2012 Report

2012
Assessment of
Demand Response and Advanced Metering

Staff Report

Federal Energy Regulatory Commission
December 2012

The opinions and views expressed in this staff report do not necessarily represent those of the
Federal Energy Regulatory Commission, its Chairman, or individual Commissioners, and are
not binding on the Commission.

ACKNOWLEDGEMENTS
Federal Energy Regulatory Commission Staff Team
David Kathan, Team Lead
Robin Aldina
Michael P. Lee
Lisa Medearis
Pamela Sporborg
Michael Tita
Dean Wight
Andy Wilkerson

Z, INC. Team
French Kreger (Z, INC.)
Valerie Richardson (DNV-KEMA)
Will Gifford (DNV-KEMA)
Christopher Elsner (Z, INC.)

TABLE OF CONTENTS
Executive Summary .................................................................................................................. 1
Chapter 1. Introduction ............................................................................................................ 3
Preparation of This Year’s Report ........................................................................................ 3
Demand Response and Advanced Metering Survey ............................................................. 4
Report Organization .............................................................................................................. 4
Regions in This Report ......................................................................................................... 5
Chapter 2. Advanced Metering Infrastructure ......................................................................... 7
Definition of Advanced Metering ......................................................................................... 7
Advanced Metering Penetration ........................................................................................... 8
Analytical Approach ..........................................................................................................8
Survey Findings .................................................................................................................8
Customer Accessibility of Advanced Metering Data ......................................................... 13
Developments and Issues in Advanced Metering ............................................................... 14
Status of the Advanced Metering Deployments Funded by the American Recovery
and Reinvestment Act .................................................................................................15
Green Button Initiative ....................................................................................................15
Expanded Customer Service Offerings ............................................................................15
Use of Advanced Metering Data for Non-Billing Applications ......................................16
Opt-Out Programs ............................................................................................................17
Chapter 3. Demand Response ................................................................................................ 21
Definition of Demand Response ......................................................................................... 21
Survey Results .................................................................................................................... 22
Analytical Approach ........................................................................................................22
Summary of Report Findings ...........................................................................................22
Demand Response Activities at the FERC ......................................................................... 36
Commission Demand Response Activities ......................................................................36
Other Demand Response Developments and Issues ........................................................... 42
National Forum on the National Action Plan on Demand Response ...............................42
U.S. Department of Energy-Sponsored Consumer Behavior Studies..............................42
NERC Demand Response Data Collection ......................................................................43
Summer 2012 Demand Response Deployments ..............................................................44
Selected State Activities ..................................................................................................45
Barriers to Demand Response ............................................................................................. 49
Chapter 4. Smart Grid Developments Supporting Demand Response .................................. 51
Demand Response-Related Smart Grid Standards Development ....................................... 51
Demand Response Activities within the NIST/SGIP Process .........................................51
Smart Grid Demonstration Program ................................................................................... 54
Appendix A: Section 1252 of the Energy Policy Act of 2005 ................................................ 57
Appendix B: Acronyms and Abbreviations ........................................................................... 61
Appendix C: Glossary ............................................................................................................. 63
Appendix D: 2012 FERC Survey Method .............................................................................. 73
Background ......................................................................................................................... 73
Development of the FERC Survey and Sampling Design .................................................. 73
The Survey Population ........................................................................................................ 75

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FERC Survey Methodology................................................................................................ 75
Working with the Data ........................................................................................................ 76
Advanced Metering ..........................................................................................................76
Demand Response ............................................................................................................77
Eliminating Double-Counting in Wholesale Demand Response ........................................ 78
Appendix E: FERC Survey Respondents ............................................................................... 81
Appendix F: Demand Response Programs and Services at Responding Entities ................... 99
Appendix G: Data for Figures in Report............................................................................... 107
Advanced Metering ........................................................................................................... 107
Demand Response ............................................................................................................. 108
Appendix H: Adjustment Methodology for FERC-731 Survey ........................................... 115
Self-Selection Assessment Subsample ............................................................................. 116
Assessment of Past Designs .............................................................................................. 117
2012 Self-Selection Bias Assessment Design................................................................... 117
Survey Response Rates ..................................................................................................... 118
Self-Selection Bias Assessment ........................................................................................ 118

LIST OF TABLES
Table 2-1. Entities with the five largest 2010 to 2012 increases in reported advanced
meters ................................................................................................................ 9
Table 2-2. Estimated advanced metering penetration by region and customer class ............. 11
Table 2-3. Estimated penetration of advanced metering by state in 2008 – 2012 .................. 12
Table 3-1. Demand response program types in the 2012 FERC Survey ................................ 21
Table 3-2. Reported potential peak reduction in Megawatts by program type and state........ 28
Table 3-3. Reported plans for new demand response programs and time-based
rates/tariffs ...................................................................................................... 32
Table D-1. Survey Population for the 2012 FERC Survey ..................................................... 75
LIST OF FIGURES
Figure 1-1. NERC regions. ....................................................................................................... 6
Figure 2-1. Estimated advanced metering penetration nationwide reported in FERC
Surveys 2006, 2008, 2010, and 2012 ................................................................ 8
Figure 2-2. Estimated advanced metering penetration nationwide in 2006, 2008, 2010
and 2012 FERC Surveys ................................................................................. 10
Figure 2-3. Estimated advanced metering penetration by type of entity in 2006, 2008
and 2010, and 2012 FERC Surveys ................................................................ 14
Figure 2-4. Reported numbers of customers and communication methods for advanced
metering by customer class ............................................................................. 14
Figure 3-1. Total reported potential peak reduction in the 2006 through 2012 FERC
Surveys ............................................................................................................ 23
Figure 3-2. Reported potential peak reduction by customer class in 2006, 2008, 2010
and 2012 .......................................................................................................... 23
Figure 3-3. Reported potential peak reduction by Independent System Operators and
Regional Transmission Operators in 2010 and 2012 ...................................... 25

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2012 Assessment of Demand Response and Advanced Metering

Figure 3-4. Reported potential peak reduction by region and customer class for the
2010 and 2012 FERC Surveys ........................................................................ 25
Figure 3-5. Reported potential peak reduction by program type and by customer class
in 2012 FERC Survey ..................................................................................... 27
Figure 3-6. Reported actual peak reduction by NERC region between 2010 and 2012
FERC Survey years ......................................................................................... 30
Figure 3-7. 2012 FERC Survey reported potential and actual peak reduction by region ....... 30
Figure 3-8. Estimated potential peak reduction by region and customer class in 2010
and 2012 .......................................................................................................... 31
Figure 3-9. Estimated potential peak reduction by entity type and customer class in
2010 and 2012 ................................................................................................. 32
Figure 3-10. Number of entities reporting interruptible/curtailable rates by region and
type of entity in 2010 and 2012 ...................................................................... 33
Figure 3-11. Reported number of customers enrolled in direct load control programs by
region and type of entity in 2010 and 2012 .................................................... 34
Figure 3-12. Number of entities reporting residential time-of-use rates by region and
type of entity in 2010 and 2012 ...................................................................... 35
Figure 3-13. Reported number of residential customers enrolled in time-of-use rates by
region and entity type in 2010 and 2012 ......................................................... 35
Figure 3-14. Number of entities reporting retail real-time pricing by region and entity
type in 2010 and 2012 ..................................................................................... 36

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EXECUTIVE SUMMARY
In the past year, significant progress has been achieved for both wholesale and retail
electricity demand response and advanced metering, supported by the actions of state
regulators, federal regulators and federal funding under the American Recovery and
Reinvestment Act, the development of interoperability standards, and efforts of industry and
customers. According to information provided by survey respondents to the Federal Energy
Regulatory Commission (FERC) 2012 Demand Response and Advanced Metering Survey,
the potential demand response resource contribution from all U.S. demand response
programs is estimated to be nearly 72,000 megawatts (MW), or about 9.2 percent of U.S.
peak demand. This is an increase of about 13,000 MW from the 2010 FERC Survey. The
regions with the largest estimated demand response capability are the Midwest-to-MidAtlantic region, the Southeast, and the Upper Midwest. With regard to advanced metering,
penetration reached approximately 22.9 percent in 2011 in the United States, compared to
approximately 8.7 percent in the 2010 FERC Survey (covering calendar year 2009). Florida,
Texas, and the West have advanced meter penetrations exceeding 30 percent. As in previous
surveys, electric cooperatives have the largest penetration, nearly 31 percent, among
categories of organizations.
More than 1,900 entities responded to the voluntary FERC survey and many made
themselves available for follow-up questions. FERC staff greatly appreciates the responses
and assistance in completing the information for this Report.

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2

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CHAPTER 1. INTRODUCTION
The Energy Policy Act of 2005 (EPAct 2005) requires the FERC to prepare and publish an
annual report on the penetration of advanced metering and demand response programs in the
electric power industry in the United States. This data is to be divided and presented by
region, and the information is to cover all types of electric consumers.
EPAct 2005 expressly requires that the Commission’s annual report identify and review:
(A) saturation and penetration rates of advanced meters and communications
technologies, devices, and systems;
(B) existing demand response programs and time-based rate programs;
(C) the annual resource contribution of demand resources;
(D) the potential for demand response as a quantifiable, reliable resource for regional
planning purposes;
(E) steps taken to ensure that, in regional transmission planning and operations,
demand resources are provided equitable treatment as a quantifiable, reliable
resource relative to the resource obligations of any load-serving entity,
transmission provider, or transmitting party; and
(F) regulatory barriers to improved customer participation in demand response, peak
reduction, and critical period pricing programs.
This Report is the fourth annual comprehensive report based on a first-of-its-kind survey of
demand response and advanced metering. The first report was published in August 2006,
Assessment of Demand Response and Advanced Metering.1 Since 2006, Commission staff
has published a series of annual reports assessing demand response and advanced metering in
the U.S. In support of these reports, the FERC staff has conducted comprehensive
nationwide surveys every other year. In intervening years reports consist of updates based on
publicly-available information and discussions with market participants and industry experts.
Commission staff published its most recent annual report in November 2011.2

Preparation of This Year’s Report
In preparing this report, Commission staff undertook several activities, the most significant
being the preparation and release of the Demand Response and Advanced Metering Survey
(2012 FERC Survey). Commission staff also reviewed relevant literature and recent
developments on advanced metering, demand response programs, and time-based rates. As
with past surveys, the 2012 FERC Survey gathers data for the previous calendar year, 2011.

1

FERC, Assessment of Demand Response & Advanced Metering: Staff Report, Docket No. AD06-2, August 7,
2006, available at http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-advmetering.asp.
2
FERC, Assessment of Demand Response & Advanced Metering: Staff Report, November 2011. The annual
reports are available at http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-advmetering.asp.
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Demand Response and Advanced Metering Survey
The 2012 FERC Survey was conducted in the spring months of 2012 and requested
information from 3,349 entities in all 50 states,3 representing all aspects of the electricity
delivery industry: investor-owned utilities, municipal utilities, rural electric cooperatives,
power marketers, state and federal agencies, and other demand response providers.4 The
survey sought the following: (a) general information about the entity responding to the
survey, including contact information, customer size, and electricity demand and
consumption; (b) the number of advanced meters and their use; (c) existing demand response
and time-based rate programs, including their current level of resource contribution; and (d)
plans for future demand response program offerings. Like the 2010 Survey, the 2012 FERC
Survey combined advanced metering and demand response questions into one survey form.
The FERC staff also made efforts to enhance the clarity of instructions and definitions for the
2012 FERC Survey.
More than 1,978 entities responded to the 2012 FERC Survey, representing a response rate of
over 59 percent. This is an increase from the 2010 FERC Survey response rate of 52 percent.
Information gathered through the 2012 FERC Survey serves as the basis for this report’s
estimates of the market penetration5 of advanced metering, demand response resource
contributions, and current demand response and time-based rate programs. This report also
utilizes results from the 2010, 2008 and 2006 FERC Surveys to assess trends in advanced
metering deployment and demand response in the U.S.

Report Organization
The Introduction (Chapter 1) of this report describes the report’s structure, along with a
brief overview of the 2012 Survey methodology and key findings. The following chapters
provide the information required by EPAct 2005 section 1252(e)(3).
Advanced Metering Infrastructure (Chapter 2) presents survey results on the penetration
of advanced metering nationally, regionally, by type of utility, customer class, and by state.
This chapter also discusses the key new developments, issues, and trends in the deployment
and adoption of advanced metering. The chapter concludes with a description of major
challenges and issues for advanced metering in the U.S.
Demand Response (Chapter 3) presents survey results on demand response programs
(including time-based rate programs), and provides the regional and national distribution of
these programs. The chapter also includes estimates of the overall size of demand response
resources in the U.S. Chapter 3 then reviews demand response trends and developments at
the national and state level, and identifies several key trends in demand response. This
chapter also reviews Commission demand response activities and steps that have been taken
to ensure comparable treatment of demand response in regional transmission planning.
3

Later in the process it was determined that 15 of these entities were either out of business or not in a relevant
business.
4
Appendices D and H include detailed information on the survey and sample design. Appendix E lists the
respondents to the survey.
5
Penetration, for the purposes of this report, refers to the ratio of advanced meters to all installed meters.
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2012 Assessment of Demand Response and Advanced Metering

Finally, Chapter 3 concludes with a summary of potential barriers to demand response, as
identified by various sources.
Smart Grid Standards Development (Chapter 4) is a new section in this report series, and
provides an overview of work underway to develop and implement smart grid
interoperability standards that help support demand response.
This report also includes eight appendices that provide reference material and additional
detail on the survey data and responses. Appendix A provides the statutory language in
section 1252 of EPAct 2005. Appendix B lists the acronyms used in this report. Appendix
C contains a glossary of the key terms used in this report and the 2012 survey. Appendix D
provides additional detail on the 2012 FERC Survey and survey response rates. Appendix E
lists the entities who responded to the 2012 FERC Survey. Appendix F lists the entities that
reported operating demand response programs in the 2012 survey. Appendix G provides
data tables associated with each of the figures in this report. Appendix H describes the
estimation methods used in this report.

Regions in This Report
As in past reports, Staff is presenting the results of the 2012 Survey by NERC region. NERC
(North American Electric Reliability Council) is an international nonprofit organization
certified by the FERC as the electric reliability organization for the U.S. The 2012 FERC
Survey uses NERC’s eight regional divisions to better identify trends and align regulatory
and industry geographical units. The regional entities are:
 Florida Reliability Coordinating Council (FRCC)
 Midwest Reliability Organization (MRO)
 Northeast Power Coordinating Council (NPCC)
 ReliabilityFirst Corporation (RFC)
 SERC Reliability Corporation (SERC)
 Southwest Power Pool (SPP)
 Texas Reliability Entity (TRE)
 Western Electricity Coordinating Council (WECC)
The map in Figure 1.1 illustrates the boundaries of the NERC regions. Although some
NERC regions include areas in Canada and Mexico, the Commission only requested data
from the U.S. portions of these NERC regions. In this report, Hawaii and Alaska are not
included in most regional data summaries, but are included in state-level data tables.

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Figure 1-1. NERC regions.

FRCC - Florida Reliability Coordinating Council
MRO - Midwest Reliability Organization
NPCC - Northeast Power Coordinating Council
RFC - ReliabilityFirst Corporation

SERC - SERC Reliability Corporation
SPP - Southwest Power Pool
TRE - Texas Reliability Entity
WECC - Western Electricity Coordinating Council

Source: North American Electric Reliability Corporation, July 2012.

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CHAPTER 2. ADVANCED METERING INFRASTRUCTURE
This chapter reports on the first topic in EPAct 2005 section 1252(e)(3):
(A) saturation and penetration rates of advanced meters and communications
technologies, devices and systems.
The information presented is divided into the following three sections and is based on the
2012 FERC Survey, with comparisons to previous FERC Surveys (as appropriate) to
demonstrate trends in advanced metering deployment on a regional basis, by type of entity,
and by customer type.6
 Definition of Advanced Metering
 Advanced Metering Penetration
 Developments and Issues in Advanced Metering
All figures and tables are labeled “Estimated…” This indicates that additional information
was used in conjunction with 2012 FERC Survey data to improve the accuracy of Staff’s
estimates. A detailed description of these estimation methods can be found in Appendix H.

Definition of Advanced Metering
For the 2012 FERC Survey, FERC staff used the following definition of advanced meters:
Advanced Meters: Meters that measure and record usage data at hourly intervals or
more frequently, and provide usage data to both consumers and energy companies at
least once daily. Data are used for billing and other purposes. Advanced meters
include basic hourly interval meters, meters with one-way communication, and realtime meters with built-in two-way communication capable of recording and
transmitting instantaneous data.
Several respondents to the 2012 FERC Survey provided lower advanced meter counts than in
previous FERC Surveys. Respondents that reported large declines were contacted for
explanation. During these calls, staff learned anecdotally that many of the reported declines
were due to respondents reclassifying their responses based on a better understanding of the
survey’s “advanced meter” definition. For example, many respondents had installed meters
with advanced metering capability, but were still in the process of programming the software
and establishing the infrastructure to allow for communication on a daily basis.
Consequently, these installed meters did not meet the advanced meter definition.

6

A full database of survey responses is available at
http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-adv-metering.asp.
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Advanced Metering Penetration
This section describes the analytical approach used in the 2012 FERC Survey and provides
summary findings.

Analytical Approach
Commission Staff estimates of advanced metering penetration in the U.S. are primarily based
on the 2012 FERC Survey data. However, the 2012 advanced metering data was
supplemented by past FERC Survey data and survey data from the Energy Information
Administration’s Annual Electric Power Industry Report (i.e., Form EIA-861 survey data)7
for this report. In contrast to previous years, the 2012 estimation methods both fill in missing
data and correct for reporting errors. A detailed explanation of these estimation methods can
be found in Appendix H.

Survey Findings
Results indicate significant growth in advanced metering deployment in the U.S. As Figure
2-1 illustrates between 2006 and 2012, the number of advanced meters currently operating in
the U.S. (38 million) as a percentage of total meters installed is estimated to be 23 percent.
This represents a 14 percentage point increase from 2010 levels.

Figure 2-1. Estimated advanced metering penetration nationwide reported in
FERC Surveys 2006, 2008, 2010, and 2012

Secondary sources suggest that advanced metering deployment will continue to increase
significantly past 2012. While as noted above the FERC Survey reports nearly 38 million
advanced meters installed as of December 31, 2011, the Institute for Energy Efficiency (IEE)
7

The Energy Information Administration collects information on advanced metering in its annual Form EIA861 (Annual Electric Power Industry Report). As Appendix H describes, EIA provided FERC staff with
preliminary Form EIA-861 data to help improve estimation.
8

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2012 Assessment of Demand Response and Advanced Metering

projects that a total of 65 million advanced meters will be deployed by 2015. 8 In addition,
recipients of U.S. Department of Energy Smart Grid Investment Grants report adding almost
1 million advanced meters over the first and second quarters of 2012.9
The following tables and figures in this chapter provide detailed information on the estimated
38 million advanced meters operating in the U.S. by geographic region, customer class, and
ownership category. Table 2-1 below lists the respondents with the five largest increases in
advanced meters from 2010 to 2012 (ranked by the size of the increase in reported advanced
meters).

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

Entity Name
Southern California Edison
Florida Power & Light Company
Pacific Gas and Electric Company
Oncor Electric Delivery Company
Puget Sound Energy, Inc.

NERC
Region
WECC
FRCC
WECC
TRE
WECC

State
CA
FL
CA
TX
WA

2010
Advanced
Meters
147,645
202,510
2,085,712
662,774
7,432

2012
Advanced
Meters
3,740,640
2,675,479
4,508,036
2,664,462
1,900,306

Advanced Meter
Increase
3,592,995
2,472,969
2,422,324
2,001,688
1,892,874

Advanced Metering
Penetration
75.2%
58.8%
88.7%
83.5%
99.9%

The advanced metering deployments shown in Table 2-1 are currently in the middle to late
stages of deployment. The funding for these advanced metering deployments were primarily
subject to state commission-approved cost recovery. For example, the California Public
Utility Commission authorized two of the state’s primary investor-owned utilities, Southern
California Edison and Pacific Gas and Electric, to replace conventional meters with advanced
meters.10 Southern California Edison expects to complete its deployment of approximately 5
million advanced meters by the end of 2012, and reports that this deployment was
approximately 78 percent complete as of January 2012.11 Pacific Gas and Electric reports
installing nearly 4.7 million advanced meters as of November 2011, and expects to complete
its advanced meter rollout by mid-2013.12

8

Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans, & Proposals, May 2012,
available at http://www.edisonfoundation.net/iee/Documents/IEE_SmartMeterRollouts_0512.pdf.
9
SmartGrid.gov, Advanced Metering Infrastructure and Customer Systems, available at
http://www.smartgrid.gov/recovery_act/deployment_status/ami_and_customer_systems.
10
California Public Utilities Commission, The Benefits of Smart Meters, available at
http://www.cpuc.ca.gov/PUC/energy/Demand+Response/benefits.htm.
11
California Public Utilities Commission, California Division of Ratepayer Advocates, Case Study of Smart
Meter System Deployment: Recommendations for Ensuring Ratepayer Benefits, March 2012, available at
http://www.dra.ca.gov/uploadedFiles/Content/Energy/Management_and_Conservation/Smart_Meters/SmartMet
erSystemDeploymentReportMar2012FinalDraft_wcover_Public.pdf.
12
PG&E, SmartMeter™ Program Data, 12/13/2011, available at
http://www.pge.com/includes/docs/pdfs/myhome/customerservice/meter/smartmeter/SmartMeterProgramData_
12-13-11.pdf.
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Figure 2-2 illustrates how advanced metering penetration has increased in nearly every
region in the continental U.S. between 2010 and 2012.13 In 2010, no NERC region had an
advanced metering penetration rate over 20 percent; by contrast, Staff estimates that three
regions (FRCC, TRE and WECC) now have an advanced metering penetration rate over 30
percent. WECC has the highest advanced metering penetration rate of over 40 percent. This
is primarily driven by investor-owned utility rollouts in California, Oregon, Nevada, Idaho,
and Arizona.

Figure 2-2. Estimated advanced metering penetration nationwide in 2006,
2008, 2010 and 2012 FERC Surveys

Penetration

2006 Survey
45%
40%
35%
30%
25%
20%
15%
10%
5%
0%

2010 Survey

2012 Survey

42.4%
38.6%
32.5%
22.0%
15.2%

14.6%

10.4%
5.3%
0.2%
MRO

2006 Survey
2008 Survey
2010 Survey
2012 Survey

2008 Survey

0.6%
3.7%
15.3%
14.6%

WECC
0.5%
2.1%
14.1%
42.4%

0.0%

TRE

SPP

SERC

RFC

FRCC

Hawaii

ASCC

NPCC

0.7%
9.0%
13.4%
38.6%

3.0%
5.8%
8.9%
15.2%

1.2%
5.8%
8.0%
22.0%

0.4%
5.1%
6.7%
10.4%

0.1%
10.4%
5.0%
32.5%

0.0%
1.6%
2.1%
0.2%

0.0%
0.0%
1.2%
0.0%

0.1%
0.3%
0.7%
5.3%

Table 2-2 compares the estimated penetration of advanced meters by customer class across
the 2008, 2010 and 2012 FERC Surveys. The increases in advanced metering penetration are
generally driven by the residential sector. However, advanced metering penetration for
nonresidential customers has also increased significantly in some regions, most notably
WECC and TRE, where advanced metering penetration is estimated to be over 30 percent.

13

A notable departure from the trend of increasing advanced metering penetration between the 2010 and 2012
Surveys is for the MRO region, where there was an apparent slight decrease in advanced metering penetration
as compared to the 2010 FERC Survey estimate. Small decreases in penetration appeared in Hawaii and ASCC
as well. In the MRO region, Wisconsin Public Service reported a decline in 375,000 advanced meters between
survey years. Follow-up conversations revealed that in the 2010 FERC Survey Wisconsin Public Service had
mistakenly reported automated meter reading (AMR) meters as advanced meters, and corrected for this in 2012.
Most of the decline in Hawaii was due to suspected AMR entries as well, discovered through comparison
analysis with the 2011 EIA-861 Survey preliminary database. In ASCC, no 2012 responses reporting advanced
meters were received, but a small number of advanced meters were estimated for one entity in ASCC in 2010.
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Table 2-2. Estimated advanced metering penetration by region and customer
class
Advanced Metering Penetration
Residential Class

All Classes
FERC Survey
Region
MRO
WECC
TRE
SPP
SERC
RFC
FRCC
Hawaii
ASCC
NPCC
United States

2008
3.7%
2.1%
9.0%
5.8%
5.8%
5.1%
10.4%
1.6%
0.0%
0.3%
4.7%

2010
15.3%
14.1%
13.4%
8.9%
8.0%
6.7%
5.0%
2.1%
1.2%
0.7%
8.7%

2012
14.6%
42.4%
38.6%
15.2%
22.0%
10.4%
32.5%
0.2%
0.0%
5.3%
22.9%

2008
4.0%
2.1%
8.5%
6.1%
6.1%
5.0%
10.8%
1.6%
0.0%
0.3%
4.7%

2010
15.8%
14.9%
13.4%
9.2%
8.3%
6.7%
5.2%
2.2%
1.3%
0.6%
8.9%

2012
15.3%
43.5%
39.0%
15.9%
24.6%
10.9%
34.5%
0.1%
0.0%
5.3%
23.9%

Nonresidential Classes
2008
2.2%
2.0%
12.4%
4.2%
3.2%
6.1%
7.8%
1.6%
0.0%
1.0%
4.2%

2010
11.9%
9.1%
13.1%
7.5%
5.9%
6.9%
3.3%
1.8%
0.6%
1.1%
7.0%

2012
8.9%
33.5%
34.1%
11.6%
5.6%
6.2%
17.1%
0.4%
0.0%
6.0%
14.4%

Table 2-3 lists estimated market penetration rates of advanced meters by state. The largest
increase in advanced metering market penetration was in the District of Columbia;
penetration in D.C. is estimated to increase from nearly zero percent in the 2010 survey to
over 80 percent in the 2012 survey.14 This can be attributed to the Potomac Electric Power
Company (Pepco) advanced metering rollout that began in 2011.15
California has the second-highest market penetration rate in the country, 70 percent. This is
primarily due to advanced metering rollouts by two utilities: Southern California Edison and
Pacific Gas and Electric.16 There were also large advanced metering deployments in other
Western states such as in Oregon, Nevada, Idaho, and Arizona. Each of these states has a
market penetration rate over 50 percent and contains at least one investor-owned utility that
deployed over 200,000 advanced meters between 2010 and 2012.17
Georgia’s advanced metering market penetration rate increased by almost 54 percentage
points from 2010 to 2012. The majority of this growth came from Cooperatives such as the
Central Georgia Electric Membership Corp., which added over 140,000 advanced meters
between 2010 and 2012.

14

As noted in the 2010 Assessment of Demand Response & Advanced Metering: Staff Report, the large apparent
decrease in advanced meter count and total meter count for the District of Columbia from 2008 to 2010 was due
to a correction in reporting that erroneously included Pepco’s meters in the Maryland suburbs in the District of
Columbia estimate.
15
In July 2011, Pepco began a smart-meter rollout that was expected to include over 500,000 customers by the
end of 2012, and complete their D.C. deployment by the end of 2011. Pepco smart-meter rollout announcement
is available at http://www.pepco.com/welcome/news/releases/archives/2011/article.aspx?cid=1787.
16
As highlighted in Table 2-1, Southern California Edison and Pacific Gas & Electric (both located in
California) were the first and third largest entities adding AMI meters in the country, respectively. Pacific Gas
& Electric is focused on installing advanced meters for all their customers by 2013, with over 9 million already
installed. See
http://www.pge.com/myhome/customerservice/smartmeter/installation/.
17
Arizona Public Service in Arizona, Idaho Power Company in Idaho, Nevada Power Company in Nevada, and
Portland General Electric Company in Oregon.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 11

Table 2-3. Estimated penetration of advanced metering by state in 2008 –
201218
State
DC
CA
ID
GA
AZ
NV
AL
DE
OR
ME
TX
OK
FL
SD
WY
PA
TN
WI
MI
ND
NC
MS
AR
NH
SC
MO
KY
OH
NE
IN
IA
KS
MN
CO
VA
CT
MD
MT
IL
MA
WA
UT
LA
NM
AK
NY
NJ
HI
RI
VT
WV

2008
2010
2012
AMI meters Total meters Penetration AMI meters Total meters Penetration AMI meters Total meters Penetration
1,348
809,412
0.2%
2
275,554
0.0%
248,133
285,046
87.1%
170,896
14,595,958
1.2%
2,475,896
14,837,434
16.7% 10,459,477
14,836,734
70.5%
105,933
769,963
13.8%
198,370
803,576
24.7%
530,655
802,440
66.1%
342,772
4,537,717
7.6%
514,403
4,401,623
11.7%
3,013,541
4,599,392
65.5%
96,727
2,810,224
3.4%
847,177
2,915,712
29.1%
1,646,410
2,977,092
55.3%
10,835
1,292,331
0.8%
24,378
1,255,950
1.9%
717,220
1,299,632
55.2%
139,972
2,774,764
5.0%
127,092
2,467,741
5.2%
1,397,672
2,604,431
53.7%
0
438,020
0.0%
10,433
455,926
2.3%
310,890
593,583
52.4%
39,797
1,890,423
2.1%
478,897
1,896,717
25.2%
960,151
1,874,339
51.2%
426
780,748
0.1%
20,315
796,691
2.5%
671,036
1,372,735
48.9%
868,204
10,870,895
8.0%
1,284,179
11,013,153
11.7%
5,948,975
16,987,336
35.0%
161,795
1,875,325
8.6%
215,462
2,028,522
10.6%
703,091
2,071,552
33.9%
765,406
9,591,363
8.0%
490,150
9,644,617
5.1%
3,052,570
9,771,192
31.2%
41,191
475,477
8.7%
41,122
432,632
9.5%
109,586
440,774
24.9%
12,268
318,282
3.9%
14,437
303,272
4.8%
70,650
308,024
22.9%
1,443,285
6,036,064
23.9%
1,493,201
6,152,994
24.3%
1,623,982
7,753,238
20.9%
60,385
3,160,551
1.9%
252,341
2,761,758
9.1%
724,469
3,738,153
19.4%
117,577
3,039,830
3.9%
757,688
3,418,498
22.2%
562,861
3,107,700
18.1%
73,948
5,311,570
1.4%
269,933
4,865,396
5.5%
738,702
4,859,675
15.2%
33,336
375,473
8.9%
42,875
445,164
9.6%
61,329
407,033
15.1%
143,093
4,771,479
3.0%
385,884
4,847,336
8.0%
644,811
4,832,250
13.3%
3
1,454,275
0.0%
97,344
1,511,958
6.4%
201,877
1,584,994
12.7%
168,466
1,488,124
11.3%
14,578
1,529,065
1.0%
162,181
1,559,849
10.4%
260
763,683
0.0%
391
755,770
0.1%
76,864
743,454
10.3%
114,619
2,373,047
4.8%
312,894
2,445,044
12.8%
246,526
2,417,863
10.2%
204,498
3,098,055
6.6%
506,416
3,072,893
16.5%
299,375
3,061,397
9.8%
105,460
2,161,142
4.9%
273,663
2,523,833
10.8%
313,094
3,353,259
9.3%
28,042
5,544,353
0.5%
289,970
6,290,618
4.6%
638,167
7,267,087
8.8%
8,630
970,774
0.9%
19,290
999,353
1.9%
83,342
977,513
8.5%
61,551
3,115,205
2.0%
148,129
3,355,485
4.4%
275,821
3,342,734
8.3%
46,407
1,714,774
2.7%
58,092
1,576,475
3.7%
124,975
1,623,036
7.7%
61,423
1,426,832
4.3%
62,626
1,467,092
4.3%
110,628
1,452,858
7.6%
37,071
2,542,113
1.5%
108,232
2,602,360
4.2%
203,717
2,709,254
7.5%
39,873
2,246,184
1.8%
111,330
2,403,001
4.6%
183,658
2,446,657
7.5%
6,448
3,965,584
0.2%
175478
3,663,525
4.8%
201,014
3,706,158
5.4%
5,838
1,600,768
0.4%
1,967
1,625,758
0.1%
101,267
2,044,906
5.0%
8
1,938,948
0.0%
4,189
2,483,628
0.2%
108,881
2,856,999
3.8%
8,979
549,136
1.6%
27,470
577,745
4.8%
20,101
563,920
3.6%
112,410
5,701,533
2.0%
286,568
6,099,158
4.7%
196,150
6,138,749
3.2%
3,907
3,077,679
0.1%
20,831
3,150,098
0.7%
70,729
3,384,865
2.1%
69,377
2,987,355
2.3%
128,857
3,298,781
3.9%
74,252
4,009,332
1.9%
37
1,056,718
0.0%
20,046
1,083,069
1.9%
18,250
1,069,087
1.7%
44,103
2,186,249
2.0%
53,848
2,245,066
2.4%
37,691
2,325,796
1.6%
20,776
904,861
2.3%
54,250
1,015,058
5.3%
68,975
4,533,949
1.5%
18
315,419
0.0%
3,835
316,289
1.2%
4,045
295,821
1.4%
12,778
7,811,335
0.2%
28,664
9,313,776
0.3%
23,756
9,063,297
0.3%
9,866
3,900,716
0.3%
25,744
3,953,683
0.7%
13,768
6,062,487
0.2%
6,550
405,228
1.6%
8,713
411,232
2.1%
737
484,479
0.2%
148
480,135
0.0%
2,381
506,379
0.5%
210
477,183
0.0%
20,755
375,202
5.5%
31,293
379,139
8.3%
128
398,300
0.0%
10
1,183,513
0.0%
7,039
1,033,802
0.7%
280
1,051,585
0.0%

Several advanced metering rollouts occurred in tandem with new time-of-use demand
response programs. For example, Oklahoma added over 450,000 advanced meters between
the 2010 and 2012 FERC Surveys, largely from the advanced metering deployments by the
18

As noted elsewhere in this Report, entities revised what meters they included as being consistent with the
definition of AMI used for this report.
12 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Oklahoma Gas and Electric (OG&E). OG&E has stated that it is interested in delaying the
need for constructing additional generation facilities until 2020; therefore, OG&E is working
to combine smart grid technology (including advanced meters) with dynamic pricing to help
manage demand and achieve this goal.19 OG&E is using a combination of state and federal
funding to complete this dual advanced metering/demand response program.20
Figure 2-3 provides the estimated national penetration rate of advanced metering by entity
type. Advanced metering penetration increased for each entity type between 2010 and 2012.
Cooperatives still had the highest penetration with 31 percent. However, advanced metering
penetration for other entity types, such as political subdivisions21 and investor-owned
utilities, are reaching similar levels, with 29 percent and 25 percent market penetration
respectively.
The growth in the political subdivision category was driven by Salt River Project, which was
responsible for over 84 percent of the total advanced meters for this entity type. Salt River
Project was the recipient of federal Smart Grid Investment Grant (SGIG) funding to help
double its advanced metering meter penetration rate between 2010 and 2012; the SGIG
project also used time-of-day pricing to allow customers to better monitor and manage their
energy consumption.22

Customer Accessibility of Advanced Metering Data
The 2010 and 2012 FERC Surveys asked respondents with demand response or time-based
rate programs to categorize the ways in which their customers are capable of receiving
detailed energy usage data: over the internet, on their bills or invoices, or via a display unit
(e.g., an in-home display). Figure 2-4 illustrates that internet-based access has become the
dominant medium for customers to retrieve their energy usage data. In 2010, an estimated
5.4 million customers (both residential and nonresidential) were capable of using the internet
to access information on their energy use. That number increased significantly to 17.5
million customers by 2012, becoming the dominant means of accessing energy usage
information.

