Light, Gas & Water Division Entergy New Orleans, Inc.

Midwest ISO Granite State Electric Company

New York Independent System Operator Grundy Electric Cooperative, Inc.

PJM Interconnection, LLC Massachusetts Electric Company

Public Service Company of New Mexico (PNM) Nantucket Electric Company

Salt River Project Agricultural Improvement & Power District OGE Energy Corporation

San Diego Gas & Electric Oklahoma Electric Cooperative

Southern California Edison (SCE) The Narragansett Electric Company

Tampa Electric Company Tri-County Electric Cooperative, Inc.

Tri-County Electric Cooperative, Inc

West Penn Power Company Real-Time Pricing

Wisconsin Electric Power Company Alpena Power Company

WPPI Energy Commonwealth Edison Company

Non-spinning Reserves Duke Energy Carolinas, LLC Duke Energy Corporation

California Independent System Operator Duke Energy Kentucky, Inc.

PJM Interconnection, LLC Entergy Arkansas Inc

Georgia Power

Other Gulf Power Company

Board of Public Utilities, City of McPherson Indiana Michigan Power Company

Carroll Electric Membership Corporation Kansas City Power & Light Company

Central Electric Cooperative, Inc. KCP&L Greater Missouri Operations Company

City of Ceylon Kentucky Power Company

Consolidated Edison Company of New York MidAmerican Energy Company

Consumers Energy Company New York State Electric & Gas

Delaware Electric Cooperative, Inc. Niagara Mohawk Power Corporation

Eastern Maine Electric Cooperative, Inc Northern Neck Electric Cooperative

Eastside Power Authority Northern Virginia Electric Cooperative

Entergy Arkansas Inc OGE Energy Corporation

Fairburn Utilities Otter Tail Power Company

ISO New England Progress Energy Carolinas

Itasca-Mantrap Cooperative Electrical Association Public Service Company of Oklahoma

Louisville Gas & Electric and Kentucky Utilities Public Service Electric & Gas Company

Minnesota Valley Electric Cooperative Rochester Gas & Electric

Mountain View Electric Association, Inc. South Carolina Public Service Authority

Nebraska Public Power District Southern California Edison (SCE)

New York Independent System Operator Tennessee Valley Authority
104 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Real-Time Pricing (Continued)

Upper Peninsula Power Corporation City of Rancho Cucamonga

Virginia Electric & Power Co City of Rock Hill

West Penn Power Company City of Roseville

Wisconsin Public Service Corporation City of Salem

Xcel Energy City of Tallahassee Utilities

City of Westfield

Regulation Clark County REMC

ISO New England Claverack REC

PJM Interconnection, LLC Clay Electric Cooperative, Inc.

Clintonville Utilities

Spinning Reserves Colorado Springs Utilities

Electric Reliability Council of Texas Columbus Southern Power Company

EnerNOC, Inc Columbus Water & Light Dept.

New York Independent System Operator Connecticut Light and Power Company

Consumers Energy

System Peak Response Transmission Tariff Cooperative Light and Power

Coosa Valley Electric Cooperative

Jefferson Energy Cooperative Crawfordsville Electric Light & Power

Nueces Electric Cooperative Crow Wing Cooperative Power & Light Company

Red River Valley Rural Electric Association Cuba City Electric & Water Utility

Dairyland Power Cooperative

Time-of-Use Delaware Electric Cooperative, Inc.

A & N Electric Cooperative Delmarva Power and Light Company

Adams Electric Cooperative Dixie Escalante REA Inc.

Adams Electric Cooperative, Inc. Duke Energy Carolinas, LLC

Algoma Utility Commission Duke Energy Corporation

Appalachian Power Company Duke Energy Indiana Inc

Arizona Public Service Duke Energy Kentucky, Inc.

Bangor Hydro Electric Company Eagle River Light & Water Commission

Bear Valley Electric Service Eastside Power Authority

Bedford Rural Elec Coop, Inc Edgecombe-Martin County Electric Membership Corp.

Bloomer Electric & Water Co Empire Electric Association, Inc.

Board of Public Utilities, City of McPherson Entergy Arkansas Inc

Boscobel Municipal Utilities Entergy Gulf States Louisiana, L.L.C.

Broad River Electric Cooperative, Inc. Entergy Louisiana Inc

Brodhead Water & Light Commission Entergy Texas, Inc.

Burlington Electric Department Evansville Water & Light

Butler Rural Electric Cooperative Association, Inc. Fitchburg Gas and Electric Light Company

Carbon Power & Light Inc Flathead Electric Cooperative, Inc.

