2010 

Assessment of 

Demand Response and Advanced Metering 

Staff Report 

Federal Energy Regulatory Commission 

February 2011 

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 

Dean Wight, Team Lead 

Caroline Daly 

David Kathan 

Michael P. Lee 

Kamaria Martin 

Pamela Silberstein 

 Michael Tita 

Rebecca Vertes 

Z, INC. Team 

Bryan Templeton (Z, INC.) 

Valerie Richardson (KEMA) 

Will Gifford (KEMA) 

Christopher Elsner (Z, INC.) 

Matthew S. Pettit (KEMA) 

Geoff Barker (KEMA) 

Ron Chebra (KEMA) 
TABLE OF CONTENTS 

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

Results of the 2010 Advanced Metering and Demand Response Survey............................. 1 

Demand Response Developments and Barriers.................................................................... 1 

Chapter 1. Introduction ............................................................................................................ 2 

Prior Reports in This Series .................................................................................................. 2

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

Demand Response and Advanced Metering Survey............................................................. 3 

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

Regions in This Report ......................................................................................................... 4 

Chapter 2. Advanced Metering Infrastructure ......................................................................... 6 

Definition of Advanced Metering......................................................................................... 6 

Summary of Advanced Metering Penetration Results.......................................................... 7 

2010 FERC Survey Design................................................................................................7 

Analysis Approach.............................................................................................................7 

Survey Findings .................................................................................................................7 

Uses of Advanced Metering.............................................................................................13 

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

American Recovery and Reinvestment Act Grant Programs ..........................................14 

Federal Government-Led Activities to Support AMI Structures and Utilization............15 

Noteworthy State Activities.............................................................................................17 

Technological Issues in Advanced Meters ......................................................................19 

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

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

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

Analysis Approach...........................................................................................................22 

Summary of Survey Findings ..........................................................................................23 

Demand Response Activities at the FERC, Barriers to Demand Response, and Staff 

Recommendations............................................................................................................... 40 

National Action Plan on Demand Response....................................................................40 

Commission Rulemakings on Demand Response Issues.................................................41 

Demand Response and Smart Grid Developments..........................................................42 

Other Demand Response Orders and Activities ..............................................................43 

Further Barriers to Demand Response.............................................................................46 

Staff Recommendations...................................................................................................50 

Appendix A: Section 1252 of the Energy Policy Act of 2005............................................... 51 

Appendix B: Abbreviated Names and Acronyms Used in This Report ................................ 54 

Appendix C: Survey Glossary ............................................................................................... 55 

Appendix D: 2010 FERC Survey Method............................................................................. 63 

Appendix E: FERC Survey Respondents .............................................................................. 72 

Appendix F: Demand Response Programs and Services at Responding Entities.................. 88 

Appendix G: Data for Figures in the Report.......................................................................... 96 

Appendix H: Adjustment Methodology for 2010 FERC Survey......................................... 104 

2010 Assessment of Demand Response and Advanced Metering      Federal Energy Regulatory Commission   i
LIST OF TABLES 

Table 3.1. Estimated advanced metering penetration by region for residential and 

nonresidential customers......................................................................................................... 10 

Table 3.2. Estimated penetration of advanced metering by state in 2006, 2008 and 2010 

FERC Surveys......................................................................................................................... 11 

Table 4.1. Demand response program classifications in the 2010 FERC Survey and changes 

from previous surveys............................................................................................................. 22 

Table 4.2. Reported potential peak load reduction in megawatts by program category and 

state ......................................................................................................................................... 38 

Table 4.3. Reported plans for new demand response programs and time-based rates/tariffs 39 

Table D1. Survey population of the 2010 and 2008 FERC Surveys ..................................... 65 

Table D2. Assigned demand response program types for RTO/ISO programs..................... 70 

Table H1. Sources of data used to impute missing 2010 FERC survey data....................... 104 

Table H2. Subsample response rates ................................................................................... 109 

LIST OF FIGURES 

Figure 2.1. NERC Regions ...................................................................................................... 5 

Figure 3.1. Estimated advanced metering penetration nationwide in 2006, 2008 and 2010 

FERC Surveys........................................................................................................................... 8 

Figure 3.2. Estimated advanced metering penetration by region in 2006, 2008 and 2010 

FERC Surveys........................................................................................................................... 9 

Figure 3.3. Estimated penetration of advanced metering by type of entity in 2006, 2008 and 

2010 FERC Surveys................................................................................................................ 12 

Figure 3.4. Reported numbers of customers and communication methods for advanced 

metering by customer class..................................................................................................... 13 

Figure 4.1. Reported number of customers enrolled in direct load control programs by region 

and type of entity .................................................................................................................... 25 

Figure 4.2. Number of entities reporting interruptible/curtailable rates by region and type of 

entity ....................................................................................................................................... 26 

Figure 4.3. Number of entities reporting residential Time-of-Use rates by region and type of 

entity ....................................................................................................................................... 27 

Figure 4.4. Reported number of residential customers enrolled in Time-of-Use rates by 

region and entity type.............................................................................................................. 28 

Figure 4.5. Number of entities reporting retail real-time pricing by region and entity type . 29 

Figure 4.6. Total reported potential peak load reduction in 2006, 2008 and 2010 FERC 

Surveys.................................................................................................................................... 29 

Figure 4.7. Reported potential peak load reduction by customer class in 2006, 2008 and 2010 

FERC Surveys......................................................................................................................... 31 

Figure 4.8. Reported potential peak load reduction by region and customer class ............... 32 

Figure 4.9. Reported potential peak load reduction by type of program and by customer class

................................................................................................................................................. 33 

Figure 4.10. Net Annual U.S. Electrical Generation, 2005 through 2009............................. 34 

Figure 4.11. Reported potential and actual 2010 peak load reductions................................. 35 

ii Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering      Federal Energy Regulatory Commission   iii

Figure 4.12. Estimated potential peak load reduction by demand response resources by 

region and customer class ....................................................................................................... 36 

Figure 4.13. Estimated potential peak load reduction by demand response resources by type 

of entity and customer class.................................................................................................... 37 

EXECUTIVE SUMMARY

Results of the 2010 Advanced Metering and Demand Response 

Survey 

Advanced metering penetration and potential peak load reductions from electric power 

demand response have increased significantly since 2008. 

The Federal Energy Regulatory Commission’s 2010 Demand Response and Advanced 

Metering Survey (2010 FERC Survey, covering calendar year 2009) indicates that advanced 

metering penetration (i.e., the fraction of all installed meters that are advanced meters) 

reached approximately 8.7 percent in the United States, compared to approximately 4.7 

percent in the 2008 FERC Survey (covering calendar year 2007). The upper Midwest, West 

and Texas have advanced meter penetrations exceeding 13 percent. As in previous surveys, 

electric cooperatives have the largest penetration, nearly 25 percent, among categories of 

organizations. 

In response to the 2010 FERC Survey, more than 500 entities reported offering demand 

response programs in the United States. The potential demand response resource 

contribution from all U.S. demand response programs is estimated to be more than 58,000 

megawatts (MW), or about 7.6 percent of U.S. peak demand. This is an increase of about 

17,000 MW from the 2008 FERC Survey. The regions with the largest estimated demand 

response resources are the Midwest-to-Mid-Atlantic region, and also the Upper Midwest and 

the Southeast.

Demand Response Developments and Barriers 

Demand response is facilitated through programs undertaken by electric utilities and demand 

response providers as well as through state and federal programs. For example, federal 

funding for advanced meters became available under the American Recovery and 

Reinvestment Act, and the Federal Energy Regulatory Commission issued the National 

Action Plan on Demand Response in June 2010—a plan which sets out actions to achieve the 

demand response potential in the United States. 

Activities to address regulatory barriers to demand response include state policy changes to 

reduce the financial effects of demand response on utilities, efforts to improve and 

standardize methods for measuring baseline electric use, the revision of wholesale market 

rules to remove barriers to participation by demand response resources, industry efforts to 

assess the cost-effectiveness of demand response, the FERC-NARUC smart response 

collaborative, and the development of interoperability standards for smart meters. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 1
2 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

CHAPTER 1. INTRODUCTION

The Energy Policy Act of 2005 (EPAct 2005) requires the FERC to prepare pertinent data 

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 consumer. 

EPAct 2005 expressly requires the Commission to quantify 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. 

Prior Reports in This Series 

In August 2006 Commission staff published the first in this series of reports, Assessment of 

Demand Response and Advanced Metering.1

 This comprehensive report was based on a 

first-of-its-kind survey of demand response and advanced metering. In 2007, the 

Commission staff published a second report,2 emphasizing results, industry activities, and 

regulatory actions taken since the previous report. The 2007 report noted that FERC staff 

would conduct, analyze, and report on the results of a comprehensive nationwide survey 

every other year, with intervening years’ reports consisting of updates based on publicly 

available information and discussions with market participants and industry experts. 

Staggering the reporting in this way allows FERC staff to provide a more informed analysis 

in each bi-yearly survey-based report while still reporting on demand response and advanced 

meters annually. A second survey (referred to here as the 2008 FERC Survey) was 

conducted in 2008 and gathered data for calendar year 2007. The results were reported in the 

2008 Assessment of Demand Response and Advanced Metering.3

 In September 2009 staff 

published the fourth report, based like the 2007 report on public information and 

 

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.asp. 2

 FERC, Assessment of Demand Response & Advanced Metering: Staff Report, September 2007, available at

http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. 3

 FERC, Assessment of Demand Response & Advanced Metering: Staff Report, December 2008, available at

http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 3

conversations with industry participants, and also drawing upon FERC’s National 

Assessment of Demand Response Potential4 published in June 2009. 

Preparation of This Year’s Report 

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

of which was the preparation and release of the 2010 Demand Response and Advanced 

Metering Survey (2010 FERC Survey), and analysis of the survey responses. As with 

previous surveys, the 2010 FERC Survey gathered data for the preceding calendar year, 

2009. 

Commission staff also reviewed the literature and regulatory developments in advanced 

metering and demand response programs including time-based rates since the publication of 

the 2009 report. 

Demand Response and Advanced Metering Survey 

The 2010 FERC Survey was conducted in the first half of 2010 with the help of Z, INC. and 

KEMA. The survey requested (a) general information about the respondent, including 

contact information; (b) the number of advanced meters and the number of total meters; (c) 

existing demand response and time-based rate programs, including their current level of 

resource contributions, and (d) near and medium-term plans for demand response programs. 

The 2010 FERC Survey combined the separate Advanced Metering Infrastructure (AMI) and 

Demand Response surveys of previous years into one. 

Responses to the survey were requested from 3,454 entities in all 50 states and representing 

all aspects of the electricity delivery industry: investor-owned utilities, municipal utilities, 

rural electric cooperatives, power marketers, state and federal agencies, and demand response 

providers.5 Later in the process it was determined that 96 of these entities were either out of 

business or not in a relevant business. 

Of the remaining 3,358 entities, 1,755 responded to the 2010 FERC Survey (a response rate 

over 52 percent). These 1,755 entities serve 112 million electric customers, which is over 77 

percent of the 145 million customers served nationally. For comparison, the 2008 FERC 

Demand Response Survey response rate was 60 percent, and the 2008 FERC AMI Survey 

response was 55 percent. 

Information gathered through the survey serves as the basis for this report’s data on the 

penetration6

 of advanced metering, the information on existing demand response and timebased rate programs, and demand response resource contributions. In addition, the results of 

the 2008 and 2006 FERC Surveys provide a time series of data on advanced metering 

penetration and the level of demand response capability in the United States. 

 

4

 FERC, A National Assessment of Demand Response Potential: Staff Report, June 2009; available at 

http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential/assessment.asp. 5

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

respondents to the survey. 

6

 Penetration, for the purposes of this report, refers to the ratio of advanced meters to all installed meters. 
Report Organization 

The report begins with this Introduction, which describes the report structure. The 

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

Advanced Metering Infrastructure presents the survey results on the penetration of 

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

This chapter also discusses developments and issues in the deployment and adoption of 

advanced metering. 

Demand Response presents the survey results on demand response programs, including 

time-based rate programs, and gives the regional and national distribution of these programs, 

as measured by the number of enrolled customers reported in the 2010 FERC Survey. This 

chapter also uses the 2010 FERC Survey data to estimate the level of demand response in the 

United States. The chapter then reviews demand response developments at the national and 

state level, and summarizes and analyzes barriers to demand response. 

Eight appendices provide reference material and additional detail on the 2010 FERC Survey 

and survey respondents. Appendix A lists 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 2010 FERC Survey. Appendix D presents 

additional detail on the 2010 FERC Survey and documents survey response rates. Appendix 

E lists the respondents to the 2010 FERC Survey. Appendix F lists the entities that indicate 

that they operate demand response programs in their responses to the 2010 FERC Survey. 

Appendix G provides data tables for each of the figures in this report. Appendix H explains 

the methodology used to estimate values for nonrespondents. 

Regions in This Report 

The North American Electric Reliability Council (NERC) is an international nonprofit 

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

works with eight regional entities, each composed of members from all segments of the 

electric industry. The 2010 FERC Survey comprises the U.S. domestic area of the NERC 

regional entities, and uses the 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) 

In this report, Hawaii and Alaska are not included in most regional data listings, but are 

shown in state-by-state data. The map in Figure 2.1 shows the boundaries of these regional 

entities. 

4 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Figure 2.1. 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. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 5
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 on advanced metering penetration is based on the 2010 FERC 

Survey with some comparisons to 2006 and 2008 FERC survey information to demonstrate 

trends in advanced metering placement on a regional basis, by type of entity, and by 

customer type. 

The information in the chapter provides summary-level data on penetration rates of advanced 

metering survey results. A database of survey responses is available online at 

http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-adv-metering.asp

This chapter has three sections: 

 Definition of Advanced Metering 

 Summary of Advanced Metering penetration 

 Developments and Issues in Advanced Metering 

Definition of Advanced Metering 

For the 2010 FERC Survey, FERC staff modified the definition for advanced meters to be 

consistent with that used by the Energy Information Administration (EIA). The definition of 

advanced meters used in the survey and this report is: 

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. 

The modified definition resulted in changes in advanced meter counts by some entities 

responding to the 2010 Survey compared to the 2008 and 2006 FERC Surveys. In follow-up 

calls, staff learned that three respondents reclassified meters previously reported as advanced 

meters to non-advanced meters because of the new requirement of “providing customers with 

usage data at least once daily.” For this reason the utility serving Jacksonville, FL, (JEA) 

reduced its advanced meter count from nearly 400,000 in the 2008 FERC Survey to zero in 

the 2010 FERC Survey. 

6 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Summary of Advanced Metering Penetration Results 

This section describes the design of the advanced metering portion of the 2010 FERC 

Survey, the approach used to analyze the results, and summary findings of the survey and 

analysis. 

2010 FERC Survey Design 

The 2010 FERC Survey contained AMI questions nearly identical to those in the 2006 and 

2008 FERC AMI Surveys, with these exceptions: (1) the 2010 FERC Survey’s definition for 

advanced meters was changed from the definition used in 2008; and (2) the 2010 FERC 

Survey asked only for the methods of communicating AMI data to customers (while previous 

surveys asked how the advanced meters were being used, e.g., for enhanced customer 

service, outage detection). FERC staff made these changes to be consistent with EIA, as 

discussed above, and to simplify the voluntary survey and encourage responses. 

Analysis Approach 

The findings presented here include estimated values that are extrapolations of survey results 

to states, regions, the United States, and types of entity. Appendix H provides a detailed 

explanation of the analysis and extrapolation approach. Also presented are the reported (not 

extrapolated) numbers of customers and communications methods for advanced metering.

In this and following chapters, figures and tables with results compiled directly from data 

submitted by survey respondents without estimation of results for those not reporting are 

labeled “Reported” or “Reporting.” Figures and tables with results that include both data 

submitted by survey respondents and estimation of results for those not reporting, based on 

survey and other information, are labeled “Estimated.” 

Survey Findings 

The 1,755 responding entities report serving 112 million electric customers, which is over 77 

percent of the 145 million customers served nationally. The response rate for the 2010 FERC 

Survey on an entity basis was 52 percent, slightly less than the previous two surveys. Small 

entities (mostly municipally owned utilities) had a response rate of about 47 percent. For 

large and medium size entities, the response rates were about 84 percent and 70 percent, 

respectively. 

The survey results present robust growth in advanced metering nationally. As indicated in 

Figure 3.1, estimated advanced metering penetration increased to 8.7 percent in 2009 versus 

4.7 percent in 2007, an 85 percent increase in penetration in two years. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 7
Figure 3.1. Estimated advanced metering penetration nationwide in 2006, 2008 and 2010 

FERC Surveys 

0%

2%

4%

6%

8%

10%

2006 Survey 2008 Survey 2010 Survey

Penetration

Figure 3.2 provides the estimated penetration of advanced meters by NERC region. MRO, 

WECC and TRE regions have penetrations exceeding 13 percent, although penetration of 

advanced meters remains below 20 percent in all regions. Growth was especially rapid in 

WECC and MRO where penetrations increased six-fold and four-fold, respectively, from 

2007 to 2009. The increase in WECC may reflect the rollout of advanced meters in 

California where the IOUs have collective targets of over 15 million advanced meters by 

2012. The increase in TRE can be attributed to the regulatory environment in this active 

competitive retail access state. Advanced metering penetration declined only in FRCC, 

where JEA, the Jacksonville utility, reclassified nearly 400,000 meters from advanced to 

non-advanced because of the change in the survey’s advanced metering definition. 

8 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Figure 3.2. Estimated advanced metering penetration by region in 2006, 2008 and 2010 

FERC Surveys 

13.4%

8.9%

8.0%

6.7%

2.1%

1.2%

15.3%

14.1%

5.0%

0.7%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

Region

Penetration

2006 Survey 2008 Survey 2010 Survey

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%

MRO WECC TRE SPP SERC RFC FRCC Hawaii ASCC NPCC

The number of advanced meters for residential customers grew notably in WECC, MRO, 

TRE and SPP. The completion of pilot programs and early ramp-up efforts is giving way to 

a “production mode” with mass market characteristics. Nationally, advanced metering 

penetration for residential customers increased to nearly 9 percent, and to 7 percent for 

nonresidential customers. Table 3.1 provides the estimated penetration of advanced meters 

by customer class reported in the 2006, 2008 and 2010 FERC Surveys.

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 9
10 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Table 3.1. Estimated advanced metering penetration by region for residential and 

nonresidential customers 

Advanced Metering Penetration (percent) 

All Meters Residential Meters Nonresidential Meters

 FERC Survey 

Region 

2006 2008 2010 2006 2008 2010 2006 2008 2010 

MRO 0.6 3.7 15.3 0.5 4.0 15.8 1.1 2.2 11.9

WECC 0.5 2.1 14.1 0.3 2.1 14.9 1.5 2.0 9.1

TRE 0.7 9.0 13.4 0.7 8.5 13.4 0.7 12.4 13.1

SPP 3.0 5.8 8.9 3.3 6.1 9.2 1.8 4.2 7.5

SERC 1.2 5.8 8.0 1.3 6.1 8.3 1.0 3.2 5.9

RFC 0.4 5.1 6.7 0.3 5.0 6.7 0.8 6.1 6.9

FRCC 0.1 10.4 5.0 0.1 10.8 5.2 0.5 7.8 3.3

Hawaii 0.0 1.6 2.1 0.0 1.6 2.2 0.1 1.6 1.8

ASCC 0.0 0.0 1.2 0.0 0.0 1.3 0.0 0.0 0.6

NPCC 0.1 0.3 0.7 0.1 0.3 0.6 0.8 1.0 1.1

United States 0.7 4.7 8.7 0.6 4.7 8.9 1.0 4.2 7.0

Table 3.2 provides estimated penetration rates of advanced meters by state. States with the 

highest growth are located primarily in the West, with Arizona, Oregon, and Idaho having 

advanced meter penetration rates above 25 percent. The increase in advanced metering 

penetration in Arizona is primarily due to movement by Arizona Public Service Company 

toward a planned target of more than 800,000 advanced meters over the next five years, as 

well as Salt River Project’s reported 450,000 advanced meters, with a goal of one million by 

2013.7

 In Oregon, Portland General Electric is moving forward with its plan to have over 

850,000 customers on advanced meters by the end of 2010. Idaho Power projects 450,000 

advanced meters by 2011. Pennsylvania and Wisconsin have penetrations above 20 percent. 

Wisconsin has the highest penetration in the MRO region. Pennsylvania has the highest 

penetration in RFC, mostly because of large numbers of advanced meters already reported in 

the 2008 FERC Survey. Missouri and South Carolina, both in SERC, also report robust 

growth in penetration. 

 

7

 Salt River Project, 2010 Annual Report, available at 

http://www.srpnet.com/about/financial/2010annualreport/power.aspx. 
Table 3.2. Estimated penetration of advanced metering by state in 2006, 2008 and 2010 

FERC Surveys 

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

AZ 5,521 2,783,083 0.2% 96,727 2,810,224 3.4% 847,177 2,915,712 29.1%

OR 2,960 1,821,710 0.2% 39,797 1,890,423 2.1% 478,897 1,896,717 25.2%

ID 29,062 739,199 3.9% 105,933 769,963 13.8% 198,370 803,576 24.7%

PA 18,200 6,053,110 0.3% 1,443,285 6,036,064 23.9% 1,493,201 6,152,994 24.3%

WI 19,882 2,983,075 0.7% 117,577 3,039,830 3.9% 757,688 3,418,498 22.2%

CA 40,153 14,253,873 0.3% 170,896 14,595,958 1.2% 2,475,896 14,837,434 16.7%

MO 8,986 3,087,821 0.3% 204,498 3,098,055 6.6% 506,416 3,072,893 16.5%

SC 19,655 2,007,339 1.0% 114,619 2,373,047 4.8% 312,894 2,445,044 12.8%

GA 73,312 4,404,447 1.7% 342,772 4,537,717 7.6% 514,403 4,401,623 11.7%

TX 28,200 10,195,134 0.3% 868,204 10,870,895 8.0% 1,284,179 11,013,153 11.7%

KY 27,501 2,225,485 1.2% 105,460 2,161,142 4.9% 273,663 2,523,833 10.8%

OK 60,273 2,024,592 3.0% 161,795 1,875,325 8.6% 215,462 2,028,522 10.6%

ND 29 367,776 0.0% 33,336 375,473 8.9% 42,875 445,164 9.6%

SD 7 484,728 0.0% 41,191 475,477 8.7% 41,122 432,632 9.5%

TN 426 3,165,211 0.0% 60,385 3,160,551 1.9% 252,341 2,761,758 9.1%

VT 1 331,161 0.0% 20,755 375,202 5.5% 31,293 379,139 8.3%

NC 29,411 4,681,178 0.6% 143,093 4,771,479 3.0% 385,884 4,847,336 8.0%

MS 82 1,015,493 0.0% 3 1,454,275 0.0% 97,344 1,511,958 6.4%

MI 31,254 4,877,345 0.6% 73,948 5,311,570 1.4% 269,933 4,865,396 5.5%

NM 1 875,393 0.0% 20,776 904,861 2.3% 54,250 1,015,058 5.3%

AL 89,702 2,738,519 3.3% 139,972 2,774,764 5.0% 127,092 2,467,741 5.2%

FL 8,479 9,679,565 0.1% 765,406 9,591,363 8.0% 490,150 9,644,617 5.1%

VA 5,016 3,412,011 0.1% 6,448 3,965,584 0.2% 175478 3,663,525 4.8%

WY 0 272,033 0.0% 12,268 318,282 3.9% 14,437 303,272 4.8%

MT 162 529,135 0.0% 8,979 549,136 1.6% 27,470 577,745 4.8%

IL 43,043 5,510,470 0.8% 112,410 5,701,533 2.0% 286,568 6,099,158 4.7%

CO 39,274 2,263,873 1.7% 39,873 2,246,184 1.8% 111,330 2,403,001 4.6%

OH 1,958 6,307,050 0.0% 28,042 5,544,353 0.5% 289,970 6,290,618 4.6%

IN 13,137 3,217,359 0.4% 61,551 3,115,205 2.0% 148,129 3,355,485 4.4%

KS 18,913 1,430,953 1.3% 61,423 1,426,832 4.3% 62,626 1,467,092 4.3%

MN 11,780 2,537,414 0.5% 37,071 2,542,113 1.5% 108,232 2,602,360 4.2%

WA 477 3,061,233 0.0% 69,377 2,987,355 2.3% 128,857 3,298,781 3.9%

IA 110 1,591,985 0.0% 46,407 1,714,774 2.7% 58,092 1,576,475 3.7%

ME 716 773,164 0.1% 426 780,748 0.1% 20,315 796,691 2.5%

LA 44 1,037,355 0.0% 44,103 2,186,249 2.0% 53,848 2,245,066 2.4%

DE 16 421,331 0.0% 0 438,020 0.0% 10,433 455,926 2.3%

HI 45 465,314 0.0% 6,550 405,228 1.6% 8,713 411,232 2.1%

NV 17 1,193,873 0.0% 10,835 1,292,331 0.8% 24,378 1,255,950 1.9%

NE 1,520 937,148 0.2% 8,630 970,774 0.9% 19,290 999,353 1.9%

UT 1 1,036,605 0.0% 37 1,056,718 0.0% 20,046 1,083,069 1.9%

AK 6 305,949 0.0% 18 315,419 0.0% 3,835 316,289 1.2%

AR 75,118 1,494,383 5.0% 168,466 1,488,124 11.3% 14,578 1,529,065 1.0%

WV 17 1,234,035 0.0% 10 1,183,513 0.0% 7,039 1,033,802 0.7%

MA 6,940 3,244,778 0.2% 3,907 3,077,679 0.1% 20,831 3,150,098 0.7%

NJ 25,222 3,884,140 0.6% 9,866 3,900,716 0.3% 25,744 3,953,683 0.7%

RI 398 480,275 0.1% 148 480,135 0.0% 2,381 506,379 0.5%

NY 3,071 7,906,309 0.0% 12,778 7,811,335 0.2% 28,664 9,313,776 0.3%

MD 130 1,972,886 0.0% 8 1,938,948 0.0% 4,189 2,483,628 0.2%

CT 3,862 1,580,365 0.2% 5,838 1,600,768 0.4% 1,967 1,625,758 0.1%

NH 306 759,514 0.0% 260 763,683 0.0% 391 755,770 0.1%

DC 0 809,412 0.0% 1,348 809,412 0.2% 2 275,554 0.0%

2006 2008 2010

*Florida and Arkansas show a large apparent decrease in advanced meter count as a result of the 2010 FERC Survey’s more restrictive 

definition of advanced meters. The District of Columbia shows a large apparent decrease in total meter count due to a correction in the 

2010 FERC Survey result of reporting issues in the 2008 FERC Survey results that erroneously included meters in the Maryland suburbs. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 11
12 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Figure 3.3 provides estimated penetration rates by type of entity. Political subdivisions8

 have 

the fastest growth in advanced metering penetration, from 0.1 percent in the 2006 FERC 

Survey to 20 percent in the 2010 FERC Survey. The high advanced meter penetration in 

Cooperatives continues the trend seen in the 2006 and 2008 FERC Surveys. The decline in 

advanced meter penetration for municipal entities from 2008 to 2010 is the result of the 

change to the definition of advanced meters as discussed in the Definition of Advanced 

Metering section above. 

Figure 3.3. Estimated penetration of advanced metering by type of entity in 2006, 2008 

and 2010 FERC Surveys 

0%

5%

10%

15%

20%

25%

30%

Type of Entity

Advanced Metering Penetration

2006 Survey 2008 Survey 2010 Survey

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%

Cooperatives Political 

Subdivision

Investor Owned 

Utility

Municipal 

Entities

Federal and 

State Utility

 

8

 Respondents identifying themselves as political subdivisions in the 2010 FERC Survey include public power 

districts, public utility districts, water and power agencies and authorities, and irrigation districts. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 13

Uses of Advanced Metering 

The 2010 FERC Survey asked respondents to categorize their Demand Response and Timebased Rates/Tariffs (DR/TBR) customers by the ways in which they are capable of receiving 

data on their electricity use: over the internet, on their bills or invoices, or via a display unit. 

The responses categorize about 8 million customers—about 5.5 percent of all meters in the 

U.S. Figure 3.4 presents the results. Use of the internet predominates for residential and 

nonresidential customers, with bills and invoices making up almost all of the remainder.9 

Display units are very uncommon. 

Figure 3.4. Reported numbers of customers and communication methods for advanced 

metering by customer class 

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

Internet Bills Display

Communication Method

Number of Customers

Nonresidential Residential

 

9

 Information may be delivered by more than one method. For example, customers may view frequently 

updated information online and also receive a monthly bill. For other types of customers, such as transportation 

and agriculture, bills and invoices are the more common data channel and the internet is slightly less prevalent. 
14 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Developments and Issues in Advanced Metering 

There have been several developments in advanced metering since the Commission issued its 

last report including the Department of Energy’s (DOE) completion of awards supporting 

Advanced Metering Infrastructure (AMI) deployment and demonstration projects, work on 

proposed standards under the National Institute of Standards and Technology (NIST) 

process, DOE reports on smart grid communications issues, expanded data collection efforts, 

noteworthy actions by state regulatory agencies, and technological advancements. This 

section of the report highlights these developments and describes some of the challenges 

facing AMI. 

American Recovery and Reinvestment Act Grant Programs 

The Department of Energy completed awards for 31 AMI grants worth $817 million under 

the American Recovery and Reinvestment Act (ARRA) Smart Grid Investment Grant 

Program.10 The ARRA grants allow recipients to recover up to 50 percent of the eligible 

project costs and are designed to accelerate the commercial use and implementation of AMI 

technologies. The ARRA AMI grants support projects with a total value of $2 billion in 29 

states. The projects are focused on providing AMI to retail consumers and, in some cases, 

information and pricing mechanisms that will allow consumers to reduce their energy use 

and costs, and improve the reliability of systems. 

The DOE also awarded $2.1 billion of funding under the ARRA Integrated and/or 

Crosscutting Systems Grant Program to support 39 demonstration projects that focus on 

adding intelligence and integrating smart grid and AMI capabilities in specific utility 

transmission and distribution systems throughout the United States. These system-based 

projects are valued in excess of $4.9 billion and are located in 31 jurisdictions. The projects 

include activities such as installing open, interoperable, two-way communications networks, 

deploying smart meters for customers, developing demand response and price responsive 

demand programs, automating advanced distribution and transmission applications, 

developing "self-healing" and power restoring properties on the grid, developing improved 

pricing programs, and supporting the deployment of plug-in electric vehicles. 

In addition, the DOE awarded grants supporting 16 regional demonstration projects that 

include smart meters in nine states. These large demonstration projects are designed to 

provide industry with business models, data to assess technical capabilities, and actual cost 

and benefit information associated with integrating these systems and components on a 

network level. 

 

10 Additional information pertaining to the grants and projects is accessible via the Federal Smart Grid Task 

Force, SmartGrid.gov – ARRA Smart Grid Programs, available: http://www.smartgrid.gov/projects. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 15

Federal Government-Led Activities to Support AMI Structures and 

Utilization 

Federal agencies and their stakeholder groups are conducting a number of activities designed 

to establish standards and protocols, develop common frameworks for access and data 

security, and collect timely information to support common structures and improve 

utilization of AMI. 