19

Oklahoma Gas & Electric, Second Year Preliminary Results Confirm Smart Technology Helps Reduce Peak
Energy Use, 1/24/2012 press release, available at http://phx.corporate-ir.net/phoenix.zhtml?c=106374&p=irolnewsArticle&ID=1652157&highlight=.
20
Ibid.
21
Political Subdivisions include public utility districts, irrigation districts, and associations like the Salt River
Project.
22
Salt River Project added over 300,000 AMI meters between 2010 and 2012, and was a significant contributor to
the estimated penetration of 30 percent for its entity type. Its rollout was driven by funding from U.S.
Department of Energy, and its plan to install one million meters for its customers. Salt River Project smart
meter information is available at http://www.srpnet.com/electric/home/millionmeters.aspx.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 13

Figure 2-3. Estimated advanced metering penetration by type of entity in
2006, 2008 and 2010, and 2012 FERC Surveys

Ownership Cooperatives Political Subdivision Investor Owned Utility Municipal Entities Federal and State Utility
2006 Survey
3.8%
0.1%
0.2%
0.3%
0.2%
2008 Survey
16.4%
2.2%
2.7%
4.9%
1.1%
2010 Survey
24.7%
20.3%
6.6%
3.6%
0.7%
2012 Survey
30.9%
29.4%
25.0%
12.4%
3.6%

Figure 2-4. Reported numbers of customers and communication methods for
advanced metering by customer class
Nonresidential

Residential

Number of Customers

18,000,000
15,000,000
12,000,000
9,000,000

6,000,000
3,000,000
0

Internet

Bills

Display

Communications Method

Developments and Issues in Advanced Metering
This section highlights developments in several key advanced metering policy areas: (1) the
status of the advanced metering deployments funded by the American Recovery and
Reinvestment Act (ARRA), (2) the Green Button initiative, (3) expanded customer offerings,
(4) use of advanced metering data for non-billing applications, and (5) noteworthy state
activities on consumer opt-out programs.
14 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Status of the Advanced Metering Deployments Funded by the American
Recovery and Reinvestment Act
The ARRA provided $4.5 billion in awards for smart grid deployment programs,23 and a
portion of that funding provided matching grants for advanced metering development. The
SGIG program has funded investments in advanced meters, networks, and hardware that
enable two-way communications between consumers and their electricity providers.
According to U.S. Department of Energy data, it has invested $2.8 billion in advanced
metering as of June 2012, and SGIG recipients have deployed and are operating 10.3 million
advanced meters. A total of 15.5 million advanced meters are planned to be deployed under
the ARRA program, and over two-thirds of these planned meters have been installed as of
September 30, 2012.24

Green Button Initiative
The Green Button Initiative is an effort for utilities to voluntarily provide retail electricity
customers with easily accessible and up-to-date data on their electricity usage. The initiative
began in September 2011 when U.S. Chief Technology Officer Aneesh Chopra challenged
the electric industry to provide customers access to their energy usage information
electronically in a user-friendly format.25 Since launching the Green Button Initiative in
January 2012, 35 utilities have committed to participate,26 which will provide 27 million
households in 17 states27 and the District of Columbia access to their energy usage
information.28 In a statement of support, the National Association of Regulatory Utility
Commissioners (NARUC) stated, “Voluntary efforts like the Green Button Initiative will
have a positive impact on both our electricity prices and the environment, and we salute the
States and utilities that are pursuing these developments.”29

Expanded Customer Service Offerings
Efforts to standardize the format of energy usage information and protect customer privacy30
have fostered the rapid development of new applications to further engage and inform
customers. Among these new offerings are home energy reports, customized alerts or
notifications, and improved management software. Advanced metering data makes it
possible for utilities and third-party service providers to offer customers these new and
23

U.S. Department of Energy, 2010 Smart Grid System Report, February 2012, p. 7, available at
http://energy.gov/oe/downloads/2010-smart-grid-system-report-february-2012.
24
Smartgrid.gov, Advanced Metering Infrastructure and Customer Systems, available at
http://www.smartgrid.gov/recovery_act/deployment_status/ami_and_customer_systems.
25
Aneesh Chopra, “Modeling a Green Energy Challenge after a Blue Button,” Office of Science and
Technology Policy, The White House, September 2011, available at
http://www.whitehouse.gov/blog/2011/09/15/modeling-green-energy-challenge-after-blue-button.
26
See http://www.whitehouse.gov/sites/default/files/microsites/ostp/energy_datapalooza_fact_sheet.pdf for
more information.
27
Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, North
Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, and West Virginia, as well as the District
of Columbia.
28
See: Green Button, Adopters, available at http://www.greenbuttondata.org/greenadopt.html.
29
National Association of Regulatory Utility Commissioners, “NARUC Applauds States, Utilities for ‘Green
Button’ Efforts,” March 23, 2012 press release, available at http://www.naruc.org/News/default.cfm?pr=306.
30
See, e.g., the NAESB Energy Service Provide Interface (see Chapter 4).
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 15

innovative products and services which are designed to help customers save money, qualify
for incentives, and consume electricity more efficiently.
For example, the U.S. Department of Energy sponsored an “Apps for Energy” contest in
April 2012 that offered $100,000 to software developers who created the best new apps to
help customers utilize Green Button electricity usage data.31 The winning application was
submitted by Leafully, which created a program that compares a customer’s energy usage to
the number of trees needed to offset the pollution created by that electricity consumption.32
Other companies used social media and peer comparison/competition to promote awareness
of energy consumption. For example, Opower recently partnered with Facebook and the
National Resources Defense Council to launch an application that allows customers to post
their electric usage data online and compare it to others with similarly-sized homes.33

Use of Advanced Metering Data for Non-Billing Applications
In addition to expanded service offerings, data derived from advanced metering allows
utilities to help tackle long-standing issues such as outage management, power and voltage
quality, overloaded customer services and overheating meter sockets. For example,
advanced meters have the ability to provide “last gasp” messages. As soon as an advanced
meter experiences an outage, an internal battery can provide enough power to transmit an
outage message back to the utility. These messages can be actively monitored, or fed into an
outage management system to determine the extent of outages and assist in dispatching the
necessary resources. In addition to facilitating timely outage responses, advanced meters can
reduce unnecessary service calls. For example, if a customer calls to report an outage, a call
center representative can attempt to contact the customer’s meter to determine immediately if
the customer has power. This ability of advanced meters to detect outages proved valuable
for several utilities on the East Coast during the restoration efforts following Hurricane
Sandy in October 2012.34 Many advanced meters also have the ability to sense the meter’s
internal temperature, related to its ability to maintain accuracy over its operating temperature
range. This can be used to detect overheating conditions within the meter.
Advanced metering systems can also open up new ways of monitoring voltage throughout an
electric distribution system; this can improve operational control and efficiency. Voltage
typically varies across a distribution circuit, and to ensure that voltage is consistently within
the allowable band (usually 114 to 126 volts), utilities have traditionally relied on
engineering models to identify potential points in a circuit where voltage may fall outside the
allowable range. Voltage levels outside allowable ranges can reduce customers’ service
quality and compromise the reliability of grid components such as transformers. However,
since advanced meters provide data more frequently than traditional meters, a utility can
monitor voltage levels using actual data throughout the circuit, rather than using engineering
31

U.S. DOE, Challenge.gov, Apps for Energy, available at http://appsforenergy.challenge.gov/.
Leafully, What is Leafully?, available at https://www.leafully.com/tour/.
33
Opower, Your electricity use vs Similar homes, available at https://social.opower.com/explore/
34
For example, see http://www.technologyreview.com/view/506711/smart-meters-help-utility-speed-sandyrestoration/ for a description of how advanced meters helped Potomac Electric Power, and see
http://www.greentechmedia.com/articles/read/a-smart-meter-in-the-superstorm for a description of how
advanced metering helped Philadelphia Electric.
32

16 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

model estimates. Controlling voltage more precisely can also help utilities and consumers
save energy; these conservation voltage reduction programs are also known as “Volt-Var.”

Opt-Out Programs
Some consumers are concerned about the privacy of customer data, cybersecurity, failure
rates, and overheating,35 as well as possible adverse health effects from radio frequency
emissions if the communications method uses radio frequencies. Because of these concerns,
many consumer groups endorse opportunity for individual customers to forgo, or “opt-out,”
of advanced meter installations at their own premises.
State regulatory bodies are considering whether to permit opt-out programs, and are coming
to varying conclusions. When evaluating an opt-out program, a state typically balances
consumer concerns regarding advanced meters against the system cost-saving benefits of
universal use in an area. Some groups argue that opt-out programs are not efficient, since
having both analog and digital systems in one area could reduce a utility’s ability to automate
functions such as meter reading, billing, and outage detection.36 Utilities also incur
additional administrative costs to accommodate customers that opt out of advanced metering;
for example, the utility might need to maintain meter reading trucks and additional staff to
support the non-advanced metering customers.37 Therefore, to maximize the potential
system benefits of advanced metering, and to avoid additional administrative costs, some
states have been hesitant to allow opt-out provisions in advanced metering deployment
programs. For example, the Idaho Public Utilities Commission recently dismissed a
consumer request to allow opting out of advanced meter installations, citing the potential
costs of an opt-out program.38
Another issue concerning opt-out programs is how to allocate the extra cost of manually
reading individual meters if some consumers choose not to use an advanced meter. The costs
of an opt-out program could be allocated to (1) all rate payers in a service territory, (2) only
the customers that choose to opt out, or (3) some combination of the two. For example, the
Maine Public Utilities Commission39 and the California Public Utilities Commission40
35

See: Maryland Public Service Commission, Notice of Opportunity to Comment, To: Service List for Case
Nos. 9207, 9208, 9294, available at http://webapp.psc.state.md.us/Intranet/Casenum/caseform_new.cfm? ;
Pennsylvania Public Utility Commission, Re: AMI Meter Deployment Inquiries: Commission staff August 24,
2012 data request, and PECO’s September 7, 2012 responses; Gregory Karp, “ComEd confirms smart meters
involved in ‘small fires’” Chicago Tribune, August 2012, available at http://articles.chicagotribune.com/201208-30/business/chi-comed-confirms-smart-meters-involved-in-small-fires--20120830_1_smart-meters-comedcustomers-poor-connection.
36
See: “The Opt-Out Challenge,” Electric Light & Power, March/April 2012, available at
http://www.elp.com/index/current-issue/electric-light-power/volume--90/issue-02.html; Institute for Electric
Efficiency, The Cost and Benefits of Smart Meters for Residential Customers, July 2011, p. 4, Available at:
http://www.edisonfoundation.net/iee/Documents/IEE_BenefitsofSmartMeters_Final.pdf.
37
Ibid
38
Meters that opt-out need to be individually read by a meter reader. See Idaho Public Utilities Commission,
Formal Complaint Objecting to Installation of AMI Meters, Case No. IPC-E-12- 04, Order No. 32500, available
at
http://www.puc.idaho.gov/internet/cases/elec/IPC/IPCE1204/ordnotc/20120327FINAL_ORDER_NO_32500.P
DF.
39
Maine Public Utilities Commission, Docket No. 2010-345, et al., Request for Commission Investigation in
Pursuing the Smart Meter Initiative, et al., Order (Part I), and Order (Part II), May 19, 2011 and June 22, 2011,
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 17

recently approved opt-out programs where the costs were assigned only to customers
choosing to opt out, on a tiered basis. The California and Maine programs offer differing
opt-out fees under a variety of options, ranging from maintaining a traditional analog meter
to simply having the wireless capabilities removed from an advanced meter. 41 Some other
states do not permit utilities to charge opt-out fees. For example, Vermont enacted
legislation eliminating opt-out fees in May 2012, and also required that any advanced meter
already installed be removed without charge if the customer requests this option.42
However, to date customer participation rates in opt-out programs have been low. For
example, less than one percent of Pacific Gas and Electric customers have opted out of
advanced meter deployments.43 Portland General Electric experienced an even lower opt-out
rate; only 4 out of 720,000 customers chose to opt out.44 These early advanced metering
deployment results indicate that opt-out provisions support individuals’ ability to make a
choice, while only an insignificant number of customers have actually decided to opt out.45
The debate surrounding opt-out programs continues, and several states continue to assess the
feasibility of implementing opt-out programs. For example, the California Public Utilities
Commission began a second phase of proceedings in June 2012 to reexamine the opt-out
issue and may consider extending an opt-out option to customer groups such as local
governments and residents of apartment buildings/condominiums.46 The second phase will
also address the possibility that the Americans with Disabilities Act prohibits that
Commission from charging opt-out fees for customers who have an analog meter for medical
reasons. In addition, the Maryland Public Service Commission issued an interim order in

available at https://mpuc-cms.maine.gov/CQM.Public.WebUI/Common/CaseMaster.aspx?CaseNumber=201000345.
40
California Public Utilities Commission, Decision Modifying Decision 08-09-039 and Adopting an Opt-Out
Program for Southern California Edison Company’s Edison SmartConnect Program, Decision 12-04-018,
Issued April 30, 2012, available at http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/165307.htm.
41
On July 12, 2012, the Maine Law Court issued a decision that vacated the portion of Maine Public Utilities
Commission’s dismissal of a complaint pertaining to health and safety concerns associated with advanced meter
usage in the Central Maine Power Company (CMP) service territory. The Maine PUC subsequently issued an
order staying disconnection of CMP customers until the conclusion of an investigation. See: Maine Public
Utilities Commission, Docket No. 2010-345, et al., Request for Commission Investigation in Pursuing the
Smart Meter Initiative, et al., Order Staying Disconnection of CMP Customers for Failure to Pay Opt-Out Fees,
August 8, 2012
42
Vermont State Legislature, The Vermont Legislative Bill Tracking System, Senate Bill No. 214, An Act
Relating to the Vermont Energy Act of 2012, Enacted May 18, 2012, available at
http://www.leg.state.vt.us/database/status/summary.cfm?Bill=S.0214&Session=2012.
43
United Telecom Council, Smart Meter Opt-Out – The Policies and Impacts, 9/27/2012 Webinar, as reported
by intelligentutility, Few and fewer opting out of smart meters, September 30, 2012, available at
http://www.intelligentutility.com/article/12/09/few-and-fewer-opting-out-smart-meters.
44
ibid.
45
Eric Lightner, Director of the Federal Smart Grid Task Force, DOE Office of Electricity Delivery and Energy
Reliability, Roundtable 2 – Policymakers Talk, June 26, 2012.
46
California Public Utilities Commission, Application of Pacific Gas and Electric Company for Approval of
Modifications to its SmartMeter™ Program and Increased Revenue Requirements to Recover the Costs of the
Modifications: Assigned Commissioner’s Ruling Amending Scope of Proceeding to Add a Second Phase,
Application No. 11-03-014, Enacted June 8, 2012, available at http://docs.cpuc.ca.gov/efile/RULC/168362.pdf.
18 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

May 2012 directing utilities to refrain from installing or activating advanced meters until a
permanent course of action is determined.47 Texas48 and Nevada49 have also been assessing
the feasibility of opt-out programs.

47

Maryland Public Service Commission, Case No. 9207: In the Matter of Potomac Electric Power Company and
Delmarva Power and Light Company Request for the Deployment of Advanced Meter Infrastructure, and Case
No. 9208: In the Matter of Baltimore Gas and Electric Company for Authorization to deploy a Smart Grid
Initiative and to Establish a Surcharge Mechanism for the Recovery of Costs, Order No. 84926: Interim Order
Regarding “Opt-out” Option for Smart Meters, May 25, 2012, available at
http://webapp.psc.state.md.us/Intranet/Casenum/submit_new.cfm?DirPath=C:\Casenum\92009299\9207\Item_203\&CaseN=9207\Item_203.
48
Public Utilities Commission of Texas, Project, Control No. 40190, Item 382: PUC Proceeding to Evaluate the
Feasibility of Instituting a Smart Meter Opt-Out Program, available at
http://interchange.puc.state.tx.us/WebApp/Interchange/application/dbapps/filings/pgControl.asp?TXT_UTILIT
Y_TYPE=A&TXT_CNTRL_NO=40190&TXT_ITEM_MATCH=1&TXT_ITEM_NO=&TXT_N_UTILITY=
&TXT_N_FILE_PARTY=&TXT_DOC_TYPE=ALL&TXT_D_FROM=&TXT_D_TO=&TXT_NEW=true.
49
Public Utilities Commission of Nevada, Application of Nevada Power Company d/b/a NV Energy and Sierra
Pacific Power Company d/b/a NV for approval of proposed trial Non-Standard Metering Option riders and
changes to existing rules and schedules associated with implementation of the NSMO riders, Docket No. 1205003, Filled May 2012.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 19

20 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

CHAPTER 3. DEMAND RESPONSE
This chapter addresses the second and third topics in EPAct 2005 section 1252(e)(3):
(B) Existing demand response programs and time-based rate programs, and
(C) The annual resource contribution of demand resources.
This chapter presents results of the 2012 FERC Survey on demand response programs,
including comparisons to previous FERC Survey results, and has three sections:
 Definition of Demand Response
 Survey Results
 Demand Response Developments at the FERC, and Barriers to Demand Response

Definition of Demand Response
The definition of demand response used in the survey and this report is:
Demand Response: Changes in electric use by demand-side resources from their
normal consumption patterns in response to changes in the price of electricity, or to
incentive payments designed to induce lower electricity use at times of high
wholesale market prices or when system reliability is jeopardized.
The demand response program types and definitions in the 2012 FERC Survey conform to
those used by NERC’s Demand Response Availability Data System (DADS). This common
terminology allows for some comparison with the DADS data. Table 4.1 contains the
program classifications included in the 2012 Survey. Definitions for each of the
classifications can be found in the Appendix C glossary.

Table 3-1. Demand response program types in the 2012 FERC Survey
Incentive-Based Programs









Demand Bidding and Buyback
Direct Load Control
Emergency Demand Response
Interruptible Load
Load as Capacity Resource
Non-Spinning Reserves
Regulation Service
Spinning Reserves

Time-Based Programs







Critical Peak Pricing with Control
Critical Peak Pricing
Peak Time Rebate
Real-Time Pricing
Time-of-Use Pricing
System Peak Response Transmission
Tariff

Note: The 2012 FERC Survey also included an “Other” category for demand response program types that
were not classified in either the Incentive-based DR Programs or Time-based Programs classifications.

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 21

Survey Results
Analytical Approach
Reported and estimated data on demand response and time-based rate programs are presented
below. As with prior year Reports, the approach taken was to gather information via survey
and to also supplement the data with Form EIA-861 data to report “annual resource
contribution” as required in EPAct Section 1252(e)(3)(C). Values that are labeled as
“reported” reflect the peak reduction (potential and actual) reported by entities in their survey
responses. Values labeled as “estimated” represent an estimate of U.S. total peak reduction,
and were derived using supplemental FERC and Form EIA-861 data, along with statistical
methods, to fill in missing data. A detailed explanation of these estimation methods can be
found in Appendix H.
Both reported and estimated demand response peak reduction are adjusted to minimize
double-counting. Appendix D describes the methods Staff used to address double counting
in the peak reduction data in more detail.

Summary of Report Findings
According to FERC Survey data, reported potential peak reduction in the U.S. increased from
2010 to 2012 by more than 10,000 MW, from 53,062 to 66,351 MW in 2012. This
represents a 25 percent increase in reported potential peak reductions from demand response.
Figure 3-1 illustrates a steady national increase in demand response capability50 across all
FERC survey years.
While demand response capability in the U.S. has steadily increased over the past few years,
the key contributors to this trend vary across customer class, ownership type, and program
type. The following sections summarize the 2012 FERC Survey findings on demand
response.
Growth in Reported Potential Peak Reduction by Customer Class
Growth in reported potential peak reduction from 2006 to 2012 occurred among all customer
classes, as illustrated in Figure 3-2.
Growth in Commercial and Industrial Potential Peak Reduction
Reported potential peak reductions by commercial and industrial customers increased by 31
percent, the largest increase of the three customer classes. This increase is due to new and
expanded demand response programs, along with improved reporting of existing programs in
the 2012 survey.51 The Oklahoma Gas and Electric (OG&E) time-of-use program is one

50

The terms “demand response capability” and “potential peak reduction” are used synonymously in this report.
For example, the 2012 response for TVA indicates a significant increase in TVA’s potential peak reduction
from 2010. The apparent increase is because certain potential peak reductions reported in 2012 existed in 2010
but were not reported for TVA’s programs in the 2010 FERC Survey. Similarly, the large changes in potential
peak reduction from 2010 to 2012 for The Detroit Edison Company and Progress Energy Florida can be
attributed to unreported 2010 data, rather than new program offerings or increased enrollment.
51

22 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

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

Reported Potential Peak Reduction (MW)

70,000

66,351

60,000
53,062
50,000
37,335

40,000
29,653
30,000
20,000
10,000
0
2006 Survey

2008 Survey

2010 Survey

2012 Survey

Survey Year

Figure 3-2. Reported potential peak reduction by customer class in 2006,
2008, 2010 and 2012
Commercial & Industrial

Residential

Wholesale

Reported Potential Peak
Reduction (MW)

35,000
30,000
25,000
20,000
15,000
10,000
5,000
0
2006 Survey

2008 Survey

2010 Survey

2012 Survey

example of a significant demand response program expansion; the utility reported adding
nearly 900 MW of demand response capability between 2010 and 2012 from commercial and
industrial consumers. OG&E’s demand response program was coordinated with an advanced
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 23

metering deployment (see Chapter 2), and as a result, OG&E reported over 1,700 new
commercial and industrial participants in its time-of-use rate program.52
Growth in Wholesale Potential Peak Reduction
Reported potential peak reduction for wholesale entities53 grew by 26 percent, from 22,884
MW in 2010 to 28,807 MW in 2012. Increased enrollment of demand response resources in
PJM Interconnection, LLC (PJM) and Midwest Independent Transmission System Operator
(Midwest ISO) largely drove this increase, as illustrated in Figure 3-3.54
Figure 3-3 also shows a marked shift in the composition of wholesale demand response
programs. Between 2010 and 2012, the reported potential peak reductions associated with
emergency demand response programs decreased and load as a capacity resource increased,
especially in the PJM and the Midwest ISO markets.
Growth in Residential Potential Peak Reduction
Reported potential peak reduction associated with residential customers grew by 13 percent,
from 7,189 MW in 2010 to 8,134 MW in 2012. Seventy percent of this increase is
attributable to investor-owned utilities’ demand response programs. For residential
customers, direct load control and time-based rates programs had the largest increases in
reported potential peak reduction. For example, Baltimore Gas and Electric reported a
significant increase in its residential direct load control program, from 272 MW of potential
peak reduction in 2010 to 763 MW in 2012.55
Reported Potential Peak Reduction by Region
Nearly every region in the U.S. increased its reported potential peak reduction between 2010
and 2012, as illustrated in Figure 3-4. ReliabilityFirst Corporation (RFC) remained the
region with the most reported potential peak reduction; RFC reported of 24,381 MW of
potential peak reduction in 2012, an increase of 8,517 MW from 2010. Most of this reported
growth is due to increased participation by demand response resources in PJM’s forward
capacity market.

52

Smartgrid.gov: Recovery Act Smart Grid Programs, Case Studies, Reducing Peak Demand to Defer Power
Plant Construction in Oklahoma, August 2011, available at
http://energy.gov/sites/prod/files/Case%20Study%20-%20Oklahoma%20Gas%20and%20Electric%20%20Reducing%20Peak%20Demand%20to%20Defer%20Power%20Plant%20Construction%20%20August%202011.pdf.
53
Wholesale entities include ISOs, RTOs, curtailment service providers, wholesale power marketing agencies
such as the Bonneville Power Administration, the Tennessee Valley Authority, generation and transmission
corporations and joint action agencies that serve member companies, and wholesale electric marketers.
54
Figure 3-3 shows the information provided by the ISOs and RTOs in 2010 and 2012 in their responses to the
2012 FERC Survey. This figure does not reflect any adjustments to eliminate double counting of potential peak
reductions reported by both retail entities and an ISO or RTO.
55
Baltimore Gas and Electric deployed its direct load control program during a PJM-initiated emergency on a
very hot day in July of 2011 and later measured the impact at approximately 600 MW. See
http://webapp.psc.state.md.us/Intranet/Casenum/submit_new.cfm?DirPath=C:\Casenum\91009199\9154\Item_214\&CaseN=9154\Item_214.
24 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Figure 3-3. Reported potential peak reduction by Independent System
Operators and Regional Transmission Operators in 2010 and 2012

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

Figure 3-4. Reported potential peak reduction by region and customer class
for the 2010 and 2012 FERC Surveys

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 25

SERC Reliability Corporation became the second largest NERC region for reported potential
peak reduction, by adding 3,655 MW; this represents a 40 percent increase from 2010.
Combined, SERC and RFC account for over 55 percent of the total U.S. reported potential
peak reduction in 2012.
In the Northeast Power Coordinating Council (NPCC), the reported potential peak reduction
declined by 40 percent between 2010 and 2012. A key driver for this drop in the reported
potential peak reduction is due to significant declines in the amount of potential peak
reduction reported by several key entities in New York.
Demand Response Program Trends
Figure 3-5 illustrates reported potential peak reduction by demand response program type.56
These program types are organized into two main groupings: incentive-based demand
response and time-based demand response programs. Traditionally, demand response
programs have used incentives to encourage electricity customers to modify their electricity
consumption when system reliability was threatened or market opportunities arose. Timebased programs, on the other hand, send price signals to electricity customers who
voluntarily choose to modify their electricity consumption in response to these signals. As in
previous years, incentive-based demand response program types represent the bulk of
reported demand response potential, but time-based program types also significantly
increased in 2012.
Four demand response program types made up 80 percent of the total reported potential peak
reduction in 2012. These programs were:
 Load as a capacity resource: 29 percent of all reported demand response potential
peak reduction
 Interruptible load: 24 percent of all reported demand response potential peak
reduction
 Direct load control: 15 percent of all reported demand response potential peak
reduction
 Time-of-use: 12 percent of all reported demand response potential peak reduction
The dominant program type in 2012 is load as a capacity resource (20,000 MW), a departure
from the results of previous surveys. In 2010, the predominant program type was emergency
demand response (13,000 MW); load as a capacity resource made up less than 9,000 MW of
the total reported potential peak reduction. This change for load as a capacity resource and
emergency demand response reflects the changes in wholesale market program offerings,
along with changes in how PJM chose to categorize its Emergency Load Response – Full
Option program.

56

A significant challenge to developing program type classifications is linking retail programs to the
classifications submitted by the ISO/RTO market operator, when a retail program is enrolled in a wholesale
market program for demand response. FERC staff conducted a process to discern this linkage in order to
eliminate double counting of programs in tabulations that include customer class. Further details on this
process are explained in Appendix H.
26 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Figure 3-5. Reported potential peak reduction by program type and by
customer class in 2012 FERC Survey

Table 3-2 lists reported peak reduction by program type and state.57 The five states reporting
the highest potential peak reductions are:



Michigan – Michigan reported the highest potential peak reduction: 5,835 MW.
Detroit Edison’s time-of-use program for commercial and industrial customers
accounts for 3,000 MW of this total.
Minnesota – Although Minnesota respondents reported a slight decrease in demand
response capability from 2010 to 2012, the state had second the largest reported
potential peak reduction in 2012: 4,392 MW. Midwest ISO’s “load as a capacity
resource” demand response program consists largely of Minnesota’s reliance on this
demand response program type.

57

In Table 3-2, Time-Based Demand Response Programs are the following program types: Critical Peak
Pricing, Critical Peak Pricing with Load Control, Time-of-Use, Real-Time Pricing, and Peak Time Rebate.
Other Incentive-Based Demand Response Programs are the following program types: Load as a Capacity
Resource, Spinning Reserves, Non-Spinning Reserves, Regulation, Demand Bidding and Buy-Back, and
System Peak Response Transmission Tariff.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 27

Table 3-2. Reported potential peak reduction in Megawatts by program type
and state
State
AK
AL
AR
AZ
CA
CO
CT
DC
DE
FL
GA
HI
IA
ID
IL
IN
KS
KY
LA
MA
MD
ME
MI
MN
MO
MS
MT
NC
ND
NE
NH
NJ
NM
NV
NY
OH
OK
OR
PA
RI
SC
SD
TN
TX
UT
VA
VT
WA
WI
WV
WY

TimeBased
183
160
158
381
26
117
68
686
24
3
9
72
25
59
28
232
3,383
573
84
282
3
59
116
0
3
1
3
1,939
169
12
105
13
1,308
4
4
85
3
1
139
25

Direct
Load
Control
17
199
13
612
193
25
76
2,620
244
36
136
24
189
92
65
178
67
822
240
994
40
315
295
184
112
2
130
45
88
56
1
68
107
605
71
449
118
0
1
250
-

Other
IncentiveBased
190
1,112
44
48
97
186
87
7
346
380
1,658
184
28
69
58
1,357
25
1,306
1,466
93
18
40
11
786
90
1,829
2,536
623
14
3,745
11
29
1,943
1,988
19
1
1,785
560
-

28 Federal Energy Regulatory Commission

Emergency
Demand
Response
256
339
37
154
58
930
20
7
310
195
271
337
6
75
62
9
32
258
44
19
74
18
420
10
50
344
4
-

Interruptible
Load
1,647
956
660
56
5
0
20
1,009
328
5
605
314
1,298
618
249
565
66
550
992
83
674
574
42
3
299
475
63
6
211
932
20
955
137
4
82
46
20
712
364
-

Other
19
9
35
86
30
1,051
0
3
41
2
-

State
Total
1,847
1,334
361
3,020
320
392
123
408
3,857
1,264
65
1,244
717
3,213
1,896
387
878
67
396
2,478
220
5,835
4,392
207
955
3
1,040
435
1,392
73
910
95
162
2,432
3,145
2,683
21
4,212
96
1,185
656
2,293
2,577
457
2,283
117
23
3,231
929
25

2012 Assessment of Demand Response and Advanced Metering






Pennsylvania -- Pennsylvania reported an increase in reported potential peak
reduction in 2012 to 4,212 MW, largely from increased demand response
participation in PJM’s forward capacity market through the Emergency Load
Response program.
Florida – Florida continues to have a large reported potential peak reduction, and
Florida’s demand response capability is provided primarily by utilities’ interruptible
load and direct load control programs.
Wisconsin – Wisconsin’s reported potential peak reduction is primarily from a
Midwest ISO program called “Load Modifying Resources.”

Three other states had large increases in reported potential peak reduction between the 2010
and 2012: Michigan, Tennessee, and Oklahoma. These increases were due primarily to the
demand response programs of Detroit Edison, the Tennessee Valley Authority, and
Oklahoma Gas and Electric, respectively.
Actual Peak Reduction
In addition to providing information on reported potential peak reductions, survey
respondents also provided information on actual (or realized) peak reductions that occurred
in 2011 from demand response programs.58 The actual peak reductions from demand
response resources for the 2010 and 2012 FERC Surveys are presented by region in Figure 36 below. The 2012 FERC Survey respondents identified a total of 20,256 MW of actual peak
reductions from demand response resources, representing use of 31 percent of the total
reported potential peak reduction. This represents an increase from the 2010 Survey in actual
peak reductions from demand response.
Figure 3-7 compares the 2012 reported potential peak reduction to actual peak reduction by
region. While RFC reported the highest potential peak reduction, it reported using only 15
percent of this potential.59 Every other NERC region used at least 25 percent of its potential
demand response capability; NPCC realized 85 percent and TRE 90 percent of its reported
potential peak reduction.
Estimated Potential Peak Reduction by Region
The above values for reported potential peak reduction likely understate the total potential
peak reduction capability in the U.S. because not all those surveyed responded and for other
reasons. Therefore, staff took steps to estimate the potential peak reduction of nonresponding entities, using FERC Survey data and other sources of information, such as Form
EIA-861 data.60 The result is called the estimated potential peak reduction, in contrast to the
reported potential peak reduction presented above.
58

As a means of confirming the data, if the actual demand response peak reduction was larger than the reported
potential peak reduction, the reported potential peak reduction was set equal to the actual demand response peak
reduction.
59
The ratio in RFC was low because no actual peak reductions from demand response resources were reported by the
two of the largest programs in the RFC region – Detroit Edison’s commercial and industrial time-of-use
program and Commonwealth Edison’s commercial and industrial interruptible load program. The RFC actualto-potential ratio for the remaining programs reported was 45 percent.
60
The estimation methodology is described in Appendices D and H.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 29

Figure 3-6. Reported actual peak reduction by NERC region between 2010
and 2012 FERC Survey years
2010 Actual peak Reduction

2012 Actual Peak Reduction

4,000
Reported Actual Peak
Reduction (MWs)

3,500
3,000
2,500
2,000
1,500
1,000
500
0
TRE

FRCC

MRO

NPCC
RFC
SERC
NERC Regions

SPP

WECC

Other

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

Figure 3-8 compares the estimated potential peak reduction by NERC region and customer
class between 2010 and 2012. Total estimated potential peak reduction is 71,654 MW, an
increase of almost 13,000 MW from 2010. RFC remained the region with highest estimate
of potential peak reduction, with a total of 25,356 MW in 2012, an increase of 8,025 MW
from the estimated 2010 potential peak reduction.

30 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Figure 3-8. Estimated potential peak reduction by region and customer class
in 2010 and 2012

Figure 3-9 presents the estimated potential peak reduction by entity type and customer
class across the 2010 and 2012 surveys. Investor-owned utilities remained the entity type
with the largest estimated potential peak reduction, 27,476 MW in 2012. Commercial and
industrial customers accounted for 75 percent of the estimated potential peak reduction for
investor-owned utility demand response programs. ISO and RTO programs’ estimated
potential peak reduction increased by 20 percent to 25,489 MW in 2012.61 Federal and state
entities added an estimated 4,600 MW of estimated potential peak reduction between 2010
and 2012.
Plans for New Demand Response Programs
FERC Survey respondents were asked to “Provide your entity’s near- and long-term plans for
new demand response programs and time-based rates/tariffs.” Table 3-3 summarizes these
responses for three time periods. Direct load control programs were the dominant planned
program type, followed by time-of-use rates programs and interruptible programs for all
three time periods. The three main and roughly equal contributors to new demand response
planned for 2012 comes from direct load control, interruptible load, and load as a capacity
resource. For programs beginning in 2013 and 2014, 80 percent of the planned demand
response from new programs was reported to come from an interruptible program or load as
a capacity resource program.

61

The estimated potential peak reductions attributed to RTO/ISO programs were reduced according to the
methodology described in Appendix D to eliminate double-counting of retail demand response programs
enrolled in wholesale market programs.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 31

Figure 3-9. Estimated potential peak reduction by entity type and customer
class in 2010 and 2012

Table 3-3. Reported plans for new demand response programs and time-based
rates/tariffs
During Calendar Year 2012

Program Type
Direct Load Control
Interruptible Load
Critical Peak Pricing with Controls
Load as Capacity Resource
Spinning Reserves
Non-Spinning Reserves
Emergency Demand Response
Regulation Service
Demand Bidding and Buyback
Time-of-Use Pricing
Critical Peak Pricing
Real-Time Pricing
Peak Time Rebate
System Peak Response Transmission Tariff
Other

Number of
Programs

Potential Peak
Reduction (MW)
489
20
3
9
3
4
9
2
4
40
8
3
7
1
7

4,579
5,842
1
5,906
370
281
1,243
60
373
12
64
5
222

During Calendar Years During Calendar Years
2013 and 2014
2015 through 2017
Potential
Potential
Number
Peak
Number
Peak
of
Reduction
of
Reduction
Programs
(MW)
Programs
(MW)
38
15
1
5
4
4
8
1
27
12
5
5
6

884
9,696
31
9,837
747
667
1,658
75
24
15
125
3
691

18
6
2
2
2
18
9
6
1
3
2

291
211
1
350
185
7
14
1
5
101

Participation in Demand Response Programs
This section discusses the reported participation of entities and customers in four specific
types of demand response program: Interruptible Load, Direct Load Control, Time-of-Use,
32 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

and Real-Time Pricing. Information on how many entities offer these programs and how
many customers participate can provide insights into trends and regional differences.
Interruptible Load Demand Response Programs
Figure 3-10 illustrates changes in the number of entities providing interruptible load demand
response between 2010 and 2012 by NERC region and entity type. Overall, the total number
of entities providing interruptible service decreased from 183 providers in 2010 to 158 in
2012.62 Cooperatives reported the largest decrease between 2010 and 2012 in the number of
entities that operate interruptible demand response programs; a lower FERC Survey response
rate for cooperatives may explain the decrease.

Figure 3-10. Number of entities reporting interruptible/curtailable rates by
region and type of entity in 2010 and 201263

Direct Load Control Demand Response Programs
The number of customers enrolled in a direct load control program by region is provided in
Figure 3-11, along with the proportion of total retail customers by NERC region. The region
with the most customers participating in direct load control programs in both 2010 and 2012
is RFC; however, FRCC and MRO had the highest proportions of retail customers
participating in these programs. Over 12 percent of MRO’s retail customers and almost 15
percent of FRCC’s retail customers reportedly participated in direct load control programs in
2012.