Cedarburg Light & Water Commission Flint Electric Membership Corporation

Central Hudson Gas & Electric Corporation Florence Utility Commission

Central Maine Power Co Florida Power & Light Company

Central Vermont Public Service Corporation Florida Public Utilities Co.

Chicopee Municipal Lighting Plant Gaffney Board of Public Works

City of Boulder City Georgia Power

City of Carlyle, Illinois Grand Haven Board of Light and Power

City of Carmi, Illinois Grand River Dam Authority

City of Crystal Falls Green Mountain Power Corporation

City of Gastonia Groton Electric Light Dept.

City of Glendale Gulf Power Company

City of Lakeland, Lakeland Electric Hartford Utilities

City of Lodi Hawaii Electric Light Company, Inc.

City of Milford Hawaiian Electric Company, Inc.

City of North Saint Paul Haywood Electric membership Corp.

City of Palo Alto Utilities Hendricks County Rural Electric Membership Cooperative

City of Pasadena High Plains Power, Inc.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 105

Time-of-Use(Continued)

Highline Electric Association Oconto Falls Water & Light Commission

Holy Cross Electric Assn, Inc OGE Energy Corporation

Hustisford Utilities Ohio Power Company

Indiana Michigan Power Company Okefenoke Rural El Member Corp

Inter County Energy Cooperative Oklahoma Electric Cooperative

Interstate Power and Light Company Orange & Rockland Utilities Inc

Itasca-Mantrap Cooperative Electrical Association Orlando Utilities Commission

Jackson County Rural electric Membership Corporation Otero County Electric Cooperative, Inc.

Jackson Electric Membership Corporation Otter Tail Power Company

JEA Ozark Border Electric Cooperative

Jefferson Energy Cooperative Pee Dee Electric Membership Corp.

Jefferson Water & Light Dept. Piedmont Electric Membership Corporation

Jemez Mountains Electric Cooperative, Inc. Pioneer Electric Cooperative, Inc.

Jo-Carroll Energy, Inc.(NFP) Plymouth Utilities

Juneau Utility Commission Potomac Electric Power Company

Kansas City Power & Light Company Poudre Valley Rural Electric Association, Inc.

Kansas Gas & Electric Company Prairie du Sac Municipal Electric & Water

Kaukauna Utilities Progress Energy Carolinas

KCP&L Greater Missouri Operations Company Progress Energy Florida

Kentucky Power Company Public Service Company of New Hampshire

Kingsport Power Company Public Service Company of Oklahoma

Kissimmee Utility Authority Public Service Electric & Gas Company

La Plata Electric Assn. Inc. PUD No 1 of Klickitat County

Lake Country Power Rappahannock Electric Cooperative

Lake Mills Light & Water Dept. Reedsburg Utility Commission

Linn County Rural Electric Cooperative Association Rice Lake Utilities

Lodi Municipal Light & Water Utility Richland Center Electric Utility

Los Angeles Department of Water and Power Richmond Power and Light

Manitowoc Public Utilities River Falls Municipal Utility

Maui Electric Company, Limited Riverside Public Utilities

McLeod Cooperative Power Association Rochester Gas & Electric

Mecklenburg Electric Cooperative Rockland Electric Co

Medford Electric Utility Sacramento Municipal Utility District

Memphis Light, Gas & Water Division Salt River Project Agricultural Improvement & Power District

Menasha Electric & Water Utilities Sangre de Cristo Electric Association

MidAmerican Energy Company Sierra Electric Cooperative, Inc.

Midwest Energy Cooperative Slinger Utilities

Mississippi Power Snohomish County PUD No 1

Mount Horeb Electric Utility South Carolina Electric & Gas Company

Mountain Parks Electric, Inc. South Carolina Public Service Authority

Mountain View Electric Association, Inc. South Central Electric Association

Muscoda Light & Water Utility South Kentucky Rural Electric Cooperative Corp

Nebraska Public Power District South Mississippi Electric Power Association

New Glarus Light & Water Works Southwestern Electric Power Company

New Holstein Public Utility Steuben Rural Electric Cooperative, Inc.