The National Institute of Standards and Technology Smart Grid Interoperability 

Standards 

The Energy Independence and Security Act (EISA) of 2007 gave the National Institute of 

Standards and Technology (NIST) "primary responsibility to coordinate development of a 

framework that includes protocols and model standards for information management to 

achieve interoperability of smart grid devices and systems...." NIST issued its NIST 

Framework and Roadmap for Smart Grid Interoperability Standards, Release 1.0 in January 

2010. In this document NIST reports that the smart grid will “ultimately require hundreds of 

standards, specifications, and requirements.” It also identified eight priority areas for 

standards development, including AMI standards.11 

NIST reviewed reports and other relevant literature and consulted with standards 

development organizations and smart grid stakeholders to identify gaps in current standards. 

NIST launched a public-private partnership, the Smart Grid Interoperability Panel (SGIP), to 

assist NIST and support the ongoing evolution of smart grid standards. NIST and the SGIP 

have initiated priority action plans and have overseen the organization of associated working 

groups to address those gaps. Two of the priority action plans focus on issues associated 

with smart metering. 

Priority action plan 05, Standard Meter Data Profiles, seeks to develop a common format for 

retrievable meter data to simplify client access to commonly shared information. Priority 

action plan 06, Demonstrate Common Semantic Model Translations for End Device Data, 

seeks to develop a common form to which meter information may be translated to (1) 

facilitate communication between devices and (2) support the common and accurate 

translation of information between meters and other devices. 

The Cyber Security Working Group (CSWG) is a permanent working group of the SGIP that 

focuses on cyber security aspects of the smart grid framework. In September 2010, NIST 

released the NIST Interagency Report 7628: Guidelines for Smart Grid Cyber Security

stemming from the work of the CSWG. One volume of the report focuses on privacy 

issues;12 NIST concluded with respect to privacy that the challenges associated with 

 

11 National Institute of Standards and Technology, Office of the National Coordinator for Smart Grid 

Interoperability, NIST Framework and Roadmap for Smart Grid Interoperability Standards, 

Release 1.0, NIST Special Publication 1108, January 2010, p. 10 

Available: http://www.nist.gov/public_affairs/releases/upload/smartgrid_interoperability_final.pdf. 12 NIST, “Guidelines for Smart Grid Cyber Security: Vol. 2, Privacy and the Smart Grid,” NISTIR 7628, 

August 2010, p. 1, Available: http://csrc.nist.gov/publications/nistir/ir7628/nistir-7628_vol2.pdf. 
16 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

safeguarding the new types of information transmitted and collected by smart grid devices 

have not been tested, and it is unclear if existing laws and regulation mitigate the associated 

risks. NIST found that the existing business policies and practices of utilities and third-party 

smart grid providers may not adequately address the privacy risks created by smart meters 

and smart appliances. 

NIST recommends that stakeholders follow standard privacy and information security 

practices to effectively and consistently safeguard the privacy of personal information. 

These practices may include conducting a privacy impact assessment before making the 

decision to deploy smart grid technologies. In addition, NIST recommends that stakeholders 

develop and document privacy policies and practices drawn from the Organization for 

Economic Cooperation and Development’s Privacy Principles and other authorities. NIST 

also recommends that stakeholders engage in privacy training and consumer education about 

privacy risks and mitigation actions. Additionally, NIST recommends that smart meters and 

other types of smart devices should be engineered to collect only the data necessary to allow 

the device to function for the purposes agreed to by smart grid consumers. 

The CSWG is also analyzing AMI cybersecurity challenges with regard to authentication of 

users and data, secure communications, and valid firmware updates. These challenges stem 

in part from a variety of AMI system attributes including the large number of meters which 

could represent points of access for a threat, typically limited processing capability within the 

meter that may be insufficient for complex security algorithms, and a network design that 

relies on information transfer from meter to meter before the accumulated data is relayed to 

the utility back office.13 

Department of Energy Reports Concerning Use and Security of AMI Information 

The DOE released two reports on October 5, 2010 that describe findings from its 

investigation of fundamental consumer and technology issues associated with AMI. DOE’s 

report, Communication Requirements of Smart Grid Technologies, finds that realization of 

smart grid benefits will rely on the increased use of communications and information 

technology and that sufficient access to communications facilities is critically important. The 

report states that DOE will seek to work with the Federal Communications Commission and 

the National Telecommunications and Information Administration to review possibilities for 

spectrum access to accommodate smart grid needs, and will need input from the utility and 

communications industries to determine spectrum requirements and identify additional and 

potentially available spectrum to support smart grid wireless communications needs. 

Devices that may require wireless technology include AMI. The report recommended the 

development of an online, interactive clearinghouse for smart grid communications 

technology applications, that would serve as a resource for utilities to share lessons learned in 

the smart grid context. In addition, the clearinghouse could include substantive information 

about the technologies and information on existing federal programs that may be helpful to 

utilities and their suppliers as they implement smart grid technologies. 

 

13 Id. at 31. 
The second report, Data Access and Privacy Issues Related to Smart Grid Technologies, 

provides: (1) DOE’s findings based on information received through an agency request for 

information to the public, and (2) a comprehensive summary of public comments on the 

issues from the spring and summer 2010 proceeding on data-privacy and data-security issues. 

DOE found that the residential and commercial customers should have access to their own 

detailed energy consumption information and that the information should be accorded 

privacy protections, including a prohibition of disclosure to third parties unless specifically 

authorized by the customer. If a customer grants a third party access to the energy data, that 

third party should also be required to protect the privacy and security of the information. 

DOE also found that consumer education and flexibility in technology and pace of 

deployment will be critical to the success and consumer acceptance of smart grid 

technologies. 

Energy Information Administration Data Collection Efforts 

EIA will significantly expand its collection of AMI-related data collection beginning in 2011 

to improve the breadth and timeliness of its information on AMI. EIA revised its Form EIA826, “Monthly Electric Sales and Revenue with State Distributions Report” to collect 

monthly, by state and sector, the number of Advanced Meter Reading (AMR) and AMI 

meters installed, as well as the energy served through AMI meters. These revisions may 

improve the ability of interested parties to monitor and assess AMI deployment and 

utilization in the United States. 

Noteworthy State Activities 

A key issue that states have been addressing is the method by which utilities may recover 

their investments in AMI. Utilities normally seek recovery of costs associated with 

infrastructure investments through rate cases held before state regulatory agencies. These 

rate cases generally address a wide variety of costs and can be time consuming and costly for 

all parties involved. In addition to rate case treatment, some states have approved a variety 

of funding mechanisms to support AMI, including cost trackers and surcharges. 

In general, cost trackers and surcharges provide cost recovery close to when the expenses 

associated with investments are incurred. Cost trackers typically allow for dollar-for-dollar 

cost recovery by the utility as costs are incurred. Surcharges (sometimes also called rate 

riders) recover costs by increasing rates by a set amount for a specific period of time. 

Surcharges generally reconcile cost estimates with actual costs on a quarterly or annual basis, 

which may slightly delay cost recovery. 

 

The use of these alternative cost recovery mechanisms generally include prudence reviews by 

state regulatory agencies. While these reviews may be limited in scope, they can help to 

achieve balance between ratepayers and investors. In August 2010, the Maryland Public 

Service Commission deferred recovery of the costs Baltimore Gas and Electric Company 

incurred to install AMI until the company is able to show in a future rate case that the meter 

installation is successful and cost-effective for consumers. It also conditioned the cost 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 17
18 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

recovery on the inclusion of a mechanism under which shareholders bear a portion of the 

financial risk.14 

Some states grant approval to pilot projects and full-scale deployment of smart meters, 

choosing the cost recovery mechanism each believes is appropriate. For example, the 

Corporation Commission of Oklahoma granted approval in July 2010 to the Oklahoma Gas 

& Electric Company for surcharge recovery of full-scale deployment smart meters in the 

company’s service territory.15 In October 2010, the New York Public Service Commission 

approved a surcharge for Consolidated Edison Company’s smart grid demonstration project 

and deferred cost recovery of five other utility projects funded through ARRA for 

consideration in future rate cases.16 At least one state identified situations where alternative 

cost recovery mechanisms are not appropriate. In September 2010, the 2nd Appellate Court 

of Illinois issued a decision prohibiting the use of a surcharge or rider to fund AMI 

investments associated with a pilot program initiated in 2009 by the Commonwealth Edison 

Company.17 

States are also addressing the consumer privacy issues associated with AMI. In September 

2010, California enacted legislation to ensure privacy protection for consumers and their 

energy consumption data.18 The legislation provides parameters by which an authorized 

third party can access and share a customers’ electric usage information and requires 

customer consent for release of its energy information. Subsequent to the legislation, the 

California Public Utilities Commission held a workshop on October 25 and 26, 2010 to 

address issues related to the creation of rules to allow for an authorized third party to access a 

customers’ electric usage information and consider any associated privacy protections that 

should be impleme 19 nted. 

 

States have also been actively addressing customer complaints and are finding that a 

common element in many challenges facing AMI is the need for consumer education, as 

identified in the National Acton Plan on Demand Response. Consumer education could 

14 Maryland Public Service Commission, Case No. 9208: In the Matter of the Application of Baltimore Gas and 

Electric Company for Authorization to Deploy a Smart Grid Initiative and to Establish a Surcharge for the 

Recovery of Cost, Order No. 83410 and Order No. 83531. 

15 The Corporation Commission of Oklahoma, Cause No. PUD 201000029: In the Matter of the Application of 

Oklahoma Gas and Electric Company for an order of the Commission Granting Pre-approval of Deployment of 

Smart Grid Technology in Oklahoma and Authorization of a Recovery Rider and Regulatory Asset, Order No. 

576595, Available: 

http://www.occeweb.com/SmartMeter/Final%20Order%20Approving%20Joint%20Stipulation%20and%20Settl

ement%20Agreement.pdf. 16 New York Public Service Commission, Case 09-E-0310: In the Matter of the American Recovery and 

Reinvestment Act of 2009 - Utility Filings for New York Economic Stimulus, Order Issued and Effective 

October 19, 2010, Available: 

http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={938D8D3D-25EE-4C25-BCD3-

A849B330E260}. 17 Commonwealth Edison Co. v. Ill. Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137, 1-08-3008, 1-

08-3030, 1-08-3054, 1-08-3313 cons., 2010 Ill. App. LEXIS 1057, (App. Ct. Ill., 2d Dist. Sept. 39, 2010), pet. 

for appeal denied, 2010 Ill. LEXIS 1312, p. 41. 

18 California Legislative Counsel, Senate Bill 1476 of the 2009-2010 Session, Available: 

http://www.leginfo.ca.gov/pub/09-10/bill/sen/sb_1451-1500/sb_1476_bill_20100929_chaptered.pdf. 19 CPUC, California’s Smart Grid, Available: http://www.cpuc.ca.gov/PUC/energy/smartgrid.htm. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 19

speed adoption of programs that employ AMI to empower and benefit consumers. For 

example, providing appropriate education early in an advanced meter deployment could 

alleviate some concerns that typically arise during deployment, such as those experienced in 

California and Texas where customers initially believed that the new meters were not 

accurate and later learned—through an independent evaluation of the accuracy and reliability 

of the installed AMI—that the advanced meters, software and billing systems may be more 

accurate than the old meters. 20 21

Technological Issues in Advanced Meters 

Recent technological improvements have expanded capabilities and reduced costs for 

advanced meters. An important advancement is the migration to full solid state advanced 

meters. Their use replaced the practice of combining separate communications components 

with measurement electronics22 or, for early advanced meters, the retrofitting of 

electromechanical meters with electronic modules containing communications and 

intelligence. 

These developments have led to a more unified platform, consolidation of common 

functions, and improvements in communications technologies. Greater use of applicationspecific integrated circuits and more capable microprocessors lower the cost of a system 

while reducing space requirements and providing greater functional capability including 

remote reprogramming. The design of smart meters now generally includes functional 

upgradability that was not possible with earlier units. These advancements have greatly 

improved the ability of advanced meters to support the growing utility requirements for 

demand response capability, tariff management, reliability management, and other programs 

to empower the consumer. 

Component interoperability, the ability of diverse systems to work together, also becomes 

more important as the interaction of power system components increase. Early adopters of 

AMI face interoperability issues as technology and standards evolve. Recently, utilities that 

installed meters that include integrated home area network (HAN) components have raised 

concerns that their meters may become obsolete if the industry adopts communication 

protocols for appliances and other components that are incompatible with their meters. The 

HAN’s function is to interconnect in-home devices, such as thermostats and appliances, and 

provide a bridge for communication to the power grid. While it is unclear how many meters 

this issue currently affects, it could be significant in the future as at least one firm projects 

that HAN capabilities will be included in 81% of all smart meters in North America by 

 

20 Structure Consulting Group, LLC., “PG&E Advanced Metering Assessment Report,” Commissioned by the 

California Public Utilities Commission, A.07-12-009 COM/MP1/jt2, pp. 8-9, Available: 

http://www.cpuc.ca.gov/NR/rdonlyres/2B0BA24E-E601-4739-AC8DDA9216591913/0/StructureExecutiveSummary.pdf. 

21 Navigant Consulting, “Evaluation of Advanced Metering System (AMS) Deployment in Texas – Meter 

Accuracy Assessment,” July 30, 2010, p. 11, Available: http://www.puc.state.tx.us/electric/reports/ams/PUCTFinal-Report_073010.pdf. 

22 The meter industry uses the term metrology, which includes a broad range of measured quantities including 

billing register data (e.g., consumption and demand) and interval usage data. 
20 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

 

2013.23 Stakeholders are engaged in a number of processes to resolve this issue, including 

the development of protocol agnostic modular devices that could serve as communication 

bridges from the in-home devices to either the HAN or power grid. 

The importance of the interoperability challenge is illustrated by the 2009 implementation of 

a company-wide AMI system by a Western utility. The utility found that the meters and the 

other system components selected for the AMI project did not properly function together. 

The utility ceased its AMI project as a result of this lack of interoperability and filed a 

request with the state regulator to conduct a new and extended AMI pilot project through 

2011. The regulator denied the request and noted that any subsequent application should 

include or be preceded by an overall smart grid plan. 

23 Pike Research new release: “49% of Smart Meters to Include Home Area Networking Connectivity by 2013”, 

April 23, 2010 (http://www.pikeresearch.com/newsroom/49-of-smart-meters-to-include-home-area-networkingconnectivity-by-2013). 
2010 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. 

In this chapter, Commission staff present results of the 2010 FERC Survey on demand 

response programs, comparisons to the 2006 and 2008 FERC Survey results, and the number 

of entities offering demand response programs, enrollment levels, and peak load reductions 

for these programs by entity type and by region. 

The information in the chapter provides summary-level results of demand response program 

activity and resources. Detailed information on responses is available on FERC’s website, 

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

This chapter has three sections: 

 Definition of Demand Response 

 Survey Results 

 Demand Response Activities at the FERC, Barriers to Demand Response, and Staff 

Recommendations 

Definition of Demand Response 

The definition of demand response used in this survey and 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. 

This definition substitutes “demand-side resources” for the phrase “end-use customers” used 

in previous surveys, to conform to the definition in use by NERC’s Demand Response Data 

Task Force in its development of a Demand Response Availability Data System (DADS) to 

collect demand response program information. Commission staff also modified the 2006 and 

2008 FERC Survey instruments for the 2010 FERC Survey. The number of program 

classifications was expanded from twelve in 2008 to fifteen in 2010. For some program 

classifications the 2008 definitions were altered.24 The new types and definitions also 

 

24 The changes in number and definition of program types may have caused respondents to reclassify programs 

from the 2008 FERC Survey to be consistent with the 2010 FERC Survey. Unlike the 2008 FERC Survey, 
22 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

conform to NERC’s DADS. Common terminology will allow comparison with the DADS 

data. Table 4.1 contains the program classifications of the 2010 FERC Survey instrument. A 

definition for each is in Appendix C, Glossary. 

Table 4.1. Demand response program classifications in the 2010 FERC Survey and 

changes from previous surveys 

2010 FERC Survey Program Classifications Change from Previous FERC Surveys

Direct Load Control

Interruptible Load

Critical Peak Pricing with Control New program classification

Load as Capacity Resource  

Spinning Reserves Previously included in Ancillary Services classification

Non‐Spinning Reserves Previously included in Ancillary Services classification

Emergency Demand Response

Regulation Service Previously included in Ancillary Services classification

Demand Bidding and Buyback

Time‐of‐Use Pricing

Critical Peak Pricing

Real‐Time Pricing

Peak Time Rebate

System Peak Response Transmission Tariff New program classification

Other

Survey Results 

Analysis Approach 

As in the advanced metering chapter of this report, this demand response section includes 

figures and tables of reported results from survey respondents, as well as estimated 

information for the entire survey population including the nonresponding entities. The 

estimated values of demand response program information for nonrespondents were based on 

data from the 2008 EIA-86125 and the 2008 FERC Demand Response Survey. Appendices 

D and H provide a detailed explanation of the analysis and estimation approach. 

In this chapter also, figures and tables with results compiled directly from data submitted by 

survey respondents without estimation of results for those not reporting are labeled 

“Reported” or “Reporting.” Figures and tables with results that include both data submitted 

 

where respondents could choose multiple program classifications for a single program, the 2010 Survey forced 

the selection of a single program classification for each program reported. 25 U.S. Energy Information Administration, Form EIA-861 Final Data File, available at 

http://www.eia.doe.gov/cneaf/electricity/page/eia861.html. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 23

by survey respondents and estimation of results for those not reporting, based on survey and 

other information, are labeled “Estimated.” 

The diversity of demand response programs poses a survey and reporting challenge. For 

instance, the same demand response potential may be reported by a utility and also by an 

RTO in whose program the utility participates. To avoid double-counting, the analysis 

subtracts the utility potential from the RTO’s potential, but this may not be possible if the 

utility and the RTO assign the program to different categories. FERC staff conferred with 

the RTOs, ISOs and a number of respondents, and sometimes changed their program 

categories to reduce any double-counting. Appendix D contains a cross-tabulation of RTO 

demand response programs in effect in 2009 and the program type assigned by staff to each 

RTO program. Double-counting can also occur with affiliates, and with generation and 

transmission cooperatives that supply energy to other cooperatives; staff attempted to 

identify and eliminate those errors as well. The rapid evolution of demand response 

programs, rules, and names increases confusion among respondents and staff alike and may 

have caused errors in spite of these measures. 

The 2010 FERC Survey changed the way respondents classify demand response programs. 

In past surveys, respondents could assign multiple classifications to a single demand 

response program. In the 2010 FERC Survey, respondents were forced to choose a single 

classification. This change may have contributed to the decline in the number of reported 

demand response programs from 2,314 in the 2008 FERC Survey to 1,931 in the 2010 FERC 

Survey. The reported numbers of entities offering various programs and the reported 

numbers of customers enrolled in such programs may also have been affected. Comparisons 

between past and current survey results should be made with this change in mind. 

Summary of Survey Findings 

Entities with demand response programs; numbers of customers in demand 

response programs. Direct load control programs have been one of the most common 

demand response programs offered since 1968.26 Direct load control programs are most 

often offered to residential or small commercial customers to control appliances such as air 

conditioning, water heating and pool pumps. These programs help sponsors balance load by 

remotely controlling the appliances during peak periods. 

RFC, WECC, FRCC, MRO and SERC have active direct load control programs. Enrollment 

levels are relatively consistent with levels reported in the 2008 FERC Survey, except in 

WECC where enrollment in direct load control programs more than doubled from the 2008 

FERC Survey, reaching 1.6 million customers. A contributing factor to the increase in direct 

load control enrollment in WECC may be the rollout over the past two years of direct load 

control programs by California’s three investor-owned utilities (IOUs). The California IOUs 

are responding to a directive by the California Public Utilities Commission requiring them to 

offer direct load control programs in support of their business case for implementing 

 

26 According to the EPRI, Detroit Edison was the first utility to implement a load control program in 1968. 

EPRI, The Demand-Side Management Information Directory, EPRI EM-4326, 1985. 
advanced meters. In contrast, the TRE, NPCC and SPP regions each have fewer than 

150,000 customers enrolled in direct load control programs. 

Consistent with the 2008 FERC Survey results, the 2010 results indicate the majority of 

customers enrolled in a direct load control program are in programs offered by their IOU, 

reflecting the larger number of customers in IOUs. This is true for all regions except TRE, 

where electric deregulation precluded regulated utilities from offering competitive services 

such as direct load control. After IOUs, cooperatives have the most customers enrolled in 

direct load control programs. 

Figure 4.1 presents the reported number of customers enrolled in direct load control 

programs by region and entity type. It is noteworthy that over 10 percent of customers in 

MRO and FRCC regions participate in direct load control programs. In FRCC, Florida 

Power and Light’s On Call direct load control program is the largest such program 

nationally, with over 800,000 customers enrolled. 

24 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 25

Figure 4.1. Reported number of customers enrolled in direct load control programs by 

region and type of entity27

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

NERC Region

Number of Customers

Cooperative Entities Federal and State Utility Investor Owned Utility Municipal Entities Other

   TRE FRCC MRO NPCC RFC SERC SPP WECC Other

Percent of total

estimated

customers in

the region in a

direct load

control program

0.8% 14.5% 12.5% 0.5% 4.1% 2.5% 0.7% 2.7% 5.7%

Figure 4.2 presents the number of entities reporting interruptible/curtailable rates by region 

and entity type. Like direct load control, interruptible/curtailable rates offer rate or tariff 

incentives. They differ from direct load control in that the customer, rather than the sponsor, 

curtails the load during peak times when directed. Nonresidential customers are typical 

participants in this type of program (residential customers are often ineligible to participate.) 

 

27 In this chapter, figures that report information for each entity type use the category “Cooperative Entities” for 

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.” Curtailment service providers, retail power marketers, regional transmission organizations 

and independent system operators are combined into “Other.” 
26 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Figure 4.2. Number of entities reporting interruptible/curtailable rates by region and type 

of entity 

0

10

20

30

40

50

60

70

80

TRE FRCC MRO NPCC RFC SERC SPP

NERC Region

Number of Entities

Cooperative Entities Federal and State Investor Owned Utilities Municipal Entities Other

The number of entities offering interruptible/curtailable rates rose from 248 in the 2008 

FERC Survey to 265 in 2010 FERC Survey. More than 85 percent of the reporting entities 

are IOUs and Cooperatives. These programs are primarily in the MRO, RFC, and SERC 

regions. The SERC region has the highest number of entities reporting 

interruptible/curtailable rates: 72 entities, compared to 50 in 2008. MRO had the largest 

number of programs in 2008 (63) and has remained essentially unchanged in 2010. There is 

an increase in the number of interruptible/curtailment rates from 2008 to 2010 in all regions 

except NPCC. NPCC dropped from 30 in the 2008 FERC Survey to 7 in 2010. 

Figure 4.3 presents the number of entities reporting time-of-use rates for residential 

customers by region and entity type. Time-of-use rates have prices that vary by time period, 

and the time periods are typically longer than one hour within a 24-hour day. The prices are 

known ahead of time and usually reflect the average cost of generating and delivering power 

during those time periods. Time-of-use rates are offered in every region by cooperatives, 

municipal and investor-owned utilities. MRO has the largest number of entities (46, the 

majority being municipals) reporting time-of-use rates. Sixty-nine fewer IOUs reported 

offering residential time-of-use rates in the 2010 FERC Survey than in the previous survey, 

contributing to an overall decline from 241 entities in the 2008 FERC Survey to 169 entities 

in the 2010 FERC Survey.28 

 

28 A methodology change in the 2010 Survey may have contributed to these declines. See discussion in the 

“Analysis Approach” section. 
Figure 4.3. Number of entities reporting residential Time-of-Use rates by region and type 

of entity 

0

10

20

30

40

50

TRE FRCC MRO NPCC RFC SERC SPP WECC

NERC Region

Number of Entities

Cooperative Entities Federal and State Investor Owned Utilities Municipal Entities Other

Figure 4.4 presents the reported number of residential customers enrolled in time-of-use rates 

by region and entity type. A reported 1.1 million U.S. residential customers are enrolled in 

time-of-use rates in the U.S. The number of residential customers reported on time-of-use 

rates declined from 1.28 million in the 2008 FERC Survey. IOUs have 77 percent of the 

reported time-of-use-enrolled customers. Cooperatives have the second highest percentage, 

about 22 percent of those enrolled. Despite time-of-use offerings by dozens of entities across 

the U.S., and particularly in MRO, most residential customers with time-of-use rates are in 

WECC. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 27
28 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Figure 4.4. Reported number of residential customers enrolled in Time-of-Use rates by 

region and entity type 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

TRE FRCC MRO NPCC RFC SERC SPP WECC

NERC Region

Number of Residential Customers

Cooperative Entities Federal and State Investor Owned Utilities Municipal Entities Other

Figure 4.5 presents the number of entities reporting having a retail real-time pricing program 

by region and type of entity. Under real-time pricing, electricity prices vary hourly or more 

often to reflect changes in the wholesale price of electricity on a day-ahead or hour-ahead 

basis. 

A total of 19 entities reported retail real-time pricing programs from all but two regions. 

This is down from the 85 entities reporting at least one real-time pricing program for retail 

customers in the 2008 FERC Survey. No municipal entities reported retail real-time pricing 

in the 2010 FERC Survey, although fifteen reported it in the 2008 FERC Survey. The 

number of cooperative entities with real-time pricing programs declined from 20 to two; 

IOUs with real-time pricing programs fell from 47 to fifteen.29 

 

29 A methodology change in the 2010 Survey may have contributed to these apparent declines. See discussion 

in the section “Analysis Approach”. The IOU real-time pricing numbers reported in the 2008 Survey may have 

been inflated by the previous methodology: in February 2006, Barbose et al reported eleven IOUs had default 

real-time pricing rates and another fifteen were considering them (Killing Two Birds with One Stone: Can 

Real-Time Pricing Support Retail Competition and Demand Response?, LBNL-59739, August 2006). 
Figure 4.5. Number of entities reporting retail real-time pricing by region and entity type 

0

1

2

3

4

5

6

7

TRE FRCC MRO NPCC RFC SERC SPP WECC

NERC Region

Number of Entities

Cooperatively Owned Utility Investor Owned Utility Federal Utility

Reported potential peak load reduction. The total potential peak load reduction from 

demand response programs reported in the 2010 FERC Survey is 53,063 MW. This is up 42 

percent from the 37,335 MW reported in the 2008 FERC Survey and 79 percent increase 

from the 29,653 MW reported in 2006. Figure 4.6 compares reported potential peak load 

reductions in the three FERC surveys. 

Figure 4.6. Total reported potential peak load reduction in 2006, 2008 and 2010 FERC 

Surveys 

0

10,000

20,000

30,000

40,000

50,000

60,000

Potential Peak Load Reduction (MW)

2006 Survey 2008 Survey 2010 Survey

2006 Survey 2008 Survey 2010 Survey

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 29
30 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Figure 4.7 presents the reported potential peak load reduction by customer class across the 

three survey years. Wholesale market participants30 and commercial and industrial 

customers together represent over 80 percent of the total potential peak reductions in the 

2010 FERC Survey, as they did in the previous survey. 

Wholesale market participants also had the largest increase in potential reductions: from 

12,656 MW in the 2008 FERC Survey to 22,884 MW in the 2010 FERC Survey. Much of 

the increase in the wholesale class is due to the growth of demand response in RTOs, from a 

reported 9,060 MW in the 2008 FERC Survey to 20,533 MW in this survey (see Figure 4.13 

below). Since 2007, ISO New England and PJM Interconnection have commenced longterm forward capacity markets that have attracted significant amounts of demand response. 

Commercial and industrial customers’ potential load reduction increased by 23 percent from 

the 2008 to 2010 FERC Surveys. Potential peak load reductions from residential customers 

remained relatively constant across all three survey periods. 

 

 

30 In this report, “wholesale market participants” refers to capacity reported in RTO demand response programs, 

less the demand response capacity reported by a retail utility and identified as also participating in an RTO 

demand response program. It also includes demand response capacity of wholesale entities such as generation 

and transmission cooperatives, municipal power agencies, and curtailment service providers. 
Figure 4.7. Reported potential peak load reduction by customer class in 2006, 2008 and 

2010 FERC Surveys 

0

5,000

10,000

15,000

20,000

25,000

Commercial &

Industrial

Residential Wholesale Other

Customer Class

Potential Peak Load Reduction (MW)

2006 Survey 2008 Survey 2010 Survey

Figure 4.8 presents the 2010 FERC Survey results for reported potential peak load reductions 

by region and customer class. Potential peak load reductions in the RFC, MRO, and NPCC 

regions reflect the substantial wholesale demand response capacity of the RTOs in those 

regions. Commercial and industrial customers, though fewer in number than residential 

customers, provide a higher total level of load reduction potential than residential customers. 

Commercial and industrial customers are more likely to have systems and technology in 

place to facilitate demand response program participation. In addition, many demand 

response programs are available only to customers above a certain size cut-off. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 31
Figure 4.8. Reported potential peak load reduction by region and customer class 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

NERC Region

Reported Peak Load Reduction (MW)

Commercial and Industrial Residential Wholesale Other

Figure 4.9 presents the reported potential peak load reduction by type of program and 

customer class. The top four demand response programs, Emergency Response, Interruptible 

Load, Direct Load Control, and Load as Capacity Resource account for 79 percent of the 

total U.S. peak load reduction potential. Except for direct load control, these programs 

predominantly enroll wholesale and commercial and industrial customers that bring high perparticipant peak load reductions. Direct load control programs are typically targeted to 

residential and small nonresidential customers; the controllable technologies are relatively 

homogeneous across these customers. Radio or other communication signals sent by the 

program sponsor are necessary for effective control of the large numbers of small loads. 

 

Emergency demand response programs (primarily wholesale) account for 24 percent of the 

peak load reductions, Interruptible Load (primarily commercial and industrial) account for 21 

percent of total peak load reductions, and Capacity programs (wholesale and commercial and 

industrial) account for 15 percent of the peak load reductions. In the 2008 FERC Survey, 

direct load control ranked first in total peak load reduction potential, and interruptible 

programs were second. The growth in emergency demand response among wholesale 

customers is particularly strong: it rises from 3,438 MW in the 2008 FERC Survey to 11,493 

in the 2010 FERC Survey, reflecting the growth of RTO demand response resources, as 

discussed at Figure 4.7. RTO and ISO areas reported growth in peak load reduction 

capability, which is reflected in the strong increase in Load as a Capacity Resource among 

wholesale customers; commercial and industrial customers also reported growth in that 

category. The 2010 FERC Survey received few responses from curtailment service providers 

(who consider much of their data proprietary), but recent public statements by large 

curtailment service providers suggest that they manage approximately 10,000 MW of 

primarily demand response resources (some of which may be among resources submitted by 

survey respondents).