62

The 2010 Report contains the number of interruptible/curtailable rate programs, rather than the number of
entities reporting one or more of these types of programs. Figure 3-10 reflects the number of entities offering
these programs in the 2010 FERC Survey.
63
For the following figures that summarize entity and customer participation in demand response, the category
“Cooperative Entities” refers to cooperatives, generation and transmission cooperatives, and political
subdivisions. Similarly, municipal utilities and municipal marketing authorities are combined into “Municipal
Entities.” Federal entities, such as Southwestern Power Administration, and state utilities, such as the Arizona
Power Authority, are combined into “Federal and State.” Unless specifically identified, “Other” refers to
curtailment service providers, retail power marketers, regional transmission organizations and independent
system operators.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 33

Figure 3-11. Reported number of customers enrolled in direct load control
programs by region and type of entity in 2010 and 2012

Percent of total
estimated
customers in the
region in a direct
load control
program

TRE

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC

Other

0.11%

14.54%

12.15%

0.25%

4.39%

2.28%

1.43%

3.09%

4.59%

Time-of-Use Demand Response Programs
Figure 3-12 illustrates the number of entities reporting residential time-of-use rates by NERC
region and entity type. The number of entities offering residential time-of-use rate demand
response programs increased slightly, from 144 in 2010 to 151 in 2012.64 MRO continued to
be the highest: 52 entities in the region reported offering a time-of-use rate for residential
customers; over half of these programs were offered by municipally owned utilities in 2012.
While the number of entities offering residential time-of-use rates has been relatively
constant from 2010 to 2012, Figure 3-13 indicates that the number of residential customers
utilizing time-of-use rates is rising. The total number of residential customers on a time-ofuse rate increased from 1.1 million in 2010 to almost 2.1 million in 2012, with almost all of
this growth occurring in RFC. Approximately 800,000 new residential customers began
using time-of-use rates in RFC between 2010 and 2012, primarily under the Potomac Electric
Power Company and Delmarva Power and Light program expansions.

64

The 2010 Report contains the number of residential time-of-use programs, rather than the number of entities
reporting one or more of these types of programs. Figure 3-12 reflects the number of entities offering these
programs in the 2010 FERC Survey.
34 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Figure 3-12. Number of entities reporting residential time-of-use rates by
region and type of entity in 2010 and 2012

Figure 3-13. Reported number of residential customers enrolled in time-ofuse rates by region and entity type in 2010 and 2012

The large increase in time-of-use participation in the RFC region illustrates a shift from
previous FERC Survey trends. In previous years, WECC was the dominant time-of-use
demand response region; however, residential time-of-use program customers in WECC
increased only slightly between the two survey years, to just over 775,000 customers (about
2.7 percent of all WECC customers).

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 35

Real-Time Pricing Programs
The number of entities that reported offering real-time pricing programs is presented in
Figure 3-14, by region and entity type. Twenty-eight entities reported offering real-time
pricing in 2012, a slight increase from the 25 entities reporting in 2010. Nearly all of the
entities offering real-time pricing programs are investor-owned utilities.65

Figure 3-14. Number of entities reporting retail real-time pricing by region
and entity type in 2010 and 2012

Demand Response Activities at the FERC
Since the publication of the November 2011 Assessment of Demand Response and Advanced
Metering, the Commission has continued to further the goal of comparable treatment of
demand response resources in wholesale markets, as well as to follow the provisions of law
requiring it to develop a plan to realize the national potential for demand response.
This section summarizes the key demand response developments and actions undertaken by
the Commission since the prior report, including several rulemakings and key demandresponse-related RTO/ISO orders.

Commission Demand Response Activities
The Commission continues to assess and monitor the wholesale electric power markets under
its jurisdiction, to ensure that resources that are technically capable of providing demand
response services are treated comparably to supply-side resources. This section summarizes
FERC actions taken in the past year that affect demand response resources in wholesale
markets, including action the Commission has taken to address compensation and

65

The 2010 Report contains the number of RTP programs, rather than the number of entities reporting one or
more RTP program. Figure 3-14 reflects the number of entities offering these programs in the 2010 FERC
Survey.
36 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

measurement and verification as well as Commission actions in response to RTO and ISO
proposals related to demand response.
Commission Rulemakings on Demand Response Issues
NAESB Wholesale Demand Response Measurement and Verification NOPR
In April 2012, the Commission issued a Notice of Proposed Rulemaking (NOPR) to amend
its regulations to incorporate by reference NAESB’s business practice standards on the
measurement and verification of demand response and energy efficiency resources that
participate in organized wholesale electricity markets. The proposed demand response
measurement and verification standards would add specificity to existing standards in several
areas, including meter data reporting, advanced notification, telemetry, and meter accuracy.
The Commission requested comments on whether the proposed demand response
measurement and verification standards are sufficiently detailed to provide transparent
measurement and verification across regions, and whether greater detail or conformity across
regions would be appropriate. By contrast, the proposed energy efficiency measurement and
verification standards would provide more substantial detail than the demand response
standards to ensure effective evaluation of the performance of energy efficiency products and
services. The proposed wholesale energy efficiency standards include four measurement and
verification methodologies, as well as a mechanism for resource providers to propose, and
organized markets to consider, alternative approaches.66 Comments on the NOPR were
received on July 30, 2012 and the Commission is evaluating those comments.
Order No. 745 Compliance Orders
Order No 745,67 issued in March 2011, requires that RTOs and ISOs pay demand response
resources participating in the day-ahead and real-time wholesale energy markets the
locational marginal price (LMP) when two conditions are met: demand response resource are
capable of balancing supply and demand in the wholesale energy markets, and dispatching
and paying LMP to demand response resources is cost-effective as determined by a net
benefits test. All six ISOs and RTOs, have made filings to comply with Order No. 745.
Commission orders approving the compliance filings of PJM, ISO-New England (ISO-NE),
and the Midwest ISO are discussed below. Commission proceedings on the compliance
filings for the California ISO (CAISO), New York ISO (NYISO), and SPP remain open at
the time of this writing.
PJM Order No. 745 Compliance (Docket No. ER11-4106)
PJM submitted its Order No. 745 compliance filing in July 2011. In its compliance filing,
PJM proposed to revise its existing compensation methods for participants in PJM’s
Economic Load Response programs from LMP less applicable avoided generation and
transmission charges in all hours to LMP in hours when a net benefits test is passed. PJM
also proposed changes to (1) rules governing self-scheduling, (2) the customer baseline load
methodology used to measure demand reductions in the energy and ancillary services
66

Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041
(2012).
67
Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 76 FR 16,658
(Mar. 24, 2011), FERC Stats. & Regs. ¶ 31,322 (2011) (Order No. 745), order on reh’g, 137 FERC ¶ 61,215
(2011).
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 37

markets, and (3) how the costs for demand response are allocated. On December 15, 2011,
the Commission accepted PJM’s filing, subject to an additional compliance filing.68 The
Commission found that PJM’s proposed tariff revisions went beyond what was required to
comply with Order No. 745, which applies only if a demand response resource has the
capability to balance supply and demand and if dispatch of the demand response resource is
cost-effective as determined by a net benefits test. PJM submitted another compliance filing
in March 2012 in response to the December order, which was accepted by the Commission in
June 2012.69
ISO-New England Order No. 745 Compliance (Docket No. ER11-4336)
ISO-NE submitted its Order No. 745 compliance filing and proposed tariff revisions in
August 2011. As part of its compliance filing, ISO-NE proposed (1) a net benefits test that
established a threshold price for submitting demand response bids, (2) adjustments to its
current baseline calculation methodology for measuring demand reductions, and (3)
allocating costs hourly in proportion to the ISO-NE Real-Time Load Obligation70 on a
system-wide basis. ISO-NE proposed implementing these changes in two stages that would
fully integrate demand response resources into its energy market by June 2016. The
Commission accepted ISO-NE’s Order No. 745 compliance filing in January 2012,71 subject
to a further compliance filing. ISO-NE submitted this second compliance filing in March
2012, which was accepted by the Commission in May 2012.72
Midwest ISO Order No. 745 Compliance (Docket Nos. ER12-1266 and ER11-4337)
The Midwest ISO submitted its Order No. 745 compliance filing in August 2011. It
proposed to establish a monthly Net Benefits Price Threshold. The Midwest ISO also
proposed to pay the applicable LMP to cost-effective demand response resources that clear
either the day-ahead or real-time energy market. Additionally, the Midwest ISO proposed to
allocate the costs associated with compensating demand resources in the real-time energy
market to market participants located within the reserve zone of demand response resources
that either purchase energy and benefit from reduced LMPs or serve load and avoid selling
energy to retail customers at a loss. The Midwest ISO proposed to allocate any remaining
costs to all load-serving entities systemwide on a pro rata load ratio share basis. The
Commission accepted this compliance filing in part and rejected it in part in December
2011.73 The Midwest ISO submitted its second Order No. 745 compliance filing in March
2012; d the Commission accepted the Midwest ISO’s Order No. 745 compliance filing in
July 2012.74
Order No. 719 Compliance Orders
The Commission issued Order No. 719 in October 2008 to improve the operation of
organized wholesale electric power markets in several areas: (1) demand response, including
68

PJM Interconnection, L.L.C., 137 FERC ¶ 61,216 (2011).
PJM Interconnection, L.L.C., 139 FERC ¶ 61,256 (2012).
70
Real-Time Load Obligation refers to the total load serving entities’ MWh load obligation of market
participants at each location during a given hour of operation. See ISO-NE Tariff, section III.3.2.1(b)(i).
71
ISO New England Inc., 138 FERC ¶ 61,042 (2012).
72
ISO New England Inc., Docket No. ER11-4336-005 (May 29, 2012) (delegated letter order)
73
Midwest Indep. Transmission Sys. Operator, Inc., 137 FERC ¶ 61,212 (2011) (Order No. 745 Compliance
Order).
74
Midwest ISO. 140 FERC 61,059 (2012).
69

38 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

pricing during periods of operating reserve shortage; (2) long-term power contracting; (3)
market-monitoring policies; and (4) the responsiveness of RTOs and ISOs to their customers
and other stakeholders.75 Several compliance filings associated with Order No. 719
implementation were submitted and approved in 2012, and details on PJM and Midwest
ISO’s filings are provided below.
PJM Order No. 719 Compliance—Scarcity Pricing (Docket No. ER09-1063-004)
PJM submitted an Order No. 71976 compliance filing and proposed tariff changes addressing
shortage pricing requirements in June 2010, and the Commission accepted the changes in
April 2012.77 PJM proposed numerous tariff changes, including changes to PJM’s demand
response programs, based on its analysis that PJM’s existing shortage pricing provisions fail
to satisfy the shortage pricing requirements of Order No. 719. The Commission accepted
PJM’s tariff revisions and found that PJM’s proposed pricing reforms would encourage
existing demand response and generation resources to continue to provide supplies during
shortage conditions, because these resources will be eligible to receive the prevailing energy
and reserve market clearing price. In addition, the Commission found that PJM’s proposal
would (1) increase the accuracy of market clearing prices during shortage conditions, (2)
minimize the need for out-of-market payments, and (3) provide clearer price signals to both
demand response and generation resources.78
Midwest ISO Order No. 719 Compliance (Docket Nos. ER12-1265 and ER09-1049)
The Midwest ISO submitted its initial Order No. 719 compliance filing in April 2009. In this
filing, MISO stated that its existing market design satisfied the requirements of Order No.
719 regarding both (1) the participation of demand response resources in ancillary services
markets,79 and (2) price formation during periods of operating reserve shortages.80 The
Midwest ISO submitted an additional filing in October 2009 that proposed tariff revisions to
allow the participation of aggregators of retail customers (ARCs) in Midwest ISO’s markets.
The Commission accepted both Midwest ISO compliance filings in December 2011, subject
to a further compliance filing. The Midwest ISO submitted its final Order No. 719
compliance filing in March 2012,81 proposing tariff revisions regarding the provision of
ancillary services by demand response resources, including measurement and verification
protocols82 and tariff revisions regarding the registration, information sharing, credit, and

75

Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. ¶
31,281 (2008) (Order No. 719), order on reh’g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order
on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).
76
Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 73 Fed. Reg. 64,100
(Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281, at P 165, et seq. (2008), order on reh’g, Order No. 719-A,
FERC Stats. & Reg. ¶ 31,292 (2009), FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B,
129 FERC ¶ 61,252 (2009).
77
PJM Interconnection L.L.C., 139 FERC ¶ 61,057 (2012).
78
PJM Interconnection, L.L.C., 139 FERC ¶ 61,057 (2012).
79
MISO April 2009 Compliance Filing, Transmittal Letter at 6-9, 11-12.
80
Id. at 20-25.
81
MISO March 14, 2012 Compliance Filing, Docket No. ER12-1265-000 (March 2012 Compliance Filing);
MISO March 23, 2012 Amended Compliance Filing, Docket No. ER12-1265-001 (March 2012 Amended
Filing).
82
MISO March 2012 Compliance Filing, Transmittal Letter at 2-6.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 39

other requirements for ARCs. The Midwest ISO proposed to compensate ARCs at the
LMP.83 The Commission accepted these proposed changes in July 2012.
Other Commission Demand Response Orders
In addition to rulemakings, the Commission also approved several revisions to RTO/ISO
tariffs related to demand response resources in regional organized wholesale markets. The
follow briefly describes these revisions and Commission actions.
California ISO Flexible Ramping Constraint (Docket No. ER12-50)
The CAISO proposed tariff changes to implement a flexible ramping constraint in October
2011 so as to provide CAISO with sufficient ramping capability to match real-time supply
with real-time demand. The CAISO plans to procure this flexible ramping capability from
committed, flexible generation resources, proxy demand resources, and participating load
resources. The Commission accepted and suspended the proposed tariff changes in
December 2011 to establish hearing and settlement judge procedures.84 CAISO is continuing
to work on developing a new flexible ramping product.
California ISO Regulation Energy Management (Docket No. ER11-4353)
In August 2011, CAISO submitted proposed revisions to its tariff to implement regulation
energy management. Regulation energy management allows energy storage resources or
demand response to provide regulation service. Under the proposal, scheduling coordinators
for non-generator resources within CAISO’s balancing authority area may choose to use
regulation energy management if they require regulation resources. The Commission
accepted CAISO’s proposal in November 2011.85
Midwest ISO’s Extended Locational Marginal Price Algorithm (Docket No. ER12668)
The Midwest ISO filed proposed revisions to its tariff in December 2011 to improve the
accuracy of pricing in its energy and operating reserve markets by allowing more resources,
including emergency demand resources, to set the LMP in the day-ahead and real-time
energy markets as well as the market clearing price in the day-ahead and real-time operating
reserve markets. The Commission accepted Midwest ISO’s proposal in July 2012, subject to
further compliance filings.86
PJM Price Responsive Demand (Docket No. ER11-4628)
PJM filed proposed tariff changes in September 2011 to support the development of price
responsive demand, an initiative for end-use customers to vary their load in response to
wholesale electricity prices. PJM proposed to incorporate this demand responsiveness by
allowing load serving entities (and other market participants), with the approval of their
relevant regulatory authorities, to commit to reducing loads to specified levels when prices
rise during emergency conditions. The mechanism is designed to allow the installed capacity
requirement of load serving entities to be reduced to reflect the lowered need for peaking
83

Id. at 7-16.
California Independent System Operator Corporation, 137 FERC ¶ 61,191 (2011).
85
California Independent System Operator Corporation, 137 FERC ¶ 61,165 (2011).
86
Midwest ISO., 140 FERC ¶ 61,067 (2012).
84

40 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

capacity due to price responsive demand commitments. Following a staff technical
conference on this proposal, the Commission accepted PJM’s filing effective May 15, 2012,
subject to further compliance.87
PJM Targeted Sub-Zonal Dispatch (Docket No. ER12-1372)
PJM filed tariff revisions in March 2012 to support sub-zonal dispatch, and recognize the
expanded selection of demand resource products. Sub-zonal dispatch would allow PJM to
dispatch a targeted set of demand response resources to address localized emergency events,
rather than calling on the full set of demand resources available within a zone. To implement
sub-zonal dispatch, PJM also proposed requiring demand response providers to have the
capability to receive electronic dispatch signals from PJM. PJM proposed that responses to
sub-zonal dispatch be voluntary at first, with no penalty for non-performance. After a twoyear transition period, PJM proposed assessing compliance charges for inadequate response
to sub-zonal dispatch only if the sub-zone is defined and posted the day before the Load
Management event. The Commission accepted PJM’s proposed tariff revisions, which were
effective June 1, 2012.88
PJM Regulation-Only CSPs (Docket No. ER12-1430)
PJM filed proposed tariff changes in April 2012 to expand the opportunity for demand
response providers and end-use customers to participate in PJM’s frequency regulation
market. PJM’s proposed changes would create an “Economic Load Response Regulation
Only Registration” to (1) simplify the aggregation process for regulation-only resources; (2)
allow two different demand response providers in the PJM Economic Load Response
Program to provide demand response services to the same end-use customer, where one
demand response provider provides regulation service; and (3) allow equipment-specific load
data, rather than load data for an entire facility, to be submitted to verify that the regulation
service that cleared the market was actually provided. The Commission accepted these tariff
revisions in June 2012.89
PJM M&V Changes (Docket No. ER11-3322)
PJM filed proposed changes to its tariff in April 2011 to clarify how the performance of
demand response capacity resources is measured during emergency dispatch and
performance verification testing. PJM stated that its current rules allowed curtailment
service providers to offset some customers’ underperformance with the “excess”
performance of other end-use customers in its portfolio, and argued that this type of
aggregation gives the appearance of a greater supply of capacity. PJM proposed to modify
the reference point of capacity demand response load reductions so that each end-use
customer’s actual load reduction results in a metered load that is less than the customer’s
peak demand (i.e., the peak contribution identified by PJM). After a technical conference on
the subject, the Commission accepted PJM’s proposal in November 2011 requiring PJM to
submit a compliance filing to modify and clarify its proposal.90

87

PJM Interconnection L.L.C., 139 FERC ¶ 61,115 (2012).
PJM Interconnection L.L.C., 139 FERC ¶ 61,165 (2012).
89
PJM Interconnection L.L.C., 139 FERC ¶ 61,172 (2012).
90
PJM Interconnection L.L.C., 137 FERC ¶ 61,108 (2011).
88

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 41

Other Demand Response Developments and Issues
In addition to FERC rulemakings and RTO/ISO demand response initiatives, several
noteworthy developments and activities occurred within and outside government. The
following summarizes (1) the National Forum on the National Action Plan on Demand
Response, (2) ARRA-funded consumer behavior studies, (3) the NERC DADS program, (4)
demand response events during the summer of 2012, and (5) selected state activities.

National Forum on the National Action Plan on Demand Response
Over the past year, the U.S. Department of Energy, with support from Commission staff,
conducted a National Forum on the National Action Plan on Demand Response.91 Working
groups comprised of national demand response experts and practitioners are preparing
reports that identified knowledge and research gaps in four areas (cost-effectiveness,
measurement and verification, program design and delivery, and modeling and tools) and the
actions needed to help implement the action items included in the National Action Plan on
Demand Response.

U.S. Department of Energy-Sponsored Consumer Behavior Studies
The ARRA includes funding and support for nine utility-sponsored consumer behavior
studies as part of ARRA’s SGIG program. The SGIG studies are designed to assess
customer acceptance and adoption of time-based electricity rates and enabling technologies,
such as advanced metering.92 The studies, carried out in nine states and varying in size from
500 to 60,000 participants, assess consumer usage of a variety of technologies, such as web
portals, in-home displays, and programmable communicating thermostats. The SGIG studies
also examine several rate structures, from simple time-of-use rates, to more complex critical
peak pricing plans, with some combinations offered on either an opt-in or opt-out basis. The
consumer behavior studies began in 2010 and are scheduled to end in 2014. SGIG recipients
are required to publish mid-term and final reports on the findings of their studies. As of July
2012, mid-term reports from Marblehead Municipal Light Department and Oklahoma Gas
and Electric (OG&E) were published, along with a final SGIG consumer behavior report
from OG&E. OG&E’s final SmartStudy Together report suggests that customers are open to
the program’s new technology and time-based pricing schedules, especially programmable
communicating thermostats and variable peak pricing with a critical peak component. Final
results from the remaining SGIG consumer behavior studies are expected between 2012 and
2014.

91

For more information on the National Action Plan on Demand Response, see National Action Plan on
Demand Response, Federal Energy Regulatory Commission, June 2010;
http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential.asp, and FERC and DOE Staff,
Implementation Proposal for the National Action Plan, July 2011, available at http://www.ferc.gov/legal/staffreports/07-11-dr-action-plan.pdf.
92
Smart Grid Investment Grant Program, Project Information: Consumer Behavior Studies, Information
available at http://www.smartgrid.gov/recovery_act/project_information?keys=&project%5B%5D=15.
42 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

NERC Demand Response Data Collection
NERC developed a regular data reporting system for demand response resources to measure
their contribution to reliability more precisely. NERC’s Demand Response Availability Data
System (DADS) collects and analyzes semiannual data from several categories of industry
participants,93 and reporting entities are required to submit information for a specified
reporting period about (1) individual demand response programs, and (2) each event for
which demand response was deployed for reliability purposes.
NERC is implementing DADS in four distinct phases:
 Phase I was completed in 2010 and served as a pilot stage for establishing the
mechanism of data collection and metrics for data analysis. It featured information
on reliability-based programs that are dispatchable and controllable.
 Phase II (the current phase of the DADS program) is mandatory94 for programs that
have been in service for one year or longer and have 10 MW or more of enrolled
resources.
 Phase III is expected to begin in the summer of 2013 and will add voluntary reporting
of non-controllable economic demand response programs such as time-of-use rates
and critical peak pricing.
 Phase IV will require reporting of all demand response resources. It is projected to
begin in 2014.
The first results of the DADS program were published in NERC’s 2012 State of Reliability
Report. 95 The report featured Phase II DADS data collected over the summer 2011 reporting
period (April 1 – September 30, 2011). From data reported by 133 entities, NERC estimates
an average of 53,005 MW of reliability demand response capacity throughout all the NERC
regions of the United States and Canada.96 NERC also reports there were 664 demand
response events called during the summer 2011 reporting period, with an average sustained
response period of 2 hours and 51 minutes.
The NERC State of Reliability Report also summarized DADS data by NERC region and
program type. The ReliabilityFirst Corporation (RFC) region had the largest demand
response capacity, with 24,386 MW registered. NERC also reported that the Interruptible
Load and Direct Load Control were the most prevalent program types, accounting for 32
percent and 26 percent of all programs respectively.

93

Responsible Entities include: Balancing Authorities, Distribution Providers, Load-Serving Entities, and
Purchasing-Selling Entities that are Registered NERC Entities. See the NERC Reliability Functional Model for
more detail, available at http://www.nerc.com/page.php?cid=2%7C247%7C108.
94
DADS data reporting is mandatory for all entities on the NERC Compliance Registry, through Section 1600
data requests. See http://www.nerc.com/files/DADS%20Quick%20Facts.pdf for more information. See also
https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/DRWG/2011/20111003/201
11003%20DRWG%20Item%2005%20DADS%20September%20Training%20Presentation.pdf for a discussion
of NERC’s authority under 18 C.F.R. Section 39.2(d).
95
North American Electric Reliability Corporation, 2012 State of Reliability Report, May 2012, available at
http://www.nerc.com/files/2012_SOR.pdf.
96
The Western Electricity Coordinating Council, the Midwest Reliability Organization, and the Northeast
Power Coordinating Council cover areas of the U.S. and Canada.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 43

Summer 2012 Demand Response Deployments
This section provides a brief overview of major summer 2012 demand response deployments
by region, along with links to additional data on summer 2012 demand response events.
According to the National Oceanic Atmospheric Administration (NOAA), summer 2012 was
one of the hottest summers on record for the U.S.97 Above-average temperatures drove high
peak electricity loads and large deployments of demand response resources across the
country.
PJM reported several large deployments of demand response resources in June and July
2012. It estimated 17,148 MW in reductions from its economic demand response program
over the month of June,98 and PJM also issued hot weather alerts for June 20-21 instructing
generators and transmission owners to defer unnecessary maintenance on plants and power
lines.99 In July, PJM reported large demand response deployments from July 2-8 and July
16-18. PJM deployed economic demand response resources from July 2-8; however, no
emergency demand response was dispatched over this one-week period.100 PJM again
utilized economic demand response resources on July 16, and a mix of economic and
emergency demand response resources from July 17-18. In the largest deployment on July
18, PJM estimates that over 2,500 MW of economic and emergency demand response
resources was deployed.101 The largest overall economic demand response responses in PJM
primarily came from Virginia, Pennsylvania, and New Jersey in June-July 2012.102 PJM did
not report any large demand response deployments during August.
New York ISO (NYISO) called upon demand response resources in June and July 2012.
NYISO called upon reliability demand response resources several times during June 2022.103 The New York Power Authority (NYPA) also deployed demand resources
participating in its Peak Reduction program for the first time on June 20, reducing hourly
peak loads in New York City up to 30 MW.104 In July, NYISO utilized reliability demand
response resources on July 18, and a mix of economic and reliability demand response

97

State of the Climate Report, July 2012, available at http://www.ncdc.noaa.gov/sotc/.
Load Response Activity Report, August 2012, available at http://pjm.com/markets-and-operations/demandresponse/~/media/markets-ops/dsr/2012-dsr-activity-report-20120810.ashx.
99
Energy Assurance Daily, June 20, 2012, available at http://www.oe.netl.doe.gov/docs/eads/ead062012.pdf.
100
PJM Estimated Demand Response Activity July 2 – 8, 2012 Report, available at http://pjm.com/markets-andoperations/demand-response/~/media/markets-ops/demand-response/pjm-hot-days-report-for-july-2-july-82012.ashx.
101
PJM Estimated Demand Response Activity July 16 – 18, 2012 Report, available at http://pjm.com/marketsand-operations/demand-response/~/media/markets-ops/demand-response/pjm-hot-days-report-july-16-182012.ashx.
102
Load Response Activity Report, August 2012, available at http://pjm.com/markets-and-operations/demandresponse/~/media/markets-ops/dsr/2012-dsr-activity-report-20120810.ashx.
103
NYISO-Called Events & Tests, August 2, 2012, available at
http://www.nyiso.com/public/webdocs/products/demand_response/general_info/Historic_EDRP_and_SCR_Act
ivation_Information.pdf.
104
NYPA press release, June 20, 2012, available at
http://www.nypa.gov/NYPAPressCenter/PressRelease/News/Hot%20Weather%20Leads%20to%20NYPAs%20
Activation%20of%20Demand%20Response%20Program%20to%20Lower%20Electricity%20Use%20in%20N
YC.html.
98

44 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

resources on July 17.105 NYISO did not report any large demand response deployments
during August.
In contrast to the Mid-Atlantic region, operators in the Midwest and New England primarily
met summer heat wave loads through non-demand resources. For example, the Midwest ISO
declared an emergency event on July 17 (which gave the Midwest ISO the option to utilize
emergency demand response resources), but wind generation unexpectedly increased by
about 200 MW shortly afterwards. As a result of this increase in supply, combined with
changing weather conditions and voluntary conservation efforts, the Midwest ISO did not
have to turn to emergency demand response resources. 106 ISO New England also did not
report calling on demand response resources from June to August 2012, although the ISO
called upon Real-Time Price Response Loads several times in late May.107
While the California ISO (CAISO) did not have any demand response deployments during
summer 2012, the ISO did issue several Flex Alerts in August 2012. Flex Alert is a CAISO
program that encourages California consumers to voluntarily conserve electricity and shift
demand to off-peak hours when the ISO issues an alert. CAISO reports that its Flex Alert
program led to significant voluntary reductions. For example, CAISO estimates that a Flex
Alert issued on August 10 resulted in nearly 1,000 MW in load reductions. PG&E, one of
the three large investor-owned utilities in California, estimates that over half of these
reductions came from PG&E’s voluntary demand response programs.108

Selected State Activities
State-regulated demand response activities over the past year have primarily focused on
evaluating applications for large-scale rollouts of new time-based electricity pricing
programs. States such as Arizona, California, and Maryland, as well as Arkansas, Oklahoma,
Illinois, Idaho, Colorado, and Connecticut, have examined the issue of time-based rates, and
many customers in these states are having their first experiences with these time-varying
rates. The following section details developments in program rollouts in these nine states,
and provides a spotlight on retail demand response programs in Texas.
Time-Based Pricing
Time-based pricing programs provide customers with economic incentives to shift
consumption away from periods of increased demand,109 giving an opportunity to save
energy expenditures. In addition, shifts in consumption may reduce the need to construct
105

NYISO-Called Events & Tests, August 2, 2012, available at
http://www.nyiso.com/public/webdocs/products/demand_response/general_info/Historic_EDRP_and_SCR_Act
ivation_Information.pdf.
106
Summer Heat Wave, MISO Market Subcommittee Presentation, August 7, 2012, available at
https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/MSC/2012/20120807/20120
807%20MSC%20Item%2002b%202012%20Summer%20Heat%20Wave.pdf.
107
See http://www.isone.com/calendar/month.action?date=20120501&cats=18,19,20&type=2&link=yes&filter=off
108
PG&E press release, available at http://www.pgecurrents.com/2012/08/17/pge-customers-heed-the-call-toconserve/.
109
Incentives include actual incurred electricity prices, a pre-specified incentive payment, or the customer’s
response to an emergency alert.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 45

new power plants to meet increasing peak demand periods. Time-based pricing programs
include a range of rate structures, such as critical peak pricing, critical peak rebates, real-time
pricing, and variable peak pricing. A number of states and utilities took actions to implement
time-based pricing programs in the past year. The Energy Information Administration (EIA)
reports that twenty-nine states have adopted time-based pricing requirements, have
requirements pending, or are studying these rate structures.110
In Arizona, an estimated one-third of the residential customers of Arizona Public Service and
Salt River Project have voluntarily chosen to participate in one of their utility’s time-of-use
programs.111 Both Arizona Public Service and Salt River Project offer web portals with userfriendly language to assist customers in making rate decisions, and offer features that allow
residential customers to compare their rate options so that interested customers may choose
the most cost-efficient rate program.112 Arizona Public Service provides graphical
comparisons of amounts paid under each available rate,113 and Salt River Project provides
customers with a web-based interactive tool that asks a series of questions so customers can
choose a plan that fits their lifestyles.114
California is another state facilitating customer participation in dynamic pricing programs: all
three investor-owned utilities in California plan to offer a dynamic pricing option to all
customers by the end of 2012.115 The California investor-owned utilities have had default
time-of-use and critical peak pricing rates for their large commercial and industrial customers
for several years, and while a law referred to as Senate Bill 645 currently prevents defaulting
residential customers to these rates, efforts are being made to expedite the transition of
residential customers to dynamic pricing plans “subject to resolution of pending proceedings
and legal resolution of SB 695 provisions.”116 The California Public Utilities Commission
110

EIA, Table 3 Existing or Pending Legislative or Regulatory Activity for Demand Response, available at
http://www.eia.gov/analysis/studies/electricity/pdf/smartggrid.pdf.
111
King, Chris, “Why energy consumers love VOLUNTARY dynamic pricing,” eMeter: Smart Grid Watch,
March 18, 2011, available at http://www.emeter.com/smart-grid-watch/2011/why-energy-consumers-lovevoluntary-dynamic-pricing/.
112
See: APS, Residential Rate Comparison, available at
https://www.aps.com/main/services/demos/RateComparisonAudio.htm; SPR, Choose your price plan & save on
electric bills, available at http://www.srpnet.com/prices/home/ChooseYourPricePlan.aspx.
113
Ibid
114
Schwartz, Judith, “Salt River Project: The Persistence of Choice,” A National Town Meeting on Demand
Response and Smart Grid, ADS Conference Presentation, June 28, 2012, available at
http://www.demandresponsetownmeeting.com/presentations/.
115
California Public Utilities Commission, Public Utilities Code Section 748 Report to the Governor and
Legislature on Actions to Limit Utility Cost and Rate Increases, May 2012, available at
http://www.cpuc.ca.gov/NR/rdonlyres/339C0DD6-0298-4BC7-AAD9A27779AA43D4/0/2012SB695ReporttoGovernorandLegislatureFinalv2.pdf.
116
For example, see California Public Utilities Commission, Proceeding A.10-08-005: Application of Pacific
Gas and Electric Company for Approval to Defer Consideration of Default Residential Time-Variant Pricing
until Its Next General Rate Case Phase 2 Proceeding, or in the Alternative for Approval of its Proposal for
Default Residential Time-Variant Pricing and For Recovery of Incremental Expenditures Required for
Implementation (U39E), available at
http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:392034754001701::NO:RP:: Proceeding A.1007-009: In the Matter of the Application of San Diego Gas & Electric Company (U902E) for Approval of its
Proposals for Dynamic Pricing and Recovery of Incremental Expenditures Required for Implementation;
available at http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:1372938263824701::NO:RP:
Proceeding A.11-06-007: Application of Southern California Edison Company (U338E) To Establish Marginal
46 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

recently authorized portions of the investor-owned utilities’ programs’ dynamic pricing
requests for 2012 through 2014 as part of the utilities’ demand response programs and budget
proposals.117
Maryland is also active in implementing dynamic pricing programs. The Maryland Public
Service Commission approved applications from Baltimore Gas and Electric and Potomac
Electric Power Company to offer peak time rebate programs. The Baltimore Gas and
Electric program was approved for rollout in June 2013, while Potomac Electric Power
Company planned to offer its program to over 5,000 customers in July 2012.118 Both
programs will be available on an opt-in basis to customers who have advanced meters
installed.
Several other states also examined and approved dynamic pricing programs and rates. These
include:
 Arkansas and Oklahoma. The Arkansas Public Service Commission and the
Oklahoma Corporation Commission have each allowed the Oklahoma Gas and
Electric Company to offer residential customers variable peak pricing rates on an optin basis.119, 120
 Illinois. In Illinois, both Ameren Utilities and Commonwealth Edison Company have
received approval from the Illinois Commerce Commission to establish residential
real-time pricing programs.121
 Idaho. The Idaho Public Utilities Commission approved a voluntary Idaho Power
dynamic pricing program, initially proposed for 1,200 customers. After Idaho Power
submits a report on its 2012 results, the program may be expanded to additional
customers in 2013.122

Costs, Allocate Revenues, Design Rates, and Implement Additional Dynamic Pricing Rates, available at
http://delaps1.cpuc.ca.gov/CPUCProceedingLookup/f?p=401:1:1372938263824701::NO:RP:.
117
The decision authorized thee-year budgets of approximately $191.9 million for PG&E, $196.3 million for
SCE and $65.8 million for SDG&E.
118
Maryland Public Service Commission, In the Matter of Baltimore Gas and Electric Company for
Authorization to Deploy a Smart Grid Initiative and To Establish a Surcharge for the Recovery of Cost, Case
No. 9208, Order No. 84925, Item 143, Issued May 24, 2012, available at:
http://webapp.psc.state.md.us/Intranet/home.cfm; and Maryland Public Service Commission, In the Matter of
Potomac Electric Power Company and Delmarva Power and Light Company Request for the Deployment of
Advanced Metering Infrastructure, Case No. 9207, Item 207, Order No. 84966, Issued June 8, 2012, available
at: http://webapp.psc.state.md.us/Intranet/home.cfm.
119
Oklahoma Corporation Commission, Standard Pricing Schedule: R-VPP Residential Variable Peak Pricing
Program, Docket No. PUD 201000016, Order No. 575500, Approved May 2010, available at
http://www.oge.com/Documents/OK/3.50%20R-VPP.pdf.
120
Arkansas Public Service Commission, Oklahoma Gas and Electric Company Residential Variable Peak
Pricing, Docket No. 10-067-U. Order No. 6, Approved June 2011, available at
http://www.oge.com/Documents/ARK/2011%20Arkansas%20Docket%2010-067-U/R-VPP%206-6-2011.pdf.
121
Illinois Commerce Commission, Real Time Pricing, available at
http://www.icc.illinois.gov/Electricity/RTP.aspx.
122
Idaho Public Utilities Commission, Case No. IPC-E-12-05: In the Matter of the Application of Idaho Power
Company for Approval of Modifications to Schedules 1, 4, and 5 Implementing a Time Variant Pricing Plan,
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 47





Colorado. In April 2011, the Colorado Public Utilities Commission (CPUC) closed a
docket on exploring the issues related to smart grid and advanced metering by issuing
a decision that included conclusions and next steps for the state.123 In this document,
the CPUC noted that one of the primary benefits of advanced meters is to provide a
platform for dynamic pricing.
Connecticut. In Connecticut, all electric distribution companies must offer voluntary
critical peak pricing or real-time pricing programs for all customer classes.124 As a
result, the Connecticut Public Utilities Regulatory Authority has approved variable
peak pricing rates for customers of both the Connecticut Light and Power
Company125 and the United Illuminating Company.126

Texas Retail Demand Response
The Public Utility Commission of Texas has developed a process to integrate the deployment
of advanced metering with competitive demand response retail service markets. After an
electric utility installs an advanced meter, residential customers in Texas have the option to
choose demand response services and compatible technologies from a number of competing
companies. Eligible demand response service providers include both retail energy providers
and vendors of third-party products and services.127 Third-party providers that participate in
Texas’ program have noted that they must engage and educate consumers on the benefits of
demand response technology.
The Public Utility Commission of Texas, ERCOT, and interested stakeholders are also
working on reducing barriers to increased demand response participation among advanced
metering customers.128,129 Through a series of workshops, stakeholders are examining a

Order No 32499, March 27, 2012, available at:
http://www.puc.idaho.gov/orders/recent/Final_Order_No_32499.pdf.
123
Colorado Public Utilities Commission, In the Matter of the Investigation of the Issues Related to Smart Grid
and Advanced Metering Technologies: Order Stating Conclusions and Next Steps, Adopted March 2011,
available at https://www.dora.state.co.us/pls/efi/EFI_Search_UI.Show_Decision?p_session_id=&p_dec=13836.
124
See: Connecticut Public Utilities Regulatory Authority, Docket No. 03-07-02RE11: Application of the
Connecticut Light and Power Company to Amend its Rate Schedule – Review of VPP Tariffs, September 21,
2011 Decision, available at
http://www.dpuc.state.ct.us/dockhist.nsf/8e6fc37a54110e3e852576190052b64d/d72d04fcf84696c18525795800
5bd05a?OpenDocument.
125
Ibid.
126
Connecticut Public Utilities Regulatory Authority, Docket No. 05-06-04RE04: Application of The United
Illuminating Company To Increase Its Rates and Charges, – Public Act 07-242, Seasonal Rates, Non
Generation-Related Time-of-Use Pricing and Related Rate Design Issues, September 28, 2008, Final Decision,
available at
http://www.dpuc.state.ct.us/dockhist.nsf/8e6fc37a54110e3e852576190052b64d/17989d79124999ea852575230
0524e43?OpenDocument.
127
See: ERCOT, Demand Side Working Group (DSWG), AMI’s Next Frontier Workshop, Agenda Item
#6:Technology/Product Providers Perspectives, August 30, 2011, available at
http://ercot.com/calendar/2011/08/20110830-DSWG.
128
ERCOT, Demand Side Working Group (DSWG), AMIT-DSWG Workshop, ‘AMI’s Next Frontier: Demand
Response Part 2’, December 16, 2011, available at http://ercot.com/calendar/2011/12/20111216-DSWG.
48 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

broad variety of potential barriers, including (1) the short duration of retail contracts (e.g., 12
or 24 months) that may not allow retail demand response providers to recover product and
service costs, (2) the lack of regulatory requirements for retail energy providers to offer
specific products, (3) limited third-party access to data, and (4) the reliability of
communication networks.