New London Electric & Water Utility Stoughton Electric Utility

New Richmond Municipal Electric Utility Sturgeon Bay Utilities

New York State Electric & Gas Sun Prairie Water & Light Commission

Niagara Mohawk Power Corporation Superior Water, Light and Power Company

North Little Rock Electric Department Tampa Electric Company

Northeastern REMC Tennessee Valley Authority

Northern Neck Electric Cooperative The Detroit Edison Company

Northern Virginia Electric Cooperative The Empire District Electric Company

Northwestern Electric Cooperative, Inc. The Satilla Rural Electric Membership Corporation

NorthWestern Energy Tri-County Electric Cooperative, Inc

Northwestern REC Tucson Electric Power
106 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Time-of-Use(Continued)

Turlock Irrigation District

Two Rivers Water & Light Utility

TXU Energy Retail Company LLC

Union Electric Company

United Electric Cooperative Services, Inc.

United Power

Valley Rural Electric Cooperative, Inc.

Village of Stratford

Virginia Electric & Power Co

Wake Electric

Waterloo Water & Light Commission

Waunakee Water & Light Commission

Waupun Utilities

Waverly Municipal Elec Utility

Westar Energy, Inc.

Westby Municipal Electric Utility

Western Indiana Energy REMC

Western Massachusetts Electric Company

Wheatland Rural Electric Cooperative

Wheeling Power Company

Wisconsin Public Service Corporation

Wisconsin Power and Light Company

WPPI Energy

Xcel Energy
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 107

APPENDIX G: DATA FOR FIGURES IN REPORT

Advanced Metering

Data supporting Figure 2-1

Estimated advanced metering penetration nationwide in 2006, 2008, 2010, and 2012 FERC Surveys

Year Advanced Metering

2006 0.7%

2008 4.7%

2010 8.7%

2012 22.9%

Data supporting Figure 2-2 

Estimated advanced metering penetration nationwide reported in 2006, 2008, 2010 and 2012 FERC Surveys

Region

2006 FERC 

Survey

2008 FERC 

Survey

2010 FERC 

Survey

2012 FERC 

Survey

ASCC 0.0% 0.0% 1.2% 0.0%

FRCC 0.1% 10.4% 5.0% 32.5%

Hawaii 0.0% 1.6% 2.1% 0.2%

MRO 0.6% 3.7% 15.3% 14.6%

NPCC 0.1% 0.3% 0.7% 5.3%

RFC 0.4% 5.1% 6.7% 10.4%

SERC 1.2% 5.8% 8.0% 22.0%

SPP 3.0% 5.8% 8.9% 15.2%

TRE 0.7% 9.0% 13.4% 38.6%

WECC 0.5% 2.1% 14.1% 42.4%

United States 0.7% 4.7% 8.7% 22.8%

Data supporting Figure 2-3

Estimated advanced metering penetration by type of entity in 2006, 2008, 2010, and 2012 FERC Surveys 

Ownership

2006 FERC 

Survey

2008 FERC 

Survey

2010 FERC 

Survey

2012 FERC 

Survey

Cooperatives 3.8% 16.4% 24.7% 30.8%

Political Subdivision 0.1% 2.2% 20.3% 29.4%

Investor-owned

Utility 0.2% 2.7% 6.6% 25.0%

Municipal Entities 0.3% 4.9% 3.6% 12.4%

Federal and State 

Utility 0.2% 1.1% 0.7% 3.6%

Overall Average 0.7% 4.7% 8.7% 22.8%
108 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Data supporting Figure 2-4

Reported numbers of customers and communication methods for advanced metering by customer class

Customer Sector Internet Bills Display Unit

Communications Vehicles 

to Residential Customers 

(n = 17,365,353) 92% (n = 15,961,296) 7% (n = 1,297,960) 1% (n = 106,097)

Communications Vehicles 

to Nonresidential 

Customers (n = 1,587,655) 91% (n = 1,448,672) 9% (n = 136,754) 0% (n = 2,229)

Communications Vehicles 

to Other Customers (n = 

125,695) 93% (n = 116,922) 7% (n = 8,769) 0% (n = 4)

Demand Response

Data supporting Figure 3-1

Total reported potential peak reduction in the 2006 through 2012 FERC Surveys

FERC Survey Year

Total reported 

potential peak 

reduction (MW)

2006 FERC Survey 29,653

2008 FERC Survey 37,335

2010 FERC Survey 53,062

2012 FERC Survey 66,351

Data supporting Figure 3-2

Reported potential peak reduction by customer class in 2006, 2008, 2010, and 2012 FERC Surveys (MW)

FERC Survey Year

Commercial 

& Industrial Residential Wholesale Other Total

2006 FERC Survey 14,362 5,803 8,899 589 29,653

2008 FERC Survey 17,434 6,056 12,656 1,190 37,335

2010 FERC Survey 21,405 7,189 22,884 1,584 53,062

2012 FERC Survey 28,088 8,134 28,807 1,321 66,351
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 109

Data supporting Figure 3-3

Reported potential peak reduction by Independent System Operators and Regional Transmission Operators 

in 2010 and. 2012 (MW)