32 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 33

Figure 4.9. Reported potential peak load reduction by type of program and by customer 

class 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Interruptible Load

Direct Load Control

Emergency Demand Response

Load as a Capacity Resource

Demand Bidding & Buy-Back

Spinning Reserves

Non-Spinning Reserves

Regulation

Other

Real-Time Pricing

Critical Peak Pricing

Critical Peak Pricing with Load Control

Peak Time Rebate

System Peak Response Transmission Tariff

Time-of-Use

Potential Peak Load Reduction (MW)

Commercial and Industrial Residential Other Retail Wholesale

Incentive-based DR

Programs

Time-based 

Programs

Actual peak load reductions. Respondents were asked to provide information on actual 

load reductions from demand response during 2009. A number of factors may influence 

realized reductions. For example, customer electric power consumption when demand 

response is needed affects the amount of load available to be reduced. Program incentives, 

penalties, and price signals may also influence participant response. In the U.S., peak 

demand is strongly influenced by summer heat, and the summer of 2009 had significantly 

fewer cooling degree-days than the summer of 2007.31 Finally, net generation in the U.S. 

during 2009 fell to its lowest level since 2003, the largest such drop in 60 years, 

accompanying a decline in Gross Domestic Product of 2.6 percent.32 It is likely that lower 

electric power consumption, as displayed in Figure 4.10, meant that existing resources were 

 

31 Cooling degree-days (CDD) are a temperature-derived measure used to forecast electrical demand. In the 

summer of 2007 there were 912 CDDs nationally (weighted by population); in summer 2009 there were 813. 

(Source: NOAA, Historical Climatology Series 5-2, May 2008 and April 2010). 

32 U.S. Energy Information Administration, Electric Power Annual 2009 

(http://eia.gov/cneaf/electricity/epa/epa_sum.html). 
adequate to meet load at most times and places, so there were fewer occasions to call on 

generation, which likely contributed to smaller actual load reductions by demand response 

resources. 

Figure 4.10. Net Annual U.S. Electrical Generation, 2005 through 2009 

3,200,000

3,400,000

3,600,000

3,800,000

4,000,000

4,200,000

4,400,000

2005 2006 2007 2008 2009

Net Generation (thousands of MWh)

 0

In total, respondents report 15,980 MW of actual demand response during 2009, equal to 30 

percent of the potential peak reduction. In the 2008 FERC Survey 13,398 MW of actual 

demand response was reported, equal to 36 percent of the potential reduction. Figure 4.11 

presents the reported potential and actual 2010 peak load reduction from demand response 

resources by region. RFC, with the highest potential peak load reduction, called on only 13 

percent of its potential. SERC called on about 34 percent of its potential peak load reduction 

in 2010, while MRO called on 27 percent of its potential load reduction. On the other hand, 

WECC called on nearly 70 percent of its available peak reduction resources, according to the 

2010 FERC Survey. 

34 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 35

Figure 4.11. Reported potential and actual 2010 peak load reductions by demand response 

resources by region

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

NERC Region

Peak Reduction (MW)

Potential Peak Reduction Actual Peak Reduction

Estimated potential peak load reductions. Commission staff estimated the potential peak 

reduction of nonresponding entities using FERC Survey data and other sources of 

information, such as EIA Form 861.33 The estimates were combined with respondent data to 

create an estimated potential peak load reduction, by region and customer type, for the entire 

U.S., as displayed in Figure 4.12. 

The estimated potential peak load reduction from demand response resources in the 2010 

FERC Survey is 58,339 MW; this is up from the estimated 40,943 MW in the 2008 FERC 

Survey and the estimated 37,522 MW in 2006 FERC Survey. The rank order of regions with 

the highest to lowest demand response resources is similar across the three surveys, with 

RFC region accounting for the majority of demand response resources. Wholesale, 

commercial and industrial customers combined comprise the highest potential peak load 

reductions in all regions except FRCC, which has large residential direct load control 

programs.

 

33 The estimation methodology is described in Appendices D and H. 
Figure 4.12. Estimated potential peak load reduction by demand response resources by 

region and customer class 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

TRE FRCC MRO NPCC RFC SERC SPP WECC Other

NERC Region

Potential Peak Load Reduction (MW)

Commercial and Industrial Residential Wholesale Other

Figure 4.13 presents the estimated potential peak reduction by demand response resources by 

type of entity and customer class. Investor owned utilities provide the greatest potential, 

through participation of commercial and industrial load.

36 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Figure 4.13. Estimated potential peak load reduction by demand response resources by 

type of entity and customer class

0

5,000

10,000

15,000

20,000

25,000

30,000

Investor Owned

Utilities

Cooperative

Entities

Municipal

Entities

Retail Power

Marketers

Potential

Federal& State RTO/ISO

Peak Load Reduction (MW)

Type of Entity

Residential Commercial & Industrial Other Retail Wholesale

 

Table 4.2 presents the reported potential peak load reduction by program category and state. 

According to reported results, all states except for Alaska and Montana have some type of 

demand response or time-based rate program. 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 37
Table 4.2. Reported potential peak load reduction in megawatts by program category and 

state

State

Time‐

Based  

Direct Load

Control  

Other

Incentive‐Based

Emergency Demand

Response  

Interruptible

Load   Other  

State

Total

AK 0 

AL 11 10 1,148 62 1,231 

AR 206 198 1,269 1,673 

AZ 30 144 - 174 

CA 534 785 593 425 457 1 2,795 

CO 104 176 191 471 

CT 5 752 757 

DC 44 40 84 

DE 160 128 288 

FL 90 2,586 38 25 429 56 3,224 

GA 559 230 1 293 - 1,083 

HI 20 29 49 

IA 5 315 512 23 311 1,166 

ID 0 343 0 343 

IL 7 60 1,160 1,353 39 - 2,619 

IN 46 86 1,304 372 83 1,891 

KS 9 26 1 34 125 3 198 

KY 67 147 28 1 2 245 

LA 1 0 535 536 

MA 0 61 601 662 

MD 70 14 752 817 11 1,664 

ME 1 483 484 

MI 3 264 934 44 503 1,748 

MN 563 1,453 1,139 229 891 135 4,410 

MO 122 73 - 5 217 1 418 

MS 100 119 219 

MT 0 0 

NC 198 317 40 111 1,210 46 1,922 

ND 31 22 37 1 68 1 160 

NE 2 324 135 170 1,000 1,631 

NH 9 7 90 106 

NJ 0 2 247 525 8 782 

NM 14 58 4 - 76 

NV 78 143 40 261 

NY 53 42 2,618 972 249 3,934 

OH 5 52 610 1,137 287 2,091 

OK 823 12 4 420 213 1,472 

OR 20 20 

PA 18 29 988 1,760 266 3,061 

RI 15 110 125 

SC 238 43 800 21 1,102 

SD 13 418 63 3 55 552 

TN 37 15 52 

TX 25 135 1,074 1,138 202 5 2,579 

UT 113 113 

VA 14 144 418 623 18 10 1,227 

VT 45 5 3 83 24 160 

WA 37 6 - 43 

WI 178 288 1,265 98 527 0 2,356 

WV 270 487 757 

WY 0 8 41 49 

38 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Plans for new demand response programs. Respondents were asked to “Provide your 

entity’s near- and long-term plans for new demand response programs and time-based 

rates/tariffs.” Table 4.3 summarizes the responses. Direct load control and critical peak 

pricing programs (of both types) are prominent among planned new programs, and the 

expected growth in the number of direct load control programs between 2010 and 2015 is 

notable. New programs that make use of advanced metering, including critical peak pricing, 

real-time pricing, and peak-time rebate, increase in number over time, while some of the 

more traditional load management strategies grow more slowly. Respondents expect the 

most new potential peak reduction to come from interruptible programs. 

Table 4.3. Reported plans for new demand response programs and time-based rates/tariffs 

  

During Calendar Year

2010

During Calendar Years

2011 and 2012

During Calendar Years

2013 through 2015

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 253 3497 324 4980 563 6301 

Interruptible Load 122 7557 119 7771 121 8328 

Critical Peak Pricing with Controls 13 234 19 395 22 813 

Load as Capacity Resource 36 1393 22 1386 22 915 

Spinning Reserves 10 1639 11 1419 10 1390 

Non-Spinning Reserves 5 316 8 92 11 232 

Emergency Demand Response 53 2027 46 1968 33 3196 

Regulation Service 3 105 5 85 6 155 

Demand Bidding and Buyback 4 240 6 227 5 425 

Time-of-Use Pricing 219 1283 205 1388 193 1489 

Critical Peak Pricing 42 354 62 624 66 910 

Real-Time Pricing 24 1259 30 1269 29 1271 

Peak Time Rebate 13 9 27 643 27 1165 

System Peak Response Transmission 

Tariff 3 36 4 111 3 311 

Other 35 2444 27 2436 25 2722 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 39
40 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Demand Response Activities at the FERC, Barriers to Demand 

Response, and Staff Recommendations 

Since the publication of the September 2009 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 carry out a legislative 

directive to develop a plan to realize the national potential for demand response. 

This chapter summarizes the key demand response developments and actions undertaken by 

the Commission since the prior report, including issuance of the National Action Plan on 

Demand Response, several rulemakings, and key demand-response-related RTO orders. It 

also describes remaining barriers to demand response identified by both the FERC and 

industry. It concludes with Commission staff recommendations for further action. 

National Action Plan on Demand Response 

On June 17, 2010, the FERC issued the National Action Plan on Demand Response (National 

Action Plan),34 a plan for the nation to achieve its potential for cost-effective demand 

resources through improved coordination of the efforts of utilities, consumers, demand 

response providers, and federal, state and local officials. As directed by section 529 of the 

2007 Energy Independence and Security Act (EISA),35 the National Action Plan is the 

product of extensive consultation over two and a half years with a broad range of industry 

stakeholders including local, state, and federal government officials, utilities, consumers, and 

nongovernmental groups. The National Action Plan consists of strategies and activities to 

achieve three objectives: technical assistance to states, a national communications program, 

and the identification or development of tools and materials for use by customers, states, and 

demand response providers. 

Specific activities identified in the National Action Plan for implementation include the 

creation of a broad coalition to coordinate and combine the demand response efforts of public 

and private organizations; the development of technical assistance related to demand 

response to support state and local decision-making; the development and implementation of 

 

34 National Action Plan on Demand Response, Federal Energy Regulatory Commission, June 17, 2010; 

http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential.asp. 35 42 U.S.C. § 8279. Section 529 of EISA directed FERC to complete a “National Action Plan on Demand 

Response” that would: 

(i) identify the requirements for technical assistance to states to allow them to maximize the amount 

of demand resources that can be developed and deployed; 

(ii) design and identify the requirements for a national communications program that includes broadbased customer education and support; and 

(iii) develop or identify analytical tools, model regulatory provisions, and model contracts for use by 

customers, states, utilities, and demand response providers. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 41

a national communications plan for demand response;36 and support for expanded and new 

analytical tools and materials for demand response analysis and assistance. 

Pursuant to section 529 of EISA, the FERC, together with the Secretary of Energy, is to 

develop of a proposal to implement the National Action Plan and submit the proposal to 

Congress. The Commission and the U.S. Department of Energy are currently developing this 

proposal and expect to deliver it to Congress in the near-term. 

Commission Rulemakings on Demand Response Issues 

Since the previous report in this series issued, the FERC has initiated one new rulemaking 

related to demand response. 

 

Demand Response Compensation in Organized Wholesale Energy Markets – Notice of 

Proposed Rulemaking (NOPR) 

On March 18, 2010, the Commission issued a proposed rule regarding compensation for 

demand response providers in organized energy markets.37 Noting that the levels of 

compensation for demand response vary significantly among RTOs and ISOs, the 

Commission questioned whether existing compensation structures are inadequate, and thus 

may be hindering the development and use of demand response, as demand response 

providers collectively continue to play a small role in wholesale markets. The NOPR 

proposed to require RTOs and ISOs to compensate demand response providers for their 

reductions in usage at the full market price in all hours. 

Based on extensive feedback from the initial comments submitted on the proposed rule, the 

FERC held a staff technical conference on September 13, 2010. There panelists discussed 

two issues: 

 if the Commission were to adopt a net benefits test for determining when to 

compensate demand response providers, what if any requirements should apply to the 

methods for determining net benefits; and 

 how costs associated with payment for demand response should be allocated within 

an ISO or RTO. 

The FERC invited all stakeholders to submit additional comment on these two issues. 

 

36 The negative customer reaction to smart meters in Texas and in California, partially due to lack of customer 

understanding about smart meters, is an example of the importance of proactively informing customers of the 

benefits and costs of new technology. See San Francisco Chronicle, “PG&E probe of SmartMeters to start 

soon,” page DC-1, Available: http://www.sfgate.com/cgibin/article.cgi?f=/c/a/2010/03/09/BU3V1CCQSI.DTL&tsp=1 (November 1, 2010).; Public Utility Commission 

of Texas, “Smart meters superior to traditional ones - Independent study ordered by PUC provides details,” 

August 2, 2010 New Release, Available: http://www.puc.state.tx.us/nrelease/2010/080210.pdf (November 1, 

2010). 

37 130 FERC ¶ 61,213 (March 18, 2010). 
42 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

Demand Response and Smart Grid Developments 

In the past year, many demand response activities—such as using smart meters to control 

electric loads—have come to overlap considerably with the nation’s smart grid initiatives. 

The FERC has been engaged in two smart grid activities that in part support demand 

response.

Standards Development for Smart Grid Demand Response Applications 

Congress addressed the need for open and interoperable standards in the development of a 

modern electricity system in EISA. EISA directed NIST to coordinate the development of a 

framework that includes standards for smart grid devices, many of which will support both 

advanced metering systems and demand response resources. Section 1305 of the EISA 

directs the Commission, once it is satisfied that the Institute’s work has led to “sufficient 

consensus” on interoperability standards, to “institute a rulemaking proceeding to adopt such 

standards and protocols as may be necessary to insure smart-grid functionality and 

interoperability in interstate transmission of electric power, and regional and wholesale 

electricity markets.”38

NIST initiated seventeen Priority Action Plans to facilitate the development of smart grid 

interoperability standards and has worked closely with other Standards Development 

Organizations to expedite the development of new standards or the refinement of existing 

standards.39 Several of the priority action plans will generate standards that support demand 

response.40 On October 6, 2010, NIST notified the FERC that the first set of consensus 

standards had been posted for review by regulators. The Commission opened a proceeding 

on these standards on October 7, 2010 with a Notice of Docketed Designation for Smart Grid 

Interoperability Standards.41 It also held a technical conference on the posted standards on 

November 14, 2010, in conjunction with the National Association of Regulatory Utility 

Commissioners (NARUC)-FERC Collaborative on Smart Response in Atlanta, Georgia. 

Coordination of Federal-State Policies 

Given the close linkage of federal and state demand response policies, NARUC and the 

FERC continue to collaborate on demand-side and smart grid issues. In the past year, two 

NARUC-FERC collaboratives (the Demand Response Collaborative and the Smart Grid 

Collaborative) were merged into a single NARUC-FERC Collaborative on Smart Response. 

The mission of the new Collaborative is to provide a forum for federal and state regulators to 

discuss smart grid and demand response policies, share best practices and technologies, and 

address issues that benefit from state and federal collaboration. The two collaboratives 

merged because of the significant overlap of issues and policies. 

 

38 42 U.S.C. § 17385 (2006). 

39 Information on the NIST smart grid effort can be found at http://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/WebHome. 

40 In particular, priority action plans 3, 4, 9, 10 and 17. 

41 See Docket No. RM11-2 for more information. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 43

Other Demand Response Orders and Activities 

The Commission continues to assess and monitor the wholesale electric power markets under 

its jurisdiction to ensure that demand response resources that are technically capable of 

providing a service are treated comparably to supply resources. In addition to a set of orders 

approving various changes to RTO and ISO demand response programs, the FERC issued a 

series of orders on compliance with the demand response provisions of the Commission’s 

Wholesale Competition Final Rule (Order No. 719). This section summarizes these 

activities. 

As described in the previous two editions of this Report, Order No. 719, issued in October 

2008, recognized and reaffirmed the importance of demand response in ensuring just and 

reasonable wholesale prices and reliable grid operations in organized Regional Transmission 

Operator (RTO) and Independent System Operator (ISO) markets. Order No. 719 directed 

the following changes to RTO and ISO market rules: 

 accept bids from demand response resources in their markets for certain ancillary 

services, on a basis comparable to other resources; 

 eliminate during a system emergency a charge to a buyer in the energy market for 

taking less electricity in the real-time market than purchased in the day-ahead market; 

 permit aggregators of retail customers to bid demand response on behalf of retail 

customers directly into the organized energy market in certain circumstances; and 

 modify their market rules, as necessary, to allow the market-clearing price during 

periods of operating-reserve shortage to reach a level that rebalances supply and 

demand so as to maintain reliability while providing sufficient provisions for 

mitigating market power. 

In Order Nos. 719-A and 719-B, issued in July and December 2009 respectively,42 the 

Commission addressed several additional issues, including demand response participation in 

organized markets and the role of the relevant electric retail regulatory authority. The 

Commission directed that RTOs and ISOs (1) must accept bids from aggregators of demand 

response from retail customers of utilities that distributed more than 4 million MWh in the 

previous fiscal year, except where prohibited by the relevant electric retail regulatory 

authority, and (2) must not accept bids from aggregators of demand response from retail 

customers of utilities that distributed 4 million MWh or less during in the previous fiscal 

year, unless permitted by the relevant electric retail regulatory authority. 

Order No. 719 required each of the six RTOs and ISOs to submit filings either proposing 

tariff amendments to comply with the rule’s requirements or to demonstrate that its existing 

 

42 Wholesale Competition in Regions with Organized Electric Markets, Order No 719-A, 128 FERC ¶ 61,059 

(July 16, 2009) (Order No. 719-A), reh’g den, Order No. 719-B, 129 FERC ¶ 61,252 (December 17, 2009). 
44 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

tariff and market design already are in compliance. The six RTOs and ISOs submitted their 

filings in individual dockets in April and May of 2009. In general, the RTOs and ISOs 

asserted in their compliance filings that they either already were in compliance with the 

Order No. 719 demand response requirements, or were working toward compliance. After 

substantial comment by stakeholders, the FERC issued initial orders finding that the RTOs 

and ISOs already had taken steps to eliminate some of the barriers to demand response 

participation within their markets, and directing the RTOs and ISOs to make additional 

filings to address remaining areas of noncompliance. 

California ISO 

The FERC accepted several Order No. 719 compliance filings related to demand response 

from the California ISO (CAISO). In June 2010, it conditionally accepted CAISO’s filing to 

implement a Scarcity Pricing Mechanism, for pricing of energy and ancillary services during 

periods of operating reserve shortages, to meet Order No. 719’s requirements for operating 

reserve shortage pricing.43 The Scarcity Pricing Mechanism applies when a shortage 

condition is triggered: when supply is insufficient to meet one or more of the CAISO’s 

ancillary services requirements within an ancillary service region or subregion. The price of 

the affected ancillary service(s) is set by administratively-determined demand curves, and 

will apply to the region or subregion in which the shortage occurs. In July 2010, the FERC 

conditionally accepted CAISO’s proposal to permit a demand response provider to bid 

demand response on behalf of retail customers directly into the CAISO's organized markets, 

as required by Order No. 719.44 The proposal introduced a new demand response product to 

the CAISO markets, the proxy demand resource, defined as a load or an aggregation of loads 

capable of measurably and verifiably reducing electric demand in response to CAISO 

dispatch instructions. In September 2010, the Commission conditionally accepted CAISO’s 

proposed tariff revisions to facilitate the provision of ancillary services by demand 

resources,45 finding them to be an incremental step toward removing barriers to comparable 

treatment of nongenerator resources to provide ancillary service products. 

ISO New England 

In a series of orders, the FERC accepted changes to ISO-NE’s market rules related to demand 

response that comply with Order No. 719. In a January 2010 order on ISO-NE’s compliance 

filing,46 the Commission stated that ISO-NE must demonstrate how “dispatchable-assetrelated demand” (DARD) resources or any revised mechanism complies with the 

comparability requirements of Order No. 719 as they pertain to the provision of ancillary 

 

43 California Independent System Operator Corporation, 131 FERC ¶ 61,280 (June 29, 2010), reh’g pending. 44 California Independent System Operator Corporation, 132 FERC ¶ 61,045 (July 15, 2010), reh’g pending. 

As part of this proposal, the California Public Utilities Commission held hearings. See Cal. Pub. Utils. 

Comm’n, Assigned Commissioner And Administrative Law Judges' Ruling Amending Scoping Memo, 

Establishing A Direct Participation Phase Of This Proceeding, And Requesting Comment On Direct 

Participation Of Retail Demand Response In CAISO Electricity Markets, 07-01-41 (Nov. 9, 2009), available at 

http://docs.cpuc.ca.gov/efile/RULINGS/109611.pdf); see also Cal. Pub. Utils. Comm’n, Decision on Phase 

Four Direct Participation Issues, 07-01-041 (June 4, 2010), available at

http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/118962.pdf. 

45 California Independent System Operator Corporation, 132 FERC ¶ 61,211 (September 10, 2010). 46 ISO New England Inc. and New England Power Pool, 130 FERC ¶ 61,054 (January 21, 2010). 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 45

services. In response, ISO-NE filed and the Commission accepted revisions to its market 

rules to reduce the minimum size requirement for DARD from 5 MW to 1 MW, and to allow 

aggregation of retail customers receiving electrical service from the same point of supply. 

The Commission also accepted tariff revisions to eliminate differences in the treatment of 

third-party aggregators of retail customers and host utilities with respect to their ability to 

aggregate customers for purposes of providing demand response resources.47 

The FERC also accepted a change to ISO-NE’s Forward Capacity Market (FCM) rules to 

prevent most demand resources from being subject to performance penalty charges that 

exceed their FCM revenues in a month. The changes also closely tie the penalty and 

incentive rates for demand resources to their FCM payment rates.48 

New York ISO 

In its April 2009 Order No. 719 compliance filing, the New York ISO (NYISO) stated that it 

either already is in compliance, or soon would be, with the requirements of the order 

regarding demand response bidding flexibility, scarcity pricing, and operating reserve. In its 

order conditionally accepting NYISO’s filing, the Commission directed NYISO to explain 

the reasonableness of its requirement that demand response resources use the same telemetry 

and communications equipment used by generators, and to provide a timeline for demand 

response resource integration into its energy market. It also directed NYISO to file its 

market rules governing the ability of aggregators to bid directly into the ancillary services 

market.49 In a follow-up filing, NYISO estimated that demand response resource integration 

would be unlikely to occur prior to the middle of 2012, and agreed to submit semiannual 

updates on progress on evaluating possible communication alternatives for demand response 

and its plan of action for the real-time energy market demand response resource 

50 integration. 

Commission clarified that, while it would not require PJM to disclose customer-specific 

PJM Interconnection, L.L.C. 

On February 9, 2009, PJM filed proposed tariff changes to clarify the right of a retail 

regulatory authority to prohibit participation of a retail customer in PJM’s demand response 

programs. In a series of orders, the Commission accepted tariff changes that (i) recognize a 

retail regulatory authority’s ability to condition the eligibility of its retail customers to 

participate in PJM’s demand response programs, (ii) address how retail regulatory 

prohibitions would affect existing registrations and commitments made by PJM market 

participants, and (iii) obligate PJM to post on its website a list of retail regulatory authorities 

that prohibit retail participation in PJM’s Demand Response Programs.51 In addition, the 

 

47 ISO New England Inc. and New England Power Pool, Docket No. ER09-1051-003 (July 23, 2010); ISO New 

urt of Appeals for the 7th Circuit, 

on a petition for review filed by the Indiana Utility Regulatory Commission. 

E ers). 48 ISO New England Inc. and New England Power Pool, Docket No. ER10-2232 (October 1, 2010). 

ngland Inc. and New England Power Pool, Docket No. ER09-1051-004 (Sept. 29, 2010) (letter ord

49 New York Independent System Operator, 129 FERC ¶ 61,164 (2009), reh’g, 131 FERC ¶ 61,114 (2010). 50 New York Independent System Operator, Docket No. ER09-1142-006 (April 23, 2010) (letter order). 51 See PJM Interconnection, L.L.C., 128 FERC ¶ 61,238 (2009) and PJM Interconnection, L.L.C., 131 FERC ¶ 

61,069 (April 23, 2010). The April 23 order is now pending before the US Co
46 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

confidential or proprietary information regarding demand response participation, this would 

not affect any rights of a state commission to obtain such information. 

Southwest Power Pool 

In its order on the Southwest Power Pool’s (SPP) Order No. 719 compliance filing,52 the 

Commission directed SPP to submit a revised filing to address comparability in a way that 

enables demand response resources to participate on terms that both address the 

characteristics of demand response resources and ensure reliable operations. Specifically, it 

directed SPP to revise its tariff to allow demand response resources, including bids from 

aggregators, to participate in SPP’s energy markets on a basis comparable to other resources. 

The Commission stated that SPP did not justify why technical requirements, policies, and 

procedures tailored for generation resources are reasonable and appropriate for 

accommodating the characteristics of technically capable demand response resources. It also 

rejected SPP’s proposed method for determining a customer’s baseline electric consumption, 

and found that SPP had not proposed a measurement and verification standard as required by 

Order No. 719. SPP was directed to address these deficiencies in a compliance filing. SPP 

filed a further compliance on demand response on May 19, 2010. 

Further Barriers to Demand Response 

This section summarizes the barriers to demand response in organized markets identified by 

the RTOs and ISO in the Order No. 719 process, and also other barriers identified outside 

that process. 

Barriers to Demand Participation in Organized Wholesale Markets 

In response to the direction in Order No. 719, each of the RTOs and ISOs studied the need 

for further reforms to remove barriers to comparable treatment of demand response 

resources.53 A review of the filed RTO and ISO barriers filings, including comments on the 

filings, identified several remaining barriers. Several of the identified barriers are the subject 

of additional compliance filings and orders that are discussed in section IV. Such barriers 

include: 

 Use of generator-specific models and offer parameters. Commenters contended 

that the ISOs and RTOs continue to impose offer parameter requirements that do not 

adequately recognize the different characteristics of demand response and traditional 

generation resources and, therefore, do not provide for comparable treatment of 

demand response resources as required by Order No. 719. 

 Shortage pricing. As identified in Order No. 719 and by several commenters, many 

of the RTOs and ISOs’ shortage pricing mechanisms may not accurately reflect 

shortages because they are triggered only after emergency provisions are initiated. 

Market rule changes to implement shortage pricing were included in several of the 

RTO compliance filings.

 

52 Southwest Power Pool, Inc., 129 FERC ¶ 61,163 (Nov. 20, 2009), reh’g pending. 53 Order No. 719, P 274. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 47

 Reliability standards on ancillary services. Regional reliability standards imposed 

on RTOs and ISOs may restrict or prevent the participation of demand response 

resources in ancillary services markets.54 

During the Order No. 719 proceeding, several additional barriers to demand response 

participation were identified by commenters, and were not directly addressed in the Rule. 

These include:

 Telemetry requirements. Unnecessary or onerous telemetry requirements for 

demand response resources have been cited as a barrier to greater demand response 

participation. Telemetry refers to near instantaneous metering and transfer of 

electricity consumption data to system operators. Commenters in the Order No. 719 

proceeding argued that in certain wholesale markets demand-side resources should 

not be subject to the same telemetry requirements as supply-side resources. 

 Price Transparency in Bilateral Capacity Markets. Commenters identified the 

lack of price transparency for the capacity value of demand response resources as a 

barrier in RTO and ISO regions that lack a centralized forward capacity market. 

Lacking a centralized forward capacity market, commenters argued, demand response 

resources must rely on bilateral contracts that may not provide the price transparency 

necessary to ensure that these resources are fairly compensated and to encourage 

additional provision of capacity by new demand response resources. 

 Market Monitoring and Mitigation. Commenters noted that a relatively new issue 

is whether demand response providers can exercise market power and thus should be 

subject to mitigation and scrutiny from market monitors. Because this issue has not 

been thoroughly addressed, demand response providers may be reluctant to bid in 

during periods of high prices due to concerns regarding exercising market power, 

especially if their bids are eligible to set the market clearing price. 

Other Barriers to Demand Response 

In addition to the barriers identified and addressed in FERC proceedings, federal, state, and 

local policy makers over the past several years have identified several additional key 

regulatory barriers to greater demand response, at both the federal and the state levels. 

Financial and Pricing Impacts Associated with Offering Demand Response 

Disincentives to investment in demand-side resources (which include both energy efficiency 

and reliability-based demand response resources) are imbedded in rate structures and 

regulation. Utilities generally earn revenue based on the amount of electricity they sell. If 

electricity consumption decreases during peak periods due to demand response initiatives and 

is not shifted to off-peak hours, utilities could lose revenue. 

 

54 For example, the Western Electricity Coordinating Council (WECC) currently does not allow loads to 

provide spinning reserve. See NERC, Special Report: Potential Reliability Impacts of Emerging Flexible 

Resources, August 2010. 
48 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

As reported in prior FERC annual demand response reports and the National Assessment, 

many states and the FERC are exploring and implementing new policies to reduce 

disincentives to investment in demand-side resources.55 

Limited Number of Retail Customers on Time-Based Rates 

The National Assessment of Demand Response Potential identified significant demand 

reduction potential if retail customers were on time-based rates.56 Heightened interest in the 

topic is evidenced by more than fifteen smart grid and demand response pilots that have been 

conducted since the mid-1990s.57 There have been only limited implementation of timebased rates and tariffs, both for optional programs that customers can voluntarily join and for 

programs in which this is the default rate (which in some cases the customer may “opt-out” 

of). California is one of the few states that have adopted a critical peak pricing tariff as its 

default rate for commercial and industrial customers. In the few states where time-based 

rates have been approved, the focus has been on peak time rebates (i.e., where customers can 

earn a rebate by reducing energy use from a baseline during a specified number of hours on 

critical peak days), limiting experience with other time-based rates. For example, in its 

approval of Baltimore Gas & Electric’s smart grid plans, the Maryland PSC rejected the 

proposed critical peak pricing rates and approved only peak time rebates.58 

Measurement and Cost-Effectiveness of Reductions 

How to effectively estimate a customer’s baseline electricity use is a primary issue in the 

measurement and verification of demand response. In RTO and ISO markets, participants in 

demand response programs measure their reductions by comparing actual meter readings 

against an estimate of what metered load would have been without the reduction in 

demand—the customer baseline. The RTOs and ISOs use various baseline methods to 

estimate consumption without demand response.59 Efforts to improve and standardize 

baseline estimates are underway at the state and industry levels. 60 Since 2008, the North 

American Energy Standards Board (NAESB) has been developing business practice 

standards for measurement and verification of demand reductions by demand response 

 

55 See, for example, the Institute of Energy Efficiency’s July 2010 summary of State Electric Efficiency 

Regulatory Framework for a summary of state activity: 

http://www.edisonfoundation.net/iee/issueBriefs/IEE_StateRegulatoryFrame_0710.pdf, and discussion 

of Wholesale Competition in Regions with Organized Markets – Order No. 719, supra. 

56 The National Assessment projects that peak demand reductions close to 20 percent of peak load in 2019 could 

achieved if all customers were on mandatory dynamic pricing. 

57 Faruqui, Ahmad and Sergici, Sanem, “Household Response to Dynamic Pricing of Electricity - A Survey of 

the Empirical Evidence,” Journal of Regulatory Economics, 38:193-225. 58 Supra note 29. 