Barriers to Demand Response
Demand-response can be accomplished through a variety of means and ways. As evidenced
by the activities described above, the federal government, the Commission, and state and
local governments have made progress on removing barriers to customer participation in
demand response. Nevertheless, and depending on the type of demand-response to be
pursued, several outstanding barriers remain.








Limited Number of Retail Customers on Time-Based Rates.
Previous
Commission staff annual reports highlighted the low number of retail customers who
purchase electricity based on time-based rates. While there is progress, without an
expanded implementation of time-based rates across the U.S., the development of
new technologies and programs and the fulfillment of the nation’s demand response
potential may be slowed.
Measurement and Cost-Effectiveness of Reductions.
While the lack of
consistency in the measurement and verification of demand reductions and the lack of
demand responsive-specific cost-effectiveness tools remain as barriers, significant
progress to reduce these barriers occurred in the past year. NAESB completed some
work on measurement and verification and the Commission issued a Notice of
Proposed Rulemaking in April proposing to adopt the Phase II wholesale demand
response measurement and verification standards. Furthermore, changes to the
measurement and verification of demand response in organized wholesale energy and
ancillary markets indicate movement toward more consistency across the various
RTOs. Finally, focused review of these two issues is occurring within the National
Forum on the National Action Plan on Demand Response.
Lack of Uniform Standards for Communicating Demand Response Pricing,
Signals and Usage Information. Communications to and interactions with demand
response resources and end-use devices are typically based on company- and
technology-specific proprietary protocols and techniques. The lack of common
information models and protocols resulted in the potential for duplicative systems and
inefficient transfer of pricing and usage information between parties. As discussed in
Chapter 4, recent standards development work being led by the National Institute of
Standards and Technology and the Smart Grid Interoperability Panel should help
remove this barrier, if industry embraces and utilities these standards.
Lack of Customer Engagement. Customers need to be effectively educated and
informed about demand response and smart grid opportunities. Effective outreach

129

Public Utility Commission of Texas, PUCT Project 34610: Implementation Project Relating to Advanced
Metering, available at http://www.puc.state.tx.us/industry/projects/electric/34610/34610.aspx.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 49



and communication are needed to explain demand response, time-based pricing and
smart grid investments and the impacts of these at the customer level. Otherwise,
customers may respond negatively to actions taken by their electric providers, e.g.,
the deployment of advanced meters. As the experiences of Oklahoma Gas and
Electric and Arizona Public Service demonstrate, successful customer engagement
efforts can be used to support smart grid investments, thereby promoting customer
support. The efforts of the Smart Grid Consumer Collaborative to draw upon best
practices may prove helpful.130
Lack of Demand Response Forecasting and Estimation Tools. As the National
Action Plan on Demand Response identified, “new tools and methods should be
developed to directly incorporate demand response into dispatch algorithms and
resource planning models,” and “to forecast and model the capability of demand
resources to adjust consumption in near real-time.”131 Current planning and
forecasting tools are not sufficiently robust to model adequately the capability of
demand response to serve as an alternative to building new generation and
transmission and to act as a resource to alleviate transmission congestion. The efforts
sponsored by U.S. Department of Energy to develop interconnection-wide plans that
include demand side resources may help address this need. In addition, the National
Forum on the National Action Plan on Demand Response is examining other
modeling needs. The National Forum effort is inventorying existing demand
response tools and models, and is identifying needed modeling and tools.

130

Consumer engagement is a key topic for the Smart Grid Consumer Collaborative (SGCC). See SGCC,
Consumer Engagement, available at http://smartgridcc.org/category/consumer-engagement.
131
FERC, National Action Plan on Demand Response, June 2010, pp. 75-76.
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2012 Assessment of Demand Response and Advanced Metering

CHAPTER 4. SMART GRID DEVELOPMENTS SUPPORTING DEMAND
RESPONSE
This chapter reports on two key smart grid developments that support the further
development of demand response resources: (1) the development of new communications
and demand response standards by the National Institute of Standards and Technology’s
Smart Grid Interoperability Panel, and (2) the Smart Grid Demonstration Program sponsored
by the U.S. Department of Energy.

Demand Response-Related Smart Grid Standards Development
In Title XIII of the Energy Independence and Security Act of 2007 (EISA), Congress
addressed the need for standards for communication and interoperability of the grid to
enable, among other things, the incorporation of demand response and demand-side
resources into grid operations. 132 EISA directed the National Institute of Standards and
Technology (NIST) to coordinate the development of a framework to achieve

interoperability of smart grid devices and systems, including protocols and model
standards for information management.133 In turn, NIST set up the Smart Grid
Interoperability Panel (SGIP), a public-private consensus-based organization, to coordinate
standards development with input from a broad range of smart grid stakeholders.134
In 2009, the Commission issued a Smart Grid Policy Statement that identified demand
response as one of four key functional priorities for smart grid interoperability standards
development.135 In the Policy Statement, the Commission reiterated that demand response
can play a important role in integrating variable sources of renewable generation, and in
maintaining system security in constrained areas.136 NIST agreed that demand response is a
priority for interoperability standards development, and has devoted considerable resources
to this effort.137 The following section reviews the progress of the SGIP efforts.

Demand Response Activities within the NIST/SGIP Process
The NIST Framework and Roadmap for Smart Grid Interoperability, Release 2.0 states the
following:
“…the SGIP focuses on two principal areas where value can be added:


Analysis of cross-functional area applications. Such applications often require
coordination between one or more technologies, and this coordination introduces

132

Public Law No. 110-140, 121 Stat. 1492, 1783-84, codified at 15 U.S.C. 17381 et seq. (2007).
EISA sec. 1305(a), codified at 15 U.S.C. 17385(a).
134
NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 2.0, at page 142.
135
Federal Energy Regulatory Commission, Smart Grid Policy, 128 FERC ¶ 61,060 (2009). The other three
functional priorities are wide-area situational awareness, energy storage, and electric transportation. The
Commission also identifies two cross-cutting priorities, namely cyber security and communication and
coordination across inter-system interfaces.
136
Id., at P 74.
137
NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 1.0.
133

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 51

issues and requirements beyond the original scope of the technology or
technologies.


Coordination among all groups which must complement each other on the
resolution of a gap or overlap in Smart Grid technologies.

The first of these focus areas, Analysis, is provided by the SGIP through the working group
structure, primarily through the Domain Expert Working Groups. The second of these focus
areas, Coordination, is provided by the SGIP through the origination and oversight of the
Priority Action Plan (PAP) groups.”138
NIST and the SGIP established the following Priority Action Plans for demand response. As
the name suggests PAPs are created when the SGIP determines there is a need for
interoperability coordination on some urgent issue.”139
 Standardized demand response information and signals;
 Standardized energy usage information;
 Wholesale demand response communication protocols; and
 Facility-level communication standards.
A number of standards related to demand response have received supermajority support
within the SGIP,140 or have made major strides to develop new standards, as described in the
following sections.
Standardized demand response information and signals
Recognizing the need for electricity providers to be able to communicate demand response
and distributed energy resources signals (e.g., price, information on system conditions, and
dispatch instructions) with each other and with customers, the SGIP sponsored several PAPs
to develop common protocols for communicating (1) price information, (2) demand response
signals, and (3) equipment status for demand response and distributed energy resources.141
Two standards development organizations, the Organization for the Advancement of
Structured Information Standards (OASIS) and NAESB, did much of the standards
development work, in collaboration with the PAP working groups.
The OpenADR Alliance, a diverse group of utilities, independent system operators,
regulators, demand response providers, and controls suppliers is currently testing various
forms of the OpenADR 2.0 standard.
138

Supra at page 143.
Id., at page 150.
140
When smart grid standards are supported by a supermajority, they are included in SGIP’s Catalog of
Standards. The Catalog of Standards is a compendium of standards and practices considered to be relevant for
the development and deployment of an interoperable Smart Grid, Information on the Catalog of Standards is
available at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/SGIPCatalogOfStandards.
141
PAP 3 (Develop Common Specification for Price and Product Definition) facilitated the development of the
OASIS Energy Market Information Exchange (eMIX) standard. PAP 4 (Develop Common Schedule
Communication Mechanism for Energy Transactions) helped produce the OASIS WS-Calendar standard. PAP
9 (Standard Demand Response and Distributed Energy Resources Signals) facilitated the development of the
OASIS Energy Interoperation standard and OpenADR 2.0. For more information on the SGIP PAP process, see
http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/WebHome.
139

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2012 Assessment of Demand Response and Advanced Metering

Standardized energy usage information
In recognition of the importance of energy usage information to the smart grid, and the lack
of a common, standardized approach, the SGIP established PAP 10 (Standard Energy Usage
Information). The associated working group had the mission to develop a standardized
information model for energy usage and to develop business rules for authorizing access to
this usage information. Without these efforts, software developers and utilities would each
need to develop customized, one-off solutions. Much of the work for this PAP has been led
by NAESB. The result of NAESB’s work (the Energy Usage Information standard) has been
included in the Catalog of Standards. NAESB has also developed an Energy Service
Provider Interface (ESPI) that provides a way for Energy Usage Information to be shared, in
a controlled manner to ensure confidentiality, between participants in the energy services
markets.
The Green Button initiative is also based on the framework created by the NAESB Energy
Usage Information and ESPI standards. As discussed in Chapter 2, Green Button is an
industry-led effort to provide electricity customers with easy access to their energy usage
data in a consumer-friendly and computer-friendly format. To further develop the Green
Button effort, the SGIP recently approved the creation of a new PAP 20 (Green Button ESPI
Evolution).
There were several national-scale efforts over the past two years that have focused on
providing privacy protection for consumer energy usage information. The SGIP Cyber
Security Working Group devoted an entire chapter of the NIST IR 7628142 to privacy
principles. NAESB has also developed a set of guidelines143 with respect to customer data
being shared between utilities and third-party service providers.
Wholesale demand response communication protocols
The SGIP recently formed the PAP 19 working group (Wholesale Demand Response
Communication Protocol) to develop and enhance data exchange between RTOs and demand
response aggregators, which may include utilities.144 The new effort is not intended to
compete with standards for communicating with end-use customers, but rather is designed to
create a seamless transfer of information and signals from wholesale system operators to
demand response aggregators and then to end-use customers.
The PAP 19 working group is in the process of identifying electricity market requirements
and gaps within current standards frameworks (including but not limited to Energy
Interoperation, OpenADR 2.0 and the IEC Common Information Modeling), to adequately
address demand response wholesale market interfaces.145
142

NISTIR 7628, Guidelines for Smart Grid Cyber Security: Vol. 2, Privacy and the Smart Grid, available
at http://nist.gov/smartgrid/upload/nistir-7628_total.pdf.
143
North American Energy Standards Board, REQ.22 Third Party Access to Smart Meter-Based Information
(2011)
144
PAP 19 began its deliberations in March 2012.
145
PAP 19 developed a Wholesale Demand Response Communication Protocol that was out for comment in
Autumn 2012. See http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/PAP19WholesaleDR for more
information.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 53

Facility-level standards
The standards discussed in the preceding sections focus on the interchange of information
and data among parties and across domains, and are not directly focused on the transfer of
information or communications at the facility level.
To address facility-level
communications, the SGIP created two additional PAPs focused on communication and
information exchange within buildings and premises.
One PAP deals with the Smart Energy Profile, which originally was a proprietary protocol
developed for residential end users by the Zigbee Alliance, a collaboration of vendors and
utilities. The Smart Energy Profile has since changed into an open standard that is
harmonized with several previously competing communications standards. A new version
2.0 that communicates with home area networks is expected to be published by the end of
2012. It however is not compatible with the older Smart Energy Profile 1.0 and successor
versions already installed in many meters. This lack of compatibility has troubled state
commissions in Texas and California. In response, the SGIP established PAP 18 to focus on
the technical issues associated with migration and the coexistence of two Smart Energy
Profile versions. PAP 18 succeeded in identifying best practices and means to allow
continued use of Smart Energy Profile 1.x and transition towards the use of Smart Energy
Profile 2.0.146
A second PAP (PAP 17) focuses on interoperability among building energy management
systems for primarily commercial buildings, although the standard could also be used in
industrial facilities and residences. The standard is being developed through a partnership
between ASHRAE and NEMA. This standard enables communications of demand response
signals from system operators and aggregators, through building energy management
systems, to equipment within facilities. It also can allow communications about electrical
loads within the facility back to the utility and other electrical service providers.

Smart Grid Demonstration Program
The Smart Grid Demonstration Program147 operated by the U.S. Department of Energy aims
to demonstrate how a suite of existing and emerging smart grid concepts can be innovatively
applied and integrated to prove technical, operational, and business model feasibility. The
goal of the program is to demonstrate new and more cost-effective smart grid technologies,
tools, techniques, and system configurations that significantly improve on the ones
commonly used today. This program is currently funding 16 smart grid regional
demonstration projects and 16 energy storage projects.148 Most of these support advanced
metering or demand response programs.
The regional smart grid demonstration projects were selected to verify smart grid viability,
quantify smart grid costs and benefits, and validate new smart grid business models at scales
that can be readily replicated across the country. Of these 16 projects, the nine that employ
146

A white paper on this transition received supermajority support within the SGIP and is available at
http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/PAP18SEP1To2TransitionAndCoexistence.
147
This program was authorized by the Energy Independence and Security Act of 2007, Section 1304, and
amended by the Recovery Act.
148
The total budget for the 32 projects is about $1.6 billion; the federal share is about $600 million.
54 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

demand response technologies or otherwise enhance demand response are described
below.149


AEP’s gridSMART Demonstration Project demonstrates the ability to maximize
distribution system efficiency and reliability, and consumer use of demand response
programs to reduce energy consumption, peak demand costs, and fossil fuel
emissions.



Battelle Memorial Institute’s Pacific Northwest Smart Grid Demonstration
Project is a collaboration between utilities, universities, and technology partners
across five states More than 20 types of responsive Smart Grid assets, including
demand response, storage, and direct load control, will be tested across six regional
and utility operational objectives at 15 unique distribution sites operated by 12
utilities.



Kansas City Power and Light’s Green Impact Zone SmartGrid Demonstration is
built around a SmartSubstation with a local distributed control system that includes
advanced generation, distribution, and customer technologies.



Long Island Power Authority’s Long Island Smart Energy Corridor will
integrate advanced metering technology with automated substation and distribution
systems to reduce peak demand and energy costs, while improving the ability to
identify and respond to outages.



Los Angeles Department of Water and Power’s Smart Grid Regional
Demonstration is a collaboration between a consortium of research institutions to
develop new Smart Grid technologies, quantify costs and benefits, validate new
models, and create prototypes to be adapted nationally. The project consists of four
broad initiatives: demand response, electric vehicle integration, customer behavior,
and cyber security.



National Rural Electric Cooperative Association’s Enhanced Demand and
Distribution Management Regional Demonstration demonstrates Smart Grid
technologies with 27 cooperatives in 11 states. The project will conduct studies in
advanced volt/volt-ampere reactive for total demand; demand response; critical peak
pricing; water heater and air conditioning load control; thermal storage; energy usage
portal pilots; consumer in-home energy display pilots; AMI integration; distribution
co-op meter data management system applications; and self-healing feeders for
improved reliability.



NSTAR Electric and Gas Corporation’s Automated Meter Reading-Based
Dynamic Pricing will enable residential dynamic pricing (time-of-use, critical peak
rates, and peak time rebates) and two-way direct load control by capturing automated
meter reading (AMR) data transmissions and communicating through existing
customer-sited broadband connections in conjunction with home area networks.

149

SmartGrid.gov, Smart Grid Demonstration Program, available at
http://www.smartgrid.gov/recovery_act/overview/smart_grid_demonstration_program.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 55



Pecan Street Project’s Energy Internet Demonstration is developing and
implementing an Energy Internet in Austin, Texas. Smart Grid technologies include
advanced metering, energy control gateways, advanced billing software, and smart
thermostats, distributed generation, thermal storage, battery storage, and smart
irrigation systems.



Southern California Edison Company’s Irvine Smart Grid Demonstration will
deploy advanced Smart Grid technologies in an integrated system to be more reliable,
secure, economic, efficient, safe, and environmentally friendly. The technology
demonstrations will include three main areas: (1) Energy Smart Customer Devices;
(2) Year 2020 Distribution System including distribution automation with looped
circuit topology, advanced voltage/VAR control, advanced distribution equipment,
smart metering, utility-scale storage, and dispatched renewable distributed generation;
and (3) a Secure Energy Network to demonstrate end-to-end management of a
complex high performance telecommunication system.

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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.

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‘‘(E) In a State that permits third-party marketers to sell electric energy to retail
electric consumers, such consumers shall be entitled to receive the same time-based
metering and communications device and service as a retail electric consumer of the
electric utility.
‘‘(F) Notwithstanding subsections (b) and (c) of section 112, each State regulatory
authority shall, not later than 18 months after the date of enactment of this paragraph
conduct an investigation in accordance with section 115(i) and issue a decision
whether it is appropriate to implement the standards set out in subparagraphs (A) and
(C).’’. H. R. 6—372
(b) STATE INVESTIGATION OF DEMAND RESPONSE AND TIMEBASED
METERING.—Section
115 of the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2625) is amended as
follows:
(1) By inserting in subsection (b) after the phrase ‘‘the standard for time-of-day rates
established by section 111(d)(3)’’ the following: ‘‘and the standard for time-based metering
and communications established by section 111(d)(14)’’.
(2) By inserting in subsection (b) after the phrase ‘‘are likely to exceed the metering’’ the
following: ‘‘and communications’’.
(3) By adding at the end the following:
‘‘(i) TIME-BASED METERING AND COMMUNICATIONS.—In making a determination
with respect to the standard established by section 111(d)(14), the investigation requirement
of section 111(d)(14)(F) shall be as follows: Each State regulatory authority shall conduct an
investigation and issue a decision whether or not it is appropriate for electric utilities to
provide and install time-based meters and communications devices for each of their
customers which enable such customers to participate in time-based pricing rate schedules
and other demand response programs.’’.
(c) FEDERAL ASSISTANCE ON DEMAND RESPONSE.—Section 132(a) of the Public
Utility
Regulatory Policies Act of 1978 (16 U.S.C. 2642(a)) is amended by striking ‘‘and’’ at the
end of paragraph (3), striking the period at the end of paragraph (4) and inserting ‘‘; and’’,
and by adding the following at the end thereof: ‘‘(5) technologies, techniques, and ratemaking methods related to advanced metering and communications and the use of these
technologies, techniques and methods in demand response programs.’’.
(d) FEDERAL GUIDANCE.—Section 132 of the Public Utility Regulatory Policies Act of
1978 (16
U.S.C. 2642) is amended by adding the following at the end thereof:
‘‘(d) DEMAND RESPONSE.—The Secretary shall be responsible for—
‘‘(1) educating consumers on the availability, advantages, and benefits of advanced metering
and communications technologies, including the funding of demonstration or pilot projects;
‘‘(2) working with States, utilities, other energy providers and advanced metering and
communications experts to identify and address barriers to the adoption of demand response
programs; and
‘‘(3) not later than 180 days after the date of enactment of the Energy Policy Act of 2005,
providing
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Congress with a report that identifies and quantifies the national benefits of demand response
and makes a recommendation on achieving specific levels of such benefits by January 1,
2007.’’.
(e) DEMAND RESPONSE AND REGIONAL COORDINATION.—
(1) IN GENERAL.—It is the policy of the United States to encourage States to coordinate,
on a regional basis, State energy policies to provide reliable and affordable demand response
services to the public.
(2) TECHNICAL ASSISTANCE.—The Secretary shall provide technical assistance to States
and regional organizations formed by two or more States to assist them in—
(A) identifying the areas with the greatest demand response potential; H. R. 6—373
(B) identifying and resolving problems in transmission and distribution networks,
including through the use of demand response;
(C) developing plans and programs to use demand response to respond to peak
demand or emergency needs; and
(D) identifying specific measures consumers can take to participate in these demand
response programs.
(3) REPORT.—Not later than 1 year after the date of enactment of the Energy Policy Act of
2005, the
Commission shall prepare and publish an annual report, by appropriate region, that assesses
demand response resources, including those available from all consumer classes, and which
identifies and reviews—
(A) saturation and penetration rate of advanced meters and communications
technologies, devices and systems;
(B) existing demand response programs and time-based rate programs;
(C) the annual resource contribution of demand resources;
(D) the potential for demand response as a quantifiable, reliable resource for regional
planning
purposes
(E) steps taken to ensure that, in regional transmission planning and operations,
demand resources are provided equitable treatment as a quantifiable, reliable resource
relative to the resource obligations of any load-serving entity, transmission provider,
or transmitting party; and
(F) regulatory barriers to improve customer participation in demand response, peak
reduction and critical period pricing programs.
(f) FEDERAL ENCOURAGEMENT OF DEMAND RESPONSE DEVICES.—It is the
policy of the
United States that time-based pricing and other forms of demand response, whereby
electricity customers are provided with electricity price signals and the ability to benefit by
responding to them, shall be encouraged, the deployment of such technology and devices that
enable electricity customers to participate in such pricing and demand response systems shall
be facilitated, and unnecessary barriers to demand response participation in energy, capacity
and ancillary service markets shall be eliminated. It is further the policy of the United States
that the benefits of such demand response that accrue to those not deploying such technology
and devices, but who are part of the same regional electricity entity, shall be recognized.

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(g) TIME LIMITATIONS.—Section 112(b) of the Public Utility Regulatory Policies Act of
1978 (16
U.S.C. 2622(b)) is amended by adding at the end the following:
‘‘(4)(A) Not later than 1 year after the enactment of this paragraph, each State regulatory
authority (with respect to teach electric utility for which it has ratemaking authority) and each
non-regulated electric utility shall commence the consideration referred to in section 111, or
set a hearing date for such consideration, with respect to the standard established by
paragraph (14) of section 111(d).
‘‘(B) Not later than 2 years after the date of the enactment of this paragraph, each State
regulatory authority (with respect to each electric utility for which it has ratemaking
authority), and each non-regulated electric utility, shall complete the consideration, and shall
make the determination, referred to in section 111 with respect to the standard established by
paragraph (14) of section 111(d).’

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APPENDIX B: ACRONYMS AND ABBREVIATIONS
AMI
AMR
ARRA
ASCC
CAISO
EIA
EISA 2007
EPAct 2005
ERCOT
FERC
FRCC
kW
ISO
ISO-NE
LMP
Midwest ISO
MRO
MW
MWh
NAESB
NERC
NIST
NPCC
NYISO
OATT
PJM
RFC
RTO
SERC
SGIG
SGIP
SPP
TRE
WECC

Advanced Metering Infrastructure
Automated Meter Reading OR Automatic Meter Reading
American Recovery and Reinvestment Act of 2009
Alaska Systems Coordinating Council
California Independent System Operator
Energy Information Administration
Energy Independence and Security Act of 2007
Energy Policy Act of 2005
Electric Reliability Council of Texas, Inc.
Federal Energy Regulatory Commission
Florida Reliability Coordinating Council
Kilowatt
Independent system operator
Independent System Operator of New England
Locational Marginal Price
Midwest Independent Transmission System Operator
Midwest Reliability Organization
Megawatt
Megawatt-hour
North American Energy Standards Board
North American Electric Reliability Corporation
National Institute of Standards and Technology
Northeast Power Coordinating Council
New York Independent System Operator
Open Access Transmission Tariff
PJM Interconnection, L.L.C
ReliabilityFirst Corporation
Regional transmission organization
SERC Reliability Corporation
Smart Grid Investment Grant
Smart Grid Interoperability Panel
Southwest Power Pool, Inc.
Texas Regional Entity
Western Electricity Coordinating Council

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APPENDIX C: GLOSSARY
Note: The terms and definitions provided in this glossary were provided to survey
respondents and are for the limited purpose of the survey.
Actual MWh Change: The total change in energy consumption (measured in MWh) that
resulted from the deployment of demand response programs during the year.
Advanced Meters: Meters that measure and record usage data at hourly intervals or more
frequently, and provide usage data to both consumers and energy companies at least once
daily. Data are used for billing and other purposes. Advanced meters include basic hourly
interval meters, meters with one-way communication, and real-time meters with built-in twoway communication capable of recording and transmitting instantaneous data.
Aggregator: See “Curtailment Service Provider”
Ancillary Services: Services that ensure reliability and support the transmission of electricity
to customer loads. Such services may include: energy imbalance, operating reserves,
contingency reserves, spinning (also known as synchronized, ten-minute spinning,
responsive) reserves, supplemental (also known as non-spinning, non-synchronized, tenminute non-synchronous, thirty-minute operating) reserves, reactive supply and voltage
control, and regulation and frequency response (also known as regulation reserves, regulation
service, up-regulation and down-regulation).
Bid Limit: The maximum bid, in $/MWh, that can be submitted by a demand response
program participant. If there is no bid limit, leave blank.
Capacity (program type): Displacement or augmentation of generation for planning and/or
operating resource adequacy; penalties are assessed for nonperformance.
Capacity Market Programs: Arrangements in which customers offer load reductions as
system capacity to replace conventional generation or delivery resources. Participating
customers typically receive notice of events requiring a load reduction and face penalties
when failing to curtail load. Incentives usually consist of up-front reservation payments.
Capacity Service: A type of demand response service in which demand resources are
obligated over a defined period of time to be an available resource for the system operator.
Commercial and Industrial: Belonging to either of the energy-consuming sectors that
consist of (a) a broad range of facility types including office buildings, retail establishments,
hospitals, universities, the facilities of federal, state, and local governments and non-profit
organizations, institutional living quarters, master-metered apartment buildings, and homes
on military bases; and (b) manufacturing facilities and equipment used for producing,
processing, or assembling goods and encompassing the following types of activities:
manufacturing; processing; agriculture, forestry and fisheries; mining; and construction.
Also, a business labeled as “industrial” by the North American Industry Classification
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System or by the energy provider on the basis of energy demand or annual usage exceeding
some specified limit set by the energy provider.
Coincident Reduction Capability: The amount of demand response curtailments that would
be realized if all demand response products were called simultaneously and all responded by
curtailing load at prearranged levels or at their enrolled quantity.
Critical Peak Pricing with Load Control: Demand-side management that combines direct
load control with a pre-specified high price for use during designated critical peak periods,
triggered by system contingencies or high wholesale market prices.
Critical Peak Pricing: Rate and/or price structure designed to encourage reduced
consumption during periods of high wholesale market prices or system contingencies by
imposing a pre-specified high rate or price for a limited number of days or hours.
Curtailment Service Provider: Businesses that sponsor demand response programs that
recruit and contract with end users, and sell the aggregated demand response to utilities,
RTOs and ISOs. A Curtailment Service Provider is sometimes called an Aggregator and is
not necessarily a load-serving entity.
Customer Sector: A group of customers: residential, commercial and industrial, and
other (for example, transportation, agricultural).
Demand Bidding & Buy-Back: A program which allows a demand resource in retail and
wholesale markets to offer load reductions at a price, or to identify how much load it is
willing to curtail at a specific price.
Demand Resource or Demand-Side Resource: An electricity consumer that can decrease
its power consumption in response to a price signal or direction from a system operator.
Demand Response: Changes in electric use by demand-side resources from their normal
consumption patterns in response to changes in the price of electricity, or to incentive
payments designed to induce lower electricity use at times of high wholesale market prices or
when system reliability is jeopardized.
Demand Response Program: A company's service/program/tariff related to demand
response, or the change in customer electric usage from normal consumption patterns in
response to changes in the price of electricity over time or in response to incentive payments
designed to induce lower electricity use at times of high wholesale market prices, or a change
in electric usage by end-use customers at the direction of a system operator or an automated
preprogrammed control system when system reliability is jeopardized. Includes both timebased rate programs and incentive-based programs.
Demand Response Program/Tariff and Program/Tariff Types: A company or utility's
service/product/compilation of all effective rate schedules, general terms and conditions and
standard forms related to demand response and/or AMI services and classification thereof.

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Direct Load Control: A demand response activity by which the program sponsor remotely
shuts down or cycles a customer’s electrical equipment (e.g., air conditioner, water heater) on
short notice. Direct load control programs are primarily offered to residential or small
commercial customers. Also known as direct control load management.
Display Unit/In-home Display: Customer on-site device that receives (from a service
provider or from a smart meter) and displays for the customer information such as usage and
pricing data, messages, and alerts.
Duration of Event: The length of an Emergency or Economic Demand Response Event, in
hours.
Economic Demand Response Event: An event in which the demand response program
sponsor directs response to an economic market opportunity, rather than for reliability or
because of an emergency in the energy delivery system.
Electric Utility: A corporation, person, agency, authority, or other legal entity or
instrumentality producing, transmitting, or distributing electricity for use primarily by the
public. This includes: investor-owned electric utilities, municipal and state utilities, federal
electric utilities, and rural electric cooperatives. A few entities that are tariff based and
affiliated with companies owning distribution facilities are also included in this definition.
Emergency Event: An abnormal system condition (for example, system constraints and
local capacity constraints) that requires automatic or immediate manual action to prevent or
limit the failure of transmission facilities or generation supply that could adversely affect the
reliability of the Bulk Electric System.
Emergency Demand Response Event: The period of time during which participants in a
Demand Response Program must reduce load. The Emergency Demand Response Event is
announced by the program sponsor in response to an Emergency Event declared by it or by
another entity such as a utility or RTO/ISO. Demand Response Program sponsors, utilities
and RTO/ISOs typically declare these emergency events.
Emergency Demand Response Program: A demand response program that provides
incentive payments to customers for load reductions achieved during an Emergency Demand
Response Event.
End-Use Customer: A firm or individual that purchases electricity for its own consumption
and not for resale; an ultimate consumer of electricity.
Energy Payment for MWh Curtailed ($/MWh): Compensation paid or received for
reductions in electric energy consumption.
Energy Service Providers: See Power Marketers.
Entity: The organization that is (1) responding to the survey, (2) offering demand response
programs, time-based rates and/or tariffs, or (3) using advanced or smart meters.
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Entity ID Number: The respondent should enter the ID number which appears on the survey
transmittal e-mail, or the ID number used for the entity’s response to the Form EIA-861
Survey.
Event Limits: The maximum number of times a demand response resource may be called
during a specified period of time (typically one year or one season).
Federal Electric Utility: A utility that is either owned or financed by the Federal
Government.
Generation and Transmission Company (G&T Company): A company that provides both
energy production and facilities for transmitting energy to wholesale customers. G&T
companies are usually formed by rural electric cooperatives and electric utilities to pool the
costs and risks of constructing and managing the generation facilities and high-voltage
transmission infrastructure which are needed to deliver energy to their customers.
Hourly Pricing: A pricing plan in which energy prices vary by the hour, usually based in
part on a wholesale market price for energy.
In-home Display: See Display Unit/In-home Display.
Industrial Sector: The energy-consuming sector that consists of manufacturing facilities and
equipment used for producing, processing, or assembling goods. The Industrial Sector
encompasses the following types of activities: manufacturing; processing; agriculture,
forestry and fisheries; mining; and construction. The term Industrial Sector may also
designate a business labeled as “industrial” by the North American Industry Classification
System or by the energy provider on the basis of energy demand or annual usage exceeding
some specified limit set by the energy provider. See Commercial and Industrial sector.
Internet: The worldwide, publicly accessible series of interconnected computer networks
that transmit data by packet switching using the standard Internet Protocol.
Interruptible Load: Electric consumption subject to curtailment or interruption under tariffs
or contracts that provide a rate discount or bill credit for agreeing to reduce load during
system contingencies. In some instances, the demand reduction may be effected by action of
the System Operator (remote tripping) after notice to the customer in accordance with
contractual provisions.
Interval: The period of time for which advanced meters measure energy usage (and possibly
other data). Increments are typically in minutes, and may consist of five-minute intervals, 15minute 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.
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Investor-Owned Electric Utility: A privately-owned electric utility whose stock is publicly
traded. It is rate regulated and authorized to achieve an allowed rate of return.
Joint Action Agency: A body consisting of utility companies, municipalities who own
public utilities, and/or municipalities who purchase energy from private utilities, which acts
as a committee for making decisions regarding the acquisition and delivery of energy
resources or related services.
Load as a Capacity Resource: Demand-side resources that commit to make pre-specified
load reductions when system contingencies arise.
Load Serving Entity: Entities that provide electric service to end-users, wholesale
customers, or both.
Mandatory Participation: Participation in the demand response program is required based
on the customer’s size or rate class. Customers are not offered the option of refusing to
respond to requests for load reduction.
Maximum Demand: The highest level of demand in MWs as tracked by an entity, such as
an hourly demand, 30-minute demand, 15-minute demand or 5-minute demand.
Maximum Demand of Customers: The highest level of total demand, in MW, for
customers participating in a demand response program, excluding any demand reduction that
results from the program. The maximum non-coincident demand of the participating
customers that would occur without the program.
Maximum Duration of Event: A specified maximum length of time a particular demand
response event will continue, usually defined by 30-minute or hourly increments.
Megawatt (MW): One thousand kilowatts or one million watts of electric power.
Megawatt-hour (MWh): One thousand kilowatt-hours or one million watt-hours of electric
energy.
Member Company: Member of a joint action agency or generation and transmission
company that supplies wholesale electricity and energy services.
Minimum Payment Rate: The smallest amount of money, in dollars per megawatt-hour,
that a program sponsor will pay a demand response program participant for reduced energy
consumption.
Minimum Reduction: A level established by the demand response program sponsor as the
least amount of demand reduction, in megawatts, a participant must achieve during a demand
response event to be considered as participating in that event or to qualify for the demand
response program.
Minimum Term: The shortest period of time that customers are obligated to participate in a
demand response program.
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Municipality: A village, town, city, county, or other political subdivision of a state.
NERC Regional Entity: One of the eight groups listed below (formerly known as Reliability
Councils) organized within the major interconnections in the North American bulk power
system. They work with the North American Electric Reliability Corporation to improve the
reliability of the bulk power system. Florida Reliability Coordinating Council (FRCC),
Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC),
ReliabilityFirst Corporation (RFC), SERC Reliability Corporation (SERC), Southwest Power
Pool RE (SPP), Texas Regional Entity (TRE), Western Electricity Coordinating Council
(WECC). The states of Alaska and Hawaii are not within a NERC Regional Entity, but for
purposes of this survey appear as a choice in NERC Regional Entity fields.
Non-Spinning Reserves: Demand-side resource that may not be immediately available, but
may provide solutions for energy supply and demand imbalance after a delay of ten minutes
or more.
Opt-In: A Time-Based Rate/Tariff or demand response program in which a customer will be
enrolled only if the customer chooses to enroll.
Opt-Out: A Time-Based Rate/Tariff or demand response program in which a customer will
be enrolled unless the customer chooses not to enroll; a program that is the default for a class
of customers but that allows individual customers to choose an alternative rate/tariff or
program.
Other (as shown in Q3, Q5 & Q6): Customers who are in a customer class that is not listed.
Other
Demand
Response
Program/Tariff:
A
company
or
utility's
service/product/compilation of all effective rate schedules, general terms and conditions and
standard forms related to demand response/AMI services for customers that are not
Residential, Commercial and Industrial, or Other.
Peak Time Rebate: Peak time rebates allow customers to earn a rebate by reducing energy
use from a baseline during a specified number of hours on critical peak days. Like Critical
Peak Pricing, the number of critical peak days is usually capped for a calendar year and is
linked to conditions such as system reliability concerns or very high supply prices.
Penalties: Fines or reductions in payments that result when a demand response program
participant fails to meet targeted reductions in power demand or chooses to not reduce
consumption during a demand response event.
Potential Peak Reduction: The sum of the load reduction capabilities (measured in
megawatts) of the demand response program participants, within the specified customer
sector, whether reductions are made through the direct control of the utility system operator
or by the participant in response to price signals or a utility request to curtail load. It reflects
the demand reduction capability, as opposed to the actual peak reduction achieved by
participants.
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Power Marketers: Business entities, including energy service providers, which are engaged
in buying and selling electricity, but which do not necessarily own generating or transmission
facilities. Power marketers and energy service providers take ownership (title) of the
electricity, unlike power brokers, who do not take title to electricity. Power marketers are
involved in interstate commerce and must file with the FERC for authority to make
wholesale sales. Energy service providers will not file with the FERC but may file with the
states if they undertake only retail transactions.
Program Type: The category of demand response arrangements between retail or wholesale
entities and their retail or wholesale customers. Examples of these arrangements include:
critical peak pricing, critical peak pricing with load control, direct load control, interruptible
load, load as a capacity resource, regulation, non-spinning reserves, spinning reserves,
demand bidding and buy-back, time of use pricing, real-time pricing, system peak response
transmission tariff, peak time rebate, and emergency demand response, all of which are
defined in this glossary.
Program End Date: A date specified when the demand response and/or time-based rate
program is no longer in effect.
Program Start Date: A date specified when a demand response and/or time-based rate
program began.
Public Utility District: Municipal corporations organized to provide electric service to both
incorporated cities and towns and unincorporated rural areas.
Publicly Owned Electric Utility: Utilities operated by municipalities, political subdivisions,
and state and federal power agencies (such as the Bonneville Power Administration and the
Tennessee Valley Authority).
Realized Demand Reduction: The largest hourly demand reduction (in megawatts) that
occurred when the demand response program was called, or that was attributable to the
demand response program, during the 2011 calendar year.
Real Time Meters: Meters that measure energy as used, with built-in two-way
communication capable of recording and transmitting instantaneous data.
Real Time Pricing: Rate and price structure in which the retail price for electricity typically
fluctuates hourly or more often, to reflect changes in the wholesale price of electricity on
either a day-ahead or hour-ahead basis.
Regulation Service: A type of Demand Response service in which a Demand Resource
increases and decreases load in response to real-time signals from the system operator.
Demand Resources providing Regulation Service are subject to dispatch continuously during
a commitment period. This service is usually responsive to Automatic Generation Control
(AGC) to provide normal regulating margin. Also known as regulation or regulating reserves,
up-regulation and down-regulation.