ISO/RTO CAISO ERCOT ISO-NE MISO NY-ISO PJM SPP

Program 

Type

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

Demand 

Bidding & 

Buy-Back 

120 0 0 0 91 202 210 0 0 37 2,635 2,252 0 0

Direct Load 

Control 

0 0 0 0 0 0 60 0 0 0 0 0 0 0

Emergency 

Demand 

Response 

0 0 237 420 2,092 1,029 230 2,149 972 197 7,295 0 0 0

Load as a 

Capacity 

Resource 

0 0 0 0 0 0 4,800 7,380 2,061 1,976 0 11,82

1

0 0

Nonspinning 

Reserves 

0 120 0 0 0 0 0 0 0 118 54 0 0

Other 0 0 0 0 0 0 0 258 37 0 0 1,385 1,514

Regulation 0 0 10 0 0 0 0 0 0 0 0 0 0 0

Spinning 

Reserves 

0 0 1,062 1,150 0 0 0 0 0 0 406 0 0 0

Data supporting Figure 3-4

Reported potential peak reduction by region and customer class for the 2010 and 2012 FERC Survey

Region Commercial & 

Industrial

Residential Wholesale Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 1,310 1,952 1,765 1,804 15 15 68 35 3,158 3,807

MRO 3,320 3,264 1,806 1,540 4,045 5,115 315 251 9,485 10,170

NPCC 1,490 719 90 34 4,649 2,972 0 0 6,228 3,725

RFC 5,267 7,476 1,139 2,100 9,199 14,677 259 128 15,864 24,381

SERC 6,451 8,672 798 1,046 1,733 2,881 172 210 9,154 12,809

SPP 1,404 2,667 79 220 1,502 1,456 141 126 3,126 4,469

TRE 72 4 123 66 1,312 1,572 3 0 1,510 1,642

WECC 2,062 3,287 1,369 1,307 430 120 626 571 4,487 5,284

Other 29 48 20 17 0 0 0 0 49 65

Total 21,405 28,088 7,189 8,134 22,884 28,807 1,584 1,321 53,062 66,351
110 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Data supporting Figure 3-5

Reported potential peak reduction in by type of program type and by customer class in 2012 FERC Survey

Type of Program

Commercial 

& Industrial Residential Wholesale Other Total

Critical Peak Pricing 261 54 6 0 321

Critical Peak Pricing with 

Load Control 129 2 0 15 147

Demand Bidding & BuyBack 139 0 3,927 0 4,066

Direct Load Control 1,638 6,940 666 534 9,777

Emergency Demand 

Response 494 110 3,734 0 4,339

Interruptible Load 14,268 45 685 649 15,647

Load as a Capacity 

Resource 2,649 77 16,600 0 19,327

Non-spinning Reserves 0 0 174 0 174

Other 105 40 1,076 54 1,276

Peak Time Rebate 58 1 0 0 59

Real-Time Pricing 1,868 6 0 0 1,874

Regulation 0 0 0 0 0

Spinning Reserves 40 0 1,150 0 1,190

System Peak Response 

Transmission Tariff 12 0 0 0 13

Time-of-Use 6,425 858 789 69 8,141

Total 28,088 8,134 28,807 1,321 66,351

Data supporting Figure 3-6 and 3-7

Reported potential and actual 2012 peak reduction by demand response resources by region

Region Potential Peak 

Reduction

Actual Peak Reduction

2012 2010 2012

FRCC 3,807 957 966

MRO 10,170 2,462 2,709

NPCC 3,725 2,497 3,151

RFC 24,381 2,051 3,651

SERC 12,809 3,086 3,520

SPP 4,469 1,466 1,863

TRE 1,642 422 1,470

WECC 5,284 2,667 2,870

Other 65 352 55

Total 66,351 15,980 20,256
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 111

Data supporting Figure 3-8

Estimated potential peak reduction by region and customer class in 2010 and 2012

Region Commercial & 

Industrial

Residential Wholesale Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 1,333 1,974 1,795 1,845 15 15 73 52 3,216 3,887