59 The North American Wholesale Electricity Demand Response 2010 Comparison developed by the ISO/RTO 

Council documents the various baseline methodologies in use. See

http://www.isorto.org/site/apps/nlnet/content2.aspx?c=jhKQIZPBImE&b=2613997&ct=8400541. 60 For example, California continues to examine demand response impact and cost-effectiveness in one of its 

proceedings. See http://docs.cpuc.ca.gov/published/proceedings/R0701041.htm for more information. 
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 49

resources at both the wholesale and retail levels.61 The FERC approved Phase I of the 

wholesale standards in April 2010.62 Work continues at NAESB on Phase II of these 

standards. As the Commission stated in its April order, “we expect Phase II will address 

issues related to baseline deployment.”63 

Efforts continue to develop cost-effectiveness methods to assess demand response and smart 

grid investments, with a particular focus on estimating benefits. Business cases filed with 

state regulators typically include in their benefit estimates both improved operational 

efficiencies and projected lowered energy and capacity costs. The size and certainty of these 

energy and capacity cost savings have been questioned during state deliberations.64 In 

addition, questions of the scope of the cost-effectiveness calculations have been raised, e.g., 

whether in-home displays and other tools for customers should be included in the costs of a 

program. 

Cost Recovery and Incentives for Enabling Technologies 

The investments in devices, controls and software to implement demand response remain one 

of the greatest barriers to increased penetration. Regulatory approaches to cost recovery for 

these devices, controls and software are being addressed in state rate cases and 

proceedings.

65 The federal government through the American Recovery and Reinvestment 

Act funded $4.5 billion in smart grid and demand response. Additional attention to best 

practices in cost recovery is needed, particularly to resolve the issue of who should bear the 

initial cost of smart grid investments installation and implementation. 

 

 

New Environmental Rule Covering the Operation of Emergency Generators 

In March 2010, the U.S. Environmental Protection Agency (EPA) issued a final rule setting 

national emission standards for hazardous air pollutants for existing stationary compression 

ignition reciprocating internal combustion engines (i.e., diesel generators).66 Diesel 

emergency generators covered in the final rule may operate up to 15 hours as part of RTO 

emergency demand response programs. This 15 hour cap is less than the minimum number 

61 North American Energy Standards Board, http://www.naesb.org/dsm-ee.asp. 62 Standards for Business Practices and Communication Protocols for Public Utilities, Final Rule, Order No. 

676-F, 75 FR 20901 (April 15, 2010). 

63 Ibid, P 37. 

64 For example, in Maryland PSC’s conditional approval of Baltimore Gas & Electric’s smart grid plans in 

Order No. 83531, the PSC raises questions about the speculative nature of these benefits – 

http://webapp.psc.state.md.us/Intranet/sitesearch/CN9208.pdf. California PUC’s 07-01-041 proceedings 

is also addressing these issues, see supra note 5. 65 For example, the Maryland PSC initially rejected Baltimore Gas & Electric’s proposed rate surcharge to 

recover the costs of their smart grid plans. The final order approved BG&E’s proposal but deferred decisions 

on recovery. Recently, the Appellate Court of Illinois ruled that a special surcharge created to pay for a smart 

grid pilot did not meet the criteria to warrant single-issue ratemaking and put into doubt the future of the pilot,

see http://www.state.il.us/court/Opinions/AppellateCourt/2010/2ndDistrict/September/2080959.pdf. 66 National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines, 

Final Rule, 75 FR 9648 (March 3, 2010). 
50 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

 

of hours (typically 60) that are required for participation in RTO emergency demand 

response programs. Several curtailment service providers petitioned EPA to reconsider the 

final rule, arguing that the rule would not allow customers with covered diesel generators to 

participate in RTO programs (emergency generators are used by many customers “behindthe-meter” to create load reductions); thereby reducing the level of the demand response 

available. The EPA recently requested comments on whether the 15 hour limitation should 

be changed.67

Staff Recommendations 

As directed by EISA, FERC staff prepared a detailed set of recommended activities that 

should be undertaken by federal, state and local policymakers to achieve the potential 

identified in the 2009 National Assessment of Demand Response Potential. These activities 

are set out in detail in the National Action Plan and are designed to address many of the 

challenges and barriers to the deployment of demand response resources discussed above.

67 National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines, 

Notice of reconsideration of final rule; request for public comment; notice of public meeting, 75 FR 75937 

(December 7, 2010). 
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. 

‘‘(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 

2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 51
(b) STATE INVESTIGATION OF DEMAND RESPONSE AND TIMEBASED METERING.—

Section 

115 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2625) is amended as follows: 

(1) By inserting in subsection (b) after the phrase ‘‘the standard for time-of-day rates established by 

section 111(d)(3)’’ the following: ‘‘and the standard for time-based metering and communications 

established by section 111(d)(14)’’. 

(2) By inserting in subsection (b) after the phrase ‘‘are likely to exceed the metering’’ the following: 

‘‘and communications’’. 

(3) By adding at the end the following: 

‘‘(i) TIME-BASED METERING AND COMMUNICATIONS.—In making a determination with 

respect to the standard established by section 111(d)(14), the investigation requirement of section 

111(d)(14)(F) shall be as follows: Each State regulatory authority shall conduct an investigation and 

issue a decision whether or not it is appropriate for electric utilities to provide and install time-based 

meters and communications devices for each of their customers which enable such customers to 

participate in time-based pricing rate schedules and other demand response programs.’’. 

(c) FEDERAL ASSISTANCE ON DEMAND RESPONSE.—Section 132(a) of the Public Utility 

Regulatory Policies Act of 1978 (16 U.S.C. 2642(a)) is amended by striking ‘‘and’’ at the end of 

paragraph (3), striking the period at the end of paragraph (4) and inserting ‘‘; and’’, and by adding the 

following at the end thereof: ‘‘(5) technologies, techniques, and rate-making methods related to 

advanced metering and communications and the use of these technologies, techniques and methods in 

demand response programs.’’. 

(d) FEDERAL GUIDANCE.—Section 132 of the Public Utility Regulatory Policies Act of 1978 (16 

U.S.C. 2642) is amended by adding the following at the end thereof: 

‘‘(d) DEMAND RESPONSE.—The Secretary shall be responsible for— 

‘‘(1) educating consumers on the availability, advantages, and benefits of advanced metering and 

communications technologies, including the funding of demonstration or pilot projects; 

‘‘(2) working with States, utilities, other energy providers and advanced metering and 

communications experts to identify and address barriers to the adoption of demand response 

programs; and 

‘‘(3) not later than 180 days after the date of enactment of the Energy Policy Act of 2005, providing 

Congress with a report that identifies and quantifies the national benefits of demand response and 

makes a recommendation on achieving specific levels of such benefits by January 1, 2007.’’. 

(e) DEMAND RESPONSE AND REGIONAL COORDINATION.— 

(1) IN GENERAL.—It is the policy of the United States to encourage States to coordinate, on a 

regional basis, State energy policies to provide reliable and affordable demand response services to 

the public. 

(2) TECHNICAL ASSISTANCE.—The Secretary shall provide technical assistance to States and 

regional organizations formed by two or more States to assist them in— 

(A) identifying the areas with the greatest demand response potential; H. R. 6—373 

(B) identifying and resolving problems in transmission and distribution networks, including 

through the use of demand response; 

(C) developing plans and programs to use demand response to respond to peak demand or 

emergency needs; and 

(D) identifying specific measures consumers can take to participate in these demand response 

programs. 

(3) REPORT.—Not later than 1 year after the date of enactment of the Energy Policy Act of 2005, the 

52 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                  Federal Energy Regulatory Commission 53

Commission shall prepare and publish an annual report, by appropriate region, that assesses demand 

response resources, including those available from all consumer classes, and which identifies and 

reviews— 

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

devices and systems; 

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

(C) the annual resource contribution of demand resources; 

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

planning 

purposes 

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

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

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

and 

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

and critical period pricing programs. 

(f) FEDERAL ENCOURAGEMENT OF DEMAND RESPONSE DEVICES.—It is the policy of the 

United States that time-based pricing and other forms of demand response, whereby electricity 

customers are provided with electricity price signals and the ability to benefit by responding to them, 

shall be encouraged, the deployment of such technology and devices that enable electricity customers 

to participate in such pricing and demand response systems shall be facilitated, and unnecessary 

barriers to demand response participation in energy, capacity and ancillary service markets shall be 

eliminated. It is further the policy of the United States that the benefits of such demand response that 

accrue to those not deploying such technology and devices, but who are part of the same regional 

electricity entity, shall be recognized. 

(g) TIME LIMITATIONS.—Section 112(b) of the Public Utility Regulatory Policies Act of 1978 (16 

U.S.C. 2622(b)) is amended by adding at the end the following: 

‘‘(4)(A) Not later than 1 year after the enactment of this paragraph, each State regulatory authority 

(with respect to teach electric utility for which it has ratemaking authority) and each nonregulated 

electric utility shall commence the consideration referred to in section 111, or set a hearing date for 

such consideration, with respect to the standard established by paragraph (14) of section 111(d). 

‘‘(B) Not later than 2 years after the date of the enactment of this paragraph, each State regulatory 

authority (with respect to each electric utility for which it has ratemaking authority), and each nonregulated electric utility, shall complete the consideration, and shall make the determination, referred 

to in section 111 with respect to the standard established by paragraph (14) of section 111(d).’ 
APPENDIX B: ABBREVIATED NAMES AND ACRONYMS USED IN THIS 

REPORT

AMI Advanced Metering Infrastructure 

AMR Automated Meter Reading OR Automatic Meter Reading 

ANSI American National Standards Institute 

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 

G&T Generation and Transmission 

HEFPA Home Energy Fair Practices Act 

kW Kilowatt 

kWh Kilowatt-hour 

ISO Independent System Operator 

ISO-NE Independent System Operator of New England 

LaaR Load acting as a resource (ERCOT category) 

MADRI Mid-Atlantic Distributed Resources Initiative 

MISO Midwest Independent System Operator 

MRO Midwest Reliability Organization 

MRTU Market redesign and technology update 

MWDRI Midwest Demand Response Initiative 

MW Megawatt 

MWh Megawatt-hour 

NAESB North American Energy Standards Board 

NERC North American Electric Reliability Corporation 

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 

RPM Reliability Pricing Model 

RTO Regional Transmission Organization 

SERC SERC Reliability Corporation 

SPP Southwest Power Pool, Inc. 

SPPR Southwest Power Pool Regional Entity 

TRE Texas Reliability Entity 

WECC Western Electricity Coordinating Council 

54 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
 

APPENDIX C: SURVEY GLOSSARY

The terms and definitions 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 oneway communication, and real-time meters with built-in two-way 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, ten-minute non-synchronous, thirtyminute 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 nonprofit 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 System or by the energy provider on the basis of energy demand or annual usage 

exceeding some specified limit set by the energy provider. 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 55
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 time-based 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. 

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. 

56 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
 

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. 

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 Form EIA-861. 

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. 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 57
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. 

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. 

58 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
 

Maximum Demand of Customers: The highest level of total demand, in MWs, for customers 

participating in a demand response program, excluding any demand reduction that results from the 

program. The maximum noncoincident 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. 

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 Reliability 

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 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 59
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. 

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 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 buyback, 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 2009 calendar year. 

Real Time Meters: Meters that measure energy as used, with built-in two-way communication 

capable of recording and transmitting instantaneous data. 

60 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
 

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 dayahead 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. 

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 notfor-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. 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 61
62 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             

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. 

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 optout 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. 
APPENDIX D: 2010 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 demand response to 

customers would help fulfill the requirement. 

In the first half of 2010 Commission Staff: 

 Identified potential survey respondents (“the survey population”); and 

 Developed a voluntary survey by revising previous demand response and advanced 

metering surveys, and developed an electronic survey form in Adobe® Reader® PDF 

format. 

Beginning in May of 2010 Z, INC. and their subcontractor KEMA: 

 Developed a sampling design based on the 2006 and 2008 FERC Demand Response 

and Advanced Metering Surveys; 

 Implemented a custom survey processing system in MicroSoft Access, which linked 

to the FERC-provided PDF Survey; 

 Reviewed the survey population and inactivated out of scope companies; 

 Fielded the 2010 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 requested from all 3,454 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 survey population was based on the universe of respondents identified by 

the Energy Information Administration (EIA) for their Form EIA-861. 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 that 96 entities were outside the scope 

of the survey or no longer in operation. These entities were inactivated in the survey database 

resulting in an active frame of 3,358. Out of this active group, 1,755 entities responded to the 

2010 FERC Survey (a response rate of over 52 percent), a decrease from the 2008 response 

rates of 60 percent (for the advanced metering survey) and 55 percent (for the demand 

response survey). 

 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 63
Development of the FERC Survey and Sampling Design 

The 2010 FERC Survey was conducted subject to Office of Management and Budget (OMB) 

authorization issued March 3, 2010 (OMB control number 1902-0251). As with past 

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. One parent section contained questions one through seven, and 

two child sections covered retail and wholesale demand response programs, as described 

below: 

Parent record (only one record per respondent) 

Question 1: Entity name, ID number, company name and 

ownership type. Primary and supervisory contact information. 

Question 2: Advanced meter and total meter counts by State and customer class. 

Question 3: Number of retail customers and meters, by NERC region and customer class. 

(Respondents with demand response or time-based rates/tariffs skipped this 

 question; those without such programs finished the survey at this question.) 

Question 4: Number of retail customers that can access the amount and frequency of their 

electricity use measured at least hourly, by display type and by customer class. 

Question 5: Plans for demand response programs and time-based rates/tariffs over the next 

 five years, by number of programs, type of program, and potential peak 

 reduction. 

Question 6: NERC regions and States in which the respondent operates. 

Question 7: For each NERC and State combination in Question 6, the number of retail 

 customers, by customer class. 

Child 1 Record (repeated as needed)

Question 8: Detailed retail demand response program information by NERC region, State, 

customer class and Program type. 

Child 2 Record (repeated 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 

asked to complete only Questions 1 through 3. Also, by having all the information relative to 

64 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
one demand response Program on one page (Child record), respondents could copy as many 

pages as required to cover all of their programs. 

The content of the 2010 FERC Survey was similar to the content of the 2008 FERC Survey. 

The structure of the survey, however, was altered by combining two formerly separate 

surveys (FERC-727 and FERC-728) into a single survey, FERC-731, with both advanced 

metering and demand response topics. This was intended to simplify the respondent’s task 

and increase the probability of response. 

 

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 3,454 organizations, as 

listed in Table D1. 

The region definition used in the 2010 FERC Survey is that used by the North American 

Electric Reliability Corporation’s eight regional entities. 

Table D1. Survey population of the 2010 and 2008 FERC Surveys 

2010 Group Name

        

2010

number 2008 Group Name

2008

number

Municipally Owned Utility   1,840 Municipal   1,845

Cooperatively Owned Utility   878 Cooperative   884

Investor Owned Utility   207 Investor Owned 223

Retail Power Marketer 128 Retail 107

Wholesale Power Marketer 46 Power Marketer   162

Political Subdivision   127 Public Utility District 126

Municipal Power Agency 21 Municipal Authority   21

State 21

Federal and State 29 Federal   10

Regional Transmission

Organization/Independent

System Operator

7

Independent System

Operator   8

Curtailment Service Provider 11 N/A

Transmission 7 N/A

Total Classified 3,301

Unclassified 57 N/A

Active Total 3,358

Inactive 96

Grand Total   3,454 3,407

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 65
FERC Survey Methodology 

On June 1, 2010, the survey was distributed through a mass e-mailing. The email message 

included an introduction to the survey, directions and the glossary. The survey itself was 

attached to the e-mail, a departure from the on-line version used for the 2008 FERC Survey. 

The PDF document was programmed such that the respondents could respond directly on the 

PDF form. They then would e-mail the survey form to an e-mail account set up specifically 

for the collection of the surveys; another account was used for inquiries from respondents 

(DRSurvey@ferc.gov and DRSurvey-Help@ferc.gov). 

Z, INC., in collaboration with the FERC staff, strove to maximize the response rate. A phone 

hotline was open daily between 9 am and 6 pm to assist respondents. The FERC staff also 

disseminated the survey through postal mail, to capture any respondents that might not have 

internet access or a functional e-mail account. Z, INC. sent out a reminder e-mail to all those 

who had not responded as of July 13, 2010, and made follow-up calls to 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 or 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 surveys came in, Z, INC. employed a rigorous system of verification and due diligence. 

Beyond the software used to collect the submissions to the e-mail account, Z, INC. also 

searched through the account looking for attachments that had not been included in the 

upload or other related problems. Anomalies and seemingly incorrect information received a 

flag, indicating the necessity for personal follow-up. 

Efforts were made to ensure the optimal structure and processing of the incoming data. Z, 

INC. created a specialized database for the 2010 FERC Survey. This database included all 

available information for each firm selected as a potential respondent, an amalgamation of 

EIA-861 data and FERC’s own records. A linked but separate portion of the database was 

then created to collect and track the incoming data from the survey participants. This 

allowed quick rectification of any updates or aberrations from past surveys or past 

information that might have been outdated or incorrect. This maintenance of the data 

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, Commission staff used the 2010 FERC Survey to estimate 

advanced metering penetration rate and potential peak load reduction. The following 

discussion describes the analysis undertaken by Commission staff and Z Inc.’s subcontractor 

KEMA Inc., who was responsible for the analysis. 

66 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Advanced Metering 

Commission staff developed estimates of the penetration rate of national and regional 

advanced metering, as required by EPAct 2005, at the national, regional, and state levels, as 

well as by load serving entity type. These estimates were to reflect all of the 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 2010 FERC Survey. Some entities did not respond to the 

2010 FERC Survey, 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 KEMA was to make statistically informed imputations of the number 

of advanced and total meters for nonresponding entities using published information from the 

2008 EIA-861 and 2008 FERC Survey. The EIA-861 file 2 contains customer counts at the 

entity level by customer class. These are highly correlated with total meter counts, a FERC 

Survey item. Other FERC Survey items – customer counts and advanced meters – have 

direct counterparts in the EIA-861. For the “Other” customer class (i.e., retail customers not 

classified as residential, commercial, or industrial), there is no comparable field in the EIA861 to link to the 2010 FERC Survey. For this customer class, the 2008 FERC Survey was 

used as a source for the comparison survey field. 

Trends in survey fields between survey years often reflect general growth or decline. For 

example, increases or decreases in total meter count tend to reflect population dynamics. 

Advanced meter count changes may reflect population dynamics as well, but also 

programmatic initiatives by the electricity retailer and other drivers. Simple imputation of 

2008 EIA-861 or 2008 FERC Survey field values for missing values in the 2010 FERC 

Survey would not reflect the general trends. For example, suppose a utility did not respond 

to the 2010 FERC Survey but provided total advanced meters by sector in the 2008 EIA-861. 

An imputation procedure that simply substitutes that entity’s 2008 EIA-861 advanced meter 

count into the 2010 FERC Survey would not reflect general growth trends. 

To account for these trends, statistical models were used to create trend factors to apply to 

the 2008 data. The models were built using entities that had responded to both the 2010 

FERC Survey and to either the 2008 FERC Survey or the EIA-861. The factors produced by 

these models could then be applied to the value for the 2008 comparison survey field for the 

2010 FERC Survey nonrespondent. Separate models were fit for small, medium, and large 

entities for each survey field to reflect different growth among size classes of load-serving 

entities. Continuing the example above, instead of a straight substitution of the 2008 EIA-861 

advanced meter count into the 2010 FERC Survey, the 2008 FERC Survey count would be 

multiplied by the modeled growth rate between 2008 EIA-861 and the 2010 FERC Survey. 

If the entity reported 8,000 advanced meters in 2008 and the modeled growth rate was twenty 

percent for other entities in its size class, the 2010 imputed value would be 8,000 x 1.2 = 

9,600 advanced meters. 

To restrict the effect of the modeled growth rates on the analysis, the sets of entities used in 

the statistical models were restricted to those whose 2010 counts were between half and 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 67
double their 2008 counts – so if several entities had ten times the advanced meters in the 

2010 FERC Survey as the 2008 FERC Survey, the modeled growth rates were not overly 

influenced by these massive individual increases. Additionally, the modeled growth factor 

was capped at a 10 percent change for meter and customer counts, which are not expected to 

vary significantly between comparison survey years. In most cases the modeled growth in 

meters and customers for the size classes between 2008 and 2010 FERC surveys was 

between one and five percent. 

Tables and figures in this report labeled as having estimated count totals are comprised of the 

responding entity counts plus the imputed counts for the nonrespondents according to the 

method described above. No imputation was done for nonresponding entities with missing 

values in the comparison fields in the 2008 FERC Survey. 

Alternative approaches were considered, such as applying weights to the meter and customer 

data submitted by 2010 FERC Survey respondents to account for nonrespondents. While 

applying nonresponse weights is common in survey estimation, they can lead to volatile 

estimates for subgroups of the survey population with high levels of nonresponse. For 

example, if fifty municipal utilities in a state were asked to complete the FERC Survey and 

only fifteen responded, the weighted estimate assumes that the number of residential 

advanced meters with respect to a size variable, which may be total customers (as reported in 

the 2008 EIA-861), is the same for the 15 respondents as the 35 nonrespondents. 

Commission staff believes that entities who respond to the FERC Survey may have higher 

advanced metering penetration than those who do not respond, which would violate the key 

assumption of nonresponse weighting. If all of the meters the fifteen municipal utilities own 

are advanced, assuming the same of the 35 nonresponding municipal utilities in the state may 

not be appropriate. 

The statistical regression model-adjusted imputation approach controls against self-selection 

bias by having past entity-level values—adjusted for growth trends—account for the meters 

and customers of nonresponding entities. Since many of the past entity-level values come 

from the mandatory EIA-861 survey, they are less subject to self-selection bias than the 

responses to the voluntary FERC Survey. Further, the response rates of the random samples 

are similar to the general response rates, as shown in Table H2, suggesting that self-selection 

is not significant. 

There is, however, the chance that the regression coefficient is biased towards the entities 

used in the regression, so the coefficients by design are limited to change the meter and 

customer counts from their respective 2008 FERC Survey counts by no more than 10 

percent. 

Demand Response 

The general extrapolation approach for the demand response section of the 2010 FERC 

Survey was consistent with the approach used for the meter and customer counts in the 

advanced metering section, as described above. The entity-level comparison survey field 

values come from either the 2008 FERC Survey or EIA-861. The 2008 EIA-861 contains 

68 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
customer class-level potential and actual peak load reduction from both time-based and 

incentive-based programs. The 2008 FERC Survey was used, as in the advanced metering 

section, for the “other” customer class balance group, and for customer counts and peak load 

reduction by specific program type. 

As with the meter and customer counts, the demand response survey item regressions were 

fit on 2008-2010 paired entity-level survey data, and resulted in factors yielding between half 

and double the 2008 values. Unlike the regression results for the total number of meters and 

total number of customers, the factors for demand response fields were not restricted to a 

maximum 10 percent statistical model-based adjustment over the 2008 values. The cap was 

not applied to demand response fields because, based on research, it is reasonable for the 

potential for peak load reduction to have increased by more than 10 percent between survey 

years. 

More details on the imputation procedure used to account for nonresponding entities can be 

found in Appendix H. 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 69
Table D2. Assigned demand response program types for RTO/ISO programs 

RTO/ISO Program Acronym Program Name Service Type FERC Staff-assigned 

Program Type 

CAISO PLP Participating Load Program Energy Demand Bidding and 

Buyback 

CAISO PLP Participating Load Program Reserve Demand Bidding and 

Buyback 

ERCOT EILS Emergency Interruptible Load Service Capacity Emergency Demand 

Response 

ERCOT LaaR / RRS / UFR Loads Acting as a Resource providing 

Responsive Reserve Service -- Under 

Frequency Relay Type 

Reserve Spinning Reserves 

ERCOT LaaR / RRS / CLR Loads Acting as a Resource providing 

Responsive Reserve Service -- Controllable 

Load Resource Type 

Reserve Spinning Reserves 

ERCOT LaaR / NSRS / Loads Acting as a Resource providing NonSpinning Reserve Service Reserve Non-spinning Reserves 

ERCOT CLR Controllable Load Resources providing 

Regulation Service 

Regulation Regulation 

ISO-NE RTDRP Real Time Demand Response Program 

[Capacity Component] 

Capacity Emergency Demand 

Response 

ISO-NE RTDRP Real Time Demand Response Program [Energy 

Component] 

Energy Emergency Demand 

Response 

ISO-NE DALRP-RTDR Day-Ahead Load Response Program for RTDRP Energy Demand Bidding and 

Buyback 

ISO-NE DALRP- RTPR Day-Ahead Load Response Program for RTPR Energy Demand Bidding and 

Buyback 

ISO-NE DRR Demand Response Reserves Pilot Reserve Non-spinning Reserves 

ISO-NE RTPR Real Time Price Response Program Energy Demand Bidding and 

Buyback 

ISO-NE RTDR Real Time Demand Response Resource Capacity Emergency Demand 

Response 

ISO-NE OP and SP FCM: On-Peak, Seasonal Peak Resources Capacity Load as a Capacity 

Resource 

ISO-NE RTEG Real Time Emergency Generation Resource Capacity Emergency Demand 

Response 

MISO EDR Emergency Demand Response Energy Emergency Demand 

Response 

MISO DRR-I Demand Response Resource Type I Energy Spinning Reserves 

MISO DRR-I Demand Response Resource Type-I Reserve Spinning Reserves 

MISO DRR-II Demand Response Resource Type II Energy Regulation 

MISO DRR-II Demand Response Resource Type-II Reserve Regulation 

MISO DRR-II Demand Response Resource Type-II Regulation Regulation 

MISO LMR Load Modifying Resource Capacity Load as a Capacity 

Resource 

NYISO DADRP Day-Ahead Demand Response Program Energy Demand Bidding and 

Buyback 

NYISO DSASP Demand Side Ancillary Services Program Reserve Spinning Reserves 

NYISO DSASP Demand Side Ancillary Services Program Reserve Non-spinning Reserves 

NYISO DSASP Demand Side Ancillary Services Program Regulation Regulation 

NYISO EDRP Emergency Demand Response Program Energy Emergency Demand 

Response 

70 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 71

RTO/ISO Program Acronym Program Name Service Type FERC Staff-assigned 

Program Type 

NYISO SCR Installed Capacity Special Case Resources 

(Energy Component) 

Energy Load as a Capacity 

Resource 

NYISO SCR Installed Capacity Special Case Resources 

(Capacity Component) 

Capacity Load as a Capacity 

Resource 

PJM Economic Economic Load Response Energy Demand Bidding and 

Buyback 

PJM Economic Economic Load Response Reserve Spinning Reserves 

PJM Economic Economic Load Response Reserve Non-spinning Reserves 

PJM Economic Economic Load Response Regulation Regulation 

PJM Emergency (Energy 

Only) 

Emergency Load Response - Energy Only Energy Emergency Demand 

Response 

PJM Emergency Full Emergency Load Response (Capacity 

Component) 

Capacity Load as a Capacity 

Resource 

PJM Emergency Full Emergency Load Response (Energy 

Component) 

Energy Load as a Capacity 

Resource 

SPP VDDR Variable Dispatch Demand Response Energy Emergency Demand 

Response 

Sources: ISO/RTO Council, North American Wholesale Electricity Demand Response 2009 Comparison 

(http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-

003829518EBD%7D/IRC%20DR%20M&V%20Standards%20Implementation%20Comparison%20(2009-04-

28).xls); FERC staff. 
APPENDIX E: FERC SURVEY RESPONDENTS

Appendix E lists the entities that responded to the 

2010 FERC Survey, organized by entity type. 

Cooperatively Owned Utilities 

A & N Electric Cooperative     MD,VA

Adams Electric Cooperative     IL

Adams Electric Cooperative, Inc.     PA

Adams Rural Electric Cooperative, Inc.     OH

Adams‐Columbia Electric Cooperative     WI

Agralite Electric Cooperative   MN

Aiken Electric Cooperative, Inc.   SC

Albemarle Electric Member Corp.     NC

Alder Mutual Light Co., Inc.    WA

Alfalfa Electric Cooperative, Inc.   KS,OK

Alger‐Delta Cooperative Electric Association    MI

Allegheny Electric Cooperative, Inc.     PA

Amicalola Electric Membership Corp     GA

Anza Electric Cooperative, Inc.    CA

Appalachian Electric Cooperative    TN

Arizona Electric Power Cooperative, Inc. AZ

Arkansas Electric Cooperative Corporation     AR

Arkansas Valley Electric Cooperative Corporation AR,OK

Arrowhead Electric Cooperative, Inc.     MN

Ashley‐Chicot Electric Cooperative, Incorporated AR

Atchison‐Holt Electric Cooperative    IA,MO

Bailey County Electric Cooperative Association TX

Bandera Electric Cooperative, Inc.    TX

BARC Electric Cooperative   VA

Barrow Utilities & Electric Coop., Inc.     AK

Barry Electric Cooperative   MO

Bartlett Electric Cooperative   TX

Basin Electric Power Cooperative     ND,SD

Bayfield Electric Cooperative   MI,WI

Beartooth Electric Cooperative, Inc.    MT,WY

Beauregard Electric Coop., Inc.    LA

Bedford Rural Electric Cooperative, Inc.     PA

Beltrami Electric Cooperative, Inc.     MN

Benton Rural Electric Association     WA

Big Country Electric Cooperative, Inc.    TX

Big Flat Electric Co‐op, Inc.    MT

Big Horn Rural Electric MT,    WY

Big Sandy Rural Electric Cooperative Corporation KY

Black Hills Electric Cooperative, Inc     SD

Black River Electric Cooperative   MO

Black River Electric Cooperative, Inc.     SC

Black Warrior Electric Membership Corporation   AL

Blue Grass Energy Cooperative Corporation     KY

Blue Ridge Electric Membership Corporation    NC

Bluebonnet Electric Cooperative, Inc.     TX

Bluestem Electric Cooperative Inc.     KS

Boone County Rural EMC   IN

Boone Electric Cooperative    MO

Brazos Electric Power Cooperative, Inc.     TX

Broad River Electric Cooperative, Inc.    NC,SC

Brown County Rural Electrical Assn.     MN

Brown‐Atchison Electric Cooperative  

        Association, Inc.       KS

Brunswick Electric Membership Corporation   NC

Buckeye Power, Inc.   OH

Buckeye Rural Electric Cooperative   OH

Burt County Public Power District   NE

Butler County Rural Electric Cooperative   IA

Butte Electric Cooperative, Inc.   SD

C & L Electric Cooperative Corporation   AR

Calhoun County Electric Cooperative Association   IA

Callaway Electric Cooperative   MO

Cam Wal Electric Cooperative, Inc   SD

Canadian Valley Electric Cooperative   OK

Caney Fork Electric Cooperative, Inc.   TN

Capital Electric Cooperative, Inc.   ND

Carbon Power & Light Inc   WY

Carroll County REMC   IN

Carroll Electric Cooperative Corporation                   AR,MO

Carroll Electric Cooperative, Inc   OH

Carteret‐Craven Electric Membership Corporation   NC

Cass County Electric Cooperative   ND

Cavalier Rural Electric Coop.,Inc.   ND

Cedar‐Knox Public Power District   NE

Central Alabama Electric Cooperative   AL

Central Electric Co‐Op   OR

Central Electric Cooperative   SD

Central Electric Cooperative, Inc.   PA

Central Electric Membership Corporation   NC

Central Electric Power Association   MS

Central Electric Power Cooperative   MO

Central Electric Power Cooperative, Inc.   SC

Central Florida Electric Cooperative, Inc.   FL

Central Georgia Electric Membership Corp   GA

Central Iowa Power Cooperative   IA

Central Virginia Electric Cooperative   VA

Chariton Valley Electric Cooperative, Inc.   IA

Chickasaw Electric Cooperative   TN

Choptank Electric Cooperative, Inc.   MD

Chugach Electric Association, Inc.   AK

Cimarron Electric Cooperative   OK

Citizens Electric Corporation   MO

Claiborne Electric Cooperative, Inc.   LA

Clark County Rural E M C   IN

Clarke Electric Cooperative, Inc.   IA

Claverack Rural Electric Cooperative, Inc.   PA

Clay County Electric Cooperative Corporation   AR

Clay Electric Cooperative, Inc.   FL

Clay‐Union Electric Corporation   SD

Clearwater‐Polk Electric Cooperative, Inc.   MN

CMS Electric Cooperative, Inc.   KS

Coahoma Electric Power Association   MS

Coast Electric Power Association   MS

Coastal Electric Membership Corporation   GA

Codington‐Clark Electric Cooperative, Inc   SD

Colquitt Electric Membership Corporation   GA

72 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Cooperatively Owned Utilities 