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Reliability: A measure of the ability of the electric system to withstand sudden disturbances
such as electric short circuits or unanticipated loss of system components.
Reliability Event: An event, such as the loss of a line or generator, or imbalance between
supply and demand, which threatens the safe operation of the grid.
Reserve: A service in which demand resources are obligated to be available to provide
demand reduction upon deployment by the system operator, based on reserve capacity
requirements that are established to meet reliability standards.
Residential: The energy-consuming sector consisting of private households. Common uses
of energy associated with this sector include space heating, water heating, air conditioning,
lighting, refrigeration, cooking, and running a variety of other electric-powered devices. The
residential sector excludes institutional living quarters. This sector excludes deliveries or
sales to master-metered apartment buildings or homes on military bases (these buildings or
homes are included in the commercial sector).
Response Time: The maximum time allowed in a demand response program for a program
participant to react to the program sponsor’s notification, in hours.
Retail: Sales covering electrical energy supplied for residential, commercial, industrial, and
other (e.g., agricultural) end-use purposes. Electricity supplied at retail cannot be offered for
resale.
Retail Customer: A purchaser of energy that consumes electricity for residential,
commercial, or industrial use, or a variety of other end-uses.
Retail Electric Customer: See Retail Customer.
Rural Electric Cooperative: A member-owned electric utility company serving retail
electricity customers. Electric cooperatives may be engaged in the generation, wholesale
purchasing, transmission, and/or distribution of electric power to serve the demands of their
members on a not-for-profit basis.
Specific Event Limits: The maximum number of times that a participant in a demand
response program may be called to reduce energy consumption during a year.
Spinning/Responsive Reserves: Demand-side resource that is synchronized and ready to
provide solutions for energy supply and demand imbalance within the first few minutes of an
Emergency Event.
System Peak Response Transmission Tariff: The terms, conditions, and rates and/or prices
for customers with interval meters who reduce load during peaks as a way of reducing
transmission charges.
Tariff: A published volume of all effective rate schedules, terms and conditions under which
a product or service will be supplied to customers.

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Time-Based Rate/Tariff: A retail rate or Tariff in which customers are charged different
prices for using electricity at different times during the day. Examples are time-of-use rates,
real time pricing, hourly pricing, and critical peak pricing. Time-based rates do not include
seasonal rates, inverted block, or declining block rates.
Time-of-Use: A rate where usage unit prices vary by time period, and where the time periods
are typically longer than one hour within a 24-hour day. Time-of-use rates reflect the average
cost of generating and delivering power during those time periods.
Transportation: An energy consuming sector that consists of electricity supplied and
services rendered to railroads and inter-urban and street railways, for general railroad use
including the propulsion of cars or locomotives, where such electricity is supplied under
separate and distinct rate schedules. In this survey, transportation customers should be
counted in the Other category.
Transportation Program/Tariff: A company or utility's service/product/compilation of all
effective rate schedules, general terms and conditions and standard forms related to demand
response/AMI services for transportation customers.
Type of Entity: The category of organization that best represents the energy market
participant. The available options include: investor-owned utility, municipal utility,
cooperative utility, state-owned utility, federally-owned utility, independent system operator,
retail power marketer, wholesale power marketer, regional transmission operator, curtailment
service provider, transmission, or other.
Voluntary: Customers have the option of participating or not participating. This would
include opt-out programs where customers are automatically enrolled but are allowed to
discontinue their participation.
Wholesale: Pertaining to a sale of electric energy for resale.
Wholesale Customer: An entity that purchases electric energy for resale.

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 71

72 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

APPENDIX D: 2012 FERC SURVEY METHOD
Background
The Energy Policy Act of 2005 (EPAct 2005) requires that the Federal Energy Regulatory
Commission prepare and publish an annual report, by appropriate region, that assesses
electricity demand response resources. Commission staff determined that a survey of a full
set of private and public entities that provide electric power and could provide demand
response to customers would help fulfill the requirement.
In the first half of 2012 Commission staff:
 Identified survey respondents, i.e., the “survey population;” and
 Developed a voluntary survey based on a PDF vehicle.
Beginning in February of 2012 Z, INC. and their subcontractor DNV KEMA
 Developed a sampling design based on the 2010 FERC Demand Response and
Advanced Metering Survey;
 Revised a custom survey processing system in Microsoft Access to interface with the
FERC provided PDF Survey;
 Reviewed the list of survey respondents and removed companies who are out
business or do are not appropriate recipients of the survey150;
 Distributed the 2012 FERC Survey, collected the data, and followed-up with
respondents where necessary; and
 Conducted data analysis of the survey responses.
Responses to the survey were originally requested from all 3,349 entities from all 50 states
representing all aspects of the electricity delivery industry: investor-owned utilities,
municipally owned utilities, wholesale and retail power marketers, state and federal agencies,
and (rural electric) cooperatives. The 2012 FERC Survey respondent list was based on the
list of entities that the Energy Information Administration (EIA) uses for their Form EIA-861
Survey Form. The FERC staff added three categories of respondents to the base set of EIA
contacts – Regional Transmission Organizations (RTOs)/Independent System Operators
(ISOs), curtailment service providers, and transmission companies.
During the survey processing period it was determined fifteen entities were no longer in
operation or should not have received the survey. These entities were removed from the
survey respondent list, resulting in a list of 3,334 active respondents. Out of this active
group, 1,978 entities responded to the 2012 FERC Survey (a response rate of 59.3 percent),
an increase from the 2010 FERC Survey response rate of 52 percent.

Development of the FERC Survey and Sampling Design
The 2012 FERC Survey was conducted subject to the same Office of Management and
Budget (OMB) authorization that was provided to the Commission for similar surveys

150

A surveyed company may have been acquired by another company, for example.

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 73

previously. The 2010 authorization of March 31, 2013 was used.151 As was done in the
previous three surveys, Commission staff fielded the survey on a voluntary rather than a
mandatory basis. Commission staff designed the survey to collect the needed information
using nine questions organized in three sections. The three sections include one parent
section containing questions one through seven and two child sections covering retail and
wholesale demand response programs:
Parent record (only one record per Utility)
Question 1: Company and contact information including utility ID, company name and
ownership type. Primary contact information along with their supervisor’s
information.
Question 2:

Advanced and total meter counts by State and customer class

Question 3:

Number of retail customers and meters by NERC region and customer class.
(optional, skip if there are demand response programs)

Question 4:

Number of retail customers that can access the amount and frequency of their
electricity use by method and by customer sector.

Question 5:

Plans for demand response programs over next 5 years by number of
programs and potential peak reduction.

Question 6:

NERC regions and states in which you operate

Question 7:
6,

Number of retail customers for each NERC and State combination in Question
by customer class.

Child 1 Record (Add additional pages as needed)
Question 8:

Detailed retail demand response program information by NERC region, State,
Customer class, and Program type.

Child 2 Record (Add additional pages as needed)
Question 9:

Detailed wholesale demand response program information by NERC region,
State, and Program type.

By shifting the detailed Demand Response program information to the end of the survey, the
burden on small utilities without demand response programs was lessened because they were
only asked to complete Questions 1 through 3. Also, by having all the information relative to
one demand response program on one page (Child record), respondents could as many pages
as required to cover each of their programs. The content of the 2012 FERC Survey mirrored

151

Links to the 2012 FERC Survey documents can be found at http://www.ferc.gov/industries/electric/indusact/demand-response/2012/survey.asp.
74 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

the 2010 FERC Survey collected. The structure of the survey was duplicative of the 2010
survey.

The Survey Population
To analyze the survey data and calculate statistics for this report, Commission staff reviewed
the composition of the survey population, and found that there were 3,349 organizations as
listed in Table D-1.
The region definition used in the FERC Survey was based on that used by the North
American Electric Reliability Corporation (NERC). Using NERC regions allows collection
of data based on how energy is traded and managed. It provides the most useful regional
grouping for the consideration of demand response resources and advanced metering
deployment that would potentially reduce barriers for participation in demand response and
time-based rate programs and/or tariffs.

Table D-1. Survey Population for the 2012 FERC Survey
Group Name
Municipally Owned Utility
Cooperatively Owned Utility
Investor-Owned Utility
Retail Power Marketer
Wholesale Power Marketer
Political Subdivision
Municipal Power Agency
Federal and State
Regional Transmission Organization/
Independent System Operator
Curtailment Service Provider
Transmission
Total Classified
Unclassified
Active Total

2012 N0.
1,834
874
194
135
42
127
19
35

2010 No.
1,840
878
207
128
46
127
21
29

7
11
9
3,287
47
3,334

7
11
7
3,301
57
3358

Inactive (removed from survey population) 15
Grand Total
3,349

96
3,454

FERC Survey Methodology
On March 23, 2012, the survey was distributed through a mass e-mailing. This message
included an introduction to the survey as well as directions and the glossary (see Appendix
C). The survey itself was attached to the e-mail. The survey form was in PDF format,
programmed such that the respondents could respond directly on the PDF form. They then
would e-mail their surveys to a main collecting point, an e-mail account set up specifically
for the collection of the surveys. For any inquiries or questions the respondents might have,
they could reach out to the FERC staff for help at [email protected] and [email protected].

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 75

Z, INC., in collaboration with the FERC staff, strove to maximize the response rate through
various means. If respondents required specific information, a phone hotline was
established, open daily between 9 am and 6 pm. FERC staff also initiated its own
dissemination of the survey through postal mail, to capture any respondents that might not
have internet access or a functional e-mail account. Additionally, Z, INC assisted in the
sending out of a reminder e-mail to all those who had not responded as of April 25, 2012. Z,
INC. also contacted all companies that were statistically significant (i.e., large companies and
those selected for the sample), as well as all medium-sized companies, reaching more than
1,200 companies individually. Finally, FERC Chairman Jon Wellinghoff sent out a letter to
all cooperating organizations, including members and representatives of the National
Association of Regulatory Commissioners, American Public Power Association, Edison
Electric Institute, and the National Rural Electric Cooperative Association, asking them to
reach out to members and the industry to encourage submission of the survey.
As responses were returned to us, Z, INC. employed a rigorous system of verification and
due diligence. Beyond the software used to collect the submissions to the e-mail account
established by the FERC staff, Z, INC. also searched through the e-mail account looking for
attachments that had not been included in the data upload or other related problems.
Anomalies and seemingly incorrect information received a flag, indicating the necessity for
personal follow-up.
Continuous efforts were also made to ensure the optimal structure and processing of the
incoming data. Z, INC. created a specialized database for the 2010 FERC-731 Survey. This
database included all available information for on each entity in the survey population, This
data base allowed for a more efficient process overall, reducing the labor involved with
cleaning data.

Working with the Data
As discussed in Chapters 2 and 3, the FERC staff used the 2012 FERC Survey to estimate
advanced metering penetration rate and potential peak reduction. The following discussion
describes the analysis undertaken by the FERC staff and Z, Inc.’s subcontractor DNV
KEMA, who was responsible for the analysis.

Advanced Metering
The FERC staff developed estimates of the penetration rate of national and regional
advanced metering required by Congress at the national, regional, and state levels, as well as
by load serving entity type. These estimates were to reflect the full universe of entities in the
United States that own electricity meters for retail. The FERC Survey population
encompasses all such entities. As such, the primary data source of the estimates produced is
the set of respondent data from the 2012 FERC Survey. Some entities in the FERC Survey
did not respond, requiring statistical estimation of advanced metering penetration in their
retail service territories so that the estimates account for the whole survey population.
The approach taken by DNV KEMA was to make statistically informed imputations of the
number of customers, advanced meters, and total meters for non-responding entities
leveraging related published information from the 2011 preliminary Form EIA-861 Survey
76 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

and FERC Survey. The Form EIA-861 Survey file 2 contains customer counts at the entity
level by customer class, which is highly correlated with total meter counts, a FERC Survey
item. Other FERC Survey items – customer counts and advanced meters – have direct
counterparts in the Form EIA-861 Survey. For the “other” customer class (i.e., retail
customers not classified as residential, commercial, or industrial), there is not a comparable
field in the Form EIA-861 Survey from which to link to the 2012 FERC Survey. For this
customer class balance group, the 2010 FERC Survey was used as the source of missing
data.152
When an entity did not respond to the 2012 FERC Survey at all, or responded but did not
provide a valid entry for the number of advanced meters for a customer class, DNV KEMA
used direct substitution of an entity’s advanced meters by sector from the reported value by
that entity in the 2011 Form EIA-861 Survey. Having the 2011 Form EIA-861 Survey
preliminary database available for comparison was valuable because both surveys collected
2011 summary information. If the sector-level advanced meter count for an entity was not
available in the preliminary 2011 Form EIA-861 Survey database made available to DNV
KEMA for this analysis, the imputation methodology from the 2010 FERC Survey analysis
was used, with updated databases supporting it.
Having access to the preliminary 2011 Form EIA-861 Survey database was valuable also
because it contains fields for both advanced and AMR meters. DNV KEMA developed an
editing procedure to identify instances where it appeared likely that the respondent was
misreporting AMR meters as advanced meters in the 2012 FERC Survey.
The logic used in the editing procedure started with computing the percent difference in
advanced meters between the 2012 FERC Survey and the 2011 Form EIA-861 Survey and
the percent difference between the meters in the 2012 FERC Survey advanced metering and
the Form EIA-861 Survey AMR meter count. If an entity did not provide an advanced meter
count on the Form EIA-861 Survey but did provide a count for AMR meters, and the AMR
meter count was within 50 percent of the reported advanced meter count on the 2012 FERC
Survey, DNV KEMA edited the advanced metering value. The 2012 FERC survey was set
to zero since the entity likely misreported an AMR meter count which does not meet the
FERC definition of advanced metering.
If the entity reported meter counts for both AMI and AMR on the Form EIA-861 Survey, and
the 2012 FERC Survey advanced meter count was found to be significantly closer to the sum
of the AMR and AMI meter totals than just the AMI meters on the Form EIA-861, the
determination was that the respondent likely included both AMI and AMR meters on the
2012 FERC Survey, when it should have only included AMI meters. In these instances, the
Form EIA-861 total AMI meters were used in the analysis.

Demand Response
The FERC Survey responses were extrapolated to estimate the demand response for the
entire FERC Survey population by imputing survey answers for nonrespondents using an
152

A secondary data source field that is used directly or following a statistical modification, in place of a
missing value on the FERC Survey, is referred to as a “donor variable”.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 77

imputation method that limits the bias introduced. The DNV KEMA approach for
imputation utilized direct substitution of responses by the entity for comparable survey items
(same survey year and identical or nearly identical wording and/or response categorization)
from related surveys when such responses are available. When direct substitution was not
available, responses from identical or closely related questions of past survey years were
utilized, with a class-level growth rate multiplier applied. Classes were defined according to
customer sector and size exactly as is documented in the 2010 report.
For potential peak reduction, the imputation process below was implemented for the tables
supporting figures 4.12 and 4.13, which give estimated potential MW by entity type, NERC
region, and customer sector.
If an entity did not provide potential peak reduction in the 2012 FERC Survey, data on
potential peak reduction from the 2011 Form EIA-861 was used. However, since the Form
EIA-861 data only contains potential peak reduction at the entity/sector level, but not by state
or demand response program type, imputations were made at this entity/sector level, not at
the state or program type level. If there was no response for potential peak reduction in the
2012 FERC survey response and an imputation was made with the EIA data, the potential
peak reduction value was assigned to the entity’s primary NERC region.
If an entity did not provide potential peak reduction either the 2012 FERC Survey or the
2011 Form EIA-861, but provided a response to the 2010 Form EIA-861 for this item, it was
multiplied by a the class-level growth rate between 2010 and 2011 and used as the imputed
value. If the customer sector for the demand response program was listed as “Other”, and the
entity did not provide potential peak reduction in the 2012 FERC Survey, the 2010 FERC
Survey response value multiplied by a class-level growth rate factor was used as the imputed
value. No imputation was used for wholesale potential peak reduction.

Eliminating Double-Counting in Wholesale Demand Response
The methodology used for tabulating wholesale potential peak reduction was designed to
identify and separate potential peak reduction that is solely wholesale in nature and is not
associated with any programs offered by retail entities (such as an investor-owned utility). If
a retail entity reported that 50 MW of potential peak reduction was enrolled in an ISO or
RTO wholesale market demand response program, the 50 MW may have also been included
in the ISO or RTO’s survey response. The 50 MW could be counted as both retail demand
response, since it was reported by a retail entity in Q8, and as wholesale demand response,
since it was reported by the ISO or RTO in its Q9 submission for wholesale entities. The 50
MW should be counted only once as either retail or wholesale. The FERC staff decision rule
for this and each prior survey has been to count it as retail demand response.
To accomplish this, DNV KEMA merged the enrolled potential demand response reported by
retail entities in Q8 with the Q9 reports by wholesale entities as negative values of the same
magnitude. In principle, the tabulation of the combined values would give the final
wholesale potential demand response. This, however, does not work because ISO/RTOs
classify their demand response programs by purpose, such as load as a capacity resource or
emergency demand response, while retail entities generally classify programs according to
78 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

the mechanism employed for reducing load, such as an air conditioner or water heater direct
load control program, or according to the contract agreement with a large commercial or
industrial customer. To align the programs to reduce double counting, DNV KEMA
reclassified the program type listed for retail entities to match the program type listed by the
ISO or RTO market program that the retail program was enrolled in. Note that the retail
program types were only recategorized in this step for the enrolled potential demand
response for the purpose of eliminating double counting. The entity’s response for potential
peak reduction by sector was according to the original program type in their response.

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 79

80 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

APPENDIX E: FERC SURVEY RESPONDENTS
Appendix E lists the entities that responded to the 2012 FERC Survey, organized by entity type.

Cooperatively Owned Utility
4-County Electric Power Assn
A & N Electric Cooperative
Adams Electric Cooperative
Adams Electric Cooperative, Inc.
Adams Rural Electric Cooperative, Inc.
Adams-Columbia Electric Cooperative
Alaska Village Elec. Coop. Inc.
Albemarle Electric Member Corp.
Alder Mutual Light Co., Inc.
Alger-Delta Cooperative Electric Association
Allamakee- Clayton El Coop, Inc
Allegheny Electric Cooperative, Inc.
Amicalola Electric Membership Corp
Anza Electric Cooperative, Inc.
Appalachian Electric Cooperative
Arizona Electric Power Cooperative, Inc.
Arkansas Electric Cooperative Corporation
Arkansas Valley Electric Cooperative Corporation
Ashley-Chicot Electric Cooperative, Incorporated
Atchison-Holt Electric Coop
Bailey County Electric Cooperative
BARC Electric Coop Inc
Barron Electric Coop
Barrow Utilities & Electric Coop., Inc.
Barry Electric Cooperative
Bartlett Electric Cooperative Inc
Basin Electric Power Coop
Bayfield Electric Cooperative
Bedford Rural Elec Coop, Inc
Beltrami Electric Cooperative, Inc
Benton Rural Electric Association
Big Bend Electric Cooperative, Inc
Big Country Electric Cooperative, Inc.
Big Flat Electric Co-op., Inc.
Big Horn County Elec Coop, Inc
Big River Electric Coop
Black Hills Electric Cooperative, Inc
Black River Electric Cooperative
Blue Grass Energy Cooperative Corporation
Blue Ridge Electric Coop Inc - (SC)
Blue Ridge Mountain EMC - (GA)
Bluebonnet Electric Cooperative Inc.
Bon Homme Yankton Electric Association, Inc.
Boone Valley Electric Coop
Brazos Electric Power Cooperative, Inc.
Broad River Electric Cooperative, Inc.
Brunswick Electric Membership Corporation
Buckeye Power, Inc.
Buckeye Rural Electric Cooperative, Inc.
Butler County Rural Elec Coop - (IA)
Butler Rural Electric Cooperative Association, Inc.
Butler Rural Electric Cooperative, Inc.
Butte Electric Cooperative
C&L Electric Cooperative Corporation
Caddo Electric Cooperative, Inc.

MS
MD,VA
IL
PA
OH
WI
AK
NC
WA
MI
IA
PA
GA
CA
TN
AZ
AR
AR,OK
AR
IA,MO
TX
VA
WI
AK
MO
TX
ND
WI
PA
MN
WA
WA
TX
MT
MT
KY
SD
MO
KY
SC
GA
TX
SD
IA
TX
NC,SC
NC
OH
OH
IA
KS
OH
SD
AR
OK

2012 Assessment of Demand Response and Advanced Metering

Calhoun County Electric Cooperative Association
Cam Wal Electric Cooperative, Inc
Canadian Valley Electric Cooperative
Caney Fork Electric Cooperative, Inc.
Capital Electric Cooperative, Inc.
Carbon Power & Light Inc
Carroll County REMC
Carroll Electric Cooperative Corporation
Carroll Electric Cooperative, Inc
Carroll Electric Membership Corporation
Carteret-Craven Electric Membership Corporation
Cass County Electric Cooperative
Cass Electric Cooperative
Cavalier Rural Electric Coop, Inc.
Central Alabama Electric Cooperative
Central Electric Cooperative
Central Electric Cooperative, Inc.
Central Electric Power Cooperative
Central Electric Power Cooperative, Inc.
Central Georgia Electric Membership Corp.
Central Iowa Power Cooperative
Central Valley Electric Coop., Inc.
Charles Mix Electric
Cherryland Electric Coop Inc
Chippewa Valley Electric Coop
Choctawhatchee Electric Cooperative, Inc.
Clark County REMC
Clark Electric Coop
Claverack REC
Clay County Electric Cooperative Corporation
Clay Electric Cooperative, Inc.
Clay-Union Electric Corporation
Clearwater Power Company
Clearwater-Polk Electric Cooperative, Inc.
Cloverland Electric Cooperative
Coahoma electric Power Association
Coastal Electric Cooperative
Codington-Clark Electric Cooperative, Inc.
Coles-Moultrie Electric Cooperative
Colquitt Electric Membership Corporation
Columbia Power Cooperative Association
Concordia Electric Cooperative, Inc.
Connexus Energy
Consolidated Electric Cooperative
Consumers Energy
Consumers Power Inc.
Cookson Hills Electric Cooperative
Cooperative Light and Power
Coosa Valley Electric Cooperative
Coos-Curry Electric Cooperative, Inc.
Cordva Electric Cooperative, Inc.
Corn Belt Energy Corporation
Corn Belt Power Cooperative
Craig-Botetourt Electric Cooperative
Craighead Electric Cooperative Corporation
Crow Wing Cooperative Power & Light Company
Cumberland Electric Membership Corporation
Dairyland Power Cooperative

IA
SD
OK
TN
ND
WY
IN
AR,MO
OH
GA
NC
ND
IA
ND
AL
SD
PA
MO
SC
GA
IA
NM
SD
MI
WI
FL
IN
WI
PA
AR
FL
SD
ID,OR,WA
MN
MI
MS
GA
SD
IL
GA
OR
LA
MN
MO
IA
OR
OK
MN
AL
OR
AK
IL
IA
VA,WV
AR
MN
TN
IA,MN,WI

Federal Energy Regulatory Commission

81

Cooperatively Owned Utility (Continued)
Dakota Electric Association
Darke Rural Electric Coop, Inc
Deep East Texas Electric Coop Inc
Delaware Electric Cooperative, Inc.
Dixie Electric Cooperative
Dixie Electric Membership Corporation
Dixie Electric Power Association
Dixie Escalante REA Inc.
Doniphan Elec Coop Assn, Inc
Douglas Electric Cooperative, Inc
Douglas Electric Cooperative, Inc.
Dubois Rural Electric Cooperative, Inc.
Duck River Electric Membership Corporation
Dunn County Electric Cooperative
East End Mutual Elec Co Ltd
East River Electric Power Cooperative, Inc.
East-Central Iowa Rural Electric Cooperative
Eastern Maine Electric Cooperative, Inc
Eau Claire Electric Coop
Edgecombe-Martin County Electric Membership Corp.
Edisto Electric, Cooperative, Inc.
Egyptian Electric Cooperative Association
Empire Electric Association, Inc.
Energy United Electric Membership Corp
Excelsior Electric Membership Corporation
Fairfield Electric Cooperative Inc.
Farmers Electric
Farmers Electric Cooperative
Farmers Electric Cooperative Corporation
Farmers Electric Cooperative, Inc
Farmers' Electric Cooperative, Inc.
Farmers' Electric Cooperative, Inc.
Federated Rural Electric
Fergus Electric Cooperative, Inc.
First Electric Cooperative Corporation
Flathead Electric Cooperative, Inc.
Flint Electric Membership Corporation
Florida Keys Electric Cooperative
Four County EMC
Fox Islands Electric Cooperative, Inc.
Franklin Electric Cooperative
Franklin Rural Electric Cooperative- (IA)
Freeborn-Mower Coop Services
French Broad Electric Membership Corporation
Fulton County REMC
Gascosage Electric Cooperative
Gibson Electric Membership Corporation
Golden Spread Electric Cooperative, Inc.
Goldenwest Electric Cooperative, Inc.
Graham County Electric Cooperative, Inc
Grundy County Rural Electric Coop
Grundy Electric Cooperative, Inc.
Guernsey-Muskingum Electric Cooperative, Inc.
Habersham Electric Membership Corporation
Halifax Electric Membership Corporation
Hart Electric Membership Corporation
Hawkeye Tri-County El Coop Inc
Haywood Electric membership Corp.

82 Federal Energy Regulatory Commission

MN
OH
TX
DE
AL
LA
MS
AZ,UT
KS
OR
SD
IN
TN
WI
ID
SD
IA
ME
WI
NC
SC
IL
CO
NC
GA
SC
ID
TX
AR
IA
MO
NM
IA,MN
MT
AR
MT
GA
FL
NC
ME
AL
IA
MN
NC,TN
IN
MO
TN
TX
MT,ND
AZ
IA
MO
OH
GA
NC,VA
GA
IA
GA,NC,SC

H-D Electric Cooperative, Inc
Heart of Texas Electric Cooperative, Inc.
Heartland Power Coop
Heartland Rural Electric Cooperative Inc
Hendricks County Rural Electric Membership
Henry County REMC
High Plains Power, Inc.
Highline Electric Association
HILCO Electric Cooperative, Inc.
Hill County Electric Cooperative, Inc.
Holmes-Wayne Electric Cooperative, Inc.
Holy Cross Electric Assn, Inc
Hood River Electric Cooperative
Houston County Electric Cooperative, Inc.
Humboldt County R E C
Idaho County Light & Power Cooperative Assoc., Inc.
Illinois Rural Electric Cooperative
Indian Electric Cooperative, Inc.
Inter-County Energy Cooperative
Intercounty Electric Cooperative Assn.
Iowa Lakes Electric Coop
Irwin Electric Membership Corp
Itasca-Mantrap Cooperative Electrical Association
J-A-C Electric Cooperative Inc
Jackson County Rural electric Membership Corporation
Jackson Electric Cooperative
Jackson Electric Membership Corporation
Jackson Energy Cooperative Corp - (KY)
Jackson Purchase Energy Corporation
Jasper County REMC
Jasper-Newton Electric Cooperative
Jefferson Energy Cooperative
Jemez Mountains Electric Cooperative, Inc.
Jo-Carroll Energy, Inc. (NFP)
Jones-Onslow Electric Membership Corporation
Jump River Electric Cooperative, Inc.
KAMO Electric Cooperative, Inc
Kankakee Valley Rural Electric Membership Corp
Kansas Electric Power Cooperative, Inc.
Kauai Island Utility Cooperative
KC Electric Association, Inc.
KEM Electric Cooperative, Inc.
Kingsbury Electric Cooperative, Inc.
Kodiak Electric Association, Inc.
Kosciusko REMC
La Plata Electric Assn. Inc.
Laclede Electric Cooperative
Lacreek Electric Association, Inc.
Lagrange County Rural E M C
Lake Country Power
Lake Region Electric Cooperative
Lamb County Electric Cooperative
Lane Electric Cooperative Inc
Lee County Electric Cooperative, Incorporated
Lewis County Rural Electric Coop Association
Licking Valley RECC
Lincoln Electric Cooperative
Linn County Rural Electric Cooperative Association

2012 Assessment of Demand Response and Advanced Metering

MN,SD
TX
IA
KS
IN
IN
WY
CO,NE
TX
MT
OH
CO
OR
TX
IA
ID
IL
OK
KY
MO
IA
GA
MN
TX
IN
WI
GA
KY
KY
IN
TX
GA
NM
IL
NC
WI
OK
IN
KS
HI
CO
ND
SD
AK
IN
CO
MO
NE,SD
IN
MN
MN
TX
OR
FL
MO
KY
MT
IA

Cooperatively Owned Utility (Continued)
Los Alamos County
Lower Yellowstone REA Inc.,
Lumbee River Electric Membership Corporation
Lynches River Electric Cooperative, Inc.
Lyntegar Electric Cooperative, Inc.
Lyon-Coffey Electric Cooperative, Inc.
M & A Electric Power Cooperative
M.J.M. Electric Cooperative, Inc.
Magic Valley Electric Cooperative, Inc.
Maquoketa Valley Rural Electric Cooperative
Marshall County REMC
McCone Electric Co-op., Inc.
McDonough Power Cooperative
McKenzie Electric Cooperative, Inc.
McLean Electric Coop
McLeod Cooperative Power Association
Meade County RECC
Mecklenburg Electric Cooperative
Menard Electric Cooperative
Middle Kuskokwim Electric Cooperative, Inc
Midland Power Coop
Mid-Ohio Energy Cooperative, Inc.
Mid-South Electric Cooperative
Midwest Electric, Inc.
Midwest Energy Cooperative
Midwest Energy, Inc.
Minnesota Valley Electric Cooperative
Minnkota Power Cooperative, Inc.
Mississippi County Electric Cooperative, Inc.
Missouri Rural Electric Cooperative
Modern Electric Water Company
Monroe County Electric Co-Operative, Inc.
Moreau-Grand Electric Cooperative, Inc.
Mountain Parks Electric, Inc.
Mountain View Electric Association, Inc.
Navasota Valley Electric Cooperative
Navopache Electric Cooperative, Inc.
Nemaha-Marshall Electric Cooperative Association, Inc
New-Mac Electric Cooperative, Inc.
NineStar Connect
Niobrara Electric Association
Noble County REMC
Nobles Cooperative Electric
Nodak Electric Coop Inc
Nolin Rural Electric Cooperative Corporation
North Alabama Electric Cooperative
North Arkansas Electric Cooperative, Incorporated
North Carolina Electric Membership Corp
North Central Electric Coop
North East Mississippi E P A
North Georgia Electric Membership Corporation
North Plains Electric Coop Inc
North Star Electric Cooperative, Inc.
North Western Electric Cooperative, Inc.
Northeast Oklahoma Electric Cooperative
Northeastern REMC
Northern Lights, Inc.
Northern Neck Electric Cooperative

NM
MT,ND
NC
SC
TX
KS
MO
IL
TX
IA
IN
MT
IL
ND
ND
MN
KY
NC,VA
IL
AK
IA
OH
TX
OH
IN,MI,OH
KS
MN
ND
AR
MO
WA
IL
SD
CO
CO
TX
AZ,NM
KS
MO
IN
NE,SD,WY
IN
MN
ND
KY
AL
AR
NC
ND
MS
GA
TX
MN
OH
OK
IN
ID,MT,WA
VA

2012 Assessment of Demand Response and Advanced Metering

Northern Virginia Electric Cooperative
Northwestern Electric Cooperative, Inc.
Northwestern REC
NorVal Electric Cooperative
Nueces Electric Cooperative
Oahe Electric Cooperative Inc.
Oakdale Electric Coop
Ocmulgee Electric Membership Corporation
Oglethorpe Power Corporation
Okanogan County Electric Cooperative Inc
Okefenoke Rural El Member Corp
Oklahoma Electric Cooperative
Osceola Electric Cooperative, Inc.
Otero County Electric Cooperative, Inc.
Ouachita Electric Cooperative Corporation
Ozark Border Electric Cooperative
Ozark Electric Cooperative, Inc.
Ozarks Electric Cooperative Corporation
Panola-Harrison Electric Cooperative, Inc.
Parke County Rural E M C
Peace River Electric Cooperative, Inc.
Pearl River Valley Electric Power Association
Pee Dee Electric Membership Corp.
Peninsula Light Company
Pennyrile Rural Electric Coop
People's Cooperative Services
People's Electric Cooperative
Petit Jean Electric Cooperative Corporation
Pickwick Electric Cooperative
Piedmont Electric Membership Corporation
Pierce-Pepin Coop Services
Pioneer Electric Cooperative, Inc.
Pitt and Greene Electric Membership Corporation
PKM Electric Coop, Inc
Planters Electric Membership Corporation
Polk-Burnett Electric Coop
Poudre Valley Rural Electric Association, Inc.
Powder River Energy Corporation
Prairie Energy Coop
Prentiss County Electric Power Association
Price Electric Coop Inc
Prince George Electric Cooperative
Raccoon Valley Electric Power Cooperative
Raft River Rural Electric Cooperative, Inc.
Ralls County Electric Cooperative
Rappahannock Electric Cooperative
Ravalli County Electric Cooperative, Inc.
Rayburn Country Electric Cooperative, Inc.;
Rayle Electric Membership Corporation
REA Energy Cooperative, Inc.
Red Lake Electric Cooperative, Inc.
Red River Valley
Red River Valley Rural Electric Association
Renville-Sibley Cooperative Power Association
Rich Mountain Electric Cooperative, Inc.
Richland Electric Coop
Rita Blanca Electric Cooperative, Inc.
Riverland Energy Cooperative