MRO 3,932 4,912 2,102 2,232 4,045 5,115 339 360 10,418 12,619

NPCC 1,954 739 98 91 4,649 2,972 173 8 6,875 3,811

RFC 6,334 7,882 1,427 2,373 9,199 14,677 371 424 17,331 25,356

SERC 7,005 9,331 1,575 1,419 1,733 2,881 208 301 10,521 13,932

SPP 1,572 2,915 80 236 1,502 1,456 154 133 3,307 4,740

TRE 113 262 134 143 1,312 1,572 53 5 1,612 1,981

WECC 2,344 3,208 1,581 1,254 430 120 626 639 4,981 5,221

Other 53 85 25 22 78 0 0 0 0 107

Total 24,640 31,310 8,817 9,616 22,884 28,807 1,998 1,921 58,339 71,654

Data supporting Figure 3.9

Estimated potential peak reduction by entity type and customer class in 2010 and 2012

Ownership Residential Commercial & 

Industrial

Other Retail Wholesale Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

Cooperative 

Entities 

2,836 2,623 3,726 2,320 855 657 1,420 1,231 8,837 6,830

Federal & State 17 42 1,104 4,694 50 48 920 1,910 2,091 6,694

InvestorOwned Utilities 5,433 6,180 17,634 20,331 827 850 0 116 23,894 27,476

Municipal 

Entities 

530 489 922 1,474 25 31 11 62 1,488 2,056

RTO/ISO 0 0 0 0 0 0 20,533 25,489 20,533 25,489

Retail Power 

Marketers 

0 65 961 0 241 0 0 0 1,202 65

Other 0 217 0 2,490 0 335 0 0 0 3,043

Total 8,816 9,616 24,347 31,310 1,998 1,921 22,884 28,807 58,045 71,654
112 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Data supporting Figure 3-10

Number of entities reporting interruptible/curtailable rates by region and type of entity in 2010 and 2012

Region Cooperative 

Entities

Federal and 

State

InvestorOwned UtilitiesMunicipal 

Entities

Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 3 3 0 0 3 3 4 3 0 0 10 9

MRO 26 18 0 0 6 9 13 9 2 5 47 41

NPCC 0 0 0 1 6 4 1 0 1 0 8 5

RFC 10 6 0 0 22 20 2 2 1 3 35 31

SERC 33 27 2 2 10 13 4 2 0 0 49 44

SPP 10 5 0 0 7 8 3 3 0 0 20 16

TRE 2 0 0 0 0 0 0 0 1 0 3 0

WECC 3 2 0 0 6 6 1 3 1 1 11 12

Total 87 61 2 3 60 63 28 22 6 9 183 158

Data supporting Figure 3-11

Reported number of customers enrolled in direct load control programs by region and type of entity in 2010 

and 2012

Region Cooperative 

Entities

Federal and 

State

Investor- Owned 

Utilities

Municipal 

Entities

Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 60,588 62,363 0 0 1,247,228 1,273,398 0 0 0 0 1,307,816 1,335,761

MRO 406,632 311,763 2,365 0 507,152 621,613 48,849 31,454 0 21,899 964,998 986,729

NPCC 6,261 645 0 0 39,634 48,630 32,660 2,739 0 0 78,555 52,014

RFC 294,278 105,646 0 0 1,203,367 1,470,728 2,270 2,050 0 7 1,499,915 1,578,431

SERC 421,625 285,054 0 0 347,748 525,778 29,577 3,000 0 0 798,950 813,832

SPP 13,119 8,220 0 0 35,479 87,331 0 0 1,869 48,598 97,420

TRE 0 0 0 0 85,000 0 171 11,500 85,171 11,500

WECC 4,602 5,457 0 0 821,610 885,822 6,872 10,362 0 1,526 833,084 903,167

Total 1,207,105

779,148 2,365 0 4,202,218 4,913,300 205,228 49,605 171 36,801 5,617,087 5,778,854

Estimated total number of customers

FRCC MRO NPCC RFC SERC SPP TRE WECC Other

9,184,587 8,120,487 20,962,205 35,925,110 35,739,376 6,825,542 10,255,206 29,250,286 817,392
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 113

Data supporting Figure 3-12

Number of entities reporting residential time-of-use rates by region and type of entity in 2010 and 2012

Region Cooperative 

Entities

Federal and 

State

Investor- Owned 

Utilities

Municipal 

Entities

Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 2 1 0 0 2 2 3 3 0 0 7 6

MRO 7 7 0 0 6 7 34 37 0 1 47 52

NPCC 3 1 1 0 7 11 3 3 3 0 17 15

RFC 9 9 0 0 9 13 1 2 0 0 19 24

SERC 12 13 1 1 8 9 0 1 0 0 21 24

SPP 3 2 0 0 2 3 0 0 0 0 5 5

TRE 1 0 0 0 0 0 0 0 0 1 1 1

WECC 16 15 0 0 4 2 4 6 3 1 27 24

Total 53 48 2 1 38 47 45 52 6 3 144 151

Data supporting Figure 3-13

Reported number of residential customers enrolled in time-of-use rate programs by region and type of entity

in 2010 and 2012

Region Cooperative 

Entities

Federal 

and State

Investor- Owned 

Utilities

Municipal 

Entities

Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 40 0 0 0 249 196 206 2,006 0 0 495 2,202