(Continued) 

Columbia Basin Electric Cooperative, Inc.   OR

Columbus Electric Cooperative, Inc.   AR,NM

Comanche Co Electric Cooperative Assn Inc   TX

Community Electric Cooperative     VA

Co‐Mo Electric Cooperative, Inc.     MO

Concordia Electric Cooperative, Inc.     LA

Connexus Energy         MN

Consolidated Electric Cooperative     MO

Consumers Energy Cooperative    IA

Consumers Power Inc.       OR

Continental Divide Electric Cooperative, Inc. NM

Cookson Hills Electric Cooperative, Inc.   OK

Cooperative Light and Power Association MN

Coos‐Curry Electric Cooperative, Inc.    OR

Copper Valley Electric Association, Inc.    AK

Corn Belt Energy Corporation      IL

Covington Electric Cooperative, Inc.     AL

Coweta‐Fayette EMC       GA

Craig‐Botetourt Electric Cooperative     VA,WV

Craighead Electric Cooperative Corporation   AR

Crawford Electric Cooperative, Inc     MO

Crow Wing Cooperative Power & Light Company  MN

Cuivre River Electric Cooperative, Inc     MO

Cullman Electric Cooperative      AL

Cumberland Electric Membership Corporation   TN

Dairyland Power Cooperative     IA,MN,WI

Dakota Electric Association       MN

Daviess‐Martin County       REMC IN

Deep East Texas Electric Cooperative, Inc. TX

Delaware Electric Cooperative, Inc.     DE

Delta Electric Power Association     MS

Denton County Electric Cooperative, Inc.   TX

Deseret Generation & Transmission  

    Co‐operative     AZ,CO,NV,UT,WY

Diverse Power Incorporated     AL,GA

Dixie Electric Cooperative     AL

Dixie Electric Membership Corporation   LA

Dixie Electric Power Association     MS

Dixie Escalante Rural Electric Association, Inc.   AZ,UT

Doniphan Electric Cooperative Assn, Inc. KS

Douglas Electric Cooperative, Inc     SD

Douglas Electric Cooperative, Inc.     OR

Dubois Rural Electric Cooperative, Inc.    IN

Duck River Electric Membership Corporation   TN

Duncan Valley Electric Cooperative     AZ,NM

Dunn County Electric Cooperative    WI

East central Oklahoma Electric Cooperative, Inc.  OK

East Mississippi Electric Power Association   MS

East River Electric Power Cooperative, Inc.   MN,SD

East‐Central Iowa Rural Electric Cooperative   IA

Eastern Maine Electric Cooperative, Inc.   ME

Eastside Power Authority   CA

Edgecombe‐Martin County Electric  

   Membership Corp.   NC

Edisto Electric Cooperative, Inc.   SC

Egyptian Electric Cooperative Association IL

Elmhurst Mutual Power & Light   WA

EnergyUnited Electric Membership Corporation   NC

Escambia River Electric Cooperative   FL

Excelsior Electric Membership Corporation (EMC)

GA

Fairfield Electric Cooperative, Inc.   SC

Fall River Rural Electric Cooperative, INC               ID,MT,WY

Fannin County Electric Cooperative, Inc.   TX

Farmers Electric Company, Ltd ID

Farmers' Electric Coop, Inc of New Mexico   NM

Farmers Electric Cooperative   TX

Farmers Electric Cooperative Corporation   AR

Farmers Electric Cooperative, Inc. IA

Farmers' Electric Cooperative, Inc.   MO

Farmers Mutual Electric Company   IL

Farmers Rural Electric Cooperative Corporation   KY

Federated Rural Electric Association   MN

FEM Electric Association, Inc   SD

Fergus Electric Cooperative, Inc.   MT

First Electric Cooperative Corporation   AR

Flathead Electric Cooperative, Inc.   MT

Flint Electric Membership Corporation   GA

Flint Hills Rural ECA, Inc   KS

Florida Keys Electric Cooperative Association, Inc.

FL

Forked Deer Electric Cooperative   TN

Four County Electric Membership Corporation   NC

Franklin Electric Cooperative AL

Franklin Rural Electric Cooperative   IA

Fulton County Rural Electric

    Membership Corporation   IN

Garkane Energy Cooperative, Inc                            AZ,UT

Garland Light and Power Co.   WY

Gascosage Electric Cooperative   MO

Georgia Transmission Corporation   GA

Gibson Electric Membership Corporation   TN

Glacier Electric Cooperative, Inc.   MT

Golden Spread Electric Cooperative, Inc.   TX

Goodhue County Cooperative Electric  

         Association   MN

Graham County Electric Cooperative, Inc.   AZ

Grand Valley Rural Power Lines, Inc.   CO

Grayson‐Collin Electric Cooperative, Inc.   TX

Great River Energy   MN

Greenbelt Electric Cooperative, Inc.   TX

Grundy Electric Cooperative, Inc.   MO

Guadalupe Valley Electric Cooperative, Inc.   TX

Guernsey‐Muskingum Electric Cooperative, Inc.   OH

Gulf Coast Electric Cooperative, Inc.   FL

Gunnison County Electric Association, Inc.   CO

Guthrie County Rural Electric Cooperative   IA

Habersham Electric Membership Corporation   GA

Hancock County Rural Electric Membership Corp.IN

Hancock Wood Electric Cooperative, Inc   OH

Harrison Rural Electrification Association, Inc.   WV

Hart Electric Membership Corporation   GA

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 73
Cooperatively Owned Utilities 

(Continued)

Haywood Electric Membership Corporation       GA,NC,SC

H‐D Electric Cooperative, Inc                                   MN,SD

Heart of Texas Electric Cooperative   TX

Heartland Rural Electric Cooperative, Inc.               KS

Hendricks County Rural Electric  

    Membership Coop   IN

Henry County Rural Electric  

  Membership Corporation   IN

Hickman‐Fulton Co. Rural Electric

   Cooperative Corp.   KY

High Plains Power Inc.   WY

Highline Electric Association   CO,NE

HILCO Electric Cooperative, Inc.     TX

Hill County Electric Cooperative, Inc.     MT

Holmes‐Wayne Electric Cooperative, Inc.   OH

Holston Electric Cooperative      TN

Holy Cross Energy        CO

Horry Electric Cooperative, Inc.     SC

Houston County Electric Cooperative, Inc.   TX

Howell‐Oregon Electric Cooperative     MO

Humboldt County Rural Electric Cooperative IA

Idaho Cnty L&P Coop Assn, Inc.   ID

Illinois Rural Electric Cooperative     IL

Indian Electric Cooperative     OK

Inside Passage Electric Coop       AK

Intercounty Electric Cooperative Association   MO

Inter‐county Energy Cooperative Cooperation KY

Irwin Electric Membership Corporation    GA

Itasca‐Mantrap Cooperative  

   Electrical Association     MN

J‐A‐C Electric Cooperative Inc.   TX

Jackson Electric Cooperative      WI

Jackson Electric Cooperative, Inc    TX

Jackson Electric Membership Corporation GA

Jackson Energy Coop Corp       KY

Jackson Purchase Energy Corporation    KY

Jasper County Rural Electric  

   Membership Corporation     IN

Jasper Newton Electric Cooperative, Inc.   TX

Jemez Mountains Electric Cooperative, Inc.   NM

Jo‐Carroll Energy, Inc.(NFP)       IL

Joe Wheeler Electric Membership Corporation   AL

Johnson County REMC     IN

Jones‐Onslow Electric Membership Corporation   NC

Jump River Electric Cooperative, Inc.     WI

KAMO Electric Cooperative, Inc    MO,OK

Kandiyohi Power Cooperative    MN

Kankakee Valley Rural Electric  

   Membership Corporation       IN

Kansas Electric Power Cooperative, Inc.   KS

Karnes Electric Cooperative Inc.     TX

Kauai Island Utility Cooperative     HI

Kay Electric Cooperative       OK

KC Electric Association, Inc.       CO

KEM Electric Cooperative, Inc.     ND

Kiamichi Electric Cooperative, Inc   OK

Kingsbury Electric Cooperative, Inc.   SD

Kodiak Electric Association, Inc.   AK

Kootenai Electric Cooperative, Inc ID

Kosciusko REMC   IN

Kotzebue Electric Assoc.   AK

Kwethluk Inc. AK

La Plata Electric Association, Inc.   CO

Laclede Electric Cooperative   MO

Lacreek Electric Association, Inc.                             NE,SD

LaGrange County Rural Electric Membership Corp.IN

Lake Region Electric Cooperative   MN

Lakeview Light & Power   WA

Lamar County Electric Cooperative Association   TX

Lamb County Electric Cooperative   TX

Lane‐Scott Electric Cooperative, Inc   KS

Lea County Electric Cooperative Inc.                       NM,TX

Lee County Electric Cooperative, Incorporated   FL

Licking Valley RECC   KY

Lighthouse Electric Cooperative, Inc.   TX

Linn County Rural Electric Cooperative Assoc.   IA

Little Ocmulgee El Member Corp   GA

Logan County Cooperative Power & Light  

Assoc Inc    OH

Lumbee River Electric Membership Corporation   NC

Lynches River Electric Cooperative, Inc   SC

Lyntegar Electric Cooperative, Inc.   TX

Lyon Rural Electric Cooperative IA

Lyon‐Lincoln Electric Cooperative, Inc. MN

M & A Electric Power Cooperative   MO

Macon Electric Cooperative   MO

Magic Valley Electric Cooperative, Inc.   TX

Magnolia Electric Power Association   MS

Maquoketa Valley REC IA

Marshall County Rural Electric Membership Corp. IN

Marshall‐DeKalb Electric Cooperative   AL

McCone Electric Co‐op., Inc.   MT

McDonough Power Coop IL

McKenzie Electric Cooperative, Inc.   ND

McLean Electric Cooperative, INC ND

McLeod Cooperative Power Association   MN

Meade County RECC   KY

Mecklenburg Electric Cooperative                          NC,VA

Medina Electric Cooperative, Inc.   TX

Meeker Cooperative Light & Power Association MN

Menard Electric Cooperative   IL

Mid South Synergy   TX

Middle Kuskokwim Electric Cooperative, Inc. AK

Mid‐Ohio Energy Cooperative, Inc. OH

Midwest Electric Inc   OH

Midwest Energy Cooperative                                   IN,MI,OH

Midwest Energy, Inc.   KS

Mid‐Yellowstone Electric Cooperative, Inc.   MT

Mille Lacs Energy Cooperative   MN

Minnesota Valley Electric Cooperative MN

Minnkota Power Cooperative, Inc.   ND

Mississippi County Electric Cooperative , Inc.   AR

Missouri Rural Electric Cooperative   MO

MJM Electric Cooperative, Inc. IL

74 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Cooperatively Owned Utilities 

(Continued) 

Modern Electric Water Company   WA

Monroe County Electric Co‐Operative, Inc. IL

Moon Lake Electric Assn. Inc.                                   CO,UT

Mora San Miguel Electric Cooperative Inc.   NM

Moreau‐Grand Electric Cooperative, Inc.   SD

Mor‐Gran‐Sou Electric Cooperative, Inc.   ND

Mountain Electric Cooperative, Inc.   TN

Mountain Parks Electric, Inc.   CO

Mountain View Electric Association, Inc. CO

Natchez Trace Electric Power Association   MS

Navarro County Electric Cooperative, Inc.   TX

Navopache Electric Cooperative, Inc.     AZ,NM

NC Electric Membership Corp     NC

Nemaha‐Marshall Electric     KS

Nespelem Valley Electric Cooperative, Inc. WA

New Enterprise Rural Electric Cooperative, Inc.   PA

New Hampshire Electric Cooperative, Inc   NH

Newberry Electric Cooperative, Inc.    SC

New‐Mac Electric Cooperative, Inc.     MO

Newton County Rural Electric

    Membership Corporation       IN

Niobrara Electric Association               NE,SD,WY

Nishnabotina Valley Rural Electric Cooperative IA

Noble County REMC       IN

Nobles Cooperative Electric               IA,MN

North Alabama Electric Cooperative    AL

North Arkansas Electric

    Cooperative, Incorporated     AR

North Central Mo. Electric Coop     MO

North Georgia Electric Membership  

   Corporation         GA

North Itasca Electric Cooperative Inc.     MN

North Plains Electric Cooperative, Inc.     TX

North Star Electric Cooperative, Inc.    MN

North Western Electric Cooperative, Inc.   OH

Northeast Missouri Electric Power Cooperative   MD

Northeast Oklahoma Electric Cooperative OK

Northeastern REMC       IN

Northern Lights, Inc.                ID,MT,WA

Northern Neck Electric Cooperative     VA

Northern Rio Arriba Electric Coop., Inc.   NM

Northern Virginia Electric Cooperative    VA

Northwestern Rural Electric Coop

    Association, Inc.        PA

NorVal Electric Cooperative       MT

Nueces Electric Cooperative, Inc.     TX

Oahe Electric Coop Inc.       SD

Ocmulgee Electric Membership Corporation GA

Oglethorpe Power Corporation     GA

Okanogan County Electric Cooperative Inc   WA

Okefenoke Rural El Member Corp    FL,GA

Oklahoma Electric Cooperative     OK

Old Dominion Electric Cooperative    VA

Oneida‐Madison Electric Cooperative Inc   NY

Ontonagon County Rural Electrification Assoc. MI

Orcas Power and Light Cooperative   WA

Oregon Trail Electric Consumers  

    Cooperative, Inc.   OR

Osage Valley Electric Cooperative Ass'n   MO

Osceola Electric Cooperative, Inc.   IA

Otero County Electric Cooperative, Inc.   NM

Otsego Electric Cooperative, Inc.   NY

Ouachita Electric Cooperative AR

Ozark Border Electric Cooperative   MO

Ozark Electric Cooperative, Inc.   MO

Ozarks Electric Cooperative Corporation               AR,OK

Pacific Northwest Generating Cooperative   OR

Palmetto Electric Cooperative, Inc.   SC

Panhandle Rural Electric Membership Association   NE

Parke County Rural Electric Membership  

Corporation IN

Paulding Putnam Electric Cooperative, Inc.               IN,OH

Pea River Electric Coop   AL

Peace River Electric Cooperative, Inc.   FL

Pedernales Electric Cooperative, Inc.   TX

Pee Dee Electric Cooperative, Inc.   SC

Pee Dee Electric Membership Corp.   NC

Pemiscot‐Dunklin Electric Cooperative, Inc.   MO

Peninsula Light Company   WA

Pickwick Electric Cooperative   TN

Piedmont Electric Membership Corporation   NC

Pioneer Rural Electric Cooperative OH

Pitt and Greene Electric Membership Corporation   NC

Planters Electric Membership Corporation   GA

Platte‐Clay Electric Cooperative, Inc.   MO

Plumas‐Sierra Rural Electric Cooperative                   CA,NV

Pointe Coupee Electric Membership Corporation LA

Pontotoc Electric Power Association   MS

Poudre Valley Rural Electric Association   CO

Powder River Energy Corporation                               MT,WY

Powell Valley Electric Cooperative   TN

Power Resources Cooperative OR

Prairie Land Electric Cooperative, Inc. KS

Prentiss County Electric Power Association   MS

Price Electric Cooperative   WI

Prince George Electric Cooperative   VA

Radiant Electric Cooperative, Inc.   KS

Raft River Rural Electric Cooperative, Inc.                ID, NV,

UT

Ralls County Electric Cooperative   MO

Randolph Electric Membership Corporation   NC

Rappahannock Electric Cooperative   VA

Ravalli County Electric Co‐op   MT

Rayburn Country Electric Cooperative, Inc.   TX

REA Energy Cooperative, Inc.   PA

Red Lake Electric Cooperative, Inc.   MN

Red River Valley Cooperative Power Association   MN

Red River Valley Rural Electric Association   OK

Renville‐Sibley Cooperative Power Association   MN

Rich Mountain Electric Cooperative, Inc.   AR

Rita Blanca Electric Coop, Inc.   TX

Rolling Hills Electric Cooperative, Inc.   KS

Rosebud Electric Coop Inc.   SD

Roughrider Electric Cooperative, Inc.   ND

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 75
Cooperatively Owned Utilities 

(Continued) 

Rural Electric Cooperative, Inc.   OK

Rusk County Electric Cooperative, Inc.     TX

Rutherford Electric Membership Corporation     NC

Sac Osage Electric Coop, Inc.     MO

Salem Electric     OR

Salmon River Electric Cooperative Inc.     ID

Salt River Electric Coop Corp     KY

Sam Houston Electric Cooperative, Inc     TX

San Bernard Electric Cooperative, Inc.     TX

San Luis Valley REC              CO

San Miguel Electric Cooperative, Inc.            TX

San Miguel Power Association Inc.            CO

San Patricio Electric Cooperative, Inc.            TX

Sangre De Cristo Electric Association, Inc          CO

Santee Electric Cooperative Inc.            SC

Satilla Rural Electric Membership Corporation   GA

Sawnee Electric Membership Corporation   GA

Se‐Ma‐No Electric Cooperative MO

Seminole Electric Cooperative, Inc.   FL

SEMO Electric Cooperative   MO

Shelby Electric Cooperative   IL

Shelby Energy Cooperative Inc. KY

Shenandoah Valley Electric Cooperative   VA,WV

Sheridan Electric Co‐op., Inc.   MT

Sho‐Me Power Electric Cooperative   MO

Sierra Electric Cooperative, Inc. NM

Singing River Electric Power Association AL,MS

Sioux Valley Southwestern Electric

    Cooperative, In MN,SD

Slash Pine Electric Membership Corporation   GA

Slope Electric Cooperative, Inc   ND

Smarr EMC   GA

Snapping Shoals Electric Membership Corporation   GA

Somerset Rural Electric Cooperative, Inc.   PA

South Central Arkansas Electric Cooperative, Inc.   AR

South Central Indiana REMC   IN

South Central Power Company   OH

South Kentucky Rural Electric Cooperative Corp KY,TN

South Louisiana Electric Cooperative Association LA

South Mississippi Electric Power Association MS

South Plains Electric Cooperative   TX

South Side Electric, Inc.   ID

Southeast Colorado Power Association   CO

Southeastern Electric Cooperative, Inc. OK

SouthEastern Illinois Electric Cooperative, Inc.   IL

Southern Indiana REC, Inc.   IN

Southern Iowa Electric Cooperative, Inc. IA

Southern Maryland Electric Cooperative, Inc. MD

Southern Pine Electric Power Association   MS

Southside Electric Cooperative, Crewe,Virginia   VA

Southwest Arkansas Electric Cooperative Corporation  AR

Southwest Electric Cooperative MO

Southwest Louisiana Electric Membership Corp   LA

Southwest Rural Electric Association                              OK,TX

Southwest Tennessee Electric  

Membership Corporation   TN

Southwest Texas Electric Cooperative, Inc   TX

Southwestern Electric Cooperative, Inc.          CO,NM,OK,TX

Square Butte Electric Cooperative ND

Steele‐Waseca Cooperative Electric   MN

Steuben Rural Electric Cooperative, Inc.   NY

Sullivan County Rural Electric Cooperative, Inc.   PA

Sumner‐Cowley Electric Cooperative, Inc.   KS

Sumter Electric Cooperative, Inc.   FL

Sumter Electric Membership Corporation   GA

Sun River Electric Cooperative, Inc.   MT

Surprise Valley Electrification Corp.                         CA,NV,OR

Sussex Rural Electric Cooperative, Inc.   NJ

Suwannee Valley Electric Cooperative, Inc.   FL

Swisher Electric Cooperative, Inc   TX

Tallahatchie Valley Electric Power Association   MS

Tallpoosa River Electric Cooperative, Inc. AL

Talquin Electric Cooperative, Inc,   FL

Taylor County Rural Electric Cooperative Corporation  KY

Taylor Electric Cooperative   WI

Taylor Electric Cooperative, Inc.   TX

The Caney Valley Electric Cooperative Assn., Inc.   KS

The Delaware County Electric Cooperative, Inc.   NY

The Frontier Power Company   OH

The Midwest Electric Cooperative Corporation   NE

Three Notch Electric Membership Corporation   GA

Tipmont Rural Electric Member Corp   IN

Traverse Electric Cooperative, Inc.                         MN,ND,SD

Tri County Electric Cooperative Association   MO

Tri‐County Electric Cooperative, Inc   TX

Tri‐County Electric Cooperative, Inc.           CO,KS,NM,OK,TX

Tri‐County Electric Membership Corporation   NC

Tri‐County Rural Electric Cooperative, Inc.   PA

Trinity Valley Electric Cooperative, Inc.   TX

Tuntutuliak Community Services Association AK

Twin County Electric Power Association   MS

Twin Valley Electric Cooperative KS

Unalakleet Valley Electric Cooperative   AK

Union County Electric Cooperative, Inc.   SD

Union Electric Membership Corporation   NC

United Electric Coop   ID

United Electric Coop Services   TX

United Electric Cooperative, Inc.                                    IA,MO

United Power, Inc   CO

Upper Cumberland Electric Membership Corporation  TN

Upshur Rural Electric Cooperative Corp   TX

Valley Electric Association                                                CA,NV

Valley Electric Membership Corporation   LA

Valley Rural Electric Cooperative, Inc.   PA

Verdigris Valley Electric Cooperative, Inc   OK

Verendrye Electric Cooperative, Inc.   ND

Vermont Electric Cooperative, Inc.   VT

Vigilante Electric Cooperative, Inc.                            ID,MT

Wabash County REMC IN

Wabash Valley Power Assn, Inc.                           IL,IN,MI,MO

Walton Electric Membership Corporation   GA

Warren Electric Cooperative, Inc.   PA

Wasco Electric Cooperative, Inc.   OR

Washington Electric Cooperative Inc   VT

76 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Cooperatively Owned Utilities 

(Continued) 

Washington Electric Cooperative, Inc.   OH

Washington Electric Membership Corporation   GA

Washington‐St.Tammany Electric

      Cooperative, Inc.     LA,MS

Wayne‐White Counties Electric Cooperative   IL

Webster Electric Cooperative   MO

West Central Electric Cooperative, Inc   MO

West River Electric Association, Inc.   SD

Western Cooperative Electric Association, Inc.   KS

Western Farmers Electric Cooperative   OK

Western Illinois Electric Coop   IL

Western Indiana Energy REMC   IN

Western Iowa Power Cooperative   IA

Wheatland Electric Cooperative, Inc.   CO,KS

White County REMC IN

White River Valley Electric Cooperative   MO

Whitewater Valley REMC   IN

Willwood Light & Power Co.   WY

Wiregrass Electric Cooperative, Inc.   AL

Wise Electric Coop Inc.   TX

Withlacoochee River Electric Cooperative, Inc.   FL

Woodruff Electric Cooperative Corporation   AR

Wright‐Hennepin Cooperative Electric Association   MN

Wyrulec Company NE,WY

Yampa Valley Electric Association, Inc.   CO,WY

Yazoo Valley Electric Power Association   MS

York Electric Cooperative, Inc.   SC

Curtailment Service Providers 

Comperio Energy LLC, d/b/a ClearChoice Energy   IL,PA

EnerNOC, Inc.     AL,AZ,CA,CO,CT,FL,

     GA,ID,KY,MA,ME,

MS,NC,NH,NM,NY,

RI,TN,TX,VA,VT,WA

Freedom Energy Logistics LLC        CT,MA,ME,NH,RI

Galt Power PA

Hess Corporation CT

Virtual Energy LLC NC

Federal Utilities 

Colorado River Indian Irrigation Project   AZ

Mission Valley Power   MT

Southwestern Power Administration             AR,MO,OK

Tennessee Valley Authority            AL,GA,KY,MS,NC,TN,VA

Western Area Power Administration   AZ,CA,CO,IA,KS,MN,

MT,ND,NE,NJ

Investor Owned Utilities 

AEP Texas Central Company   TX

AEP Texas North Company   TX

Ajo Improvement Company   AZ

Alabama Power Company   AL

Alcoa Power Generating, Inc.   IN

ALLETE Inc.   MN

Alpena Power Company   MI

Amana Society Service Co.   IA

Aniak Light & Power Co., Inc.   AK

Appalachian Power Company                                        VA,WV

Arizona Public Service Company AZ

Atlantic City Electric Company   NJ

Avista Corporation, dba Avista Utilities                         ID,WA

Baltimore Gas and Electric Company   MD

Bangor Hydro Electric Company   ME

Bear Valley Electric Service   CA

Black Diamond Power Company   WV

Black Hills Power, Inc.                                                MT,SD,WY

Black Hills/Colorado Electric Utility Co. LP   CO

Cap Rock Energy Corporation   TX

CenterPoint Energy Houston Electric, LLC   TX

Central Hudson Gas & Electric Corporation NY

Central Illinois Light Co   IL

Central Illinois Pub Serv Co, IL

Central Maine Power Company   ME

Central Vermont Public Service Corporation   VT

Cheyenne Light Fuel and Power   WY

Chitina Electric, Inc.   AK

Citizens Electric Co   PA

Cleco Power LLC   LA

Cleveland Electric Illuminating Co   OH

Columbus Southern Power Company   OH

Commonwealth Edison Company   IL

Competitive Energy Services, LLC   ME

Connecticut Light and Power Co   CT

Consolidated Edison Company of New York   NY

Consumers Energy Company MI

Dahlberg Light and Power Company   WI

Delmarva Power & Light Company                                DE,MD

Duke Energy Carolinas, LLC                                             NC,SC

Duke Energy Corporation                                IN,KY,NC,OH,SC

Duke Energy Indiana Inc   IN

Duke Energy Kentucky, Inc.   KY

Duquesne Light Company PA

El Paso Electric Company                                                 NM,TX

Elk Power Company WV

Empire Direct Electric Company                        AR,KS,MO,OK

Entergy Arkansas, Inc.   AR

Entergy Gulf States Louisiana, LLC LA

Entergy Louisiana, Inc.   LA

Entergy Mississippi, Inc.   MS

Entergy New Orleans, Inc.   LA

Entergy Texas, Inc.   TX

Farmington River Power Company   CT

Fitchburg Gas and Electric Light Company   MA

Florida Power & Light, Co.   FL

Florida Public Utilities FL

Georgia Power   GA

Granite State Electric Company   NH

Green Mountain Power Corporation   VT

Gulf Power Company   FL

Gustavus Electric Company   AK

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 77
Investor Owned Utilities 

(Continued) 