VA
OK
PA
MT
TX
SD
WI
GA
GA
WA
GA
OK
IA
NM
AR
MO
MO
AR,OK
LA,TX
IN
FL
MS
NC
WA
KY
MN
OK
AR
TN
NC
WI
AL
NC
MN
GA
WI
CO
MT,WY
IA
MS
WI
VA
IA
ID
MO
VA
MT
TX
GA
PA
MN
MN
OK
MN
AR
WI
TX
WI

Federal Energy Regulatory Commission

83

Cooperatively Owned Utility (Continued)
Rock Energy Cooperative
Rolling Hills Electric Cooperative, Inc.
Roseau Electric Coop
Rosebud Electric Cooperative
Roughrider Electric Cooperative, Inc
Rural Electric Cooperative, Inc.
Rushmore Electric Power Cooperative, Inc
Rusk County Electric Cooperative, Inc.
Sac Osage Electric Coop, Inc
Salem Electric
Salmon River Electric Cooperative, Inc.
Salt River Electric Coop. Corp.
Sam Houston Electric Cooperative, Inc.
Sangre de Cristo Electric Association
Santee Electric Cooperative, Inc.
Scenic Rivers Energy Coop
Se-Ma-No Electric Cooperative
Sequachee Valley Electric Coop
Shelby Electric Cooperative
Shelby Energy Cooperative
Shenandoah Valley Electric Cooperative
Sheridan Electric Co-op., Inc.
Sho-Me Power Electric Cooperative
Sierra Electric Cooperative, Inc.
Sioux Valley SW Elec Coop
Slash Pine Electric Membership Corporation
Smarr EMC
Snapping Shoals El Member Corp
South Central Arkansas Electric Cooperative,
South Central Electric Association
South Central Power Company
South Kentucky Rural Electric Coop Corp
South Mississippi Electric Power Association
South Plains Electric Cooperative
South Side Electric
Southeast Electric Cooperative, Inc.
Southeastern Electric Cooperative, Inc.
Southern Illinois Power Cooperative
Southern Indiana REC, Inc.
Southern Maryland Electric Cooperative, Inc.
Southwest Arkansas Electric Cooperative Corporation
Southwest Electric Cooperative
Southwest Texas Elec Coop, Inc
Southwestern Electric Cooperative, Inc.
Square Butte Electric Cooperative
St Croix Electric Coop
Steuben Rural Electric Cooperative, Inc.
Sumter Electric Cooperative, Inc.
Sumter Electric Membership Corporation
Surry-Yadkin Elec Member Corp
Suwannee Valley Electric Cooperative, Inc.
T.I.P. Rural Electric Cooperative
Tallapoosa River Electric Cooperative, Inc.
Talquin Electric Cooperative, Inc,
Taylor Electric Cooperative
Tennessee Valley Electric Coop
The Brown Atchison Electric Cooperative Assn., Inc.
The Frontier Power Company

84 Federal Energy Regulatory Commission

IL,WI
KS
MN
SD
ND
OK
SD
TX
Mo
OR
ID
KY
TX
CO
SC
WI
MO
TN
IL
KY
VA
MT
MO
NM
MN,SD
GA
GA
GA
AR
MN
OH
KY,TN
MS
TX
ID
MT,SD,WY
OK
IL
IN
MD
AR
MO
TX
IL
ND
WI
NY
FL
GA
NC
FL
IA
AL
FL
WI
TN
KS
OH

The Midwest Electric Cooperative Corporation
The Radiant Electric Cooperative, Inc.
The Satilla Rural Electric Membership Corporation
Three Notch Electric Membership Corporation
Tippah Electric Power Association
Traverse Electric Cooperative, Inc.
Tri-County Electric Coop
Tri-County Electric Cooperative, Inc
Tri-County Electric Cooperative, Inc.
Tri-County Electric Membership Corporation
Trinity Valley Electric Cooperative, Inc.
Turlock Irrigation District
Twin County Electric Power Association
Twin Valley Electric Cooperative
Union County Electric Cooperative, Inc.
Union Electric Membership Corp
Union Rural Electric Coop, Inc.
United Electric Cooperative
United Electric Cooperative Services, Inc.
United Power
Upper Cumberland Electric Membership Corporation
Upper Missouri G & T Electric Cooperative, Inc.
Upshur Rural Electric Cooperative Corp
Upson Electric Membership Cooperation
Valley Electric Association, Inc.
Valley Rural Electric Cooperative, Inc.
Verdigris Valley Electric Cooperative
Vermont Electric Cooperative, Inc.
Vernon Electric Coop
Victoria Electric Coop., Inc.
Vigilante Electric Cooperative, Inc
Volunteer Electric Coop
Wabash County REMC
Wake Electric
Warren Electric Cooperative, Inc
Warren Rural Electric Coop Corp
Washington Electric Co-Op Inc.
Washington Electric Membership Corporation
Wayne-White Counties Electric Cooperative
Webster Electric Cooperative
Wells Rural Electric Company
West Central Electric Cooperative, Inc.
West Oregon Electric Cooperative, Inc.
Western Cooperative Electric Association, Inc.
Western Illinois Electrical Coop
Western Indiana Energy REMC
Western Iowa Power Cooperative
Wheatland Electric Cooperative, Inc.
Wheatland Rural Electric Cooperative
Whetstone valley electric cooperative, Inc
White County Rural Electric Membership Corporation
Whitewater Valley REMC
Wild Rice Electric Coop, Inc
Wiregrass Electric Cooperative, Inc.
Withlacoochee River Electric Cooperative, Inc.
Woodruff Electric Cooperative Corporation
Yazoo Valley Electric Power Association
York Electric Cooperative, Inc.

2012 Assessment of Demand Response and Advanced Metering

NE
KS
GA
GA
MS
MN,ND,SD
MN
TX
OK
NC
TX
CA
MS
KS
SD
NC
OH
IA,MO
TX
CO
TN
MT,ND
TX
GA
CA,NV
PA
OK
VT
WI
TX
MT
TN
IN
NC
PA
KY
VT
GA
IL
MO
NV,UT
MO
OR
KS
IL
IN
IA
KS
WY
SD
IN
IN
MN
AL
FL
AR
MS
SC

Curtailment Service Provider
Energy Curtailment Specialists, Inc.

Energy Investment Systems, Inc.
Energy spectrum, Inc
EnerNOC, Inc
Galt Power, Inc
KEYTEX Energy LLC
Richards Energy Group, Inc.

CA,DC,DE,IL,IN,MD,
NJ,NY,OH,PA,TX,VA,
WV
NY
NJ,NY
MD
PA
PA
PA

Federal Utility
Colorado River Indian Irrigation Project
Mission Valley Power
Southeastern Power Administration
Southwestern Power Administration
Tennessee Valley Authority
Western Area Power Administration

AZ
MT
GA
AR,MO,OK
AL,GA,KY,MS,NC,TN,
VA
AZ,CA,CO,IA,KS,MN,
MT,ND,NE,NJ

Investor-Owned Utility
Black Hills Power, Inc.
AEP Texas Central Company
AEP Texas North Company
Alabama Power Company
Alaska Power & Telephone Co
Alpena Power Company
Amana Society Service Co.
Aniak Light & Power Co., Inc.
Appalachian Power Company
Arizona Public Service
Atlantic City Electric Company
Avista Corporation, dba Avista Utilities
Baltimore Gas and Electric Company
Bangor Hydro Electric Company
Bear Valley Electric Service
Black Hills/Colorado Electric Utility Co. LP
Block Island Power Co
Central Hudson Gas & Electric Corporation
Central Maine Power Co
Central Vermont Public Service Corporation
Cheyenne Light, Fuel and Power Company
Chitina Electric, Inc.
Citizens' Electric Company
Cleco Power LLC
Cleveland Electric Illuminating Co
Columbus Southern Power Company
Commonwealth Edison Company
Competitive Energy Services, LLC
Connecticut Light and Power Company
Consolidated Edison Company of New York
Consumers Energy Company
Dahlberg Light and Power Company
Delmarva Power and Light Company
Duke Energy Carolinas, LLC
Duke Energy Corporation

MT,SD,WY
TX
TX
AL
AK
MI
IA
AK
VA,WV
AZ
NJ
WA
MD
ME
CA
CO
RI
NY
ME
VT
WY
AK
PA
LA
OH
OH
IL
ME
CT
NY
MI
WI
DE,MD
NC,SC
OH

2012 Assessment of Demand Response and Advanced Metering

Duke Energy Indiana, Inc
Duke Energy Kentucky, Inc
Duquesne Light Company
Entergy Arkansas Inc
Entergy Gulf States Louisiana, LLC
Entergy Louisiana Inc.
Entergy Mississippi, Inc.
Entergy New Orleans, Inc.
Entergy Texas, Inc.
Fale-Safe, Inc
Fishers Island Electric company
Fitchburg Gas and Electric Light Company

IN
KY
PA
AR
LA
LA
MS
LA
TX
OR
NY
MA

Florida Power & Light Company
Florida Public Utilities Co.
Georgia Power
Granite State Electric Company
Green Mountain Power Corporation
Gulf Power Company

FL
FL
GA
NH
VT
FL

Gustavus Electric Company
Hawaii Electric Light Company, Inc.
Hawaiian Electric Company, Inc.

AK
HI
HI

Hughes Power & Light Co.
Idaho Power Company
Indiana Michigan Power Company
Indiana-Kentucky Electric Corp
Interstate Power and Light Company
Jersey Central Power & Light Co
Kansas City Power & Light Company
Kansas Gas & Electric Company
KCP&L Greater Missouri Operations Company
Kentucky Power Company
Kentucky Utilities
Kingsport Power Company
Louisville Gas & Electric and Kentucky Utilities
Luminant ET Services Company
Massachusetts Electric Company
Maui Electric Company, Limited
McGrath Light and Power
Metropolitan Edison Co
Miami Power Corporation
MidAmerican Energy Company
Minnesota Power, Inc.
Mississippi Power
Monongahela Power Co
Mt Carmel Public Utility Company
Nantucket Electric Company
Nevada Power Company
New York State Electric & Gas
Niagara Mohawk Power Corporation
Northern Indiana Public Service Company
NorthWestern Energy
NSTAR Electric Company
OGE Energy Corporation
Ohio Edison Co
Ohio Power Company
Ohio Valley Electric Corporation
Oncor Electric Delivery Company LLC
Orange & Rockland Utilities Inc

AK
ID,OR
IN,MI
IN
IA
NJ
KS,MO
KS
MO
KY
KY
TN
KY,VA
TX
MA
HI
AK
PA
OH
IA,IL,SD
MN
MS
WV
IL
MA
NV
NY
NY
IN
MT
MA
AR,OK
OH
OH
OH
TX
NY

Federal Energy Regulatory Commission

85

Investor-Owned Utility (Continued)
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy Company
Pennsylvania Electric Co
Pennsylvania Power Co
Portland General Electric Company
Potomac Electric Power Company
PPL Electric Utilities
Progress Energy Carolinas
Progress Energy Florida
Public Service Company of New Hampshire
Public Service Company of New Mexico (PNM)
Public Service Company of Oklahoma
Public Service Electric & Gas Company
Puget Sound Energy, Inc.
Rochester Gas & Electric
Rockland Electric Co
Safe Harbor Water Power Corporation
San Diego Gas & Electric
Sharyland Utilities, L.P.
Sierra Pacific Power Company
South Carolina Electric & Gas Company
Southern California Edison (SCE)
Southern Indiana Gas & Elec Co

MN,ND,SD
CA
CA,ID,OR,UT,WA,WY
PA
PA
PA
OR
DC,MD
PA
NC,SC
FL
NH
NM
OK
NJ
WA
NY
NY
PA
CA
TX
NV
SC
CA
IN

Southwestern Electric Power Company
Superior Water, Light and Power Company
Tampa Electric Company
The Dayton Power and Light Company
The Detroit Edison Company
The Empire District Electric Company
The Narragansett Electric Company
The Potomac Edison Company
The Toledo Edison Co
The United Illuminating Company
Tucson Electric Power
Union Electric Company
Unitil Energy Systems, Inc.
Upper Peninsula Power Corporation
Virginia Electric & Power Co
West Penn Power Company
Westar Energy, Inc.
Western Massachusetts Electric Company
Wheeling Power Company
Wisconsin Electric Power Company
Wisconsin Public Service Corporation
Wisconsin River Power Company
Wisconsin Power and Light Company
Xcel Energy

AR,LA,TX
WI
FL
OH
MI
AR,KS,MO,OK
RI
MD,WV
OH
CT
AZ
MO
NH
MI,WI
NC,VA
PA
KS
CT
WV
MI,WI
WI
MI,WI
WI
MI,WI

City of New Roads
City of Starke
City of Vermillion
Eugene Water & Electric Board
Fillmore City Electric Department
Indiana Municipal Power Agency
Intermountain Power Agency
Ipnatchiaq Electric Company
Massachusetts Municipal Wholes Electric Co
Missouri Basin Municipal Power Agency
Municipal Electric Authority of Georgia
Municipal Energy Agency of Mississippi
New York Municipal Power Agency
Northern Municipal Power Agency
Oklahoma Municipal Power Authority
Pocahontas Municipal Utilities
Public Utility District No.1 of Grays Harbor County
Sacramento Municipal Utility Dist
Texas Municipal Power Agency
Town of Pendleton
Utah Municipal Power Agency
Village of Trenton
Vinton Public Power Authority
Wyoming Municipal Power Agency

Municipally Owned Utility
Adrian Public Utilities
Aitkin Public Utilities
Albany Water, Gas & Light Commission
Algoma Utility Commission
Alta Vista Municipal Utilities
Ames, City of
Anita Municipal Utilities
Atlantic Municipal Utilities
Auburn Board of Public
Austin Utilities
Bagley Public Utilities
Bainbridge Municipal Electric Utility
Bamberg Board of Public Works
Bancroft Municipal Utilities
Baraga Electric Utility
Barnesville Municipal Electric
Barton Village, Inc.
Bath Electric Gas & Water System
Beaver City Corporation
Benton County Electric System
Biwabik Public Utilities
Bloomer Electric & Water Co
Blooming Prairie Public Utility Commission
Board of Public Works of The City of Lewes
Board of Water, Electric & Communications

Municipal Power Agency
Alabama Municipal Electric Authority
Centralia City Light
City of Alton
City of Anthony
City of Bentonville - (AR)
City of Drain
City of Mooreland - (OK)

86 Federal Energy Regulatory Commission

LA
FL
SD
OR
UT
IN
CA
AK
MA
SD
GA
MS
NY
MN
OK
IA
WA
CA
TX
IN
UT
NE
LA
WY

AL
WA
IA
KS
AR
OR
OK

2012 Assessment of Demand Response and Advanced Metering

MN
MN
GA
WI
IA
IA
IA
IA
NE
MN
MN
IN
SC
IA
MI
MN
VT
NY
UT
TN
MN
WI
MN
DE
IA

Municipally Owned Utility (Continued)
Bolivar Energy Authority
Borough of Berlin (PA)
Borough of Butler- (NJ)
Borough of Ellwood City
Borough of Ephrata
Borough of Goldsboro
Borough of Grove City
Borough of Hatfield
Borough of Kutztown - (PA)
Borough of Lansdale
Borough of Lavallette- (NJ)
Borough Of Lehighton
Borough of Middletown
Borough of Mifflinburg
Borough of Mont Alto
Borough of Olyphant- (PA)
Borough of Park Ridge - (NJ)
Borough of Pemberton
Borough of Perkasie
Borough of Pitcairn - (PA)
Borough of Quakertown- (PA)
Borough of Royalton
Borough of Schuylkill Haven - (PA)
Borough of Smethport
Borough of South River (NJ)
Borough of St Clair- (PA)
Borough of Tarentum (PA)
Borough of Wampum
Borough Watsontown (PA)
Boscobel Municipal Utilities
Borough of Catawissa
Borough of Duncannon
Bowling Green Municipal Utilities
Boylston Municipal Light Department
Brainerd Public Utilities
Braintree Electric Light Department (BELD)
Bremen Electric Light & Power Co
Brigham City Corporation
Bristol Virginia Utilities
Brodhead Water & Light Commission
Brooklyn Municipal Utilities
Brownfield Power & Light
Brownsville Public Utilities Board
Brownsville Utility Department
Burlington Electric Department
Cairo Public Utility Company
Canby Utility Board
Canton Municipal Utilities
Carrollton Board of Public Works
Cascade Municipal Utilities
Cedarburg Light & Water Commission
Centerville Municipal Power & Light
Centuria Municipal Electric Utility
Chicopee Municipal Lighting Plant
Chillicothe Municipal Utility
City & Borough of Sitka, Electric Department
City & County of San Francisco
City of Hickman

TN
PA
NJ
PA
PA
PA
PA
PA
PA
PA
NJ
PA
PA
PA
PA
PA
NJ
NJ
PA
PA
PA
PA
PA
PA
NJ
PA
PA
PA
PA
WI
PA
PA
KY
MA
MN
MA
IN
UT
VA
WI
IA
TX
TX
TN
VT
IL
OR
MS
MO
IA
WI
IN
WI
MA
MO
AK
CA
KY

2012 Assessment of Demand Response and Advanced Metering

City of California
City of Abbeville
City of Abbeville- SC
City of Aberdeen
City of Acworth
City of Ada
City of Adel
City of Afton
City of Akron (IA)
City of Akutan
City of Albany - (IL)
City of Albany- (MO)
City of Albemarle
City of Albion
City of Alcoa Electric Department
City of Alexander City
City of Alexandria
City of Algona
City Of Alma
City of Alpha
City of Altamont
City of Altamont - (KS)
City of Anaheim Public Utilities Department
City of Anoka
City of Ansley
City of Anthon
City of Aplington
City of Arapahoe
City of Arcadia
City of Arcadia - (KS)
CITY OF ARLINGTON
City of Arma
City of Ashland
City of Athens
City of Atka
City of Auburn (IA)
City of Auburn Electric Utility
City of Augusta
City of Ava (MO)
City of Axtell
City of Azusa
City of Blackwell
City of Baldwin City Kansas
City of Bandon
City of Banning
City oF Bartlett, Texas
City of Bartow
City of Bastrop
City of Batavia
City of Baudette
City of Beaver City
City of Bedford, Virginia
City of Bellville (TX)
City of Benham
City of Benkelman
City of Benton - (AR)
City of Berea Municipal Utility
City Of Beresford

MO
LA
SC
MS
GA
MN
GA
IA
IA
AK
IL
MO
NC
ID
TN
AL
MN
IA
KS
MN
IL
KS
CA
MN
NE
IA
IA
NE
WI
KS
MN
KS
KS
AL
AK
IA
IN
KS
MO
KS
CA
OK
KS
OR
CA
TX
FL
TX
IL
MN
NE
VA
TX
KY
NE
AR
KY
SD

Federal Energy Regulatory Commission

87

Municipally Owned Utility (Continued)
City of Bethany
City of Big Stone City
City of Bloomfield
City of Blountstown
City of Blue Earth
City of Blue Mound
City of Bluffton/Bluffton Utilities
City of Boerne
City of Boulder City
City of Bountiful
City of Bowie
City of Brady
City of Breckenridge- (MN)
City of Breda
City of Breese
City of Brenham
City of Brewster (MN)
City of Bridgeport Ne
City of Bristol - (TN)
City of Broken Bow
City of Bronson
City of Brookings
City of Brownton
City of Bryan (OH)
City of Buffalo (IA)
City of Buffalo, Minnesota
City of Buford
City of Buhl
City of Burke
City of Burley - (ID)
City of Burlingame
City of Burlington
City of Burt
City of Burwell
CITY OF BUSHNELL
City of Butler (MO)
City of Cabool
City of Calhoun
City of Cambridge
City of Camden, SC
City of Cameron
City of Camilla
City of Carlyle, Illinois
City of Carmi, Illinois
City of Cartersville, Georgia
City of Cascade Locks
City of Casey
City of Castroville
City of Cawker City
City of Celina
City of Central City
City of Centralia (KS)
City of Centralia, Missouri
City of Ceylon
City of Chapman
City of Chattanooga - (TN)
City of Chelsea
City of Cheney

88 Federal Energy Regulatory Commission

MO
SD
IA
FL
MN
KS
IN
TX
NV
UT
TX
TX
MN
IA
IL
TX
MN
NE
TN
NE
KS
SD
MN
OH
IA
MN
GA
MN
SD
ID
KS
CO
IA
NE
FL
MO
MO
GA
NE
SC
MO
GA
IL
IL
GA
OR
IL
TX
KS
OH
NE
KS
MO
MN
KS
TN
MI
WA

City of Chetopa
City of Chewelah
City of Chignik
City of Cimarron
City of Claremore
City of Cleveland - (OH)
City of Clewiston
City of Clinton- (TN)
City of Clinton, Combined Utility System
City of Cody
City of Coffeyville, Kansas
City of Colby
City of Coleman
City of Collins
City of Collinsville
City of Columbia
City of Columbia City
City of Columbiana
City of Columbus
City of Columbus, Ohio
City of Comanche
City of Commerce, GA
City of Coon Rapids
City of Corona
City of Covington
City of Covington - (TN)
City of Cozad / Board of Public Works
City of Crane (MO)
City of Crete
City of Crystal Falls
City of Cuba
City of Cushing
City of Danville
City of David City
City of Dayton (IA)
City of Denver (IA)
City of Detroit Lakes
City of Dighton
City of Dike
City of Doerun
City of Dothan
City of Douglas
City of Dover Public Utilities
City of Dowagiac
City of Due West
City of Duncan
City of Durant (IA)
City of Dysart
City of Earlville
City of East Grand Forks - (MN)
City Of East Point Power East Point Georgia
City of Eaton Rapids
City of Edgar (NE)
City of Edmond
City of Egegik
City of Elberton
City of Elfin Cove
City of Elizabethton

2012 Assessment of Demand Response and Advanced Metering

KS
WA
AK
KS
OK
OH
FL
TN
SC
WY
KS
KS
TX
MS
OK
MO
IN
OH
MS
OH
OK
GA
IA
CA
GA
TN
NE
MO
NE
MI
MO
OK
IA
NE
IA
IA
MN
KS
IA
GA
AL
GA
DE
MI
SC
OK
IA
IA
IA
MN
GA
MI
NE
OK
AK
GA
AK
TN

Municipally Owned Utility (Continued)
City of Elk Point
City of Ellaville
City of Ellensburg
City of Ellsworth
City of Elroy
City of Elwood
City of Emerson
City of Enterprise
City of Erie (KS)
City of Escanaba
City of Escondido
City of Estherville
City of Eudora
City of Evergreen
City of Fairbank
City of Fairbury
City of Fairfax
City of Fairhope
City of Fairview
City of Faith
City of Fallon (NV)
City of Falls City
City of Farmersville
City of Farmington
City of Fayetteville
City of Flandreau
City of Flora
City of Florence (AL)
City of Floresville
City of Fonda
City of Fontanelle
City of Forest Grove Light and Power
City of Fort Meade
City of Fort Morgan
City of Fort Pierre - (SD)
City of Fosston
City of Fountain
City of Franklin (NE)
City of Franklin Power & Light
City of Frederick
City of Fredonia
City of Fulton
City of Galion
City of Gallatin
City of Gallup
City Of Galt
City of Galva
City of Garden City
City Of Garland
City Of Gas City
City of Gastonia
City of Geary
City of Geneseo
City of Geneva
City of Georgetown
City of Giddings
City of Gilbert
City of Giltner

SD
GA
WA
IA
WI
KS
NE
UT
KS
MI
CA
IA
KS
AL
IA
NE
MN
AL
OK
SD
NV
NE
TX
NM
TN
SD
IL
AL
TX
IA
IA
OR
FL
CO
SD
MN
CO
NE
VA
OK
KS
MO
OH
MO
NM
MO
KS
KS
TX
IN
NC
OK
IL
IL
TX
TX
MN
NE

2012 Assessment of Demand Response and Advanced Metering

City of Gladstone
City of Glasco
City of Glen Elder
City of Glendale
City of Glenwood Springs - CO
City of Goldthwaite
City of Gonzales
City of Goodland
City of Gothenburg
City of Graettinger
City of Grafton - (ND)
City of Grand Island
City of Grand Junction (IA)
City of Granite
City of Grant
City of Grantville
City of Greendale
City of Greensburg (KS)
City of Gridley
City of Griffin
City of Groton
City of Grove City
City of Guttenberg
City of Hagerstown, IN
City of Hallettsville
City of Halstad
City of Hampton
City of Harbor Springs
City of Harrisonville
City of Hart Hydro
City of Hartford (AL)
City of Hartley
City of Hastings
City of Haven
City of Hawarden
City of Healdsburg (CA)
City of Hebron
City of Hecla
City of Hemphill
City of Henning
City of Herington
City of Hermann
City of Herndon
City of Hertford (NC)
City of Higginsville
City of Highland
City of Hill City
City of Hillsboro
City of Holdrege
City of Hominy (OK)
City of Hope
City of Hopkinton
City of Horton
City of Houston
City of Howard
City of Hubbard
City of Hubbell
City of Hudson
City of Hugoton

MI
KS
KS
CA
CO
TX
TX
KS
NE
IA
ND
NE
IA
OK
NE
GA
IN
KS
CA
GA
SD
MN
IA
IN
TX
MN
GA
MI
MO
MI
AL
IA
NE
KS
IA
CA
NE
SD
TX
MN
KS
MO
KS
NC
MO
IL
KS
KS
NE
OK
ND
IA
KS
MO
SD
OH
NE
OH
KS

Federal Energy Regulatory Commission

89

Municipally Owned Utility (Continued)
City of Hunnewell
City of Huntingburg - (IN)
City of Imperial
City of Indianola
City of Isabel (KS)
City of Itta Bena
City of Iuka
City of Jackson
City of Jackson (OH)
City of Jacksonville Beach
City of Janesville
City of Jasper, TX
City of Jetmore
City of Jonesville (LA)
City of Kahoka
City of Kandiyohi
City of Kansas City
City of Kasson
City of Kennett
City of Kiel
City of Kimball
City of Kingfisher
City of Kings Mountain
City of Kiowa (KS)
City of Kirkwood (MO)
City of La Crosse
City of La Grange
City of La Grange (GA)
City of La Plata
City of Lafayette
City of Lake City Electric Utility
City of Lake Crystal (MN)
City of Lake Mills
City of Lake Park- (IA)
City of Lake View
City of Lake Worth Utilities
City of Lakefield
City of Lakeland, Lakeland Electric
City of Lakota
City of Lamar
City of Lamar- (Colorado)
City of Lampasas (TX)
City of Lanett
City of Larchwood
City of Larned
City of Larsen Bay
City of Las Animas Municipal Light & Power
City of Laurel (NE)
City of Laurens
City of Laurinburg
City of Lawler (IA)
City of Lawrenceville
City of Le Sueur (MN)
City of Lebanon
City of Lehigh
City of Lenox (IA)
City of Lexington
City of Liberal

90 Federal Energy Regulatory Commission

MO
IN
NE
NE
KS
MS
KS
GA
OH
FL
MN
TX
KS
LA
MO
MN
KS
MN
MO
WI
NE
OK
NC
KS
MO
KS
TX
GA
MO
AL
MN
MN
IA
IA
IA
FL
MN
FL
ND
MO
CO
TX
AL
IA
KS
AK
CO
NE
IA
NC
IA
GA
MN
OH
IA
IA
NE
MO

City of Liberty
City of Lincoln Center
City of Lincoln Electric System
CITY OF LINDSAY
City of Lindsborg
City of Linneus (MO)
City of Litchfield Public Utilities
City of Livermore
City of Livingston
City of Lockhart
City of Lodgepole (NE)
City of Lodi
City of Lompoc
City of Long Grove (IA)
City of Lowell
City of Lucas
City of Luray (KS)
City of Luverne
CITY OF LYONS
City of Mabel (MN)
City of Maddock
City of Madison (MN)
City of Madison (NE)
City of Malden (MO) Board of Public Works
City of Mangum (OK)
City of Manitou (OK)
City of Mankato
City of Manokotak
City of Mansfield
City of Mansfield (GA)
City of Mapleton
City of Marathon
City of Marietta (GA)
City of Marion
City of Marshall
City of Marshall, Michigan
City of Marshfield
City of Martinsville Electric Department
City of Mascoutah
City of Mason
City of McLeansboro
City of McMinnville (OR)
City of Meade
City of Meadville
City of Memphis (MO)
City of Mendon - (OH)
City of Mesa
City of Milan
City of Milan (MO)
City of Milford
City of Milford (IA)
City of Miller (SD)
City of Milton
City of Minden
City of Minden (NE)
City of Mindenmines (MO)
City of Mindoka (ID)
City of Minneapolis (KS)

2012 Assessment of Demand Response and Advanced Metering

TX
KS
NE
OK
KS
MO
MN
IA
TX
TX
NE
CA
CA
IA
MI
KS
KS
MN
NE
MN
ND
MN
NE
MO
OK
OK
KS
AK
MO
GA
IA
IA
GA
KS
IL
MI
WI
VA
IL
TX
IL
OR
KS
MO
MO
OH
AZ
TN
MO
DE
IA
SD
WA
LA
NE
MO
ID
KS

Municipally Owned Utility (Continued)
City of Mishawaka
City of Monmouth
City of Monroe
City of Montezuma (IA)
City of Montezuma (KS)
City of Monticello
City of Moore Haven (FL)
City of Mora (MN)
City of Moran
City of Moreno Valley (CA)
City of Morrill
City of Moultrie
City of Mount Dora
City of Mount Hope (KS)
City of Mount Vernon
City of Mountain Iron
City of Mountain Lake
City of Mountain View
City of Mt Pleasant
City of Mulberry (KS)
City of Mulvane - - (KS)
City of Murray
City of Nashwauk
City of Natchitoches
City of Nebraska City
City of Needles
City of Neligh
City of Neodesha (KS)
City of Neola (IA)
City of New Braunfels - (TX)
City of New Hampton (IA)
City of New Lisbon Municipal Electric & Water Dept.
City of New Madrid (MO)
City of New Ross
City of Newberry, Florida
City of Newburg (MO)
City of Newkirk
City of Newton
City of Nicholasville
City of Nielsville
City of Niles (MI)
City of Nixa Utilities
City of North Saint Paul
City of Northwood
City Of Norton Kansas
City of Norway Dept. of Power & Light
City of Oberlin (KS)
City of Ocala Utility Services
City of Odessa
City of Oglesby (IL)
City of Olivia (MN)
City of Onawa
City of Onida (SD)
City of Opelika
City of Ord
City of Orient (IA)
City of Ortonsville - (MN)
City of Osage City

IN
OR
GA
IA
KS
GA
FL
MN
KS
CA
KS
GA
FL
KS
MO
MN
MN
MO
UT
KS
KS
UT
MN
LA
NE
CA
NE
KS
IA
TX
IA
WI
MO
IN
FL
MO
OK
IL
KY
MN
MI
MO
MN
ND
KS
MI
KS
FL
MO
IL
MN
IA
SD
AL
NE
IA
MI
KS

2012 Assessment of Demand Response and Advanced Metering

City of Osawatomie
City of Osborne
City of Osceola
City of Osceola (AR)
City of Osford
City of Oxford (GA)
City of Painesville
City of Palo Alto Utilities
City of Paris (AR)
City of Paris (KY)
City of Park River - (ND)
City of Pasadena
City of Paton - (IA)
City of Perry, MO.
City of Peterson
City of Petoskey
City of Piedmont
City of Pierce
City of Pierre
City of Pierz
City of Piqua (OH)
City of Plainview (NE)
City of Plaquemine (LA)
City of Plattsburgh - (NY)
City of Pomona (KS)
City of Poplar Bluff
City of Port Angeles
City of Pratt (KS)
City of Preston
City of Princeton
City of Princeton (WI)
City of Pryor (OK)
City of Purcell
City of Quitman
City of Radford - Electric Department
City of Radium
City of Rancho Cucamonga
City of Randall
City of Randolph (NE)
City of Rayne
City of Readlyn (IA)
City of Red Cloud
City of Redding
City of Renwick (IA)
City of Richland
City of Rising Sun (IN)
City of Riverdale
City of Robertsdale
City of Robinson
City of Rock Hill
City of Rockwood
City of Roodhouse
City of Roseau
City of Roseville
City of Round Lake
City of Rupert
City of Rushford
City of Rushmore - (MN)

KS
KS
MO
AR
KS
GA
OH
CA
AR
KY
ND
CA
IA
MO
MN
MI
AL
NE
SD
MN
OH
NE
LA
NY
KS
MO
WA
KS
IA
IL
WI
OK
OK
GA
VA
KS
CA
MN
NE
LA
IA
NE
CA
IA
WA
IN
ND
AL
KS
SC
TN
IL
MN
CA
MN
ID
MN
MN

Federal Energy Regulatory Commission

91

Municipally Owned Utility (Continued)
City of Russell
City of Russell (MA)
City of Ruston (LA)
City of Sabula
City of Saint Peter
City of Salamanca
City of Salem
City of Sanborn
City of Sauk Centre
City of Schuyler (NE)
City of Scranton
City of Scribner
City of Seaford
City of Sebewaing (MI)
City of Seguin
City of Seneca
City of Seward (AK)
City of Seymour (TX)
City of Shasta Lake
City of Sheboygan Falls
City of Shelbina
City of Shelby (NC)
City of Shelby (OH)
City of Sherrill Power & Light
City of Shiner
City of Shullsburg (WI)
City of Sibley
City of Sidney
City of Siloam Springs (AR)
City of Sioux Falls (SD)
City of Slater
City of Smithville
City of Snyder
City of Soda Springs
City of South Sioux City
City of Spring Grove
City of Springfield
City of Springfield, IL
City of St Charles
City of St Louis
City Of St Marys
City of St Robert (MO)
City of St. Charles
City of St. Clairsville
City of St. George
City of St. James
City Of St. John
City of St. Marys
City of Stafford (KS)
City of Stanhope
City of Stanton
City of Stanton (IA)
City of Starkville
City of State Center
City of Statesville (NC)
City of Stephen - (MN)
City of Stephenson
City of Stockton

92 Federal Energy Regulatory Commission

KS
MA
LA
IA
MN
NY
VA
IA
MN
NE
KS
NE
DE
MI
TX
SC
AK
TX
CA
WI
MO
NC
OH
NY
TX
WI
IA
NE
AR
SD
MO
TX
NE
ID
NE
MN
CO
IL
IL
MI
KS
MO
MN
OH
UT
MN
KS
OH
KS
IA
ND
IA
MS
IA
NC
MN
MI
KS

City of Strawberry Point
City of Stroud (OK)
City of Stuart (NE)
City of Sullivan
City of Sumas
City of Superior (NE)
City of Sutton
City of Sylvania (GA)
City of Syracuse
City of Tallahassee Utilities
City of Taunton
City of Tecumseh
City of Tenakee Springs
City of Thayer
City of Thief River Falls
City of Timpson (TX)
City of Toronto (KS)
City of Traverse City
City of Trenton (TN)
City of Trinidad
City of Troy
City of Troy - (IN)
City of Troy
City of Tulia
City of Tupelo - (MS)
City of Tuskegee
City of Two Harbors
City of Tyler
City of Tyndall
City of Udall
City of Unalaska
City of Union City
City of Union
City of Unionville
City of Valentine
City of Valley City
City of Vandalia
City of Vermillion (KS)
City of Versailles
City of Virginia
City of Wadena Electric & Water
City of Wakefield (NE)
City of Wall Lake
City of Wamego
City of Warren - (MN)
City Of Warroad
City of Washington (IN)
City of Washington (KS)
City of Washington
City of Waterloo
City of Watertown
City of Wathena
City of Wauchula
City of Weiser
City of Wellington
City of West Liberty
City of West Plains
City of Westbrook

2012 Assessment of Demand Response and Advanced Metering

IA
OK
NE
MO
WA
NE
NE
GA
NE
FL
MA
NE
AK
MO
MN
TX
KS
MI
TN
CO
KS
IN
AL
TX
MS
AL
MN
MN
SD
KS
AK
TN
SC
MO
NE
ND
MO
KS
OH
MN
MN
NE
IA
KS
MN
MN
IN
KS
GA
IL
NY
KS
FL
ID
KS
IA
MO
MN