MRO 1,546 18,533 0 0 20,387 25,704 284 284 0 7,506 22,217 52,027

NPCC 63 36 0 0 148,706 168,248 10,152 2,073 148 0 159,069 170,357

RFC 1,521 1,420 0 0 138,910 953,035 0 2 0 0 140,431 954,457

SERC 3,289 3,230 5 5 33,301 46,986 0 124 0 0 36,595 50,345

SPP 15 46,302 0 0 1,452 2,717 0 0 0 0 1,467 49,019

TRE 8 0 0 0 0 0 0 0 0 4,000 8 4,000

WECC 237,187 12,154 0 0 498,477 529,428 2,388 4,249 0 232,201 738,052 778,032

Total 243,669 81,675 5 5 841,482 1,726,314 13,030 8,738 148 243,707 1,098,334 2,060,439
114 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Data supporting Figure 3-14

Number of entities reporting retail real-time pricing by region and type of entity in 2010 and 2012

Region Cooperative 

Entities

Federal and 

State

InvestorOwned UtilitiesMunicipal 

Entities

Other Total

2010 2012 2010 2012 2010 2012 2010 2012 2010 2012 2010 2012

FRCC 0 0 0 0 0 5 0 0 0 0 0 5

MRO 0 0 0 0 4 3 0 0 0 0 4 3

NPCC 1 0 0 0 2 8 0 0 0 0 3 8

RFC 0 0 0 2 7 5 0 0 0 0 7 7

SERC 0 0 1 0 3 4 0 0 1 0 5 4

SPP 1 0 0 0 4 0 0 0 0 0 5 0

TRE 0 0 0 0 0 0 0 0 0 0 0 0

WECC 0 0 0 0 1 1 0 0 0 0 1 1

Total 2 0 1 2 21 26 0 0 1 0 25 28
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 115

APPENDIX H: ADJUSTMENT METHODOLOGY FOR FERC-731

SURVEY

The following four flow charts summarize the estimation process used for the 2012 FERC 

Survey to assign estimated values for entities that did not respond to four key FERC Survey 

fields: total meters, advanced meters, total customers, and potential peak load reduction. The 

2012 estimation process utilized data from the initial 2011 EIA-861 Survey, along with 

responses from the 2010 FERC Survey. In cases when an imputation could not be used, the 

universe-level estimates are not accounting for those cases.

1. Missing from 2012 FERC Survey: Total Meters153

Yes

 No

2. Missing from 2012 FERC Survey: Advanced Meters

 

153 Total meters for the commercial and industrial sectors did not have a strong enough correlation with total 

customers to justify direct imputation of customers from either the EIA-861 or 2010 FERC Survey, when total 

meters were not provided by the respondent.

Commercial & 

Industrial

Residential

Other

2011 EIA861

Responder?

Impute by applying the respondent’s 

customer-level growth rate from 2010 

FERC Survey to the 2011 EIA-861 

Survey. If Other, impute with direct 

substitution from the 2010 FERC 

Survey.

If Residential, do a 1:1 substitution using 

the number of residential customers 

reported in the 2011 EIA-861 Survey. 

Otherwise, do not impute. 

Commercial & 

Industrial

Residential

Other

Direct substitution of 2011 EIA861 reported AMI meters, 

according to procedure detailed 

in Appendix D 

2010 FERC

Responder?

Yes

No If a 2010 FERC Survey 

Responder, impute by applying 

the 2010 to 2012 class-level 

growth rate, according to the 

2010 Assessment of Demand 

Response and Advanced 

Metering Appendix H. 

Otherwise, do not impute.
116 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

3. Missing from 2012 FERC Survey: Potential Peak Reduction

Yes

 No

4. Missing from 2012 FERC Survey: Total Customers

Self-Selection Assessment Subsample

The FERC Staff determined that the 2012 FERC Survey, to adhere with its Congressional 

directive, should collect or estimate information on all entities that provide electric power 

and demand response to customers in the U.S. However, the FERC Survey is voluntary, and 

essentially a census of respondents to the EIA-861 Survey, with the addition of Regional 

Transmission Operators (RTOs), Independent System Operators (ISOs), and curtailment 

service providers. As such, there is inherent risk for self-selection bias; for example, some 

entities may be more likely to respond to the FERC Survey if they have already deployed 

advanced meters or demand response programs, and these are key measures of the survey. 