Hawaiian Electric   HI

Idaho Power Company                             ID,OR

Illinois Power Co IL

Indiana Michigan Power Company                       IN,MI

Indiana‐Kentucky Electric Corporation IN

Indianapolis Power & Light Company IN

Interstate Power and Light Company                  IA,MN

Jersey Central Power & Light Co   NJ

Kansas City Power & Light Company                  KS,MO

KCP&L Greater Missouri Operation Company   MO

Kentucky Power Company   KY

Kentucky Utilities   KY

Kingsport Power Company   TN

Louisville Gas & Electric Co   KY

Maine Public Service Company   ME

Massachusetts Electric Company MA

Maui Electric Company, Ltd HI

McGrath Light and Power   AK

Metropolitan Edison Co   PA

MidAmerican Energy Company                          IA,IL,SD

Mississippi Power Company       MS

Monongahela Power Company

     d/b/a Allegheny Power       WV

Mt. Carmel Public Utility Co.      IL

Nantucket Electric Company     MA

Napakiak Ircinraq Power Company     AK

Nevada Power Company       NV

New York Electric & Gas Corporation     NY

Niagara Mohawk Power Corporation     NY

North Central Power Co., Inc.     WI

Northern Indiana Public Service Co.     IN

NorthWestern Energy       SD

Nstar Electric         MA

OGE Energy Corporation       AR,OK

Ohio Edison Co.         OH

Ohio Power Company       OH

Ohio Valley Electric Corporation    IN

Omya Inc.         VT

Oncor Electric Delivery Company LLC     TX

Otter Tail Power Co.              MN,ND,SD

Pacific Gas and Electric Company     CA

PacifiCorp                    CA,ID,OR,UT,WA,WY

PECO Energy         PA

Pennsylvania Electric Co       PA

Pennsylvania Power Co       PA

Portland General Electric Company    OR

Potomac Edison Company  

     d/b/a Allegheny Power                MD,VA,WV

Potomac Electric Power Company    DC,MD

PPL Electric Utilities       NY,PA

Progress Energy Carolinas   NC,SC

Progress Energy Florida   FL

Public Service Co of NH   NH

Public Service Company of New Mexico NM

Public Service Company of Oklahoma   OK

Public Service Electric & Gas Company   NJ

Puget Sound Energy, Inc.   WA

Rochester Gas & Electric Corporation   NY

Safe Harbor Water Power Corporation   PA

San Diego Gas & Electric Company   CA

Sierra Pacific Power Company   NV

South Carolina Electric & Gas Company   SC

Southern California Edison   CA

Southern Indiana Gas & Electric Co.   IN

Southwestern Electric Power Company               AR,LA,TX

Superior Water Light and Power   WI

Tampa Electric Company   FL

Tanana Power Company   AK

The Dayton Power and Light Company OH

The Detroit Edison Company MI

The Morenci Water and Electric Company   AZ

The Narragansett Electric Company   RI

The Toledo Edison Co   OH

The United Illuminating Company   CT

Tucson Electric Power Co.   AZ

UGI Utilities, Inc   PA

Union Electric Company   MO

Union Power Company   WV

Unitil Energy Systems, Inc.   NH

Upper Peninsula Power Company   MI

Vermont Marble Power Division of Omya Inc.   VT

Virginia Electric and Power Company                            NC,VA

West Penn Power Company d/b/a Allegheny Power PA

Western Massachusetts Electric Co   MA

Wheeling Power Company WV

Wisconsin Electric Power Company   MI,WI

Wisconsin Power and Light Company   WI

Wisconsin Public Service Corporation                            MI,WI

Wisconsin River Power Company   WI

XCEL d/b/a Northern States Power Co –  

    Minnesota                                                               MN,ND,SD

XCEL d/b/a Northern States Power Co ‐ Wisconsin     MI,WI

XCEL d/b/a Public Service Co of Colorado   CO

XCEL d/b/a Southwestern Public Service Co                NM,TX

Municipal Power Agencies 

Indiana Municipal Power Agency   IN

Long Island Power Authority   NY

Massachusetts Municipal Wholesale

      Electric Company   MA

Minnesota Municipal Power Agency   MN

Municipal Electric Authority of Georgia   GA

Municipal Energy Agency of Mississippi   MS

New York Municipal Power Agency NY

Northern Municipal Power Agency   MN

Oklahoma Municipal Power Authority   OK

Piedmont Municipal Power Agency   SC

Sacramento Municipal Utility District   CA

Southern Minnesota Municipal Power Agency MN

Springville Light & Power   UT

Texas Municipal Power Agency   TX

Tuolumne Public Power Agency   CA

Utah Municipal Power Agency   UT

Walters Public Works Authority OK

78 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Washington City Power UT

Wyoming Municipal Power Agency   WY

Municipally Owned Utilities 

Adrian Public Utilities   MN

Aitkin Public Utilities MN

Albany Water, Gas & Light Commission   GA

Albertville Municipal Utilities Board AL

Algoma Utility Commission   WI

Alta Municipal Utilities   IA

Ames, City of IA

Anita Municipal Utilities IA

Arcadia Electric Utility   WI

Art Bahr   WI

Athens Utilities Board   TN

Atlantic Municipal Utilities IA

Auburn Board of Public Works   NE

Austin Energy   TX

Austin Utilities   MN

Badger Power Marketing Authority of WI Inc   WI

Bainbridge Municipal Electric Utility IN

Bamberg Board of Public Works   SC

Bancroft Municipal Utilities IA

Baraga Electric Utility   MI

Bardwell City Utilities KY

Barnesville Municipal Utility   MN

Barton Village, Inc.   VT

Bastrop Power & Light   TX

Bath Electric Gas & Water Systems   NY

Beaches Energy Services   FL

Beaver City Corporation   UT

Belmont Light & Water   WI

Benton County Electric System TN

Benton Electric System   TN

Berlin Town of MD   MD

Biwabik Public Utilities   MN

Black River Falls Municipal Electric & Water   WI

Blooming Prairie Public Utility Commission   MN

Bluffton Utilities   IN

Board of Public Utilities, City of McPherson   KS

Board of Water, Electric & Communications IA

Bolivar Energy Authority   TN

Borough of Butler   NJ

Borough of Ellwood City   PA

Borough of Goldsboro   PA

Borough of Hatfield   PA

Borough of Lavallette NJ

Borough of Mont Alto PA

Borough of New Wilmington   PA

Borough of Park Ridge   NJ

Borough of Royalton   PA

Borough of Smethport   PA

Borough of Wampum   PA

Borough of Watsontown   PA

Borough of Weatherly, PA   PA

Boscobel Municipal Utilities   WI

Bowling Green Municipal Utilities   KY

Brainerd Public Utilities   MN

Brigham City Corporation   UT

Brodhead Water & Light Commission   WI

Brooklyn Municipal Utilities   IA

Brownsville Public Utilities Board   TX

Brownsville Utility Department   TN

Bryan Texas Utilities   TX

Burlington Electric Department   VT

Cairo Public Utility Company IL

Canton Municipal Utilities   MS

Carroll County Electric Department   TN

Carrollton Board of Public Works MO

Carthage Water & Electric Plant   MO

Cascade Municipal Utilities   IA

Catawissa Borough PA

Cedar Falls Utilities IA

Cedarburg Light & Water Commission   WI

Centerville Municipal Power & Light IN

Chickamauga Electric System   GA

Chicopee Municipal Lighting Plant   MA

City and Borough of Yakutat

     d/b/a Yakutat Power AK

City of Abbeville   SC

City of Afton   IA

City of Albermarle   NC

City of Alcoa Electric Department   TN

City of Alexandria   LA

City of Alliance   NE

City Of Alma   KS

City of Alpha   MN

City of Altamont   IL

City of Anaheim   AK

City of Anoka   MN

City of Ansley   NE

City of Arapahoe   NE

City of Arma   KS

City of Attica   KS

City of Augusta   KS

City of Ava   MO

City of Azusa   CA

City of Bandon   OR

City of Bartow FL

City of Baudette   MN

City of Bedford   VA

City of Belleville   KS

City of Beloit   KS

City of Benkelman   NE

City of Bentonville AR

City of Berea Municipal Utilities   KY

City of Big Stone   SD

City of Blakely   GA

City of Blanding   UT

City of Bloomfield IA

City of Blue Hill   NE

City of Boulder City   NV

City of Bountiful   UT

City of Bowie TX

City of Brady   TX

City of Breda   IA

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 79
Municipally Owned Utilities 

(Continued) 

City of Breese IL

City of Bridgeport   NE

City of Bronson   KS

City of Brookings   SD

City of Brownton   MN

City of Brundidge   AL

City of Buffalo   MN

City of Buford   GA

City of Burke   SD

City of Burlington   CO

City of Burwell   NE

City of Bushnell    IL

City of Butler   MO

City of Cabool   MO

City of Cairo              GA

City of Caledonia               MN

City of Caliente                NV

City of Callender        IA

City of Camden   SC

City of Campbell   MO

City of Carlyle IL

City of Carmi IL

City of Cascade Locks OR

City of Castroville   TX

City of Central City   NE

City of Centralia   MO

City of Chanute   KS

City of Charlevoix   MI

City of Chaska MN

City of Chattahoochee FL

City of Chetopa   KS

City of Chewelah   WA

City of Chignik   AK

City of Clewiston   FL

City of Clinton, Combined Utility System   SC

City of Clintonville   WI

City of Cody   WY

City of Coffeyville   KS

City of Colby   KS

City of Coleman   TX

City of Collins   MS

City of Collinsville   OK

City of Columbia MO

City of Columbiana   OH

City of Columbus, Division of Power and Water OH

City of Comanche   OK

City of Commerce   GA

City of Crystal Falls   MI

City of Cuero   TX

City of Curtis NE

City of Cushing   OK

City of Cuyahoga Falls Electric Department   OH

City of Danville IA

City of David City   NE

City of Delco ID

City of Denton   TX

City of Deshler   NE

City of Detroit   MI

City of Doerun   GA

City of Dover   OH

City of Dover Public Utilities   DE

City of Drain   OR

City of Duncan   OK

City of Durant, Mississippi   MS

City of Dysart IA

City of Edmond Electric   OK

City of El Dorado Springs   MO

City of Elba   AL

City of Elberton   GA

City of Eldorado   OK

City of Elk Point   SD

City of Ellaville   GA

City of Ellensburg   WA

City of Ellsworth   IA

City of Ely ‐ Ely Utilities Commission   MN

City of Enterprise   UT

City of Escondido CA

City of Estherville   IA

City of Eudora   KS

City of Evergreen   AL

City of Fairbury   NE

City of Faith   SD

City of Falls City   NE

City of Farmersville   TX

City of Farmington   MO

City of Fayette MO

City of Fennimore   WI

City of Flatonia   TX

City of Flora   IL

City of Floresville Electric Light & Power System   TX

City of Fonda   IA

City of Forest Grove Light and Power   OR

City of Fort Collins   CO

City of Fort Meade   FL

City of Fosston   MN

City of Fountain   CO

City of Franklin   VA

City of Frederick   OK

City of Fulton   MO

City of Galion   OH

City of Gallatin   MO

City of Garden City   KS

City of Garland   TX

City of Gas City   IN

City of Gastonia   NC

City of Geneseo   IL

City of Giddings   TX

City of Gillette   WY

City of Girard   KS

City of Glasco   KS

City of Glendale   CA

City of Goldthwaite   TX

City of Gothenburg   NE

City of Granbury   TX

80 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Municipally Owned Utilities 

(Continued) 

City of Grand Island   NE

City of Grand Junction   IA

City of Granite   OK

City of Green Cove Springs Electric Utility   FL

City Of Greenfield   IN

City of Gridley   CA

City of Groton   SD

City of Groton Dept of Utilities   CT

City of Guttenberg   IA

City of Hall City   KS

City of Hamilton   OH

City of Hannibal   MO

City of Hart   MI

City of Haven   KS

City of Hebron   NE

City of Helper   UT

City of Hempstead TX

City of Hermann   MO

City of Hickman   NE

City of High Point NC

City of Highland   IL

City of Hill City   KS

City of Hillsboro   ND

City of Holyrood   KS

City of Homestead FL

City of Hominy   OK

City of Hope   ND

City of Howard   SD

City of Hubbard Light Dept. OH

City of Hudson   OH

City of Hugoton   KS

City of Hunnewell   MO

City of Independence   MO

City Of Iola   KS

City of Isabel KS

City of Jackson   GA

City of Janesville   MN

City of Jasper IN

City of Jonesville LA

City of Kasson   MN

City of Kennett MO

City of Kings Mountain   NC

City of Kosciusko   MS

City of La Plata   MO

City of Lafayette   GA

City of LaGrange, Georgia    GA

City of LaHarpe   KS

City of Lake City Electric Utility   MN

City of Lake View   IA

City of Lake Worth Utilities   FL

City of Lakefield MN

City of Lakeland, Lakeland Electric   FL

City of Lakin   KS

City of Lakota   ND

City of Lamar Utilities Board   CO

City of Larchwood   IA

City of Larned   KS

City of Las Animas Municipal Light and Power   CO

City of Laurens IA

City of Laurinburg   NC

City of Lawrenceville   GA

City of Lebanon   OH

City of Lebanon Utilities IN

City of Leesburg FL

City of Lehigh IA

City of Lewes Board of Public Works   DE

City of Liberal   MO

City of Liberty   TX

City of Lincoln Center   KS

City of Lincoln Electric System   NE

City of Linton IN

City of Livingston   TX

City of Lockhart   TX

City of Lockwood   MO

City of Lodi   CA

City of Lucas   KS

City of Lumberton   NC

City of Luverne   MN

City of Mabel   MN

City of Maddock   ND

City of Mangum   OK

City of Mansfield   MO

City of Marceline   MO

City of Marshall IL

City of Marshfield   WI

City of Maryville Electric Department   TN

City of McLaughlin SD

City of McLeansboro   IL

City of Medford   WI

City of Memphis   MO

City of Mesa   AZ

City of Metropolis   IL

City of Minden   LA

City of Mitchell   NE

City of Monroe   GA

City of Monroe City   MO

City of Monroe, NC   NC

City of Monticello   GA

City of Moore Haven   FL

City of Moran   KS

City of Morrill   KS

City of Mount Dora   FL

City of Mount Vernon   MO

City of Mountain Iron   MN

City of Mountain Lake   MN

City of Mountain View   MO

City of Murray   UT

City of Naperville   IL

City of Neligh   NE

City of Neodesha   KS

City of New Lisbon   WI

City of New Martinsville   WV

City of Newberry   FL

City of Newburg   MO

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 81
Municipally Owned Utilities 

(Continued) 

City of Newton IL

City of Newton Falls   OH

City of Niles Light Dept.   OH

City of Nixa Utilities MO

City of North Little Rock‐Electric Department   AR

City of Northwood Utilities ND

City of Norton   KS

City of Norway Dept. of Power & Light   MI

City of Odessa   MO

City of Onida   SD

City of Orangeburg Dept. of Public Utilities   SC

City of Ord   NE

City of Orient   IA

City of Osawatomie   KS

City of Osborne   KS

City of Osceola   MO

City of Oxford   KS

City of Painesville Municipal Electric Plant   OH

City of Palo Alto Utilities   CA

City of Perry MO

City of Peru   IL

City of Petoskey MI

City of Pierz   MN

City of Plankinton   SD

City of Plummer   ID

City of Poplar Bluff   MO

City of Port Angeles   WA

City of Powell   WY

City of Prescott   AR

City of Providence   KY

City of Purcell   OK

City of Radford   VA

City of Rancho Cucamonga   CA

City of Randall   MN

City of Rayne   LA

City of Redding Electric Utility CA

City of Richland   MO

City of Richland Energy Services   WA

City of Robertsdale   AL

City of Rock Falls   IL

City of Rock Hill   SC

City of Roodhouse IL

City of Roseau   MN

City of Roseville   CA

City of Round Lake               MN

City of Rupert                ID

City of Ruston   LA

City of Saint Peter   MN

City of Salamanca Board of Public Utilities NY

City of Salem   VA

City of Sanborn   IA

City of Schulenburg   TX

City of Scottsburg Municipal Electric Utility   IN

City of Scranton   KS

City of Scribner   NE

City of Seaford   DE

City of Seattle Light Department                               WA

City of Seguin   TX

City of Seneca   SC

City of Sergeant Bluff   IA

City of Seward   NE

City of Sheboygan Falls   WI

City of Shelbina   MO

City of Shiner   TX

City of Shullsburg   WI

City of Sikeston Board of Municipal Utilities   MO

City of Sioux Center   IA

City of Smithville   TX

City of Southport   NC

City of Spring Grove   MN

City of Springfield IL

City of St Marys   KS

City of St. Clairsville   OH

City of St. Francis   KS

City of St. George   UT

City of St. James   MN

City of St. John   KS

City of Stanhope   IA

City of State Center   IA

City of Steelville   MO

City of Stephen   MN

City of Stephenson MI

City of Stilwell   OK

City of Stockton   KS

City of Stratford   IA

City of Strawberry Point   IA

City of Sullivan   MO

City of Sylvester   GA

City of Tallahassee   FL

City of Thayer   MO

City of Thomasville   GA

City of Traer   IA

City of Troy   AL

City of Udall   KS

City of Unalaska   AK

City of Union   SC

City of Valley City   ND

City of Vandalia   MO

City of Vermillion   SD

City of Wadena Electric & Water   MN

City of Wadsworth   OH

City Of Wakefield   MI

City of Warroad   MN

City of Washington   NC

City of Waterloo   IL

City of Watertown   NY

City of Watonga   OK

City of Waynesville   MO

City of Waynoka OK

City of Weimar TX

City of Weiser ID

City of West Liberty   IA

City of Westerville   OH

City of Westfield MA

82 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Municipally Owned Utilities 

(Continued) 

City of White Mountain Utilities   AK

City of Whitesboro   TX

CIty of Willow Springs   MO

City of Windom   MN

City of Winfield   KS

City of Winnfield   LA

City of Wray   CO

City of Yoakum   TX

City Utilities of Springfield   MO

City Water & Light Plant of the City of Jonesboro   AR

Clarksville Light & Water Co.   AR

Columbia Power & Water Systems   TN

Columbus Water & Light Dept.   WI

Concord Municipal Utility   MA

Conway Corporation   AR

Corbin City Utilities Commission   KY

Corwith Municipal Utilities   IA

Cozad Board of Public Works   NE

Crawfordsville Electric Light & Power IN

Cuba City Electric & Water Utility   WI

Cumberland, City of   WI

Decatur Utilities   AL

Delano Municipal Utilities   MN

Delta Municipal Light and Power   CO

Denison Municipal Utilities   IA

Dickson Electric Department   TN

Dublin Municipal Electric   IN

Duncannon Borough   PA

Dyersburg Electric System   TN

Eagle River Light & Water Commission   WI

Easley Combined Utility System   SC

East Grand Forks Water and Light   MN

Easton Utilities Commission   MD

Electric and Water Plant Board of the

     City of Frankfort   KY

Elk River Municipal Utilities ‐ City of Elk River   MN

Erwin Utilities   TN

Eugene Water & Electric Board   OR

Evansville Water & Light   WI

Fairburn Utilities   GA

Fillmore City Corporation   UT

Fitzgerald Wtr Lgt & Bond Comm   GA

Florence Utility Commission   WI

Forest City Municipal Utilities   IA

Fort Payne Improvement Authority   AL

Fort Pierce Utilities Authority   FL

Franklin Electric Plant Board   KY

Gaffney Board of Public Works   SC

Gainesville Regional Utilities   FL

Gallatin Department of Electricity   TN

Garnett Municipal Electric   KS

Geary Utilities Authority   OK

Glasgow Electric Plant Board KY

Glencoe Light and Power Commission   MN

Glenwood Springs City of   CO

Grafton Electric   IA

Grand Haven Board of Light and Power   MI

Grand Marais Public Utilities   MN

Grand Rapids Public Utilities Commission   MN

Greeneville Light & Power System   AL

Greenfield Municipal Utilities IA

Greenwood Utilities Commission   MS

Groton Electric Light   MA

Guam Power Authority   GU

Guntersville Electric Board   AL

Harriman Utility Board   TN

Harrisonburg Electric Commission   VA

Hartford Utilities   WI

Hartley Municipal Utilities   IA

Hartselle Utilities   AL

Hastings City of   NE

Hawarden Municipal Utilities   IA

Heber Light and Power   UT

Henderson City Utility Commission   KY

Hermiston Energy Services   OR

Hillsdale Board of Public Utilities   MI

Holland Board of Public Works   MI

Holy Springs Utility Department   MS

Hooversville Boro Elec Lgt Co.   PA

Hope Water and Light Commission   AR

Hopkinsville Electric System   KY

Hudson Municipal Electric Utility IA

Humboldt Utilities   TN

Huntsville Utilities   AL

Hurricane City Power   UT

Hustisford Utilities   WI

Hyrum City Corp.   UT

Independence Light & Power   IA

Indianola Municipal Utilities IA

Ipnatchiaq Electric Company   AK

Jackson Energy Authority   TN

Jamestown Board of Public Utilities   NY

JEA   FL

Jefferson Water & Light Dept.   WI

Jewett City Dept. of Public Utilities   CT

Juneau Utility Commission WI

Kansas City Board of Public Utilities   KS

Kaukauna Utilities   WI

Kaysville City Corporation UT

Kenyon Municipal Utilities   MN

Kerrville Public Utility Board   TX

Ketchikan Public Utilities   AK

Kimballton Municipal Utilities IA

Kingman City of   KS

Kissimmee Utility Authority   FL

Knoxville Utilities Board   TN

La Farge Municipal Electric Utility   WI

La Junta Municipal Utilities   CO

Lafayette Utilities System   LA

Lafollette Utilities Board   TN

Lake Mills Light & Water Dept.   WI

Lake Mills Municipal Utilities   IA

Lake Placid Village, Inc.   NY

Lampasas City of   TX

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 83
Municipally Owned Utilities 

(Continued) 

L'anse Electric Utility   MI

Laurens Commission of Public Works   SC

Lawrenceburg Municipal Utility   IN

Lexington Electric System   TN

Litchfield Public Utilities   MN

Littleton Water and Light Department   NH

Lodi Municipal Light & Water Utility   WI

Lodi Village of   OH

Logan City Light and Power   UT

Logansport Municipal Utilities   IN

Longmont Power & Communications   CO

Los Angeles Department of Water and Power   CA

Lowell Light and Power   MI

Lubbock Power & Light   TX

Madelia Municipal Light & Power   MN

Madison Electric   ME

Manilla Municipal Utilities   IA

Manti City   UT

Maquoketa Municipal Electric Utility   IA

Marquette Board of Light and Power   MI

Marshall Municipal Utilities   MO

McMinnville Electric System   TN

Melrose Public Utilities   MN

Memphis Light, Gas & Water Division   TN

Menasha Electric & Water Utilities   WI

Milton‐Freewater City Light & Power   OR

Moorhead Public Service   MN

Morgan City Corporation UT

Morristown Utilities Commission   TN

Mount Horeb Electric Utility   WI

Mount Pleasant Municipal Utilities   IA

Mt. Pleasant City TN TN

Navajo Tribal Utility Authority   AZ,NM

Nebraska City Utilities   NE

Negaunee Electric Department   MI

New Castle Municipal Services Commission   DE

New Glarus Light & Water Works   WI

New Hampton Municipal Light Plant   IA

New Hampton Village Precinct   NH

New Holstein Public Utility   WI

New London Electric & Water Utility   WI

New Richmond Municipal Electric Utility   WI

Newbern Electric Water & Gas              TN

Newkirk Municipal Authority               OK

Newport Utilities Board                   TN

North Branch Water & Light Comm.              MN

Norwalk Third Taxing District              CT

Ocala Utility Services                FL

Oconomowoc Utilities                WI

Oconto Falls Water & Light Commission            WI

Orlando Utilities Commission              FL

Orrville Utilities                  OH

Osage Municipal Utilities                IA

Ottawa, City of                  KS

Owatonna Public Utilities                MN

Owensboro Municipal Utilities              KY

Page Electric Utility       AZ

Paragonah Town         UT

Paragould Light Water and Cable     AR

Paris Board of Public Utilities      TN

Pasadena Water & Power       CA

Pascoag Utility District    RI

Payson City       UT

Pella City of         IA

Peru Utilities       IN

PES Energize ‐ Pulaski Electric System     TN

Philadelphia Utilities       MS

Pierre Municipal Utilities       SD

Piggott Light and Water       AR

Plattsburgh Municipal Lighting Department NY

Plymouth Utilities         WI

Ponca City Utility Authority       OK

Prairie du Sac Municipal Electric & Water   WI

Precinct of Woodsville       NH

Price Municipal Corporation       UT

Princeton Municipal Light Department    MA

Princeton Public Utilities       MN

Proctor Public Utilities Commission     MN

Provo City Corp         UT

Public Service Commission of Yazoo City   MS

Public Works Commission of the  

     City of Fayetteville       NC

Reedsburg Utility Commission     WI

Reedy Creek Improvement Disrtrict    FL

Rensselaer Municipal Electric Utility    IN

Reynolds, Village of       NE

Rice Lake Utilities         WI

Richland Center Electric Utility     WI

Richmond Power and Light     IN

Ripley Power and Light       TN

River Falls Municipal Utility       WI

Riverside Public Utilities       CA

Rochelle Municipal Utilities   IL

Rochester Public Utilities   MN

Rock Port Municipal Utilities   MO

Rock Rapids Municipal Utility   IA

Rockford Municipal Light Plan   IA

Russellville Electric Board   AL

Russellville Electric Plant Board   KY

Santa Clara City   UT

Sebewaing Light & Water   MI

Sevier County Electric System TN

Shakopee Public Utilities Commission   MN

Shawano Municipal Utilities   WI

Sheffield Utilities   AL

Shelbyville Power System   TN

Silicon Valley Power   CA

Sioux Falls Municipal Light & Power   SD

Sitka City & Borough of   AK

Sleepy Eye Public Utilities MN

Slinger Utilities   WI

Smithville Electric System   TN

South Norwalk Electric and Water CT

South Vienna Corporation   OH

84 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Municipally Owned Utilities 

(Continued) 

Spencer Municipal Utilities   IA

Spooner, City of   WI

Spring City Corp   UT

Spring Valley Public Utilities   MN

Springfield Public Utilities MN

Story City Municipal Electric Utility   IA

Stoughton Electric Utility   WI

Straughn Municipal Electric IN

Sturgeon Bay Utilities   WI

Sun Prairie Water & Light Commission WI

Superior Utilities, City of Superior Nebraska   NE

Tacoma Public Utilities   WA

Tatitlek Electric Utility   AK

Tell City Electric Department   IN

Tenakee Springs Electric Utility   AK

Terrebonne Parish Consolidated Government   LA

The City of Holyoke Gas and Electric Department  MA

The City of Plainview   NE

The Hagerstown Light Department   MD

Thurmont Municipal Light Company   MD

Tillamook People's Utility District   OR

Tipton Municipal Electric Utility   IN

Tipton Municipal Utilities   IA

Town of Argos IN

Town of Avilla   IN

Town of Ayden   NC

Town of Black Creek   NC

Town of Bostic   NC

Town of Braintree Electric Light Department   MA

Town of Brooklyn   IN

Town of Brookston IN

Town of Center ‐ Municipal Light & Power   CO

Town of Clayton   NC

Town of Coatesville IN

Town of Culpeper   VA

Town of Dallas       NC

Town of Deaver         WY

Town of Edenton         NC

Town of Forest City       NC

Town of Frederick         CO

Town of Fredonia         AZ

Town of Front Royal       VA

Town of Granite Falls       NC

Town of Guernsey         WY

Town of Gueydan         LA

Town of Hagerstown       IN

Town of Haxtun   CO

Town of Highlands   NC

Town of Holden   UT

Town of Hookerton NC

Town of Julesburg   CO

Town of Knightstown IN

Town of Ladoga   IN

Town of Landis   NC

Town of Laverne   OK

Town of Lucama   NC

Town of Lyons   CO

Town of Manitou   OK

Town of Massena   NY

Town of Merrimac Municipal Light Department MA

Town of Middletown   DE

Town of Montezuma   IN

Town Of Oak City   UT

Town of Pine Bluffs   WY

Town of Pittsboro IN

Town of Prosperity   SC

Town of Red Springs   NC

Town of Robersonville   NC

Town of Ruston   WA

Town of Ryan   OK

Town of Sharpsburg   NC

Town of South Hadley   MA

Town of South Whitley IN

Town of Spiceland   IN

Town of Steilacoom   WA

Town of Stowe Electric Department   VT

Town of Wallingford, Department of  

    Public Utilities   CT

Town of Williamsport   MA

Town of Winamac IN

Trempealeau Municipal Electric Utility   WI

Trenton Municipal Utilities   MO

Tullahoma Board of Public Utilities   TN

Two Rivers Water & Light Utility   WI

Utilities Commission, City of New Smyrna Beach  FL

Van Buren Light & Power District   ME

Village of Akron NY

Village of Albany   IL

Village of Angelica   NY

Village of Arcade   NY

Village of Bergen   NY

Village of Black Earth   WI

Village of Brocton   NY

Village of Callaway   NE

Village of Carey Electric OH

Village of Cashton WI

Village of Castile   NY   

Village of Clinton   MI

Village of Daggett   MI

Village of Davenport   NE

Village of Decatur   NE

Village of Deshler   OH

Village of Endicott   NE

Village of Endicott Municipal Light   NY

Village of Fairport   NY

Village of Frankfort   NY

Village of Freeport   NY

Village of Genoa   OH

Village of Glouster   OH

Village of Grafton   OH

Village of Greene   NY

Village of Greenport   NY

Village of Hamilton   NY

Village of Hampton   NE

2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 85
Municipally Owned Utilities 

(Continued) 

Village of Holbrook   NE

Village of Hyde Park, Inc.   VT

Village of Jackson Center   OH

Village of Ladd   IL

Village of Little Valley   NY

Village of Lucas   OH

Village of Lydonville Electric Department   VT

Village of Marshallville   OH

Village of Mayville   NY

Village of Mendon   OH

Village of Merrillan   WI

Village of Minster   OH

Village of Northfield Electric Department   VT

Village of Orleans Electric Dept. Inc.   VT

Village of Oxford   NE

Village of Paw Paw   MI

Village of Pemberville   OH

Village of Philadelphia   NY

Village of Prague   NE

Village of Richmondville   NY

Village of Riverton   IL

Village of Rockville Centre   NY

Village of Sherburne   NY

Village of Shickley   NE

Village of Shiloh   OH

Village of Silver Springs Municipal Electric   NY

Village of Solvay   NY

Village of Spalding   NE

Village of Stratford   WI

Village of Stratton   NC

Village of Talmage   NE

Village of Trenton   NE

Village of Versailles   OH

Village of Waynesfield   OH

Village of Westfield   NY

Village of Wharton   OH

Village of Winnetka, Water & Electric Department IL

Village of Woodsfield   OH

Vinton Municipal Electric Utility   IA

Wadsworth Electric and Communications   OH

Wagoner Public Works Authority              OK

Waterloo Water & Light Commission              WI

Waunakee Water & Light Commission              WI

Waupun Public Utilities                WI

Weakley County Municipal Electric System            TN

Wellesley Municipal Light Plant            MA

Westbrook Public Utilities           MN

Westby Municipal Electric Utility           WI

Whitehall Municipal Electric Utility           WI

Willmar Municipal Utilities           MN

Wilton Municipal Light and Power         IA

Wonewoc Electric & Water Department           WI

Political Subdivisions 

Alamo Power District #3           NV

Alaska Energy Authority   AK

Brazos River Authority   TX

Butler Public Power District NE

Canby Utility Board   OR

Central Lincoln People's Utility District   OR

Columbia River Peoples Utility District   OR

Crisp County Power Commission   GA

Cuming County Public Power District   NE

Electrical Dist No3 Pinal Cnty   AZ

Electrical District # 2   AZ

Electrical District No. 4, Pinal County, Arizona   AZ

Electrical District No. 5, Pinal County, Arizona   AZ

Elkhorn Rural Public Power District   NE

Emerald People's Utility District   OR

Energy Northwest WA

Guadalupe‐Blanco River Authority   TX

Imperial Irrigation District   CA

Kennebunk Light & Power District ME

Kings River Conservation District CA

Klickitat County Public Utility District No. 1   WA

Lincoln County Power District No. 1 NV

Loup River Public Power District   NE

Loup Valleys Rural Public Power District   NE

McCook Public Power District   NE

Midvale Irrigation District   WY

Mohegan Tribal Utility Authority   CT

Municipal Energy Agency of Nebraska   NE

North Central Public Power District   NE

Northern Wasco Co PUD   OR

Northwest Rural Public Power District NE

Omaha Public Power District   NE

Perennial Public Power District NE

Placer County Water Agency   CA

Platte River Power Authority   CO

Polk County Rural Public Power District   NE

Public Utility District No. 1 of Benton County   WA

Public Utility District No. 1 of Douglas County   WA

Public Utility District No. 1 of  

    Grays Harbor County   WA

Public Utility District No. 1 of  

     Pend Oreille County   WA

Public Utility District No. 1 of Wahkiakum County WA

PUD #1 of Ferry County   WA

PUD No 3 of Mason County   WA

PUD No. 1 of Cowlitz County   WA

PUD No. 1 of Whatcom County   WA

Roosevelt Public Power District NE

Salt River Project (SRP)   AZ

Seward County Public Power District   NE

Snohomish County Public Utility District #1   WA

South Feather Water and Power Agency   CA

Southern Public Power District   NE

Southwest Public Power District   NE

Strawberry Electric Service District   UT

Texas General Land Office   TX

Tohono O'odham Utility Authority   AZ

Tonopah Irrigation District AZ

Turlock Irrigation District   CA

86 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                                    Federal Energy Regulatory Commission 87

Political Subdivisions (Continued) 

Twin Valleys Public Power District   NE

Utah Associated Municipal Power Systems            ID,NV,UT

Vera Water and Power   WA

WPPI Energy   WI

Retail Power Marketers 

3 Phases Renewables LLS   CA

Agway Energy Services, LLC   NY

Central Electric Inc.   AK

Chain Lakes Power, LP., dba Simple Power, L.P   TX

Champion Energy Services, LLC   IL,PA,TX

Columbia Utilities Power, LLC   NY

Commerce Energy, Inc.   CA

CPL Retail Energy, LP   TX

Direct Energy Business, LLC (fka Strategic Energy, LLC)

                                                                      CA,CT,IL,MA,MD,NJ,

                                                                            NY,OH,PA,TX

Direct Energy Services, LLC   CT

Direct Energy, LP   TX

Dominion Retail, Inc.                       CT,MA,MD,ME,NY,OH,PA

Dow Hydrocarbons and Resources, LLC   TX

dPi Energy L.L.C   TX

Empire Natural Gas Corporation NY

Energetix, Inc.   NY

Energy Cooperartive of New York   NY

Energy West Resources, Inc.   MT

Entergy Solutions LLC     MA,NY

Fulcrum Retail Energy LLC d/b/a Amigo Energy   TX

Integrys Energy Services of New York, Inc.   NY

Integrys Energy Services, Inc.                 CT,DC,DE,IL,MA,MD,

                                                          ME,MI,NH,NJ,NY,OH,PA,RI

Jack Rich, Inc. d/b/a Anthracite Power & Light   PA

Just Energy Texas   TX

KeySpan Energy Services Inc   NY

MC‐Squared Energy Services, llc   IL

New York Industrial Energy Buyers, LLC   NY

NYSEG Solutions, Inc.   NY

Penstar Power, LLC   TX

Peoples Energy Services, Corp IL

Shell Energy North America, LP                     CA,NV,TX,WA

Suez Energy Resources North America    CT,DC,DE,IL,MA,

              MD, ME,NJ,NY,PA,TX

Tara Energy, LLC   TX

Texas Retail Energy, LLC   TX

TriEagle Energy, LLC   TX

TXU Energy Retail Company LLC TX

U.S. Energy Partners LLC   NY

UGI Energy Services, Inc   PA

Wolverine Power Marketing Cooperative, Inc.   MI

WTU Retail Energy, LP   TX

RTO/ISOs

California Independent System Operator   CA

Electric Reliability Council of Texas Inc.   TX

ISO New England   MA

Midwest ISO   IN

New York Independent System Operator   NY

PJM Interconnection, LLC   PA

Southwest Power Pool, Inc   AR

State Utilities 

Ak‐Chin Energy Services   AZ

Arizona Power Authority   AZ

California Department of Water Resources   CA

Colorado River Commission of Nevada   NV

Custer Public Power District   NE

Dept of Water Resources/CA Energy  

    Resources Sched.   CA

Grand River Dam Authority   OK

Nebraska Public Power District                                       NE,SD

New River Light and Power Company   NC

New York Power Authority   NY

Northeast Nebraska Public Power District   NE

Overton Power District No. 5   NV

PUD No 1 of Clark County   WA

South Carolina Public Service Authority   SC

South Central Public Power District   NE

Virginia Polytechnic Institute ‐ Electric Service   VA

Wheat Belt Public Power District   NE

Transmission 

Big Rivers Electric Corporation   KY

City of Peterson   MN

City of Whalan   MN

ITC Midwest                                                            IA,IL,MN,MO

ITC Transmission   MI

Michigan Electric Transmission Company MI

NW Electric Power Coop., Inc.   MO

Swans Island Electric Co‐op Inc.   ME

Wholesale Power Marketers 

BP Energy Company   TX

Cargill Power Markets LLC   MN

Conectiv Energy Supply, Inc.   DE

Dynegy Power Marketing Inc.   TX

Mirant Energy Trading, LLC                         CA,MA,MD,NY,VA

MKEC   KS

PPL EnergyPlus LLC   PA

Select Energy, Inc.   CT

Sempra Generation   CA

Sunflower Electric Power Corp   KS

Tenaska Power Services, Co.                                            DE,TX

Toledo Bend Project Joint Operation                             LA,TX
APPENDIX F: DEMAND RESPONSE PROGRAMS AND SERVICES AT 

RESPONDING ENTITIES

Appendix F lists entities that responded to the 2010 FERC Survey and indicated that they 

offer one or more demand response programs, organized by demand response program type. 