Municipally Owned Utility (Continued)
City of Westfield
City of Whalan
City of Whigham
City of White
City of Whittemore
City of Wilber
City of Willow Springs
City of Windom
City of Winfield (KS)
City of Winner
City of Winnfield
City of Winona
City of Winterset (IA)
City of Winterville
City of Winthrop (MN)
City of Wisner
City of Woolstock
City of Wrangell
City of Wray
City of Wymore (NE)
City of Yoakum, Texas
City Utilities of Springfield, MO
City Water & Light Plant of the City of Jonesboro
City of Girard
Clarksdale Public Utilities
Clarksville Light & Water Co
Clintonville Utilities
Colorado Springs Utilities
Columbia Power & Water Systems
Columbus Water & Light Dept.
Conway Corporation
Corbin City Utilities Commission
Corwith Municipal Utilities
Crawfordsville Electric Light & Power
Cuba City Electric & Water Utility
Cumberland, City of
Cuyahoga Falls Electric System
D.G. Hunter Power Station
Darlington Light & Power Co
Delano Municipal Utilities
Delta Municipal Light and Power
Dublin Municipal Electric Utilities
Eagle River Light & Water Commission
Easley Combined Utility System
East Bay Municipal Utility District
Easton Utilities Commission
Ediburg Municipal Utilities
Electric and Water Plant Board of the City of Frankfort
Elk River Municipal Utilities
Evansville Water & Light
Fairburn Utilities
Fitzgerald Wtr Lgt
Florence Utility Commission
Foley Board of Utilities
Forest City Municipal Utilities
Fort Collins Utilities
Fort Pierce Utilities Authority
Fremont Department of Utilities

MA
MN
GA
SD
IA
NE
MO
MN
KS
SD
LA
MO
IA
NC
MN
NE
IA
AK
CO
NE
TX
MO
AR
KS
MS
AR
WI
CO
TN
WI
AR
KY
IA
IN
WI
WI
OH
LA
IN
MN
CO
IN
WI
SC
CA
MD
IN
KY
MN
WI
GA
GA
WI
AL
IA
CO
FL
NE

2012 Assessment of Demand Response and Advanced Metering

Gaffney Board of Public Works
Gainesville Regional Utilities
Galena Electric Utility
Gallatin Department of Electricity
Glasgow Electric Plant Board
Glencoe Light and Power Commission
Gold Country Energy
Goltry Public Works Authority
Grafton Electric
Grand Haven Board of Light and Power
Green Cove Springs Electric Utility
Greenfield Municipal Utilities
Greenwood Commissioners Public Works
Greenwood Utilities
Groton Electric Light Dept.
Grundy Center Mun. Light & Power
Harriman Utility Board
Harrisonburg Electric Commission
Hartford Utilities
Havana Power & Light Company
Hawley Public Utilities
Heber Light & Power Company
Helper City
Henderson Power and Light
Hermiston Energy Services
Hibbing Public Utilities
Hingham Municipal Light Plant
Holland Board of Public Works
Holy Springs Utility Department
Hooversville Electric Light Co
Hope Water and Light Commission
Hopkinsville Electric System
Hudson Light & Power Department
Hudson Municipal Electric Utility
Hurricane City Power
Hustisford Utilities
Hutchinson Utilities Commission
Hyrum City Corp.
Idaho Falls Power
Illinois Municipal Electric Agency
Independence Light & Power
Indianola Municipal Utilities
Jamestown Board of Public Utilities
JEA
Jefferson Water & Light Dept.
Jewett City Department of Public Utilities
Juneau Utility Commission
Kaukauna Utilities
Kaysville City Corporation
Keewatin Public Utilities
Kennebunk Light & Power District
Kenyon Municipal Utility
Kerrville Public Utility Board
Ketchikan Public Utilities
Kimballton Municipal Utilities
Kirbyville Light & Power Co
Kissimmee Utility Authority
Knoxville Utilities Board

SC
FL
AK
TN
KY
MN
AK
OK
IA
MI
FL
IA
SC
MS
MA
IA
TN
VA
WI
FL
MN
UT
UT
KY
OR
MN
MA
MI
MS
PA
AR
KY
MA
IA
UT
WI
MN
UT
ID
IL
IA
IA
NY
FL
WI
CT
WI
WI
UT
MN
ME
MN
TX
AK
IA
TX
FL
TN

Federal Energy Regulatory Commission

93

Municipally Owned Utility (Continued)
Kokhanok Village Council
Kosciusko Water & Light Plant
La Farge Municipal Electric Co.
La Porte City Utilities
Lafayette Utilities System
Lake Mills Light & Water Dept.
Lake Placid Village, Inc.
L'anse Electric Utility
Lansing Board of Water & Light
Lassen Municipal Utility District
Lawrenceburg Municipal Utilities
Lebanon Utilities
Levan Town Corporation
Lexington Electric System
Littleton Water and Light Department
Lockwood Water & Light Company
Lodi Municipal Light & Water Utility
Logan City Light and Power
Logansport Municipal Utilities
Longmont Power & Communications
Los Angeles Department of Water and Power
Louisville Electric System
Madelia Municipal Light & Power
Manitowoc Public Utilities
Manti City
Maquoketa Municipal Electric Utility
Marquette Board of Light and Power
Marshall Municipal Utilities
Matinicus Plantation Electric Co
Mayor & Council of Middletown
McMinnville Electric System
Meadow Town Corp.
Memphis Light, Gas & Water Division
Menasha Electric & Water Utilities
Merrimac Municipal Light Department
Metlakatla Power & Light
Monroe City
Moorhead Public Service
Morgan City (LA)
Morgan City Corporation
Morristown Utilities Commission
Mount Horeb Electric Utility
Mount Pleasant Municipal Utilities
Municipal Commission of Boonville
Municipal Electric Utility of the City of Cedar Falls
Municipal Services Commission
Muscoda Light & Water Utility
Negaunee Electric Department
New Glarus Light & Water Works
New Hampton Village Precinct
New Holstein Public Utility
New London Electric & Water Utility
New Martinsville Municipal Electric Utility
New Richmond Municipal Electric Utility
New Ulm Public Utilities Comm
Newberry Water & Light Board
Nome Joint Utility System
North Branch Water & Light Comm.

94 Federal Energy Regulatory Commission

AK
MS
WI
IA
LA
WI
NY
MI
MI
CA
IN
IN
UT
TN
NH
MO
WI
UT
IN
CO
CA
MS
MN
WI
UT
IA
MI
MN
ME
DE
TN
UT
TNI
WI
MA
AK
UT
MN
LA
UT
TN
WI
IA
NY
IA
DE
WI
MI
WI
NH
WI
WI
WV
WI
MN
MI
AK
MN

North Little Rock Electric Department
Norwich Public Utility
Oconto Falls Water & Light Commission
Okeene Public Works Authority
Orlando Utilities Commission
Orrville Utilities
Osage Municipal Utilities
Owatonna Public Utilities
Owensboro Municipal Utilities
Page Electric Utility
Palmrya Board of Public Works
Paragould Light Water and Cable
Parowan City Corporation
Pascoag Utility District
Payson City Corporation
Pella City of
Pend Oreille PUD
Piggott Light and Water
Plymouth Utilities
Prague Public Works Authority
Prairie du Sac Municipal Electric & Water
Precinct of Woodsville
Price Municipal Corporation
Princeton Public Utilities Commission
Proctor Public Utilities Commission
Prospect Corporation
Provo City Corporation
Public Works Commission of the City of Fayetteville
PUD No 1 of Asotin County
PUD No 1 of Skamania Co
Raton Public Service Company
Redwood Falls Public Utility Commission
Reedsburg Utility Commission
Reedy Creek Improvement District
Rensselaer Municipal Electric Utility
Reynolds, Village of
Rice Lake Utilities
Richland Center Electric Utility
Richmond Power and Light
River Falls Municipal Utility
Riverside Public Utilities
Rochelle Municipal Utilities
Rock Port Municipal Utilities
Rock Rapids Municipal Utilities
Rockford Municipal Light Plan
Sallisaw Municipal Authority
Santa Clara City
Second Taxing District of Norwalk
Sevier County Electric System
Shakopee Public Utilities Commission
Shawano Municipal Utilities
Sikeston Board of Municipal Utilities
Silicon Valley Power, City of Santa Clara
Sioux Center Municipal Electric Utility
Sleepy Eye Public Utilities
Slinger Utilities
Smithville Electric System
Snohomish County PUD No 1

2012 Assessment of Demand Response and Advanced Metering

AR
CT
WI
OK
FL
OH
IA
MN
KY
AZ
MO
AR
UT
RI
UT
IA
WA
AR
WI
OK
WI
NH
UT
MN
MN
OH
UT
NC
WA
WA
NM
MN
WI
FL
IN
NE
WI
WI
IN
WI
CA
IL
MO
IA
IA
OK
UT
CT
TN
MN
WI
MO
CA
IA
MN
WI
TN
WA

Municipally Owned Utility (Continued)
South Hadley Electric Light Department
South Vienna Corporation
Spanish Fork City Corporation
Spencer Municipal Utilities
Spencerport Electric
Spooner Municipal Utilities
Spring Valley Public Utilities
Springville Light & Power
Stoughton Electric Utility
Straughn Municipal Electric
Stuart Municipal Utilities
Sturgeon Bay Utilities
Sumner Municipal Light Plant
Sun Prairie Water & Light Commission
Sylacauga Utilities Board
Tacoma Public Utilities
TDX Manley Generating LLC
Tell City Electric Department
The City of Holyoke Gas and Electric Department
The Hagerstown Light Department
Third Taxing District Electric Dept.
Tipton Municipal Electric Utility
Tipton Municipal Utilities
Town of Argos Utilities
Town of Ashburnham
Town of Avilla
Town of Bargersville
Town of Belmont
Town of Black Creek
Town of Blackstone
Town of Bostic
Town of Boyce
Town of Brinson
Town of Brooklyn
Town of Clayton (NC)
Town of Coatesville
Town of Coulee Dam
Town of Crane
Town of Culpeper Light & Power
Town of Dallas
Town of Eatonville
Town of Etna Green
Town of Ferdinand
Town of Forest City
Town of Fountain
Town of Frankton
Town of Frederick
Town of Fredonia
Town of Front Royal
Town of Granada
Town of Granite Falls
Town of Groveland
Town of Guernsey
Town of Gueydan
Town of Hardwick
Town of Haxtun
Town of High Point
Town of Highlands

MA
OH
UT
IA
NY
WI
MN
UT
WI
IN
IA
WI
IA
WI
AL
WA
AK
IN
MA
MD
CT
IN
IA
IN
MA
IN
IN
MA
NC
VA
NC
LA
GA
IN
NC
IN
WA
IN
VA
NC
WA
IN
IN
NC
NC
IN
CO
AZ
VA
CO
NC
MA
WY
LA
VT
CO
NC
NC

2012 Assessment of Demand Response and Advanced Metering

Town of Hobgood
Town of Ipswich
Town of Julesburg
Town of Kingsford Heights
Town of Knightstown (Municipal Electric Utility)
Town of Ladoga (IN)
Town of Landis
Town of Laverne- (OK)
Town of Lewisville
Town of Lucama
Town of Lyons
Town of MacClesfield
Town of Madison (ME)
Town of Maiden (NC)
Town of Manilla (IA)
Town of Mansfield (MA)
Town of Massena Electric Department
Town of Middleborough (MA)
Town of Middletown-(IN)
Town of Montezuma
Town of New Carlisle (IN)
Town of Oak City
Town of Paxton Municipal Light Department
Town of Pinetops
Town of Pineville (NC)
Town of Princeton (MA)
Town of Prosperity, SC
Town of Rowley (MA)
Town of Ruston (WA)
Town of Ryan (OK)
Town of Scotland Neck (NC)
Town of Sharpsburg
Town of South Whitley
Town of Spiceland
Town of Spiro
Town of Stantonsburg
Town of Stowe
Town of Templeton (MA)
Town of Veedersburg
Town of Vidalia
Town of Wakefield (VA)
Town of Walkerton
Town of Wallingford, Department of Public Utilities
Town of Walstonburg
Town of Waynesville
Town of Winamac
Town of Winnsboro
Town of Wolfeboro
Traer Municipal Utilities
Trenton Municipal Utilities
Tullahoma Board of Public Utilities
Two Rivers Water & Light Utility
Van Buren Light & Power District
Village of Akron
Village of Angelica
Village of Arcade
Village of Arcadia
Village of Arnold

NC
MA
CO
IN
IN
IN
NC
OK
IN
NC
CO
NC
ME
NC
IA
MA
NY
MA
IN
IN
IN
UT
MA
NC
NC
MA
SC
MA
WA
OK
NC
NC
IN
IN
OK
NC
VT
MA
IN
LA
VA
IN
CT
NC
NC
IN
SC
NH
IA
MO
TN
WI
ME
NY
NY
NY
OH
NE

Federal Energy Regulatory Commission

95

Municipally Owned Utility (Continued)
Village of Bartley
Village of Belmont
Village of Bergen
Village of Bethany Illinois
Village of Black Earth
Village of Blanchester
Village of Brainard
Village of Brocton
Village of Callaway
Village of Campbell (NE)
Village of Carey
Village of Castile
Village of Chester
Village of Churchville
Village of Clinton
Village of Daggett
Village of Davenport
Village of De Witt
Village of Deshler
Village of Dorchester
Village of Endicott Municipal Light
Village of Fairport
Village of Frankfort (NY)
Village of Freeburg
Village of Freeport
Village of Glouster
Village of Grafton
Village of Greene
Village of Greenport
Village of Hampton
Village of Haskins
Village of Hazel Green
Village of Hemingford/Hemingford Municipal Utilities
Village of Holbrook
Village of Holley Municipal Electric Department
Village of Jackson Center - (OH)
Village of Lakeview (OH)
Village of Little Valley
Village of Lodi (OH)
Village of Lucas

NE
WI
NY
IL
WI
OH
NE
NY
NE
NE
OH
NY
NE
NY
MI
MI
NE
NE
OH
NE
NY
NY
NY
IL
NY
OH
OH
NY
NY
NE
OH
WI
NE
NE
NY
OH
OH
NY
OH
OH

Village of Lyndonville
Village of Marshallville
Village of Mayville
Village of Merrillan (WI)
Village of Morrill (NE)
Village of New Bremen (OH)
Village of New Knoxville (OH)
Village of Oak Harbor (OH)
Village Of Oxford
Village of Paw Paw
Village of Pemberville (OH)
Village of Philadelphia
Village of Polk - (NE)
Village of Rantoul
Village of Rockville Centre
Village of Seville Board of Public Affairs
Village of Sherburn
Village of Shickley

VT
OH
NY
WI
NE
OH
OH
OH
NE
MI
OH
NY
NE
IL
NY
OH
NY
NE

96 Federal Energy Regulatory Commission

Village of Silver Springs Municipal Electric
Village of Skaneateles (NY)
Village of Spalding
Village of Spencer
Village of Springville
Village of Stratford
Village of Stratton
Village of Swanton
Village of Talmage
Village of Theresa
Village of Tontogany
Village of Tupper Lake
Village of Viola
Village of Watkins Glen
Village of Wellington
Village of Westfield
Village of Wharton
Village of Winnetka
Vinton Municipal Electric Utility
Bowling Green
Wadsworth Utilities
Wagoner Public Works Authority
Walters Public Works Authority
Washington City Power
Waterloo Water & Light Commission
Waunakee Water & Light Commission
Waupun Utilities
Waverly Municipal Elec Utility
Weakley County Municipal Electric System
Weatherford Municipal Utility System
West Boylston Lighting Plant
West Point Municipal Utility
Westby Municipal Electric Utility
Williamstown Utility Commission
Wilton Municipal Light and Power
Wisconsin Dells Electric Utility
Wonewoc Municipal Water & Light Dept
Wyandotte Municipal Service Commission
Wynnewood City Utilities Authority

NY
NY
NE
NE
NY
WI
NE
VT
NE
NY
OH
NY
WI
NY
OH
NY
OH
IL
IA
OH
OH
OK
OK
UT
WI
WI
WI
IA
TN
TX
MA
IA
WI
KY
IA
WI
WI
MI
OK

Political Subdivision
Alamo Power District #3
Arkansas River Power Authority
Butler Public Power District
Cedar-Knox PPD
Chimney Rock Public Power District
City of El Dorado Springs
City of Steelville
Clatskanie PUD
Cornhusker Public Power District
Dawson Public Power District
Eastside Power Authority
Electrical District # 2
Electrical District No. 4 Pinal County
Electrical District No. 5 Pinal County
Elkhorn Rural Public Power District
Emerald People's Utility District
Howard Greeley Rural Public Power District

2012 Assessment of Demand Response and Advanced Metering

NV
CO
NE
NE
NE
MO
MO
OR
NE
NE
CA
AZ
AZ
AZ
NE
OR
NE

Political Subdivision (Continued)
Kings River Conservation District
Kwig Power Company
Louisiana Energy and Power Authority
Loup River Public Power District
Loup Valleys Rural Public Power District
McCook Public Power District
Merced Irrigation District
Midvale Irrigation District
North Central Public Power District
Northeast Nebraska Public Power District
Oakdale & South San Joaquin Irrigation D.

CA
AK
LA
NE
NE
NE
CA
WY
NE
NE
CA

Direct Energy Services, LLC

Overton Power District No. 5
Perennial Public Power District
Placer County Water Agency
Platte River Power Authority
Polk County Rural Public Power District
Public Service Commission of Yazoo City
Public Utility District #1 of Ferry County
Public Utility District No. 1 of Wahkiakum County
PUD #1 of Clallam County
PUD No 1 of Clark County
PUD No 1 of Klickitat County
PUD No 3 of Mason County
PUD No. 1 of Whatcom County
Roosevelt Public Power District

NV
NE
CA
CO
NE
MS
WA
WA
WA
WA
WA
WA
WA
NE

MxEnergy Electric, Inc.
Power Choice/ Pepco Energy Serv

Salt River Project Agricultural Improvement & Power
South Feather Water and Power Agency
Southern California PPA
Southern Public Power District
Southwest Public Power District
The Central Nebraska Public Power and Irrigation
Tillamook People's Utility District
Tohono O'odham Utility Authority
Tonopah Irrigation District
Village of Endicott
WPPI Energy

AZ
CA
CA
NE
NE
NE
OR
AZ
AZ
NE
WI

Regional Transmission Organization/
Independent Transmission Operator
California Independent System Operator
Electric Reliability Council of Texas
ISO New England
Midwest ISO
New York Independent System Operator
PJM Interconnection, LLC
Southwest Power Pool

CA
TX
MA
IN
NY
PA
AR

Direct Energy, LP
Dow Hydrocarbons and Resources LLC.
Energy Plus Holdings LLC
En-Toucn Systems, Inc. d/b/a En-Touch Energy
First Choice Power
Gateway Energy Services Corporation
Integrys Energy Services of New York, Inc.
Integrys Energy Services, Inc.

Shell Energy North America, LP
South Jersey Energy
Spartan Renewable Energy, Inc.
Tara Energy, LLC
Texas Retail Energy, LLC
TXU Energy Retail Company LLC
U.S. Energy Partners LLC
UGI Energy Services, Inc.
Wolverine Power Marketing Cooperative
WTU Retail Energy, LP

CT,DC,DE,IL,MA,MD,
ME,NJ,NY,OH,PA,RI
TX
TX
CT,IL,MD,NJ,NY,PA,
TX
TX
TX
MD,NJ,NY,PA
NY
CT,DC,DE,IL,MA,MD,
ME
TX
DC,DE,IL,MA,MD,NJ,
NY,PA,TX
TX
NJ
MI
TX
TX
TX
NY
DC,DE,MD,NJ,NY,PA
MI
TX

State Utility
Alaska Energy Authority
Commonwealth Utilities Corporation
Energy Northwest
Grand River Dam Authority
Nebraska Public Power District
New York Power Authority
South Carolina Public Service Authority
The Metropolitan Water District of Southern Calif
Toledo Bend Project Joint Operations
Virginia Tech Electric Service

AK
MP
WA
OK
NE,SD
NY
SC
CA
TX
VA

ITC Great Plains

KS,OK

ITC Midwest LLC
ITC Transmission
Michigan Electric Transmission Company
Swans Island Electric Coop Inc
Vermont Electric Power Co, Inc
Vermont Electric Trans Co Inc

IA,IL,MN,MO
MI
MI
ME
VT
VT

Retail Power Marketer
3 Phases Renewables
Accent Energy Holdings, LLC
Agway Energy Services, LLC
Ameren Energy Marketing
Amigo Energy
Anthracite Power & Light
AP Holdings, LLC
APN Starfirst, L.P.
APNA Holdings LLC dba APNA Energy
CPL Retail Energy, LP

CA
NY,TX
NY
IL
TX
PA
NY,PA,TX
PA
TX
TX

Wholesale Power Marketer
AES Eastern Energy LP
Badger Power Marketing Auth
CL Power Sales Eight LLC
CP Power Sales Seventeen LLC
Dynegy Power Marketing, LLC

NV
WI
CA
MA
TX

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission

97

Edison Mission Marketing & Trading, Inc. - WSPP
GenOn Energy Management, LLC
Great Bay Power Marketing, Inc.
Guthrie County Rural Electric Cooperative
H.Q. Energy Services (U.S.) Inc.
JP Morgan
Luminant Energy Company LLC
Macquarie Energy LLC
NextEra Energy Power Marketing, LLC
PPL EnergyPlus LLC
PSEG Energry Resources & Trade LLC
Rainbow Energy Marketing Corporation
RRI Energy Services, LLC
Select Energy, Inc.
Sunflower Electric Power Corporation
TransAlta Energy Marketing

98 Federal Energy Regulatory Commission

MA
FL,IL,MA,MD,MS,NJ,NY,OH,PA,TX,VA
MA,ME,NH,NJ,NY,VT
IA
CT
TX
TX
TX
FL
MT
NJ
ND
TX
TX
KS
NY

2012 Assessment of Demand Response and Advanced Metering

APPENDIX F: DEMAND RESPONSE PROGRAMS AND SERVICES AT
RESPONDING ENTITIES
Appendix F lists entities that responded to the 2012 FERC Survey and indicated that they offer one or more
demand response programs, organized by demand response program type.
Entergy Gulf States Louisiana, L.L.C.

Critical Peak Pricing
Butler Rural Electric Cooperative, Inc.
Canadian Valley Electric Cooperative
City of Algona
City of Palo Alto Utilities

ISO New England
Niagara Mohawk Power Corporation
PJM Interconnection, LLC
Southern California Edison (SCE)

Clay Electric Cooperative, Inc.
Fairfield Electric Cooperative Inc.
Flint Electric Membership Corporation
Green Mountain Power Corporation
High Plains Power, Inc.
Jackson Electric Membership Corporation
JEA
OGE Energy Corporation
Rayle Electric Membership Corporation
Red River Valley Rural Electric Association
Richmond Power and Light
Rural Electric Cooperative, Inc.
Sacramento Municipal Util Dist
San Diego Gas & Electric
Sioux Valley SW Elec Coop
Southern California Edison (SCE)
Tampa Electric Company
The Detroit Edison Company
Town of High Point
United Power
Wisconsin Public Service Corporation
Wynnewood City Utilities Authority

Direct Load Control

Critical Peak Pricing with Load Control

C&L Electric Cooperative Corporation
Caddo Electric Cooperative, Inc.
Capital Electric Cooperative, Inc.
Carroll Electric Cooperative Corporation
Carroll Electric Membership Corporation
Cass County Electric Cooperative
Central Alabama Electric Cooperative
Central Electric Cooperative
Central Electric Cooperative, Inc.
Central Georgia Electric Membership Corp.
Central Vermont Public Service Corporation
Charles Mix Electric
Citizens' Electric Company
City of Big Stone City
City of East Grand Forks - (MN)
City of Gothenburg
City of Groton
City of Halstad

Adams Electric Cooperative, Inc.
Arizona Public Service
Cass County Electric Cooperative
City of Monroe
Coles-Moultrie Electric Cooperative
Dairyland Power Cooperative
Flathead Electric Cooperative, Inc.
Municipal Services Commission
Northwestern Electric Cooperative, Inc.
Otter Tail Power Company
Sacramento Municipal Utility District
Salt River Project Agricultural Improvement & Power District
San Diego Gas & Electric
Sioux Valley SW Elec Coop
Town of High Point
Warren Electric Cooperative, Inc

Demand Bidding & Buy-Back
City of Glendale
City of Milford
Connecticut Light and Power Company
Duke Energy Carolinas, LLC
Duke Energy Corporation
Duke Energy Indiana, Inc.
City of Saint Peter

2012 Assessment of Demand Response and Advanced Metering

A & N Electric Cooperative
Adams Electric Cooperative
Adams Electric Cooperative, Inc.
Adams-Columbia Electric Cooperative
Alabama Municipal Electric Authority
Alabama Power Company
Allegheny Electric Cooperative, Inc.
Ames, City of
Ashley-Chicot Electric Cooperative, Incorporated
Austin Utilities
Baltimore Gas and Electric Company
BARC Electric Coop Inc
Barnesville Municipal Electric
Bedford Rural Elec Coop, Inc
Black Hills Electric Cooperative, Inc
Blooming Prairie Public Utility Commission
Bon Homme Yankton Electric Association, Inc.
Brunswick Electric Membership Corporation
Burlington Electric Department
Butler Public Power District
Butler Rural Electric Cooperative, Inc.
Butte Electric Cooperative

City of Hawarden City of Milford
City of Milford
City of Olivia (MN)
City of Port Angeles
City of Rock Hill
City of Roseau
City of Roseville
City of St. James

Federal Energy Regulatory Commission

99

Direct Load Control (Continued)
City of Valley City
City of Vermillion
City of Wadena Electric & Water
City of Winner
Claverack REC
Clay County Electric Cooperative Corporation
Clay-Union Electric Corporation
Cleveland Electric Illuminating Co
Coles-Moultrie Electric Cooperative
Commonwealth Edison Company
Connexus Energy
Consolidated Edison Company of New York
Cooperative Light and Power
Corn Belt Energy Corporation
Corn Belt Power Cooperative
Craighead Electric Cooperative Corporation
Crow Wing Cooperative Power & Light Company
Dairyland Power Cooperative
Dakota Electric Association
Delaware Electric Cooperative, Inc.
Delmarva Power and Light Company
Dixie Electric Membership Corporation
Douglas Electric Cooperative, Inc.
Duke Energy Carolinas, LLC
Duke Energy Corporation
Duke Energy Indiana Inc
Duke Energy Kentucky, Inc.
East River Electric Power Cooperative, inc.
Elk River Municipal Utilities
Elkhorn Rural Public Power District
Emerald People's Utility District
EnergyUnited Electric Membership Corporation
Entergy New Orleans, Inc.
Excelsior Electric Membership Corporation
Fairfield Electric Cooperative Inc.
Farmers Electric Cooperative Corporation
Farmers' Electric Cooperative, Inc.
Federated Rural Electric
First Electric Cooperative Corporation
Flint Electric Membership Corporation
Florida Power & Light Company
Fort Collins Utilities
Georgia Power
Grundy Electric Cooperative, Inc.
Hawaiian Electric Company, Inc.
Haywood Electric membership Corp.
H-D Electric Cooperative, Inc
Henry County REMC
Highline Electric Association
Idaho Power Company
Illinois Rural Electric Cooperative
Indiana Michigan Power Company
Interstate Power and Light Company
Itasca-Mantrap Cooperative Electrical Association
Jackson Electric Membership Corporation
Jackson Energy Cooperative Corp - (KY)

100 Federal Energy Regulatory Commission

Jefferson Energy Cooperative
Jersey Central Power & Light Co
Kansas City Power & Light Company
Kansas Gas & Electric Company
KCP&L Greater Missouri Operations Company
Kingsbury Electric Cooperative, Inc.
Lake Region Electric Cooperative
Lee County Electric Cooperative, Incorporated
Louisville Gas & Electric and Kentucky Utilities
Marshall Municipal Utilities
McLean Electric Coop
McLeod Cooperative Power Association
Mecklenburg Electric Cooperative
Menard Electric Cooperative
Metropolitan Edison Co
MidAmerican Energy Company
Midwest Electric, Inc.
Midwest Energy Cooperative
Midwest Energy, Inc.
Midwest ISO
Minnesota Valley Electric Cooperative
Minnkota Power Cooperative, Inc.
Mississippi County Electric Cooperative, Inc.
Moorhead Public Service
Mountain View Electric Association, Inc.
Municipal Commission of Boonville
Nevada Power Company
Nobles Cooperative Electric
North Arkansas Electric Cooperative, Incorporated
North Carolina Electric Membership Corp
North Central Electric Coop
Northeastern REMC
Northern Municipal Power Agency
Northern Virginia Electric Cooperative
Oahe Electric Cooperative Inc.
Ohio Edison Co
Osceola Electric Cooperative, Inc.
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Pee Dee Electric Membership Corp.
Pennsylvania Electric Co
Pennsylvania Power Co
People's Electric Cooperative
Perennial Public Power District
Piedmont Electric Membership Corporation
Pocahontas Municipal Utilities
Potomac Electric Power Company
Power Choice/ Pepco Energy Services
Prince George Electric Cooperative
Princeton Public Utilities Commission
Progress Energy Carolinas
Progress Energy Florida
Public Service Electric & Gas Company
Puget Sound Energy, Inc.
Rappahannock Electric Cooperative

2012 Assessment of Demand Response and Advanced Metering

Direct Load Control (Continued)
Renville-Sibley Cooperative Power Association
Rolling Hills Electric Cooperative, Inc.
Sacramento Municipal Utility District
San Diego Gas & Electric
Santee Electric Cooperative, Inc.
Shakopee Public Utilities Commission
Shelby Electric Cooperative
Shenandoah Valley Electric Cooperative
Sioux Center Municipal Electric Utility
Sioux Valley SW Elec Coop
South Central Electric Association
South Central Power Company
Southeastern Electric Cooperative, Inc.
Southern California Edison (SCE)
Southern Indiana Gas & Elec
Southern Indiana REC, Inc.
Southern Maryland Electric Cooperative, Inc.

Manitowoc Public Utilities
Midwest ISO
Monongahela Power Co
Nebraska Public Power District
New York Independent System Operator
New York State Electric & Gas
Niagara Mohawk Power Corporation
Northern Virginia Electric Cooperative
Pacific Gas and Electric Company
Rochester Gas & Electric
Sacramento Municipal Utility District
Sierra Pacific Power Company
Southern California Edison (SCE)
Tampa Electric Company
The United Illuminating Company
West Penn Power Company

Southwest Public Power District
Southwestern Electric Power Company
Spring Valley Public Utilities
Steuben Rural Electric Cooperative, Inc.
Sumter Electric Cooperative, Inc.
Superior Water, Light and Power Company
Tampa Electric Company
The Detroit Edison Company
The Frontier Power Company
The Midwest Electric Cooperative Corporation
The Toledo Edison Co
Town of Massena Electric Department
Tucson Electric Power
TXU Energy Retail Company LLC
Union County Electric Cooperative, Inc.
United Electric Cooperative
United Power
Virginia Electric & Power Co
Westar Energy, Inc.
Whetstone valley electric cooperative, Inc
Wiregrass Electric Cooperative, Inc.
Wisconsin Public Service Corporation
Wisconsin Power and Light Company
Woodruff Electric Cooperative Corporation
Xcel Energy
York Electric Cooperative, Inc.

Interruptible Load

Emergency Demand Response

City of Rock Hill
City of Saint Peter
City of Sheboygan Falls
City of Tallahassee Utilities
City Utilities of Springfield, MO
Clay Electric Cooperative, Inc.
Columbus Southern Power Company
Commonwealth Edison Company
Connecticut Light and Power Company
Connexus Energy
Consolidated Edison Company of New York
Consumers Energy Company

Central Hudson Gas & Electric Corporation
City of Columbus, Ohio
Electric Reliability Council of Texas
Energy spectrum, Inc
EnerNOC, Inc
ISO New England
Kansas City Power & Light Company
Keytex Energy LLC

2012 Assessment of Demand Response and Advanced Metering

Adams Electric Cooperative
Adams Electric Cooperative, Inc.
Alabama Power Company
APN Starfirst, L.P.
Appalachian Power Company
Arkansas Electric Cooperative Corporation
Atchison-Holt Electric Coop
Austin Utilities
Baltimore Gas and Electric Company
Blooming Prairie Public Utility Commission
Board of Public Utilities, City of McPherson
Bon Homme Yankton Electric Association, Inc.
Borough of Lansdale
Brunswick Electric Membership Corporation
C&L Electric Cooperative Corporation
Carroll Electric Cooperative Corporation
Carroll Electric Membership Corporation
Central Electric Cooperative
Central Iowa Power Cooperative
Central Vermont Public Service Corporation
City of Cartersville, Georgia
City of Elroy
City of Halstad
City of Lakeland, Lakeland Electric
City of Lincoln Electric System
City of Port Angeles

Federal Energy Regulatory Commission

101

Interruptible Load (Continued)
Corn Belt Energy Corporation
Crow Wing Cooperative Power & Light Company
Dairyland Power Cooperative
Dakota Electric Association
Delaware Electric Cooperative, Inc.
Dixie Escalante REA Inc.
Duke Energy Carolinas, LLC
Duke Energy Corporation
Duke Energy Indiana Inc
Duke Energy Kentucky, Inc.
Elk River Municipal Utilities
EnergyUnited Electric Membership Corporation
Entergy Arkansas Inc
Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana Inc
Entergy New Orleans, Inc.
Entergy Texas, Inc.
Federated Rural Electric
First Electric Cooperative Corporation
Florida Power & Light Company
Fort Collins Utilities
Four County EMC
Georgia Power
Green Mountain Power Corporation
Hawaiian Electric Company, Inc.
Howard Greeley Rural Public Power District
Idaho Power Company
Illinois Rural Electric Cooperative
Indiana Michigan Power Company
Interstate Power and Light Company
Itasca-Mantrap Cooperative Electrical Association
JEA
Jefferson Energy Cooperative
Kansas City Power & Light Company
Kansas Gas & Electric Company
KCP&L Greater Missouri Operations Company
Kentucky Power Company
Lake Country Power
Lake Region Electric Cooperative
Lamb County Electric Cooperative
Lee County Electric Cooperative, Incorporated
Linn County Rural Electric Cooperative Association
Louisville Gas & Electric and Kentucky Utilities
Loup River Public Power District
Loup Valleys Rural Public Power District
Marshall Municipal Utilities
Mecklenburg Electric Cooperative
Menard Electric Cooperative
MidAmerican Energy Company
Midwest Energy Cooperative
Midwest Energy, Inc.
Midwest ISO
Minnesota Power, Inc.
Minnesota Valley Electric Cooperative
Mississippi County Electric Cooperative, Inc.
Mississippi Power

102 Federal Energy Regulatory Commission

Moorhead Public Service
Mountain View Electric Association, Inc.
Municipal Electric Utility of the City of Cedar Falls, Iowa
New York Power Authority
Nobles Cooperative Electric
North Carolina Electric Membership Corp
Northern Virginia Electric Cooperative
NorthWestern Energy
Ocmulgee Electric Membership Corporation
Ohio Power Company
OSCEOLA ELECTRIC COOPERATIVE, INC.
Ouachita Electric Cooperative Corporation
Ozarks Electric Cooperative Corporation
Pacific Gas and Electric Company
PECO Energy Company
Prince George Electric Cooperative
Progress Energy Carolinas
Progress Energy Florida
Public Service Company of Oklahoma
Public Service Electric & Gas Company
Rappahannock Electric Cooperative
Richards Energy Group, Inc.
Sacramento Municipal Utility District
Salt River Project Agricultural Improvement & Power
District
San Diego Gas & Electric
Shelby Electric Cooperative
Shenandoah Valley Electric Cooperative
South Carolina Electric & Gas Company
South Carolina Public Service Authority
South Central Arkansas Electric Cooperative, Incorporated
South Central Electric Association
South Kentucky Rural Electric Cooperative Corp
Southern California Edison (SCE)
Southern Indiana Gas & Electric Co
Southern Maryland Electric Cooperative, Inc.
Southwest Arkansas Electric Cooperative Corporation
Southwestern Electric Power Company
Spencer Municipal Utilities
Sumter Electric Cooperative, Inc.
T.I.P. Rural Electric Cooperative
Tampa Electric Company
Tennessee Valley Authority
The Detroit Edison Company
The Empire District Electric Company
The Potomac Edison Company
The Satilla Rural Electric Membership Corporation
Tucson Electric Power
Union County Electric Cooperative, Inc.
Upper Peninsula Power Corporation
Virginia Electric & Power Co
Warren Electric Cooperative, Inc
Webster Electric Cooperative
West Penn Power Company
Westar Energy, Inc.
Wheeling Power Company
Whetstone Valley Electric Cooperative, Inc

2012 Assessment of Demand Response and Advanced Metering

Interruptible Load (Continued)
Wisconsin Electric Power Company
Wisconsin Public Service Corporation
Wisconsin Power and Light Company
Woodruff Electric Cooperative Corporation
WPPI Energy
Xcel Energy

Northwestern REC
Oklahoma Electric Cooperative
Orange & Rockland Utilities Inc
Puget Sound Energy, Inc.
Rockland Electric Co
Salt River Project Agricultural Improvement & Power
District
Sierra Electric Cooperative, Inc.
South Carolina Electric & Gas Company
Southern California Edison (SCE)
Southwest Power Pool

Load as a Capacity Resource

Spring Valley Public Utilities
United Electric Cooperative Services, Inc.
United Power
Western Massachusetts Electric Company
Wisconsin Electric Power Company
Withlacoochee River Electric Cooperative, Inc.