Since the propensity to respond may be related to key measures in the FERC Survey, OMB 

directed the Commission to assess the potential for self-selection bias in the FERC Survey, as 

compared to traditional statistical sampling methods. As in previous survey years, the FERC 

staff prepared a “bias assessment sample,” or a statistical subsample from the full survey 

population. This section of the report describes the “bias assessment sample” design, and 

compares the estimates derived from the full dataset with the corresponding estimates 

produced from the bias assessment sample. If the corresponding estimates are within an 

acceptable margin of error, it supports the hypothesis that a census of the target population 

achieves as reliable estimates as a traditional statistical sample. However, significant 

Commercial & 

Industrial

Residential

Other

Do a 1:1 substitution using total MW 

peak load reduction potential reported in 

the 2011 EIA-861 Survey

Regression-based imputation using class 

average growth from 2010 FERC Survey 

to 2012 FERC Survey, applied to 2010 

FERC data. If not a 2010 FERC Survey 

responder, do not impute.

2011 EIA

Responder?

Commercial & 

Industrial

Residential

Other

Regression-based imputation using class 

average growth from 2010 FERC Survey 

to 2011 EIA-861 Survey, applied to 

2010 FERC data
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 117

differences in the corresponding estimates would indicate a significant risk for self-selection 

bias in the FERC Survey.

Assessment of Past Designs

The designs for 2006 and 2008 bias assessment samples utilize known relationships of 

advanced metering penetration with region, utility type, and utility size. Although 

curtailment service providers and generation & transmission entities do not provide retail 

electricity and have no advanced meters associated with them, they are unique and important 

respondents to the survey, especially with respect to demand response data, so selecting these 

respondents into the sample with certainty ensures they would be accounted for. The 2010 

bias assessment sample was very similar to those constructed in 2006 and 2008, except for 

utilizing ratio estimation rather than simple random sampling. This change improved the 

sampling efficiency, but added complexity to the sample construction process. 

2012 Self-Selection Bias Assessment Design

DNV KEMA maintained the same basic design used in 2006, 2008, and 2010, with some 

modifications. Key features of the design are as follows:

 Entities were stratified by state, ownership type, and size category (small, medium, 

large, or other). In 2010, entities were stratified by NERC region rather than state.

 Within strata, units were selected either with certainty or probability proportionate to 

size (PPS). Entities were selected with certainty if they fell in the “large” size 

category or they did not have a number of customers served for the state listed in the 

EIA-861 Survey. Entities were selected PPS within the strata defined as above, with 

proportional allocation of a target sample size of 750 among the entities in the various 

strata.

 The total sample size obtained was 797 EIA utility ID/state code combinations. Some 

entities were included in the sample for more than one state, so the number of unique 

EIA utility IDs was 727.

The switch to using state instead of NERC region for the geographic stratification component 

was based on the addition of state-level estimates in the 2010 FERC Survey, as well as the 

availability of state-level customer data in the EIA-861 Survey, but not by NERC. This 

modification resulted in more strata, and fewer sample cases per strata, but better state-level 

coverage overall. 

The 2012 bias assessment sample design also selects more entities with certainty; all large 

utilities and all entities without a listed number of customers served in a state were included 

in the sample. Large utilities were selected with certainty because they tend to have a 

disproportionally large contribution towards total advanced metering and demand response 

estimates. Entities without an assigned number of customers were included with certainty 

because without a measure of size to use in the sample selection, there was no other way to 

include them without using a different sample design; this also helped minimize overall 

sampling complexity and include respondents such as curtailment service providers.
118 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

No special follow-up measures beyond that of the full mail-out sample was used in 2012. All 

entities, whether in the sample or not, were subject to a follow-up based on their expected 

contribution in the survey population. 