Critical Peak Pricing 

Adams Electric Cooperative, Inc. 

Alabama Power Company 

Brown County Rural Electrical Assn. 

C & L Electric Cooperative Corporation 

City of Gastonia 

Clay Electric Cooperative, Inc. 

Connecticut Light and Power Co 

Crisp County Power Commission 

El Paso Electric Company 

Green Mountain Power Corporation 

Guadalupe Valley Electric Cooperative, Inc. 

Gulf Power Company 

Gunnison County Electric Association, Inc. 

Holy Cross Energy 

Idaho Power Company 

Jackson Electric Membership Corporation 

Kentucky Utilities 

Midwest Electric Inc 

Pacific Gas and Electric Company 

Richmond Power and Light 

Rural Electric Cooperative,Inc. 

Salt River Project (SRP) 

San Patricio Electric Cooperative, Inc. 

Santee Electric Cooperative Inc. 

Sawnee Electric Membership Corporation 

Southern California Edison 

Tampa Electric Company 

Town of Edenton 

Wisconsin Public Service Corporation 

Critical Peak Pricing with Load 

Control 

Alabama Power Company 

Blue Ridge Electric Membership Corporation 

Bluestem Electric Cooperative Inc. 

Brown County Rural Electrical Assn. 

Cass County Electric Cooperative 

Choptank Electric Cooperative, Inc. 

City of Fort Collins 

City of Hickman 

City of High Point 

City of Washington 

Edgecombe-Martin County Electric Membership Corp. 

EnergyUnited Electric Membership Corporation 

Farmers Electric Cooperative, Inc. 

Jackson Electric Cooperative, Inc 

Midwest Electric Inc 

New Castle Municipal Services Commission 

New York Power Authority 

Otter Tail Power Co. 

Red River Valley Cooperative Power Association 

Rutherford Electric Membership Corporation 

Sangre De Cristo Electric Association, Inc 

Tri-County Rural Electric Cooperative, Inc. 

United Power, Inc 

Demand Bidding & Buy-Back 

Denton County Electric Cooperative, Inc. 

Duke Energy Corporation 

Idaho Cnty L&P Coop Assn, Inc. 

Pacific Gas and Electric Company 

Potomac Edison Company d/b/a Allegheny Power 

Southern California Edison 

Wheatland Electric Cooperative, Inc. 

Wisconsin Public Service Corporation 

Direct Load Control 

A & N Electric Cooperative 

Adams Electric Cooperative 

Adams Electric Cooperative, Inc. 

Adams-Columbia Electric Cooperative 

Agralite Electric Cooperative 

Alabama Power Company 

Alcoa Power Generating, Inc. 

Ames, City of 

Arrowhead Electric Cooperative, Inc. 

Ashley-Chicot Electric Cooperative, Incorporated 

Atlantic City Electric Company 

Austin Energy 

Austin Utilities 

Avista Corporation, dba Avista Utilities 

Baltimore Gas and Electric Company 

BARC Electric Cooperative 

Barnesville Municipal Utility 

Beaver City Corporation 

Bedford Rural Electric Cooperative, Inc. 

Blue Ridge Electric Membership Corporation 

Bluestem Electric Cooperative Inc. 

Boone Electric Cooperative 

Brown County Rural Electrical Assn. 

Brunswick Electric Membership Corporation 

Buckeye Power, Inc. 

Burlington Electric Department 

Butler Public Power District 

C & L Electric Cooperative Corporation 

Capital Electric Cooperative, Inc. 

Carroll Electric Cooperative Corporation 

Cass County Electric Cooperative 

Central Alabama Electric Cooperative 

88 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Direct Load Control (continued) 

Central Electric Cooperative 

Central Electric Cooperative, Inc. 

Central Florida Electric Cooperative, Inc. 

Central Georgia Electric Membership Corp 

Central Illinois Pub Serv Co, 

Central Vermont Public Service Corporation 

Choptank Electric Cooperative, Inc. 

City of Alliance 

City of Big Stone 

City of Breda 

City of Columbia 

City of Fort Collins 

City of Gothenburg 

City of Groton 

City of Kasson 

City of Northwood Utilities 

City of Rock Hill 

City of Roseville 

City of Saint Peter 

City of Sioux Center 

City of Southport 

City of St. James 

City of Valley City 

City of Vermillion 

City of Wadena Electric & Water 

City of Washington 

Clay County Electric Cooperative Corporation 

Clay-Union Electric Corporation 

Clearwater-Polk Electric Cooperative, Inc. 

Cleveland Electric Illuminating Co 

Codington-Clark Electric Cooperative, Inc 

Commonwealth Edison Company 

Community Electric Cooperative 

Connexus Energy 

Consolidated Edison Company of New York 

Cooperative Light and Power Association 

Corn Belt Energy Corporation 

Coweta-Fayette EMC 

CPL Retail Energy, LP 

Craighead Electric Cooperative Corporation 

Crawfordsville Electric Light & Power 

Crow Wing Cooperative Power & Light Company 

Cuivre River Electric Cooperative, Inc 

Custer Public Power District 

Dairyland Power Cooperative 

Dakota Electric Association 

Delaware Electric Cooperative, Inc. 

Delmarva Power & Light Company 

Denison Municipal Utilities 

Direct Energy, LP 

Douglas Electric Cooperative, Inc 

Duke Energy Corporation 

Dunn County Electric Cooperative 

Duquesne Light Company 

Duquesne Light Company 

East Grand Forks Water and Light 

East River Electric Power Cooperative, Inc. 

Elk River Municipal Utilities - City of Elk River 

EnergyUnited Electric Membership Corporation 

Entergy Arkansas, Inc. 

Entergy Louisiana, Inc. 

Excelsior Electric Membership Corporation (EMC) 

Farmers Electric Cooperative Corporation 

Farmers Rural Electric Cooperative Corporation 

Federated Rural Electric Association 

FEM Electric Association, Inc 

First Electric Cooperative Corporation 

Flint Electric Membership Corporation 

Flint Hills Rural ECA, Inc 

Florida Power & Light, Co. 

Fulton County Rural Electric Membership Corporation 

Grand Marais Public Utilities 

Grand Rapids Public Utilities Commission 

Grundy Electric Cooperative, Inc. 

Guernsey-Muskingum Electric Cooperative, Inc. 

Hawaiian Electric 

Haywood Electric Membership Corporation 

H-D Electric Cooperative, Inc 

Henry County Rural Electric Membership Corporation 

High Plains Power Inc. 

Highline Electric Association 

Horry Electric Cooperative, Inc. 

Idaho Power Company 

Illinois Rural Electric Cooperative 

Indiana Michigan Power Company 

Indianapolis Power & Light Company 

Inter-county Energy Cooperative Cooperation 

Interstate Power and Light Company 

Itasca-Mantrap Cooperative Electrical Association 

Jackson Electric Cooperative 

Jackson Electric Membership Corporation 

Jersey Central Power & Light Co 

Kandiyohi Power Cooperative 

Kansas City Power & Light Company 

Kay Electric Cooperative 

KCP&L Greater Missouri Operation Company 

Kentucky Utilities 

Kingsbury Electric Cooperative, Inc. 

Lake Region Electric Cooperative 

Lamb County Electric Cooperative 

Lee County Electric Cooperative, Incorporated 

Lighthouse Electric Cooperative, Inc. 

Long Island Power Authority 

Loup Valleys Rural Public Power District 

Lyon Rural Electric Cooperative 

Lyon-Lincoln Electric Cooperative, Inc. 

Marshall Municipal Utilities 

McLean Electric Cooperative, INC 

McLeod Cooperative Power Association 

Mecklenburg Electric Cooperative 

Meeker Cooperative Light & Power Association 

Menard Electric Cooperative 

MidAmerican Energy Company 

Midwest Electric Inc 

Midwest Energy Cooperative 

Midwest ISO 

Mid-Yellowstone Electric Cooperative, Inc. 

Mille Lacs Energy Cooperative 

Milton-Freewater City Light & Power 

Minnesota Valley Electric Cooperative 

Minnkota Power Cooperative, Inc. 

Mississippi County Electric Cooperative , Inc. 

Moorhead Public Service 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 89
Direct Load Control (continued) 

Mountain View Electric Association, Inc. 

Municipal Commission of Boonville 

NC Electric Membership Corp 

Nevada Power Company 

New Hampshire Electric Cooperative, Inc 

New York Electric & Gas Corporation 

Niobrara Electric Association 

Nishnabotina Valley Rural Electric Cooperative 

Nobles Cooperative Electric 

North Arkansas Electric Cooperative, Incorporated 

North Central Mo. Electric Coop 

Northeastern REMC 

Northern Neck Electric Cooperative 

Northern Virginia Electric Cooperative 

Northwest Rural Public Power District 

Northwestern Rural Electric Coop Association, Inc. 

Oahe Electric Coop Inc. 

OGE Energy Corporation 

Ohio Edison Co. 

Osage Municipal Utilities 

Osceola Electric Cooperative, Inc. 

Otsego Electric Cooperative, Inc. 

Otter Tail Power Co. 

Pacific Gas and Electric Company 

PacifiCorp 

Panhandle Rural Electric Membership Association 

Pee Dee Electric Membership Corp. 

Pennsylvania Electric Co 

Perennial Public Power District 

Piedmont Electric Membership Corporation 

Platte-Clay Electric Cooperative, Inc. 

Polk County Rural Public Power District 

Potomac Electric Power Company 

Prince George Electric Cooperative 

Progress Energy Carolinas 

Progress Energy Florida 

Public Service Company of New Mexico 

Public Service Electric & Gas Company 

Puget Sound Energy, Inc. 

Randolph Electric Membership Corporation 

Rappahannock Electric Cooperative 

REA Energy Cooperative, Inc. 

Red River Valley Cooperative Power Association 

Renville-Sibley Cooperative Power Association 

Rice Lake Utilities 

Richmond Power and Light 

Rochester Public Utilities 

Rolling Hills Electric Cooperative, Inc. 

Roughrider Electric Cooperative, Inc. 

Rutherford Electric Membership Corporation 

Salt River Project (SRP) 

San Diego Gas & Electric Company 

Santee Electric Cooperative Inc. 

Sawnee Electric Membership Corporation 

Shakopee Public Utilities Commission 

Shelby Electric Cooperative 

Shelby Energy Cooperative Inc. 

Sioux Valley Southwestern Electric Cooperative, Inc. 

Somerset Rural Electric Cooperative, Inc. 

South Central Power Company 

South Central Public Power District 

Southeastern Electric Cooperative, Inc. 

Southern California Edison 

Southern Indiana Gas & Electric Co. 

Southern Maryland Electric Cooperative, Inc. 

Southside Electric Cooperative, Crewe,Virginia 

Southwest Public Power District 

Spring Valley Public Utilities 

Steuben Rural Electric Cooperative, Inc. 

Sullivan County Rural Electric Cooperative, Inc. 

Sumter Electric Cooperative, Inc. 

Sussex Rural Electric Cooperative, Inc. 

Tampa Electric Company 

The Caney Valley Electric Cooperative Assn., Inc. 

The Detroit Edison Company 

The Frontier Power Company 

The Midwest Electric Cooperative Corporation 

The Toledo Edison Co 

Town of Ayden 

Town of Edenton 

Town of Frederick 

Town of Massena 

Tri-County Electric Membership Corporation 

Tri-County Rural Electric Cooperative, Inc. 

Union County Electric Cooperative, Inc. 

United Electric Cooperative, Inc. 

United Power, Inc 

Verendrye Electric Cooperative, Inc. 

Village of Arcade 

Village of Genoa 

Wabash Valley Power Assn, Inc. 

White County REMC 

White River Valley Electric Cooperative 

Willmar Municipal Utilities 

Wiregrass Electric Cooperative, Inc. 

Wisconsin Power and Light Company 

Wisconsin Public Service Corporation 

Woodruff Electric Cooperative Corporation 

Wright-Hennepin Cooperative Electric Association 

XCEL d/b/a Northern States Power Co - Minnesota 

XCEL d/b/a Northern States Power Co - Wisconsin 

XCEL d/b/a Public Service Co of Colorado 

XCEL d/b/a Southwestern Public Service Co 

Emergency Demand Response 

ALLETE Inc. 

Blue Ridge Electric Membership Corporation 

Borough of Weatherly, PA 

CenterPoint Energy Houston Electric, LLC 

City of Alpha 

City of Anaheim 

City of Columbia 

Concord Municipal Utility 

Delmarva Power & Light Company 

Electric Reliability Council of Texas Inc. 

Granite State Electric Company 

Hess Corporation 

Integrys Energy Services of New York, Inc. 

ISO New England 

Midwest ISO 

Monongahela Power Company d/b/a Allegheny Power 

Nebraska Public Power District 

90 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Emergency Demand Response 

(continued) 

New Hampshire Electric Cooperative, Inc 

New York Independent System Operator 

New York Power Authority 

Old Dominion Electric Cooperative 

Pacific Gas and Electric Company 

PECO Energy 

PJM Interconnection, LLC 

Potomac Edison Company d/b/a Allegheny Power 

Rochester Gas & Electric Corporation 

Sacramento Municipal Utility District 

Southern California Edison 

Suez Energy Resources North America 

Tampa Electric Company 

The Narragansett Electric Company 

The United Illuminating Company 

Town of Braintree Electric Light Department 

Village of Minster 

West Penn Power Company d/b/a Allegheny Power 

Interruptible Load 

Adams Electric Cooperative 

Adams Electric Cooperative, Inc. 

Adams-Columbia Electric Cooperative 

Agralite Electric Cooperative 

Alabama Power Company 

Alcoa Power Generating, Inc. 

Appalachian Power Company 

Arkansas Electric Cooperative Corporation 

Austin Utilities 

Bluestem Electric Cooperative Inc. 

Board of Public Utilities, City of McPherson 

Boone Electric Cooperative 

Brazos Electric Power Cooperative, Inc. 

Brown County Rural Electrical Assn. 

Brunswick Electric Membership Corporation 

Buckeye Power, Inc. 

Burlington Electric Department 

California Independent System Operator 

Central Electric Cooperative 

Central Iowa Power Cooperative 

Central Vermont Public Service Corporation 

Cimarron Electric Cooperative 

City of Cairo 

City of Columbia 

City of Lakeland, Lakeland Electric 

City of Lincoln Electric System 

City of Rock Hill 

City of Saint Peter 

City of Sheboygan Falls 

City of Tallahassee 

City of Washington 

City of Winfield 

City Utilities of Springfield 

Clay Electric Cooperative, Inc. 

Cleveland Electric Illuminating Co 

Columbus Southern Power Company 

Community Electric Cooperative 

Connecticut Light and Power Co 

Connexus Energy 

Consolidated Edison Company of New York 

Cooperative Light and Power Association 

Corn Belt Energy Corporation 

Cozad Board of Public Works 

Cuivre River Electric Cooperative, Inc 

Dairyland Power Cooperative 

Dakota Electric Association 

Dixie Escalante Rural Electric Association, Inc. 

Duke Energy Corporation 

El Paso Electric Company 

Elk River Municipal Utilities - City of Elk River 

Empire Direct Electric Company 

Entergy Arkansas, Inc. 

Entergy Louisiana, Inc. 

Entergy Texas, Inc. 

Farmers Electric Cooperative, Inc. 

FEM Electric Association, Inc 

First Electric Cooperative Corporation 

Flint Electric Membership Corporation 

Florida Power & Light, Co. 

Four County Electric Membership Corporation 

Fulton County Rural Electric Membership Corporation 

Gainesville Regional Utilities 

Georgia Power 

Grand Marais Public Utilities 

Green Mountain Power Corporation 

Hawaiian Electric 

H-D Electric Cooperative, Inc 

High Plains Power Inc. 

Horry Electric Cooperative, Inc. 

Illinois Rural Electric Cooperative 

Indiana Michigan Power Company 

Indiana Municipal Power Agency 

ISO New England 

Itasca-Mantrap Cooperative Electrical Association 

JEA 

Kandiyohi Power Cooperative 

Kansas City Power & Light Company 

KCP&L Greater Missouri Operation Company 

Kentucky Power Company 

Lee County Electric Cooperative, Incorporated 

Linn County Rural Electric Cooperative Association 

Marshall Municipal Utilities 

McLean Electric Cooperative, INC 

McLeod Cooperative Power Association 

Menard Electric Cooperative 

Metropolitan Edison Co 

MidAmerican Energy Company 

Midwest ISO 

Mille Lacs Energy Cooperative 

Minnesota Municipal Power Agency 

Minnesota Valley Electric Cooperative 

Mississippi County Electric Cooperative , Inc. 

Mississippi Power Company 

Monongahela Power Company d/b/a Allegheny Power 

Moorhead Public Service 

Mountain View Electric Association, Inc. 

NC Electric Membership Corp 

Nobles Cooperative Electric 

. North Arkansas Electric Cooperative, Incorporated 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 91
Interruptible Load (continued) 

North Itasca Electric Cooperative Inc. 

Northeastern REMC 

Northern Indiana Public Service Co Northern Virginia 

Electric Cooperative 

NorthWestern Energy 

Northwestern Rural Electric Coop Association, Inc. 

Nstar Electric 

Ocmulgee Electric Membership Corporation 

OGE Energy Corporation 

Ohio Edison Co. 

Ohio Power Company 

Oklahoma Electric Cooperative 

Omaha Public Power District 

Osceola Electric Cooperative, Inc. 

Ozark Border Electric Cooperative 

Ozarks Electric Cooperative Corporation 

Pacific Gas and Electric Company 

Palmetto Electric Cooperative, Inc. 

PECO Energy 

Pennsylvania Electric Co 

Potomac Edison Company d/b/a Allegheny Power 

PPL Electric Utilities 

Prince George Electric Cooperative 

Progress Energy Carolinas 

Progress Energy Florida 

Public Service Co of NH 

Public Service Company of Oklahoma 

Public Service Electric & Gas Company 

Rappahannock Electric Cooperative 

Red River Valley Rural Electric Association 

Rochester Public Utilities 

Roughrider Electric Cooperative, Inc. 

Sacramento Municipal Utility District 

Salt River Electric Coop Corp 

Salt River Project (SRP) 

San Diego Gas & Electric Company 

Satilla Rural Electric Membership Corporation 

SEMO Electric Cooperative 

Shelby Electric Cooperative 

Shelby Energy Cooperative Inc. 

Shenandoah Valley Electric Cooperative 

Sierra Pacific Power Company 

South Carolina Electric & Gas Company 

South Carolina Public Service Authority 

South Central Arkansas Electric Cooperative, Inc. 

South Kentucky Rural Electric Cooperative Corp 

Southern California Edison 

Southern Indiana Gas & Electric Co. 

Southside Electric Cooperative, Crewe,Virginia 

Southwest Arkansas Electric Cooperative Corporation 

Southwest Rural Electric Association 

Southwestern Electric Power Company 

Spencer Municipal Utilities 

Suez Energy Resources North America 

Sumter Electric Cooperative, Inc. 

Sussex Rural Electric Cooperative, Inc. 

Tampa Electric Company 

Tennessee Valley Authority 

The Detroit Edison Company 

The Toledo Edison Co 

Tri-County Electric Membership Corporation 

Union County Electric Cooperative, Inc. 

United Electric Cooperative, Inc. 

Upper Peninsula Power Company 

Village of Minster 

Wabash Valley Power Assn, Inc. 

Warren Electric Cooperative, Inc. 

Webster Electric Cooperative 

West Penn Power Company d/b/a Allegheny Power 

Western Farmers Electric Cooperative 

Wheeling Power Company 

Willmar Municipal Utilities 

Wisconsin Power and Light Company 

Wisconsin Public Service Corporation 

Woodruff Electric Cooperative Corporation 

WPPI Energy 

Wright-Hennepin Cooperative Electric Association 

XCEL d/b/a Northern States Power Co - Minnesota 

XCEL d/b/a Northern States Power Co - Wisconsin 

XCEL d/b/a Public Service Co of Colorado 

XCEL d/b/a Southwestern Public Service Co 

Load as a Capacity Resource 

Adams Electric Cooperative, Inc. 

Bedford Rural Electric Cooperative, Inc. 

Bluebonnet Electric Cooperative, Inc. 

Cass County Electric Cooperative 

Central Electric Cooperative, Inc. 

Claverack Rural Electric Cooperative, Inc. 

Commonwealth Edison Company 

Comperio Energy LLC, d/b/a ClearChoice Energy 

Dow Hydrocarbons and Resources, LLC 

Galt Power 

Indianapolis Power & Light Company 

Midwest ISO 

New York Electric & Gas Corporation 

New York Independent System Operator 

New York Power Authority 

Northwestern Rural Electric Coop Association, Inc. 

Pacific Gas and Electric Company 

REA Energy Cooperative, Inc. 

Rochester Gas & Electric Corporation 

Somerset Rural Electric Cooperative, Inc. 

Southern California Edison 

Southern Minnesota Municipal Power Agency 

Sullivan County Rural Electric Cooperative, Inc. 

Sussex Rural Electric Cooperative, Inc. 

Tampa Electric Company 

Town of Ayden 

Tri-County Electric Cooperative, Inc 

Tri-County Rural Electric Cooperative, Inc. 

United Electric Cooperative, Inc. 

Valley Rural Electric Cooperative, Inc. 

Virtual Energy LLC 

Wabash Valley Power Assn, Inc. 

Wellesley Municipal Light Plant 

Wisconsin Electric Power Company 

WPPI Energy 

92 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Non-Spinning Reserve 

PJM Interconnection, LLC 

Electric Reliability Council of Texas Inc. 

PacifiCorp 

Other 

Agralite Electric Cooperative 

Alabama Power Company 

ALLETE Inc. 

Arizona Public Service Company 

Boone Electric Cooperative 

Brown County Rural Electrical Assn. 

Brunswick Electric Membership Corporation 

City of Groton 

City of Monroe, NC 

City of Northwood Utilities 

City of Radford 

City of Salem 

City of Thomasville 

City of Vermillion 

Commonwealth Edison Company 

Cozad Board of Public Works 

Dakota Electric Association 

Dixie Escalante Rural Electric Association, Inc. 

Electrical Dist No3 Pinal Cnty 

Escambia River Electric Cooperative 

Four County Electric Membership Corporation 

Great River Energy 

Illinois Rural Electric Cooperative 

Itasca-Mantrap Cooperative Electrical Association 

Kandiyohi Power Cooperative 

Kansas City Power & Light Company 

KCP&L Greater Missouri Operation Company 

Laurens Commission of Public Works 

Minnesota Valley Electric Cooperative 

Nebraska Public Power District 

New York Independent System Operator 

Niagara Mohawk Power Corporation 

North Central Power Co., Inc. 

Northern Indiana Public Service Co. 

Ocmulgee Electric Membership Corporation 

Puget Sound Energy, Inc. 

Salt River Project (SRP) 

Sawnee Electric Membership Corporation 

Sierra Electric Cooperative, Inc. 

South Carolina Electric & Gas Company 

Southern California Edison 

Southwest Power Pool, Inc 

Spring Valley Public Utilities 

Tennessee Valley Authority 

Town of Ayden 

United Electric Coop Services 

Village of Decatur 

Wisconsin Electric Power Company 

Withlacoochee River Electric Cooperative, Inc. 

Peak Time Rebate 

Austin Energy 

Baltimore Gas and Electric Company 

Central Vermont Public Service Corporation 

City of Laurinburg 

City of Thomasville 

Elk River Municipal Utilities - City of Elk River 

Granite State Electric Company 

Grundy Electric Cooperative, Inc. 

Massachusetts Electric Company 

Nantucket Electric Company 

OGE Energy Corporation 

Potomac Electric Power Company 

The Narragansett Electric Company 

Union Electric Company 

Real-Time Pricing 

Alpena Power Company 

Central Hudson Gas & Electric Corporation 

Commonwealth Edison Company 

Crisp County Power Commission 

Duke Energy Corporation 

Georgia Power 

Gulf Power Company 

Indiana Michigan Power Company 

Kansas City Power & Light Company 

KCP&L Greater Missouri Operation Company 

Kentucky Power Company 

MidAmerican Energy Company 

New Hampshire Electric Cooperative, Inc 

Nstar Electric 

OGE Energy Corporation 

Otter Tail Power Co. 

PJM Interconnection, LLC 

Potomac Edison Company d/b/a Allegheny Power 

Progress Energy Carolinas 

Public Service Company of Oklahoma 

Public Service Electric & Gas Company 

South Carolina Public Service Authority 

Southern California Edison 

Wheatland Electric Cooperative, Inc. 

XCEL d/b/a Northern States Power Co - Minnesota 

XCEL d/b/a Northern States Power Co - Wisconsin 

Regulation 

Electric Reliability Council of Texas Inc. 

PJM Interconnection, LLC 

Tanana Power Company 

Spinning Reserves 

Electric Reliability Council of Texas Inc. 

Galt Power 

PJM Interconnection, LLC 

System Peak Response 

Transmission Tariff 

Habersham Electric Membership Corporation 

Red River Valley Rural Electric Association 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 93
Time-of-Use 

A & N Electric Cooperative 

Adams Electric Cooperative 

Adams Electric Cooperative, Inc. 

Adams-Columbia Electric Cooperative 

Algoma Utility Commission 

Appalachian Power Company 

Arizona Public Service Company 

Bangor Hydro Electric Company 

Bear Valley Electric Service 

Big Horn Rural Electric 

Black River Falls Municipal Electric & Water 

Board of Public Utilities, City of McPherson 

Brodhead Water & Light Commission 

Burlington Electric Department 

Butler County Rural Electric Cooperative 

Carbon Power & Light Inc 

Carteret-Craven Electric Membership Corporation 

Cedarburg Light & Water Commission 

Central Florida Electric Cooperative, Inc. 

Central Hudson Gas & Electric Corporation 

Central Vermont Public Service Corporation 

Choptank Electric Cooperative, Inc. 

City of Boulder City 

City of Carlyle 

City of Columbia 

City of Crystal Falls 

City of Denton 

City of Detroit 

City of Forest Grove Light and Power 

City of Gastonia 

City of Glendale 

City of Gothenburg 

City of Lakeland, Lakeland Electric 

City of Marshfield 

City of Medford 

City of Palo Alto Utilities 

City of Rancho Cucamonga 

City of Redding Electric Utility 

City of Roseville 

City of Salem 

City of Westfield 

Clark County Rural E M C 

Claverack Rural Electric Cooperative, Inc. 

Clay Electric Cooperative, Inc. 

Coast Electric Power Association 

Colorado River Commission of Nevada 

Columbus Southern Power Company 

Columbus Water & Light Dept. 

Connecticut Light and Power Co 

Consumers Energy Cooperative 

Coweta-Fayette EMC 

Crawfordsville Electric Light & Power 

Crisp County Power Commission 

Crow Wing Cooperative Power & Light Company 

Cuba City Electric & Water Utility 

Dairyland Power Cooperative 

Delmarva Power & Light Company 

Delta Electric Power Association 

Denton County Electric Cooperative, Inc. 

Direct Energy Business, LLC (fka Strategic Energy, 

LLC) 

Direct Energy Services, LLC 

Duke Energy Corporation 

Eagle River Light & Water Commission 

El Paso Electric Company 

Electrical Dist No3 Pinal Cnty 

Empire Direct Electric Company 

Energetix, Inc. 

Entergy Arkansas, Inc. 

Entergy Louisiana, Inc. 

Entergy Texas, Inc. 

Evansville Water & Light 

Fitchburg Gas and Electric Light Company 

Flathead Electric Cooperative, Inc. 

Florence Utility Commission 

Florida Power & Light, Co. 

Four County Electric Membership Corporation 

Gaffney Board of Public Works 

Gainesville Regional Utilities 

Georgia Power 

Grand Haven Board of Light and Power 

Grand River Dam Authority 

Granite State Electric Company 

Green Mountain Power Corporation 

Groton Electric Light 

Gulf Power Company 

Hartford Utilities 

Heart of Texas Electric Cooperative 

Hendricks County Rural Electric Membership Coop 

Highline Electric Association 

Holy Cross Energy 

Hustisford Utilities 

Idaho Power Company 

Indiana Michigan Power Company 

Interstate Power and Light Company 

Jackson Electric Cooperative, Inc 

Jackson Electric Membership Corporation 

Jefferson Water & Light Dept. 

Jemez Mountains Electric Cooperative, Inc. 