Arizona Public Service
Brazos Electric Power Cooperative, Inc.
Cass County Electric Cooperative
City of Radford - Electric Department
Cooperative Light and Power
EnerNOC, Inc
Idaho Power Company
Memphis Light, Gas & Water Division
Midwest ISO
New York Independent System Operator
PJM Interconnection, LLC
Public Service Company of New Mexico (PNM)
Salt River Project Agricultural Improvement & Power District
San Diego Gas & Electric
Southern California Edison (SCE)
Tampa Electric Company
Tri-County Electric Cooperative, Inc

Peak Time Rebate

West Penn Power Company
Wisconsin Electric Power Company
WPPI Energy

Real-Time Pricing

Non-spinning Reserves

Duke Energy Carolinas, LLC Duke Energy Corporation
Duke Energy Kentucky, Inc.
Entergy Arkansas Inc
Georgia Power

California Independent System Operator
PJM Interconnection, LLC

Other
Board of Public Utilities, City of McPherson
Carroll Electric Membership Corporation
Central Electric Cooperative, Inc.
City of Ceylon
Consolidated Edison Company of New York
Consumers Energy Company
Delaware Electric Cooperative, Inc.
Eastern Maine Electric Cooperative, Inc
Eastside Power Authority
Entergy Arkansas Inc
Fairburn Utilities
ISO New England
Itasca-Mantrap Cooperative Electrical Association
Louisville Gas & Electric and Kentucky Utilities
Minnesota Valley Electric Cooperative
Mountain View Electric Association, Inc.
Nebraska Public Power District
New York Independent System Operator

2012 Assessment of Demand Response and Advanced Metering

Entergy New Orleans, Inc.
Granite State Electric Company
Grundy Electric Cooperative, Inc.
Massachusetts Electric Company
Nantucket Electric Company
OGE Energy Corporation
Oklahoma Electric Cooperative
The Narragansett Electric Company
Tri-County Electric Cooperative, Inc.

Alpena Power Company
Commonwealth Edison Company

Gulf Power Company
Indiana Michigan Power Company
Kansas City Power & Light Company
KCP&L Greater Missouri Operations Company
Kentucky Power Company
MidAmerican Energy Company
New York State Electric & Gas
Niagara Mohawk Power Corporation
Northern Neck Electric Cooperative
Northern Virginia Electric Cooperative
OGE Energy Corporation
Otter Tail Power Company
Progress Energy Carolinas
Public Service Company of Oklahoma
Public Service Electric & Gas Company
Rochester Gas & Electric
South Carolina Public Service Authority
Southern California Edison (SCE)
Tennessee Valley Authority

Federal Energy Regulatory Commission

103

Real-Time Pricing (Continued)
Upper Peninsula Power Corporation
Virginia Electric & Power Co
West Penn Power Company
Wisconsin Public Service Corporation
Xcel Energy

City of Rancho Cucamonga
City of Rock Hill
City of Roseville
City of Salem
City of Tallahassee Utilities
City of Westfield

Regulation

Clark County REMC
Claverack REC
Clay Electric Cooperative, Inc.
Clintonville Utilities

ISO New England
PJM Interconnection, LLC

Spinning Reserves

Colorado Springs Utilities
Columbus Southern Power Company
Columbus Water & Light Dept.
Connecticut Light and Power Company
Consumers Energy

Electric Reliability Council of Texas
EnerNOC, Inc
New York Independent System Operator

System Peak Response Transmission Tariff
Jefferson Energy Cooperative
Nueces Electric Cooperative
Red River Valley Rural Electric Association

Time-of-Use
A & N Electric Cooperative
Adams Electric Cooperative
Adams Electric Cooperative, Inc.
Algoma Utility Commission
Appalachian Power Company
Arizona Public Service
Bangor Hydro Electric Company
Bear Valley Electric Service
Bedford Rural Elec Coop, Inc
Bloomer Electric & Water Co
Board of Public Utilities, City of McPherson
Boscobel Municipal Utilities
Broad River Electric Cooperative, Inc.
Brodhead Water & Light Commission
Burlington Electric Department
Butler Rural Electric Cooperative Association, Inc.
Carbon Power & Light Inc
Cedarburg Light & Water Commission
Central Hudson Gas & Electric Corporation
Central Maine Power Co
Central Vermont Public Service Corporation
Chicopee Municipal Lighting Plant
City of Boulder City
City of Carlyle, Illinois
City of Carmi, Illinois
City of Crystal Falls
City of Gastonia
City of Glendale
City of Lakeland, Lakeland Electric
City of Lodi
City of Milford
City of North Saint Paul
City of Palo Alto Utilities
City of Pasadena

104 Federal Energy Regulatory Commission

Cooperative Light and Power
Coosa Valley Electric Cooperative
Crawfordsville Electric Light & Power
Crow Wing Cooperative Power & Light Company
Cuba City Electric & Water Utility
Dairyland Power Cooperative
Delaware Electric Cooperative, Inc.
Delmarva Power and Light Company
Dixie Escalante REA Inc.
Duke Energy Carolinas, LLC
Duke Energy Corporation
Duke Energy Indiana Inc
Duke Energy Kentucky, Inc.
Eagle River Light & Water Commission
Eastside Power Authority
Edgecombe-Martin County Electric Membership Corp.
Empire Electric Association, Inc.
Entergy Arkansas Inc
Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana Inc
Entergy Texas, Inc.
Evansville Water & Light
Fitchburg Gas and Electric Light Company
Flathead Electric Cooperative, Inc.
Flint Electric Membership Corporation
Florence Utility Commission
Florida Power & Light Company
Florida Public Utilities Co.
Gaffney Board of Public Works
Georgia Power
Grand Haven Board of Light and Power
Grand River Dam Authority
Green Mountain Power Corporation
Groton Electric Light Dept.
Gulf Power Company
Hartford Utilities
Hawaii Electric Light Company, Inc.
Hawaiian Electric Company, Inc.
Haywood Electric membership Corp.
Hendricks County Rural Electric Membership Cooperative
High Plains Power, Inc.

2012 Assessment of Demand Response and Advanced Metering

Time-of-Use(Continued)
Highline Electric Association
Holy Cross Electric Assn, Inc
Hustisford Utilities
Indiana Michigan Power Company
Inter County Energy Cooperative
Interstate Power and Light Company
Itasca-Mantrap Cooperative Electrical Association
Jackson County Rural electric Membership Corporation
Jackson Electric Membership Corporation
JEA
Jefferson Energy Cooperative
Jefferson Water & Light Dept.
Jemez Mountains Electric Cooperative, Inc.
Jo-Carroll Energy, Inc.(NFP)
Juneau Utility Commission
Kansas City Power & Light Company
Kansas Gas & Electric Company
Kaukauna Utilities
KCP&L Greater Missouri Operations Company
Kentucky Power Company
Kingsport Power Company
Kissimmee Utility Authority
La Plata Electric Assn. Inc.
Lake Country Power
Lake Mills Light & Water Dept.
Linn County Rural Electric Cooperative Association
Lodi Municipal Light & Water Utility
Los Angeles Department of Water and Power
Manitowoc Public Utilities
Maui Electric Company, Limited
McLeod Cooperative Power Association
Mecklenburg Electric Cooperative
Medford Electric Utility
Memphis Light, Gas & Water Division
Menasha Electric & Water Utilities
MidAmerican Energy Company
Midwest Energy Cooperative
Mississippi Power
Mount Horeb Electric Utility
Mountain Parks Electric, Inc.
Mountain View Electric Association, Inc.
Muscoda Light & Water Utility
Nebraska Public Power District
New Glarus Light & Water Works
New Holstein Public Utility
New London Electric & Water Utility
New Richmond Municipal Electric Utility
New York State Electric & Gas
Niagara Mohawk Power Corporation
North Little Rock Electric Department
Northeastern REMC
Northern Neck Electric Cooperative
Northern Virginia Electric Cooperative
Northwestern Electric Cooperative, Inc.
NorthWestern Energy
Northwestern REC

2012 Assessment of Demand Response and Advanced Metering

Oconto Falls Water & Light Commission
OGE Energy Corporation
Ohio Power Company
Okefenoke Rural El Member Corp
Oklahoma Electric Cooperative
Orange & Rockland Utilities Inc
Orlando Utilities Commission
Otero County Electric Cooperative, Inc.
Otter Tail Power Company
Ozark Border Electric Cooperative
Pee Dee Electric Membership Corp.
Piedmont Electric Membership Corporation
Pioneer Electric Cooperative, Inc.
Plymouth Utilities
Potomac Electric Power Company
Poudre Valley Rural Electric Association, Inc.
Prairie du Sac Municipal Electric & Water
Progress Energy Carolinas
Progress Energy Florida
Public Service Company of New Hampshire
Public Service Company of Oklahoma
Public Service Electric & Gas Company
PUD No 1 of Klickitat County
Rappahannock Electric Cooperative
Reedsburg Utility Commission
Rice Lake Utilities
Richland Center Electric Utility
Richmond Power and Light
River Falls Municipal Utility
Riverside Public Utilities
Rochester Gas & Electric
Rockland Electric Co
Sacramento Municipal Utility District
Salt River Project Agricultural Improvement & Power District
Sangre de Cristo Electric Association
Sierra Electric Cooperative, Inc.
Slinger Utilities
Snohomish County PUD No 1
South Carolina Electric & Gas Company
South Carolina Public Service Authority
South Central Electric Association
South Kentucky Rural Electric Cooperative Corp
South Mississippi Electric Power Association
Southwestern Electric Power Company
Steuben Rural Electric Cooperative, Inc.
Stoughton Electric Utility
Sturgeon Bay Utilities
Sun Prairie Water & Light Commission
Superior Water, Light and Power Company
Tampa Electric Company
Tennessee Valley Authority
The Detroit Edison Company
The Empire District Electric Company
The Satilla Rural Electric Membership Corporation
Tri-County Electric Cooperative, Inc
Tucson Electric Power

Federal Energy Regulatory Commission

105

Time-of-Use(Continued)
Turlock Irrigation District
Two Rivers Water & Light Utility
TXU Energy Retail Company LLC
Union Electric Company
United Electric Cooperative Services, Inc.
United Power
Valley Rural Electric Cooperative, Inc.
Village of Stratford
Virginia Electric & Power Co
Wake Electric
Waterloo Water & Light Commission
Waunakee Water & Light Commission
Waupun Utilities
Waverly Municipal Elec Utility
Westar Energy, Inc.
Westby Municipal Electric Utility
Western Indiana Energy REMC
Western Massachusetts Electric Company
Wheatland Rural Electric Cooperative
Wheeling Power Company
Wisconsin Public Service Corporation
Wisconsin Power and Light Company
WPPI Energy
Xcel Energy

106 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

APPENDIX G: DATA FOR FIGURES IN REPORT
Advanced Metering
Data supporting Figure 2-1
Estimated advanced metering penetration nationwide in 2006, 2008, 2010, and 2012 FERC Surveys
Year
2006
2008
2010
2012

Advanced Metering
0.7%
4.7%
8.7%
22.9%

Data supporting Figure 2-2
Estimated advanced metering penetration nationwide reported in 2006, 2008, 2010 and 2012 FERC Surveys
Region
ASCC
FRCC
Hawaii
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
United States

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

2008 FERC
Survey
0.0%
10.4%
1.6%
3.7%
0.3%
5.1%
5.8%
5.8%
9.0%
2.1%
4.7%

2010 FERC
Survey
1.2%
5.0%
2.1%
15.3%
0.7%
6.7%
8.0%
8.9%
13.4%
14.1%
8.7%

2012 FERC
Survey
0.0%
32.5%
0.2%
14.6%
5.3%
10.4%
22.0%
15.2%
38.6%
42.4%
22.8%

Data supporting Figure 2-3
Estimated advanced metering penetration by type of entity in 2006, 2008, 2010, and 2012 FERC Surveys
Ownership
Cooperatives
Political Subdivision
Investor-owned
Utility
Municipal Entities
Federal and State
Utility
Overall Average

2006 FERC
Survey
3.8%
0.1%

2008 FERC
Survey
16.4%
2.2%

2010 FERC
Survey
24.7%
20.3%

2012 FERC
Survey
30.8%
29.4%

0.2%
0.3%

2.7%
4.9%

6.6%
3.6%

25.0%
12.4%

0.2%
0.7%

1.1%
4.7%

0.7%
8.7%

3.6%
22.8%

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission

107

Data supporting Figure 2-4
Reported numbers of customers and communication methods for advanced metering by customer class
Customer Sector

Internet

Bills

Display Unit

Communications Vehicles
to Residential Customers
(n = 17,365,353)

92% (n = 15,961,296)

7% (n = 1,297,960)

1% (n = 106,097)

Communications Vehicles
to
Nonresidential
Customers (n = 1,587,655)

91% (n = 1,448,672)

9% (n = 136,754)

0% (n = 2,229)

Communications Vehicles
to Other Customers (n =
125,695)

93% (n = 116,922)

7% (n = 8,769)

0% (n = 4)

Demand Response
Data supporting Figure 3-1
Total reported potential peak reduction in the 2006 through 2012 FERC Surveys
Total reported
potential peak
FERC Survey Year
reduction (MW)
2006 FERC Survey
29,653
2008 FERC Survey
37,335
2010 FERC Survey
53,062
2012 FERC Survey
66,351

Data supporting Figure 3-2
Reported potential peak reduction by customer class in 2006, 2008, 2010, and 2012 FERC Surveys (MW)
Commercial
FERC Survey Year
& Industrial Residential Wholesale
Other
Total
2006 FERC Survey
14,362
5,803
8,899
589
29,653
2008 FERC Survey
17,434
6,056
12,656
1,190
37,335
2010 FERC Survey
21,405
7,189
22,884
1,584
53,062
2012 FERC Survey
28,088
8,134
28,807
1,321
66,351

108 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Data supporting Figure 3-3
Reported potential peak reduction by Independent System Operators and Regional Transmission Operators
in 2010 and. 2012 (MW)
ISO/RTO

CAISO

ERCOT

ISO-NE

MISO

NY-ISO

PJM

SPP

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

120

0

0

0

91

202

210

0

0

37

2,635

2,252

0

0

0

0

0

0

0

0

60

0

0

0

0

0

0

0

0

0

237

420

2,092

1,029

230

2,149

972

197

7,295

0

0

0

0

0

0

0

0

0

4,800

7,380

2,061

1,976

0

11,82
1

0

0

0

120

0

0

0

0

0

0

0

118

54

0

0

0

0

0

0

0

0

0

258

37

0

0

1,385

1,514

Regulation

0

0

10

0

0

0

0

0

0

0

0

0

0

0

Spinning
Reserves

0

0

1,062

1,150

0

0

0

0

0

0

406

0

0

0

Program
Type
Demand
Bidding &
Buy-Back
Direct Load
Control
Emergency
Demand
Response
Load as a
Capacity
Resource
Nonspinning
Reserves
Other

Data supporting Figure 3-4
Reported potential peak reduction by region and customer class for the 2010 and 2012 FERC Survey
Region

Commercial &
Industrial
2010

Residential

2012

2010

Wholesale

2012

2010

Other

2012

2010

Total

2012

2010

2012

FRCC

1,310

1,952

1,765

1,804

15

15

68

35

3,158

3,807

MRO

3,320

3,264

1,806

1,540

4,045

5,115

315

251

9,485

10,170

NPCC

1,490

719

90

34

4,649

2,972

0

0

6,228

3,725

RFC

5,267

7,476

1,139

2,100

9,199

14,677

259

128

15,864

24,381

SERC

6,451

8,672

798

1,046

1,733

2,881

172

210

9,154

12,809

SPP

1,404

2,667

79

220

1,502

1,456

141

126

3,126

4,469

TRE

72

4

123

66

1,312

1,572

3

0

1,510

1,642

WECC

2,062

3,287

1,369

1,307

430

120

626

571

4,487

5,284

Other

29

48

20

17

0

0

0

0

49

65

Total

21,405

28,088

7,189

8,134

22,884

28,807

1,584

1,321

53,062

66,351

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission

109

Data supporting Figure 3-5
Reported potential peak reduction in by type of program type and by customer class in 2012 FERC Survey
Commercial
Type of Program
& Industrial Residential Wholesale
Other
Total
Critical Peak Pricing
261
54
6
0
321
Critical Peak Pricing with
Load Control
129
2
0
15
147
Demand Bidding & BuyBack
139
0
3,927
0
4,066
Direct Load Control
1,638
6,940
666
534
9,777
Emergency
Demand
Response
494
110
3,734
0
4,339
Interruptible Load
14,268
45
685
649
15,647
Load as a Capacity
Resource
2,649
77
16,600
0
19,327
Non-spinning Reserves
0
0
174
0
174
Other
105
40
1,076
54
1,276
Peak Time Rebate
58
1
0
0
59
Real-Time Pricing
1,868
6
0
0
1,874
Regulation
0
0
0
0
0
Spinning Reserves
40
0
1,150
0
1,190
System Peak Response
Transmission Tariff
12
0
0
0
13
Time-of-Use
6,425
858
789
69
8,141
Total
28,088
8,134
28,807
1,321
66,351
Data supporting Figure 3-6 and 3-7
Reported potential and actual 2012 peak reduction by demand response resources by region
Region

FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Other
Total

Potential Peak
Reduction
2012
3,807
10,170
3,725
24,381
12,809
4,469
1,642
5,284
65
66,351

110 Federal Energy Regulatory Commission

Actual Peak Reduction
2010
957
2,462
2,497
2,051
3,086
1,466
422
2,667
352
15,980

2012
966
2,709
3,151
3,651
3,520
1,863
1,470
2,870
55
20,256

2012 Assessment of Demand Response and Advanced Metering

Data supporting Figure 3-8
Estimated potential peak reduction by region and customer class in 2010 and 2012
Region

Commercial &
Industrial

Residential

Wholesale

Other

Total

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

FRCC

1,333

1,974

1,795

1,845

15

15

73

52

3,216

3,887

MRO

3,932

4,912

2,102

2,232

4,045

5,115

339

360

10,418

12,619

NPCC

1,954

739

98

91

4,649

2,972

173

8

6,875

3,811

RFC

6,334

7,882

1,427

2,373

9,199

14,677

371

424

17,331

25,356

SERC

7,005

9,331

1,575

1,419

1,733

2,881

208

301

10,521

13,932

SPP

1,572

2,915

80

236

1,502

1,456

154

133

3,307

4,740

TRE

113

262

134

143

1,312

1,572

53

5

1,612

1,981

WECC

2,344

3,208

1,581

1,254

430

120

626

639

4,981

5,221

Other

53

85

25

22

78

0

0

0

0

107

Total

24,640

31,310

8,817

9,616

22,884

28,807

1,998

1,921

58,339

71,654

Data supporting Figure 3.9
Estimated potential peak reduction by entity type and customer class in 2010 and 2012
Ownership

Residential

Commercial &
Industrial

Other Retail

Wholesale

Total

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

Cooperative
Entities
Federal & State

2,836

2,623

3,726

2,320

855

657

1,420

1,231

8,837

6,830

17

42

1,104

4,694

50

48

920

1,910

2,091

6,694

InvestorOwned Utilities
Municipal
Entities
RTO/ISO

5,433

6,180

17,634

20,331

827

850

0

116

23,894

27,476

530

489

922

1,474

25

31

11

62

1,488

2,056

0

0

0

0

0

0

20,533

25,489

20,533

25,489

Retail Power
Marketers
Other

0

65

961

0

241

0

0

0

1,202

65

0

217

0

2,490

0

335

0

0

0

3,043

8,816

9,616

24,347

31,310

1,998

1,921

22,884

28,807

58,045

71,654

Total

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission

111

Data supporting Figure 3-10
Number of entities reporting interruptible/curtailable rates by region and type of entity in 2010 and 2012
Region

Cooperative
Entities
2010

FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Total

Federal and
State

2012
3
18
0
6
27
5
0
2
61

3
26
0
10
33
10
2
3
87

2010

InvestorOwned Utilities

2012
0
0
1
0
2
0
0
0
3

0
0
0
0
2
0
0
0
2

2010
3
6
6
22
10
7
0
6
60

Municipal
Entities

2012
3
9
4
20
13
8
0
6
63

2010

Other

2012 2010
0
3
2
9
1
0
1
2
0
2
0
3
1
0
1
3
6
22

4
13
1
2
4
3
0
1
28

Total

2012
0
5
0
3
0
0
0
1
9

2010
10
47
8
35
49
20
3
11
183

2012
9
41
5
31
44
16
0
12
158

Data supporting Figure 3-11
Reported number of customers enrolled in direct load control programs by region and type of entity in 2010
and 2012
Region

Cooperative
Entities
2010

FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Total

Federal and
State

Investor- Owned
Utilities

2012 2010 2012

2010

2012

2010

Other

2012 2010

Total

2012

2010

2012

60,588

62,363

0

0

1,247,228

1,273,398

0

0

0

0

1,307,816

1,335,761

406,632

311,763

2,365

0

507,152

621,613

48,849

31,454

0

21,899

964,998

986,729

6,261

645

0

0

39,634

48,630

32,660

2,739

0

0

78,555

52,014

294,278

105,646

0

0

1,203,367

1,470,728

2,270

2,050

0

7

1,499,915

1,578,431

421,625

285,054

0

0

347,748

525,778

29,577

3,000

0

0

798,950

813,832

13,119

8,220

0

0

35,479

87,331

0

0

1,869

48,598

97,420

0

0

0

5,457

0

0

779,148

2,365

0

4,602
1,207,105

Estimated total number of customers
FRCC
MRO
NPCC
RFC
9,184,587

Municipal
Entities

8,120,487

20,962,205

112 Federal Energy Regulatory Commission

35,925,110

0

85,000

0

171

11,500

85,171

11,500

821,610

885,822

6,872

10,362

0

1,526

833,084

903,167

4,202,218

4,913,300

205,228

49,605

171

36,801

5,617,087

5,778,854

SERC

SPP

TRE

WECC

Other

35,739,376

6,825,542

10,255,206

29,250,286

817,392

2012 Assessment of Demand Response and Advanced Metering

Data supporting Figure 3-12
Number of entities reporting residential time-of-use rates by region and type of entity in 2010 and 2012
Region

Cooperative
Entities
2010

Federal and
State

2012

2010

Investor- Owned
Utilities

2012

Municipal
Entities

2010

2012

2010

Other

2012

2010

Total

2012

2010

2012

FRCC

2

1

0

0

2

2

3

3

0

0

7

6

MRO

7

7

0

0

6

7

34

37

0

1

47

52

NPCC

3

1

1

0

7

11

3

3

3

0

17

15

RFC

9

9

0

0

9

13

1

2

0

0

19

24

SERC

12

13

1

1

8

9

0

1

0

0

21

24

SPP

3

2

0

0

2

3

0

0

0

0

5

5

TRE

1

0

0

0

0

0

0

0

0

1

1

1

WECC

16

15

0

0

4

2

4

6

3

1

27

24

Total

53

48

2

1

38

47

45

52

6

3

144

151

Data supporting Figure 3-13
Reported number of residential customers enrolled in time-of-use rate programs by region and type of entity
in 2010 and 2012
Region

FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Total

Cooperative
Entities

Federal
and State

Investor- Owned
Utilities

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

2010

2012

40

0

0

0

249

196

206

2,006

0

0

495

2,202

1,546

18,533

0

0

20,387

25,704

284

284

0

7,506

22,217

52,027

63

36

0

0

148,706

168,248

10,152

2,073

148

0

159,069

170,357

1,521

1,420

0

0

138,910

953,035

0

2

0

0

140,431

954,457

3,289

3,230

5

5

33,301

46,986

0

124

0

0

36,595

50,345

15

46,302

0

0

1,452

2,717

0

0

0

0

1,467

49,019

8

0

0

0

0

0

0

0

0

4,000

8

4,000

237,187

12,154

0

0

498,477

529,428

2,388

4,249

0

232,201

738,052

778,032

243,669

81,675

5

5

841,482

1,726,314

13,030

8,738

148

243,707

1,098,334

2,060,439

2012 Assessment of Demand Response and Advanced Metering

Municipal
Entities

Other

Total

Federal Energy Regulatory Commission

113

Data supporting Figure 3-14
Number of entities reporting retail real-time pricing by region and type of entity in 2010 and 2012
Region

Cooperative
Entities
2010

FRCC
MRO
NPCC

0

RFC
SERC
SPP
TRE
WECC
Total

0

0
1
0
1
0
0
2

Federal and
State

2012
0
0
0

2010

0
0
0
0
0
0

0

0
0
0
1
0
0
0
1

114 Federal Energy Regulatory Commission

InvestorOwned Utilities

2012
0
0
0

2010

2
0
0
0
0
2

7

0
4
2
3
4
0
1
21

Municipal
Entities

2012
5
3
8

2010

5
4
0
0
1
26

0

0
0
0
0
0
0
0
0

Other

2012
0
0
0

2010

0
0
0
0
0
0

0

0
0
0
1
0
0
0
1

2012 Assessment of Demand Response and Advanced Metering

Total

2012
0
0
0

2010

0
0
0
0
0
0

7

0
4
3
5
5
0
1
25

2012
5
3
8
7
4
0
0
1
28

APPENDIX H: ADJUSTMENT METHODOLOGY FOR FERC-731
SURVEY
The following four flow charts summarize the estimation process used for the 2012 FERC
Survey to assign estimated values for entities that did not respond to four key FERC Survey
fields: total meters, advanced meters, total customers, and potential peak load reduction. The
2012 estimation process utilized data from the initial 2011 EIA-861 Survey, along with
responses from the 2010 FERC Survey. In cases when an imputation could not be used, the
universe-level estimates are not accounting for those cases.
1. Missing from 2012 FERC Survey: Total Meters153
Residential

Commercial &
Industrial

Yes

2010 FERC
Responder?

Other

No

Impute by applying the respondent’s
customer-level growth rate from 2010
FERC Survey to the 2011 EIA-861
Survey. If Other, impute with direct
substitution from the 2010 FERC
Survey.
If Residential, do a 1:1 substitution using
the number of residential customers
reported in the 2011 EIA-861 Survey.
Otherwise, do not impute.

2. Missing from 2012 FERC Survey: Advanced Meters
Yes
Residential
2011 EIA861
Responder?

Commercial &
Industrial
Other

No

Direct substitution of 2011 EIA861 reported AMI meters,
according to procedure detailed
in Appendix D
If a 2010 FERC Survey
Responder, impute by applying
the 2010 to 2012 class-level
growth rate, according to the
2010 Assessment of Demand
Response
and
Advanced
Metering
Appendix
H.
Otherwise, do not impute.

153

Total meters for the commercial and industrial sectors did not have a strong enough correlation with total
customers to justify direct imputation of customers from either the EIA-861 or 2010 FERC Survey, when total
meters were not provided by the respondent.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 115

3. Missing from 2012 FERC Survey: Potential Peak Reduction
Yes
Do a 1:1 substitution using total MW
Residential
peak load reduction potential reported in
2011 EIA
the 2011 EIA-861 Survey
Responder?

Commercial &
Industrial
No
Other

Regression-based imputation using class
average growth from 2010 FERC Survey
to 2012 FERC Survey, applied to 2010
FERC data. If not a 2010 FERC Survey
responder, do not impute.

4. Missing from 2012 FERC Survey: Total Customers
Residential
Regression-based imputation using class
average growth from 2010 FERC Survey
to 2011 EIA-861 Survey, applied to
2010 FERC data

Commercial &
Industrial
Other

Self-Selection Assessment Subsample
The FERC Staff determined that the 2012 FERC Survey, to adhere with its Congressional
directive, should collect or estimate information on all entities that provide electric power
and demand response to customers in the U.S. However, the FERC Survey is voluntary, and
essentially a census of respondents to the EIA-861 Survey, with the addition of Regional
Transmission Operators (RTOs), Independent System Operators (ISOs), and curtailment
service providers. As such, there is inherent risk for self-selection bias; for example, some
entities may be more likely to respond to the FERC Survey if they have already deployed
advanced meters or demand response programs, and these are key measures of the survey.
Since the propensity to respond may be related to key measures in the FERC Survey, OMB
directed the Commission to assess the potential for self-selection bias in the FERC Survey, as
compared to traditional statistical sampling methods. As in previous survey years, the FERC
staff prepared a “bias assessment sample,” or a statistical subsample from the full survey
population. This section of the report describes the “bias assessment sample” design, and
compares the estimates derived from the full dataset with the corresponding estimates
produced from the bias assessment sample. If the corresponding estimates are within an
acceptable margin of error, it supports the hypothesis that a census of the target population
achieves as reliable estimates as a traditional statistical sample. However, significant
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2012 Assessment of Demand Response and Advanced Metering

differences in the corresponding estimates would indicate a significant risk for self-selection
bias in the FERC Survey.

Assessment of Past Designs
The designs for 2006 and 2008 bias assessment samples utilize known relationships of
advanced metering penetration with region, utility type, and utility size. Although
curtailment service providers and generation & transmission entities do not provide retail
electricity and have no advanced meters associated with them, they are unique and important
respondents to the survey, especially with respect to demand response data, so selecting these
respondents into the sample with certainty ensures they would be accounted for. The 2010
bias assessment sample was very similar to those constructed in 2006 and 2008, except for
utilizing ratio estimation rather than simple random sampling. This change improved the
sampling efficiency, but added complexity to the sample construction process.

2012 Self-Selection Bias Assessment Design
DNV KEMA maintained the same basic design used in 2006, 2008, and 2010, with some
modifications. Key features of the design are as follows:





Entities were stratified by state, ownership type, and size category (small, medium,
large, or other). In 2010, entities were stratified by NERC region rather than state.
Within strata, units were selected either with certainty or probability proportionate to
size (PPS). Entities were selected with certainty if they fell in the “large” size
category or they did not have a number of customers served for the state listed in the
EIA-861 Survey. Entities were selected PPS within the strata defined as above, with
proportional allocation of a target sample size of 750 among the entities in the various
strata.
The total sample size obtained was 797 EIA utility ID/state code combinations. Some
entities were included in the sample for more than one state, so the number of unique
EIA utility IDs was 727.

The switch to using state instead of NERC region for the geographic stratification component
was based on the addition of state-level estimates in the 2010 FERC Survey, as well as the
availability of state-level customer data in the EIA-861 Survey, but not by NERC. This
modification resulted in more strata, and fewer sample cases per strata, but better state-level
coverage overall.
The 2012 bias assessment sample design also selects more entities with certainty; all large
utilities and all entities without a listed number of customers served in a state were included
in the sample. Large utilities were selected with certainty because they tend to have a
disproportionally large contribution towards total advanced metering and demand response
estimates. Entities without an assigned number of customers were included with certainty
because without a measure of size to use in the sample selection, there was no other way to
include them without using a different sample design; this also helped minimize overall
sampling complexity and include respondents such as curtailment service providers.
2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 117

No special follow-up measures beyond that of the full mail-out sample was used in 2012. All
entities, whether in the sample or not, were subject to a follow-up based on their expected
contribution in the survey population.

Survey Response Rates
Entity Type

Cooperatively Owned Utility
Curtailment Service Provider
Federal Utility
Investor-Owned Utility
Municipal Power Agency
Municipally Owned Utility
Political Subdivision
Retail Power Marketer
State Utility
Generation
and
Transmission
Wholesale Power Marketer

Advanced
Metering
Response
Rate
53%
24%
63%
78%
58%
70%
44%
20%
35%
78%
19%

DR
Response
Rate
25%
24%
13%
64%
0%
19%
12%
4%
12%
0%
0%

Self-Selection Bias Assessment
The analysis of the FERC Survey subsample is geared towards determining whether a census
sample is necessary for determining reliable results for the key advanced metering and
demand response measures collected in the FERC Survey. The subsample versus full-sample
tabulated results for the following tables are given below:
 Estimated Advanced Metering Penetration by NERC Region and Entity Type
 Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector
Both tables use extrapolations to account for the full survey universe. The full-sample table
is taken directly from Appendix G and the subsample extrapolation uses sampling weights
with a ratio adjustment to account for nonresponse.

118 Federal Energy Regulatory Commission

2012 Assessment of Demand Response and Advanced Metering

Estimated Advanced Metering Penetration by NERC Region and Entity Type - FullSample Analysis
NERC
Cooperatively
Political
Investor- Municipally Federal Overall
Region Owned Utilities Subdivisions
Owned
Owned
and State
Utilities
Utilities
Utilities
FRCC
14%
0%
38%
14%
0%
32%
MRO
33%
4%
10%
4%
45%
15%
NPCC
20%
0%
7%
5%
0%
5%
RFC
36%
0%
10%
5%
1%
10%
SERC
36%
0%
19%
11%
1%
22%
SPP
29%
5%
14%
2%
91%
15%
TRE
17%
0%
72%
24%
0%
39%
WECC
26%
36%
48%
18%
23%
42%
Other
0%
0%
0%
5%
0%
2%
Overall
31%
29%
25%
12%
4%
23%
Estimated Advanced Metering Penetration by NERC Region and Entity Type Subsample Analysis
NERC
Cooperatively
Political
Investor- Municipally Federal Overall
Region Owned Utilities Subdivisions
Owned
Owned
and
Utilities
Utilities
State
Utilities
FRCC
30%
0%
38%
11%
0%
33%
MRO
44%
9%
18%
0%
78%
18%
NPCC
48%
0%
6%
0%
0%
6%
RFC
25%
0%
9%
1%
1%
9%
SERC
58%
0%
0%
21%
2%
16%
SPP
37%
0%
15%
0%
91%
17%
TRE
28%
0%
74%
8%
0%
58%
WECC
16%
35%
61%
46%
100%
57%
Other
0%
0%
3%
0%
0%
3%
Overall
46%
33%
23%
24%
12%
26%
The subsample analysis results for the chosen advanced metering table shows that overall,
the subsample performed well, with only a 3 percent difference in overall advanced metering
penetration in the U.S. and was only 2 percentage points different for investor-owned
utilities. Similarly, the results are extremely comparable for the NERC region marginal
totals. The penetration estimate for RFC, for example was 2 percentage points different for
the full sample and the subsample, and was even closer for NPCC. However, it is clear that
abandoning the census in favor for a sample would lead to self-selection bias for cooperatives
and municipally owned utilities, and for certain regions, as suggested by moderate pairwise
differences for MRO.

2012 Assessment of Demand Response and Advanced Metering

Federal Energy Regulatory Commission 119

Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector – Full Sample

Region
FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Other
Total

Commercial
& Industrial
1,974
4,912
739
7,882
9,331
2,915
262
3,208
85
31,310

Residential
1,845
2,232
91
2,373
1,419
236
143
1,254
22
9,616

Other
52
360
8
424
301
133
5
639
0
1,921

Total
3,872
7,504
839
10,680
11,051
3,284
409
5,101
107
42,847

Estimated Potential Peak Reduction by NERC Region and Retail Customer Sector - Subsample

Region
FRCC
MRO
NPCC
RFC
SERC
SPP
TRE
WECC
Other
Total

Commercial
& Industrial
1,952
3,754
733
11,642
10,251
4,834
29
3,658
47
36,900

Residential
1,804
1,662
23
3,481
1,830
414
737
1,565
19
11,535

Other
35
94
0
128
128
556
0
2,430
0
3,371

Total
3,792
5,511
756
15,251
12,209
5,804
766
7,653
65
51,807

The analysis results for demand response suggest that utilizing a statistical sample instead of
a census would lead to biased results. Unlike the advanced metering assessment, which
shows above that reliable results are achievable through aggregating the data by one
categorical variable, the demand response results show that most of the tabulations have
pairwise differences of 20 percent or more. It is therefore advisable to continue using a
census of the survey universe rather than using a statistical sample to maintain reliable survey
estimates for demand response.

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2012 Assessment of Demand Response and Advanced Metering