Survey Response Rates

Entity Type Advanced 

Metering 

Response 

Rate

DR 

Response 

Rate

Cooperatively Owned Utility 53% 25%

Curtailment Service Provider 24% 24%

Federal Utility 63% 13%

Investor-Owned Utility 78% 64%

Municipal Power Agency 58% 0%

Municipally Owned Utility 70% 19%

Political Subdivision 44% 12%

Retail Power Marketer 20% 4%

State Utility 35% 12%

Generation and 

Transmission

78% 0%

Wholesale Power Marketer 19% 0%

Self-Selection Bias Assessment

The analysis of the FERC Survey subsample is geared towards determining whether a census 

sample is necessary for determining reliable results for the key advanced metering and 

demand response measures collected in the FERC Survey. The subsample versus full-sample 

tabulated results for the following tables are given below:

 Estimated Advanced Metering Penetration by NERC Region and Entity Type

 Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector

Both tables use extrapolations to account for the full survey universe. The full-sample table 

is taken directly from Appendix G and the subsample extrapolation uses sampling weights 

with a ratio adjustment to account for nonresponse.
2012 Assessment of Demand Response and Advanced Metering Federal Energy Regulatory Commission 119

Estimated Advanced Metering Penetration by NERC Region and Entity Type - FullSample Analysis

NERC 

Region

Cooperatively 

Owned Utilities

Political 

Subdivisions

InvestorOwned

Utilities

Municipally 

Owned 

Utilities

Federal 

and State 

Utilities

Overall

FRCC 14% 0% 38% 14% 0% 32%

MRO 33% 4% 10% 4% 45% 15%

NPCC 20% 0% 7% 5% 0% 5%

RFC 36% 0% 10% 5% 1% 10%

SERC 36% 0% 19% 11% 1% 22%

SPP 29% 5% 14% 2% 91% 15%

TRE 17% 0% 72% 24% 0% 39%

WECC 26% 36% 48% 18% 23% 42%

Other 0% 0% 0% 5% 0% 2%

Overall 31% 29% 25% 12% 4% 23%

Estimated Advanced Metering Penetration by NERC Region and Entity Type -

Subsample Analysis

NERC 

Region

Cooperatively 

Owned Utilities

Political 

Subdivisions

InvestorOwned

Utilities

Municipally 

Owned 

Utilities

Federal 

and 

State 

Utilities

Overall

FRCC 30% 0% 38% 11% 0% 33%

MRO 44% 9% 18% 0% 78% 18%

NPCC 48% 0% 6% 0% 0% 6%

RFC 25% 0% 9% 1% 1% 9%

SERC 58% 0% 0% 21% 2% 16%

SPP 37% 0% 15% 0% 91% 17%

TRE 28% 0% 74% 8% 0% 58%

WECC 16% 35% 61% 46% 100% 57%

Other 0% 0% 3% 0% 0% 3%

Overall 46% 33% 23% 24% 12% 26%

The subsample analysis results for the chosen advanced metering table shows that overall, 

the subsample performed well, with only a 3 percent difference in overall advanced metering 

penetration in the U.S. and was only 2 percentage points different for investor-owned

utilities. Similarly, the results are extremely comparable for the NERC region marginal 

totals. The penetration estimate for RFC, for example was 2 percentage points different for 

the full sample and the subsample, and was even closer for NPCC. However, it is clear that 

abandoning the census in favor for a sample would lead to self-selection bias for cooperatives 

and municipally owned utilities, and for certain regions, as suggested by moderate pairwise 

differences for MRO.
120 Federal Energy Regulatory Commission 2012 Assessment of Demand Response and Advanced Metering 

Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector – Full Sample

Region

Commercial 

& Industrial Residential Other Total

FRCC 1,974 1,845 52 3,872

MRO 4,912 2,232 360 7,504

NPCC 739 91 8 839

RFC 7,882 2,373 424 10,680

SERC 9,331 1,419 301 11,051

SPP 2,915 236 133 3,284

TRE 262 143 5 409

WECC 3,208 1,254 639 5,101

Other 85 22 0 107

Total 31,310 9,616 1,921 42,847

Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector - Subsample

Region

Commercial 

& Industrial Residential Other Total

FRCC 1,952 1,804 35 3,792

MRO 3,754 1,662 94 5,511

NPCC 733 23 0 756

RFC 11,642 3,481 128 15,251

SERC 10,251 1,830 128 12,209

SPP 4,834 414 556 5,804

TRE 29 737 0 766

WECC 3,658 1,565 2,430 7,653

Other 47 19 0 65

Total 36,900 11,535 3,371 51,807

The analysis results for demand response suggest that utilizing a statistical sample instead of 

a census would lead to biased results. Unlike the advanced metering assessment, which 

shows above that reliable results are achievable through aggregating the data by one 

categorical variable, the demand response results show that most of the tabulations have 

pairwise differences of 20 percent or more. It is therefore advisable to continue using a 

census of the survey universe rather than using a statistical sample to maintain reliable survey 

estimates for demand response.