Jo-Carroll Energy, Inc.(NFP) 

Johnson County REMC 

Juneau Utility Commission 

Kansas City Power & Light Company 

Kaukauna Utilities 

KCP&L Greater Missouri Operation Company 

Kentucky Power Company 

Kiamichi Electric Cooperative, Inc 

Kingsport Power Company 

La Plata Electric Association, Inc. 

Lake Mills Light & Water Dept. 

Laurens Commission of Public Works 

Linn County Rural Electric Cooperative Association 

Lodi Municipal Light & Water Utility 

Long Island Power Authority 

Los Angeles Department of Water and Power 

Magic Valley Electric Cooperative, Inc. 

Maquoketa Valley REC 

Maui Electric Company, Ltd 

McLeod Cooperative Power Association 

Mecklenburg Electric Cooperative 

Menasha Electric & Water Utilities 

MidAmerican Energy Company 

Midwest Energy, Inc. 

94 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 95

Time-of-Use (continued) 

Minnesota Municipal Power Agency 

Mississippi Power Company 

Moon Lake Electric Assn. Inc. 

Mount Horeb Electric Utility 

Mountain Parks Electric, Inc. 

Mountain View Electric Association, Inc. 

Muscoda Light & Water Utility 

Nebraska Public Power District 

Nevada Power Company 

New Glarus Light & Water Works 

New Hampshire Electric Cooperative, Inc 

New Holstein Public Utility 

New London Electric & Water Utility 

New Richmond Municipal Electric Utility 

New York State Electric & Gas Corporation 

Noble County REMC 

North Central Power Co., Inc. 

Northern Neck Electric Cooperative 

Northern Rio Arriba Electric Coop., Inc. 

Northwest Rural Public Power District 

NorthWestern Energy 

Northwestern Rural Electric Coop Association, Inc. 

NYSEG Solutions, Inc. 

Oconomowoc Utilities 

Oconto Falls Water & Light Commission 

OGE Energy Corporation 

Ohio Power Company 

Okefenoke Rural El Member Corp 

Oklahoma Electric Cooperative 

Orlando Utilities Commission 

Otero County Electric Cooperative, Inc. 

Otsego Electric Cooperative, Inc. 

Otter Tail Power Co. 

Pacific Gas and Electric Company 

Palmetto Electric Cooperative, Inc. 

Pee Dee Electric Cooperative, Inc. 

Pee Dee Electric Membership Corp. 

Piedmont Electric Membership Corporation 

Plymouth Utilities 

Potomac Electric Power Company 

Poudre Valley Rural Electric Association 

Powder River Energy Corporation 

Prairie du Sac Municipal Electric & Water 

Progress Energy Carolinas 

Progress Energy Florida 

Public Service Co of NH 

Public Service Company of Oklahoma 

Public Service Electric & Gas Company 

PUD No 1 of Clark County 

Red River Valley Rural Electric Association 

Reedsburg Utility Commission 

Rice Lake Utilities 

Richland Center Electric Utility 

Richmond Power and Light 

River Falls Municipal Utility 

Riverside Public Utilities 

Sacramento Municipal Utility District 

Salt River Electric Coop Corp 

Salt River Project (SRP) 

San Luis Valley REC 

Satilla Rural Electric Membership Corporation 

Sawnee Electric Membership Corporation 

Sierra Electric Cooperative, Inc. 

Sierra Pacific Power Company 

Silicon Valley Power 

Singing River Electric Power Association 

Slinger Utilities 

Snohomish County Public Utility District #1 

Somerset Rural Electric Cooperative, Inc. 

South Carolina Electric & Gas Company 

South Carolina Public Service Authority 

South Kentucky Rural Electric Cooperative Corp 

South Mississippi Electric Power Association 

Southeast Colorado Power Association 

Southern California Edison 

Southwest Louisiana Electric Membership Corp 

Southwest Rural Electric Association 

Southwestern Electric Cooperative, Inc. 

Southwestern Electric Power Company 

Spooner, City of 

Steuben Rural Electric Cooperative, Inc. 

Stoughton Electric Utility 

Sturgeon Bay Utilities 

Sullivan County Rural Electric Cooperative, Inc. 

Sun Prairie Water & Light Commission 

Sussex Rural Electric Cooperative, Inc. 

Suwannee Valley Electric Cooperative, Inc. 

Tampa Electric Company 

Taylor Electric Cooperative 

Tri-County Electric Cooperative, Inc 

Tucson Electric Power Co. 

Two Rivers Water & Light Utility

TXU Energy Retail Company LLC 

Union Electric Company 

United Electric Coop Services 

United Power, Inc 

Valley Rural Electric Cooperative, Inc. 

Verdigris Valley Electric Cooperative, Inc 

Village of Greenport 

Village of Stratford 

Warren Electric Cooperative, Inc. 

Washington-St.Tammany Electric Cooperative, Inc. 

Waterloo Water & Light Commission 

Waunakee Water & Light Commission 

Waupun Public Utilities 

West River Electric Association, Inc. 

Westby Municipal Electric Utility 

Western Massachusetts Elec Co 

Wheatland Electric Cooperative, Inc. 

Wheeling Power Company 

Whitehall Municipal Electric Utility 

Willmar Municipal Utilities 

Wisconsin Power and Light Company 

Wisconsin Public Service Corporation 

WPPI Energy 

Wyrulec Company 

XCEL d/b/a Northern States Power Co - Minnesota 

XCEL d/b/a Northern States Power Co - Wisconsin 

Yazoo Valley Electric Power Association 
APPENDIX G: DATA FOR FIGURES IN THE REPORT

Appendix G provides the numerical data used to create the figures in the 2010 FERC 

Assessment of Demand Response and Advanced Metering, and the sources of the data. The 

data is this appendix, where compiled directly from data submitted by survey respondents 

without estimation of results for those not reporting, are labeled “Reported” or “Reporting.” 

Data that include estimation of results for those not reporting, based on survey and other 

information, are labeled “Estimated.” 

Advanced Metering 

Data supporting Figure 3.1 

Estimated advanced metering penetration nationwide in 2006, 2008 and 2010 FERC Surveys 

Year Advanced Metering 

2010 5.9%

2008 4.7%

2010 8.7%

Source: 2006, 2008 and 2010 FERC Surveys 

Data supporting Figure 3.2 

Estimated advanced metering penetration by region in 2006, 2008 and 2010 FERC Surveys

Region 

2006 FERC 

Survey 

2008 FERC 

Survey 

2010 FERC 

Survey 

MRO 0.6% 3.7% 15.3%

WECC 0.5% 2.1% 14.1%

ERCOT (TRE) 0.7% 9.0% 13.4%

SPP 3.0% 5.8% 8.9%

SERC 1.2% 5.8% 8.0%

RFC 0.4% 5.1% 6.7%

FRCC 0.1% 10.4% 5.0%

Hawaii 0.0% 1.6% 2.1%

ASCC 0.0% 0.0% 1.2%

NPCC 0.1% 0.3% 0.7%

United States 0.7% 4.7% 8.7%

Source: 2006, 2008 and 2010 FERC Surveys 

96 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Data supporting Figure 3.3 

Estimated penetration of advanced metering by type of entity in 2006, 2008 and 2010 FERC 

Surveys 

Ownership 

2006 FERC 

Survey 

2008 FERC 

Survey 

2010 FERC 

Survey 

Cooperatives 3.8% 16.4% 24.7% 

Political Subdivision 0.1% 2.2% 20.3% 

Investor Owned Utility 0.2% 2.7% 6.6% 

Municipal Entities 0.3% 4.9% 3.6% 

Federal and State Utility 0.2% 1.1% 0.7% 

Overall Average 0.7% 4.7% 8.7% 

Source: 2006, 2008 and 2010 FERC Surveys 

Data supporting Figure 3.4 

Reported numbers of customers and communication methods for advanced metering by 

customer class 

Customer Class Internet Bills 

Display 

Unit 

Communications Vehicles to Nonresidential Customers 

(n = 915,726) 

61% (n = 

560,452) 

38% (n = 

346,750) 

1% (n = 

8,524) 

Communications Vehicles to Residential Customers (n = 

7,093,081) 

68% (n = 

4,819,498) 

31% (n = 

2,186,869) 

1% (n = 

86,714) 

Communications Vehicles to Other Customers (n = 

52,812) 

47% (n = 

24,664) 

53% (n = 

27,959) 

.36% (n = 

189) 

Source: 2010 FERC Survey 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 97
Demand Response 

Data supporting Figure 4.1 

Reported number of customers enrolled in direct load control programs by region and type of 

entity 

Region 

Cooperative 

Entities 

Federal 

and State 

Investor 

Owned 

Utilities 

Municipal 

Entities Other Total 

TRE 85,000 171 85,171

FRCC 60,588 1,247,228 1,307,816

MRO 406,632 2,365 507,152 48,849 964,998

NPCC 6,261 39,634 32,660 78,555

RFC 294,278 1,203,367 2,270 1,499,915

SERC 421,625 347,748 29,577 798,950

SPP 13,119 35,479 48,598

WECC 4,602 821,610 6,872 833,084

Other 39,000 39,000

Total 1,207,105 2,365 4,241,218 205,228 171 5,656,087

Source: 2010 FERC Survey 

Estimated total number of customers 

TRE FRCC MRO NPCC RFC SERC SPP WECC Other 

11,242,472 9,001,379 7,694,462 16,062,605 36,257,770 31,682,323 6,509,331 31,044,502 683,840 

Source: 2008 FERC Survey, EIA-861 

Data supporting Figure 4.2 

Number of entities reporting interruptible/curtailable rates by region and type of entity 

Region 

Cooperative 

Entities 

Federal 

and State 

Investor 

Owned 

Utilities 

Municipal 

Entities Other Total 

TRE 1 0 0 0 1 2

FRCC 3 0 3 5 0 11

MRO 37 0 13 12 0 62

NPCC 0 0 6 1 0 7

RFC 14 0 46 1 0 61

SERC 31 9 29 3 0 72

SPP 9 0 10 4 0 23

WECC 8 0 17 2 0 27

Total 103 9 124 28 1 265

Source: 2010 FERC Survey 

98 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Data supporting Figure 4.3 

Number of entities reporting residential time-of-use rates by region and type of entity 

Region 

Cooperative 

Entities 

Federal 

and State 

Investor 

Owned 

Utilities 

Municipal 

Entities Other Total 

TRE 1 0 0 0 0 1

FRCC 2 0 2 3 0 7

MRO 8 0 3 35 0 46

NPCC 3 0 9 4 3 19

RFC 10 0 23 1 0 34

SERC 12 1 10 0 0 23

SPP 3 0 1 0 0 4

WECC 19 0 12 5 0 36

Total 58 1 60 48 3 169

Source: 2010 FERC Survey 

Data supporting Figure 4.4 

Reported number of customers enrolled in time-of-use rate programs by region and type of 

entity 

Region 

Cooperative 

Entities 

Federal 

and State 

Investor 

Owned 

Utilities 

Municipal 

Entities Other Total 

TRE 8 0 0 0 0 8

FRCC 40 0 249 206 0 495

MRO 1,546 0 20,387 284 0 22,217

NPCC 63 0 148,706 10,152 148 159,069

RFC 1,521 0 138,910 0 0 140,431

SERC 3,289 5 33,301 0 0 36,595

SPP 15 0 1,452 0 0 1,467

WECC 237,187 0 498,477 2,388 0 738,052

Total 243,669 5 841,482 13,030 148 1,098,334

Source: 2010 FERC Survey

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 99
Data supporting Figure 4.5 

Number of entities reporting retail real-time pricing by region & type of entity 

Region 

Cooperative 

Entities 

Federal and 

State 

Investor 

Owned Utilities Total 

TRE 0 0 0 0 

FRCC 0 0 0 0 

MRO 0 0 1 1 

NPCC 1 0 2 3 

RFC 0 0 6 6 

SERC 1 2 3 6 

SPP 0 0 2 2 

WECC 0 0 1 1 

Total 2 2 15 19 

Source: 2010 FERC Survey 

Data supporting Figure 4.6 

Total reported potential peak load reduction in the 2006, 2008 and 2010 FERC Surveys 

 Total reported potential peak load reduction (MW)

2006 FERC 

Survey 29,653 

2008 FERC 

Survey 37,335 

2010 FERC 

Survey 53,062 

Source: 2006, 2008 and 2010 FERC Surveys 

Data supporting Figure 4.7 

Reported potential peak load reduction by customer class in 2006, 2008, and 2010 FERC 

Surveys (MW) 

 

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 

Source: 2006, 2008 and 2010 FERC Surveys 

100 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
Data supporting Figure 4.8 

Reported potential peak load reduction in MW by region and customer class 

Region 

Commercial 

& Industrial Residential Wholesale Other Total 

TRE 72 123 1,312 3 1,510

FRCC 1,310 1,765 15 68 3,158

MRO 3,320 1,806 4,045 315 9,485

NPCC 1,490 90 4,649 0 6,228

RFC 5,267 1,139 9,199 259 15,864

SERC 6,451 798 1,733 172 9,154

SPP 1,404 79 1,502 141 3,126

WECC 2,062 1,369 430 626 4,487

Other 29 20 0 0 49

Total 21,405 7,189 22,884 1,584 53,062

Source: 2010 FERC Survey 

Data supporting Figure 4.9 

Reported potential peak load reduction in MW by type of program and by customer class 

Type of Program 

Commercial 

and 

Industrial Residential Wholesale Other Total 

Critical Peak Pricing 401 30 100 88 619

Critical Peak Pricing with 

Load Control 129 8 0 13 149

Demand Bidding & Buy-Back 1,251 0 2,750 17 4,018

Direct Load Control 1,687 5,568 793 957 9,006

Emergency Demand 

Response 1,375 163 11,493 11 13,041

Interruptible Load 9,524 50 1,033 371 10,977

Load as a Capacity 

Resource 3,503 1,124 4,110 53 8,790

Non-Spinning Reserves - - 118 - 118

Other 151 134 1,000 56 1,340

Peak Time Rebate 90 4 0 94

Real-Time Pricing 1,117 4 0 0 1,121

Regulation - - 10 - 10

Spinning Reserves 46 - 1,442 - 1,488

System Peak Response 

Transmission Tariff 1 4 0 - 5

Time-of-Use 2,132 100 35 19 2,285

Total 21,405 7,189 22,884 1,584 53,062

Source: 2010 FERC Survey 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 101
Data supporting Figure 4.10 

Net annual U.S. electrical generation, 2005 through 2009 (thousands of megawatt-hours) 

Year Net annual U.S. electrical generation

2005 4,055,423 

2006 4,064,702 

2007 4,156,745 

2008 4,119,388 

2009 3,953,111 

Source: Energy Information Administration 

Data supporting Figure 4.11 

Reported potential and actual 2010 peak load reduction in MW by demand response 

resources by region 

Region Potential Peak Reduction Actual Peak Reduction 

TRE 1,510 442

FRCC 3,158 957

MRO 9,485 2,462

NPCC 6,228 2,497

RFC 15,864 2,051

SERC 9,154 3,086

SPP 3,126 1,466

WECC 4,487 2,667

Other 49 352

Total 53,062 15,980

Source: 2010 FERC Survey 

Data supporting Figure 4.12 

Estimated potential peak load reduction in MW by demand response resources, by region and 

customer class 

Region 

Commercial 

& Industrial Residential Wholesale Other Total 

TRE 113 134 1,312 53 1,612 

FRCC 1,333 1,795 15 73 3,216 

MRO 3,932 2,102 4,045 339 10,418 

NPCC 1,954 98 4,649 173 6,875 

RFC 6,334 1,427 9,199 371 17,331 

SERC 7,005 1,575 1,733 208 10,521 

SPP 1,572 80 1,502 154 3,307 

WECC 2,344 1,581 430 626 4,981 

Other 53 25 78 

Total 24,640 8,817 22,884 1,998 58,339 

Source: 2010 FERC Survey 

102 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 103

Data supporting Figure 4.13 

Estimated potential peak load reduction in MW by demand response resources by type of 

entity and customer class 

Ownership Residential

Commercial 

& Industrial 

Other 

Retail Wholesale Total 

Investor Owned Utilities 5,433 17,634 827 0 23,894

Cooperative Entities 2,836 3,726 855 1,420 8,837

Municipal Entities 530 922 25 11 1,488

Retail Power Marketers 0 961 241 0 1,202

Federal & State 17 1,104 50 920 2,091

RTO/ISO 20,533 20,533

Total 8,816 24,347 1,998 22,884 58,045

Source: 2010 FERC Survey 
APPENDIX H: ADJUSTMENT METHODOLOGY FOR 2010 FERC

SURVEY

The following table summarizes the data used for imputing missing 2010 data in fields 

involved in the tables and figures in this report, as described in Appendix D. 

Table H1. Sources of data used to impute missing 2010 FERC survey data 

2010 Field Sector Comparison Survey Comparison Survey Fields Sort Variable 

Meters Residential 2008 EIA-861 file 2 RESIDENTIAL_CONSUMERS Residential Revenues 

Meters 

Commercial 

& Industrial 2008 EIA-861 file 2 

COMMERCIAL_CONSUMERS, 

INDUSTRIAL_CONSUMERS C & I Revenues 

Meters Other 

2008 FERC DR 

Survey Q7-OtherMeters Size 

Customers Residential 2008 EIA-861 file 2 RESIDENTIAL_CONSUMERS Residential Revenues 

Customers 

Commercial 

& Industrial 2008 EIA-861 file 2 

COMMERCIAL_CONSUMERS, 

INDUSTRIAL_CONSUMERS C & I Revenues 

Customers Other 

2008 FERC DR 

Survey Q7-OtherMeters Size 

AMI 

Meters Residential 2008 EIA-861 file 8 AMI_METERING_RESIDENTIAL Residential Revenues 

AMI 

Meters 

Commercial 

& Industrial 2008 EIA-861 file 8 

AMI_METERING_COMMERCIAL, 

AMI_METERING, INDUSTRIAL C & I Revenues 

AMI 

Meters Other 

2008 FERC DR 

Survey Q8-15Min-OtherAMI, Q8-Hourly-OtherAMI Size 

DR 

Program 

Customers Residential 2008 EIA-861 file 3 PRICERESPRES, TIMERESPRES Residential Retail Sales 

DR 

Program 

Customers 

Commercial 

& Industrial 2008 EIA-861 file 3 

PRICERESPCOM, PRICERESPIND, 

TIMERESPCOM, TIMERESPIND C & I Retail Sales 

DR 

Program 

Customers Other 2008 EIA-861 file 3 Nbr_cust_enrolled Nbr_cust_in_Class 

DR 

Program 

Customers 

DLC 

Program - 

Residential 

2008 FERC DR 

Survey Nbr_Cust_Enrolled Nbr_Cust_in_Class 

DR 

Program 

Customers 

TOU 

Program - 

Residential 

2008 FERC DR 

Survey Nbr_Cust_Enrolled Nbr_Cust_in_Class 

Potential 

DR Peak 

Reduction Residential 2008 EIA-861 file 3 LMPOTENTPEAKREDANNRES Residential Retail Sales 

Potential 

DR Peak 

Reduction 

Commercial 

& Industrial 2008 EIA-861 file 3 

LMPOTENTPEAKREDANNCOM, 

LMPOTENTPEAKREDANNIND C & I Retail Sales 

Potential 

DR Peak 

Reduction Other 

2008 FERC DR 

Survey Potential_Peak_Red Not Used 

Actual DR 

Peak 

Reduction Residential 2008 EIA-861 file 3 LMACTUALPEAKREDANNRES Residential Retail Sales 

Actual DR 

Peak 

Reduction 

Commercial 

& Industrial 2008 EIA-861 file 3 

LMACTUALPEAKREDANNCOM, 

LMACTUALPEAKREDANNIND C & I Retail Sales 

Actual DR 

Peak 

Reduction Other 

2008 FERC DR 

Survey Actual_Peak_Red Not Used 

104 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
The steps for producing the imputed values for the nonrespondent entities were as follows: 

Step 1: Merge comparison survey variables to 2010 FERC data at the level needed for 

the analysis tables and figures. There are four possible response cases for entities in the 

merged data sets: 

1) Entity provided a response in both 2010 and the 2008 comparison survey field 

2) Entity provided a response in 2010 but not in the 2008 comparison survey field 

3) Entity provided no response in 2010 but provided a response in the 2008 comparison survey 

field 

4) Entity responded in neither 2010 nor the 2008 comparison survey field 

Step 2: Isolate the entities in case 1 above and compute the percent increase from the 

comparison survey field and the 2010 variable. 

Step 3: Subset further, keeping just the entities with a percent increase between -50 and 

+100 (so the 2010 value was between half and twice that of the 2008 comparison value). 

Step 4: Assign a size variable to small, medium, or large depending on the value of the 

sort variable. Add this to the step 3 data set. 

Small: sort variable in the first quartile of the step 3 subset 

Medium: sort variable between the first and third quartiles of the step 3 subset 

Large: sort variable greater than the third quartile of the step 3 subset 

Step 5: Plot the 2010 variable against the 2008 comparison survey variable by size 

category to check for linearity. 

Step 6: When sufficient data exists, fit a linear regression of the 2010 variable on the 

comparison survey field with no intercept for each size category. 

Step 7: Merge the three size category regression coefficients onto the step 1 data set 

according to the size of the sort variable, i.e. medium sized entities will be assigned the 

regression coefficient fit for the medium sized entities. 

Step 8: For the case 3 entities in step 1 above, assign the 2010 value as follows: 

2010 value = 2008 comparison survey field * regression coefficient 

Each of these case 3 entities is assigned an imputation flag. 

Self-Selection Assessment Subsample

Commission staff determined that the FERC Survey, to adhere with its EPAct 2005 directive, 

must collect information on all entities that provide electric power and demand response to 

customers in the U.S. The FERC Survey population, essentially a census of respondents to 

the EIA-861 with the addition of Regional Transmission Operators (RTOs), Independent 

System Operators (ISOs), and Curtailment Service Providers (CSPs), is a voluntary survey. 

As such, there is inherent risk of self-selection bias – some subgroups of the entities asked to 

respond to the FERC Survey may be more likely to respond than others and the propensity 

for responding may be related to key measures in the FERC Survey such as advanced 

metering penetration.

The role of the subsample is to establish a subset of the full FERC Survey sample from 

which a set of survey response rates, subject to less risk of self-selection bias, may be used to 

compare against the corresponding set of response rates in the complementary portion of the 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 105
main survey sample for which no special measures were taken to reduce the risk of selfselection bias. Significant differences in corresponding response rates would indicate that 

there is risk of self-selection bias in the full set of respondents to the FERC Survey. 

While the Commission designed the survey instrument and collection process with the goal 

of obtaining a survey response from every targeted electricity providing entity, this 

subsample was targeted for follow-up measures such as callbacks to achieve as high a 

response rate as possible given the resource constraints of the survey and time constraints for 

reporting results. This extensive follow-up effort reaches out to potential respondents who 

chose not to respond for any number of reasons with the goal of obtaining responses by 

assisting them in filling out the form, explaining the purpose of the survey, and 

accommodating their wishes to complete the survey form by some other means. 

2006 and 2008 Subsample Designs 

In 2006 the FERC Survey was approved as a census with the following terms and conditions: 

“OMB approves this collection for one year with the following terms of clearance: FERC has 

agreed to several changes to its survey design to mitigate the potential for self-selection bias 

and will draw a random sample of 776 for follow-up to ensure a representative sample for the 

advanced metering survey. FERC will report back to OMB on achieved response rates by 

strata and on the results of analyses comparing the random sample to the universe of 

responses. FERC will also note any meaningful differences in its final report to Congress.” 

Commission expert knowledge of advanced metering penetration led the sample to be 

stratified into groups of similar entities rather than a simple random sample from the full 

frame. The attributes stratifying the sample population into cells of similar entities were 

NERC region, type of utility, and the number of retail customers served which are then 

grouped into size categories as follows: 

 Large – 100,000 or more customers 

 Medium – more than 25,000 and fewer than 100,000 customers 

 Small – 25,000 or fewer customers 

 Non-Retail – Entities that do not serve retail customers directly 

106 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Subsample Design 

The same basic subsample design as was used in 2006 and 2008 was maintained for the 2010 

FERC Survey, with some modifications. 

 Entities continued to be stratified by utility type and region, but unlike 2006 and 

2008, not according to the small, medium, and large categories. In 2010 the total 

number of customers will be used as the measure-of-size variable to select the 

uncertain portion of the sample via stratified ratio estimation assuming a very weak 

association between number of customers and advanced metering penetration. 

 A subset of the frame will be selected as a simple random sample rather than using 

the number of consumers as a measure of size. This subset will consist of entities for 

which the frame lacks information for NERC region and total number of consumers. 

These entities cannot be selected using the method above because they do not have 

the strata fields or the measure-of-size needed for selection. 

 The following NERC Regions plus Alaska and Hawaii, as well as split regions 

composed of them, will be considered in scope for the sample: 

 AK 

 FRCC 

 HI 

 MRO 

 NPCC 

 RFC (formerly MAAC, MAIN, and ECAR) 

 SERC 

 SPP 

 TRE 

 WECC 

 The following entity types will be considered in scope for the sample: 

 Co-operative 

 CSP 

 Federal 

 IOU 

 Municipal 

 Municipal Power Authority 

 Political Subdivision 

 Retail Power Marketer 

 State 

 ISO/RTO 

 The total sample size was fixed at 700. 

2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 107
 Stratified simple random sample – 50 from list of 461 entities meeting the following 

criteria: 

 Fewer than 10 consumers or none listed on the frame 

 Municipal Marketing Authorities 

 Cross-listed between NERC regions 

 The sample of 50 will be stratified by ownership and drawn using proportional 

allocation. 

 Stratified Ratio Estimation – 650 (from 2925 entities in NERC/ownership and size 

strata) 

Entities were selected at random within ownership type/regional strata, with minimum strata 

sample sizes constrained to three or more entities. If a region/ownership group has just one 

or two entities, they were selected with certainty. 

The stratified ratio estimation splits the strata further into small, medium, and large groups 

with the cutoffs for each size group determined by the sampling algorithm. Within the 

ultimate strata cells, the sampling algorithm selects entities with probability proportionate to 

their size, so the entity with the most consumers within an ownership type/region/size cell 

will have a greater chance of being selected than the other entities in the cell. Although the 

size categories for the sample strata will not have fixed cutoff levels, the response rates will 

be reported according to the size categories used in 2006 and 2008 for consistency with prior 

reports. 

Additional follow-ups outside the 700 entities in the sample were carried out for 

nonresponding entities in order to achieve the highest possible overall response rate. The 

follow-up effort utilized a list of all entities in the mail-out, ordered according to their 

relative priority for obtaining a response. The ordered list was organized in three tiers. The 

top tiers consisted of entities serving 100,000 or more consumers, ISOs, RTOs, or have and 

entities having State or Federal ownership. The middle tier consisted of entities serving 

between 25,000 and 100,000 consumers, and the final tier the remaining entities. Within 

each tier the entities were assigned a random order so that the follow-up effort was not biased 

by ownership type within the respective tiers. The follow-up was done first focusing 

completely on the top tier, then moving to the middle tier, and finally the third tier. 

108 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering             
2010 Assessment of Demand Response and Advanced Metering                           Federal Energy Regulatory Commission 109

Table H2. Subsample response rates 

Type of Entity Size 

Total 

Numbe

r 

DR 

Sample 

Respons

e Rate 

(n=940) 

DR 

Actual 

Respons

e Rate 

(n=537) 

AMI 

Sample 

Respons

e Rate 

(n=2183

) 

AMI 

Actual 

Respons

e Rate 

(n=1746

) 

Overall 

Sample 

Respons

e Rate 

(n=2182

) 

Overall 

Actual 

Respons

e Rate 

(n=1755

) 

Large 23 63.6% 60.9% 72.7% 69.6% 72.7% 69.6%

Mediu

m 

188 40.7% 38.3% 81.3% 74.5% 81.3% 74.5%

Other 47 0.0% 21.3% 80.0% 55.3% 80.0% 59.6%

Cooperatively Owned 

Utility 

Small 620 25.7% 21.9% 67.6% 61.9% 68.6% 62.1%

Curtailment Service 

Provider Other 11 0.0% 9.1% 50.0% 18.2% 50.0% 18.2%

Large 2 100.0

%

100.0

%

100.0

%

100.0

% 

100.0

%

100.0

%

Mediu

m 

1 0.0% 0.0% 100.0

%

100.0

% 

100.0

%

100.0

%

Other 16 0.0% 6.3% 50.0% 62.5% 50.0% 62.5%

Federal and State Utility 

Small 10 37.5% 30.0% 87.5% 90.0% 87.5% 90.0%

Large 114 79.8% 76.3% 96.2% 94.7% 96.2% 94.7%

Mediu

m 

22 40.0% 40.9% 80.0% 77.3% 80.0% 77.3%

Other 27 0.0% 0.0% 0.0% 14.8% 0.0% 18.5%

Investor Owned Utility 

Small 44 14.3% 11.4% 60.7% 52.3% 60.7% 52.3%

Large 20 50.0% 50.0% 83.3% 85.0% 83.3% 85.0%

Mediu

m 

87 19.6% 14.9% 66.7% 59.8% 66.7% 59.8%

Other 21 0.0% 19.0% 100.0

% 57.1% 100.0% 57.1%

Municipally Owned 

Utility 

Small 1733 3.4% 6.8% 55.9% 45.3% 55.9% 45.5%

Mediu

m 

1 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

Other Other 53 0.0% 0.0% 10.0% 3.8% 10.0% 3.8%

Small 3 0.0% 100.0

% 0.0% 100.0% 0.0% 100.0%

Large 7 71.4% 71.4% 85.7% 85.7% 85.7% 85.7%

Mediu

m 

12 8.3% 8.3% 66.7% 66.7% 66.7% 66.7%

Other 23 0.0% 4.3% 0.0% 30.4% 0.0% 34.8%

Political Subdivision 

Small 85 15.6% 11.8% 62.5% 56.5% 62.5% 56.5%

Large 18 18.2% 22.2% 27.3% 27.8% 27.3% 27.8%

Mediu

m 

18 14.3% 11.1% 85.7% 66.7% 85.7% 66.7%

Other 71 14.3% 2.8% 42.9% 23.9% 42.9% 25.4%

Power Marketer 

Small 67 10.5% 7.5% 47.4% 29.9% 47.4% 29.9%

Regional Transmission 

Organization/Independe

nt System Operator 

Other 7 0.0% 100.0

% 0.0% 85.7% 0.0% 100.0%

Transmission Other 7 0.0% 0.0% 0.0% 42.9% 0.0% 42.9%

Total 3358 27.8% 15.6% 64.6% 52.0% 64.6% 52.3%
Self-Selection Bias Assessment 

As described in Appendix D, the regression-adjusted imputation used to extrapolate survey 

results to the survey population limited self-selection bias by using data from the mandatory 

EIA-861 survey, where available. A subsample was also used, as described above, for 

comparison with the general respondents. The subsample procedures were carried out, and 

follow-up efforts extended from the subsample to the overall survey frame for larger entities 

to maximize the overall response rate. The table above summarizes the response rates for the 

general respondents and the subsample for the advanced metering and demand response 

sections of the 2010 FERC Survey. Comparison of the response rates suggests no strong 

evidence of self-selection bias. 

110 Federal Energy Regulatory Commission                  2010 Assessment of Demand Response and Advanced Metering