Demand Response and Advanced Metering

2018 Assessment of

Staff Report

Federal Energy Regulatory Commission

November 2018
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2018 

Assessment of 

Demand Response and Advanced Metering 

Staff Report 

Federal Energy Regulatory Commission 

November 2018 

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. 
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ACKNOWLEDGEMENTS

Federal Energy Regulatory Commission Staff Team

Ben Foster, Team Lead

David Burns

David Kathan 

Michael P. Lee 

Samin Peirovi
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Federal Energy Regulatory Commission Page i

TABLE OF CONTENTS

: Introduction .............................................................................................................. 1

: Saturation and penetration rate of advanced meters ................................................ 3

Developments and issues in advanced metering ..................................................................... 6

 : Annual resource contribution of demand resources ............................................... 12

Retail demand response programs ........................................................................................ 12

Wholesale demand response programs ................................................................................. 14

2018 demand response deployments .................................................................................... 17

 : Potential for demand response as a quantifiable, reliable resource for regional 

planning purposes ..................................................................................................................... 20

NERC’s Demand Response Availability Data System ......................................................... 20

 : Existing demand response programs and time-based rate programs and 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 ............... 21

Enrollment in retail demand response and time-based rate programs .................................. 21

FERC demand response orders and activities ....................................................................... 25

Other federal demand response activities ............................................................................. 27

Developments and issues in demand response ..................................................................... 28

 : Regulatory barriers to improved customer participation in demand response, peak 

reduction, and critical period pricing programs ........................................................................ 32

Appendix: Map of NERC Regional Entities (as of May 2017) ................................................ 35
Page ii Federal Energy Regulatory Commission

LIST OF TABLES & FIGURES

Table 2-1: Estimates of Advanced Meter Penetration Rate ............................................................ 3

Table 3-1: Potential Peak Demand Savings (MW) from Retail Demand Response Programs by 

NERC Region (2015 & 2016)....................................................................................................... 12

Table 3-2: Potential Peak Demand Savings (MW) from Retail Demand Response Programs by 

Region and Customer Class (2016) .............................................................................................. 14

Table 3-3: Demand Resource Participation in RTO/ISO Demand Response Programs .............. 15

Table 5-1: Customer Enrollment in Retail Demand Response Programs, by Region .................. 22

Table 5-2: Customer Enrollment in Retail Time-based Rate Programs, by Region (2015 & 2016)

....................................................................................................................................................... 24

Figure 2-1: Advanced Meter Growth (2007 – 2016) ...................................................................... 4

Figure 2-2: Number of Advanced Meters by NERC Region (2013 – 2016) .................................. 6

Figure 3-1: Potential Peak Demand Savings (MW) from Retail Demand Response Programs by 

NERC Region (2013 – 2016) ........................................................................................................ 13

Figure 5-1: Customer Enrollment in Retail Demand Response Programs by NERC Region ...... 23

Figure 5-2: Customers Enrolled in Retail Time-based Rate Programs by NERC Region ........... 25
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 1

FERC Staff Report 

ASSESSMENT OF DEMAND RESPONSE AND ADVANCED METERING 

Pursuant to Energy Policy Act of 2005 section 1252(e)(3) 

November 2018 

: Introduction

This report is the Federal Energy Regulatory Commission staff’s (Commission staff’s) thirteenth

annual report on demand response and advanced metering required by section 1252(e)(3) of the 

Energy Policy Act of 2005 (EPAct 2005). The information presented in the report is based on 

publicly-available data and discussions with industry experts. Highlights of the report include 

the following: 

• Advanced meters1 are the most prevalent type of metering deployed throughout the

country, accounting for nearly half of all meters installed and operational in the United

States. According to the Energy Information Administration (EIA),

2

 70.8 million

advanced meters were operational nationwide in 2016 out of a total of 151.3 million

meters, indicating a 46.8 percent penetration rate;

• Over the past year, electric utilities in Florida, Mississippi, Rhode Island, Virginia, and

elsewhere received approval for, or proposed, large-scale deployment of advanced

meters, in some cases as part of grid modernization efforts. In Massachusetts, Kentucky,

and elsewhere, state regulators and utilities are taking more targeted or cautious

approaches to advanced meter deployment, while other states such as Texas are seeking

to get more benefits out of their existing advanced meters by leveraging those

investments through, for example, data sharing mechanisms;

• Regulators in several states, including Maryland, Minnesota, Ohio, and Pennsylvania,

have approved, or are considering, time-based rate pilots, some in combination with

proposed electric vehicle charging infrastructure investments. In other states, including

California and Pennsylvania, regulators are considering next steps for demand response

and time-based rate programs; and

• Demand resource participation in the wholesale markets increased by approximately

three percent from 2016 to 2017, to a total of 27,541 MW. The contribution of demand

1 As defined by the U.S. Energy Information Administration (EIA), Advanced Metering Infrastructure (AMI) Meters (also 

referred to throughout this report as “advanced meters”) are “[m]eters that measure and record usage data[,] at a minimum, in

hourly intervals and provide usage data at least daily to energy companies and may also provide data to consumers. Data are 

used for billing and other purposes. Advanced meters include basic hourly interval meters and extend to real-time meters with 

built-in two-way communication capable of recording and transmitting instantaneous data.” Other types of meters currently in 

use—such as standard electromechanical, standard solid state, and Automated Metering Reading (AMR) meters—are not 

considered advanced meters for the purposes of this report. See EIA, Form EIA-861: Annual Electric Power Industry Report 

Instructions, at 18, http://www.eia.gov/survey/form/eia_861/instructions.pdf. 2 EIA, Form EIA-861 Advanced_Meters_2016 data file (released November 2017).
November 2018 Assessment of Demand Response and Advanced Metering

Page 2 Federal Energy Regulatory Commission

resources to meeting peak demand increased to 5.6 percent in 2017 from 5.3 percent in 

2016.

The report addresses the six requirements included in section 1252(e)(3) of EPAct 2005, which 

directs the Commission to identify and review: 

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

devices and systems (Chapter 2);

(B) existing demand response programs and time-based rate programs (Chapter 5);

(C) the annual resource contribution of demand resources (Chapter 3);

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

planning purposes (Chapter 4);

(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 (Chapter 5); and

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

reduction and critical period pricing programs (Chapter 6).
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 3

: Saturation and penetration rate of advanced meters

This chapter reports on penetration rates for advanced meters, and developments related to grid 

modernization and advanced metering. As summarized in Table 2-1, Figure 2-1, and noted in 

previous staff reports, recent data indicate that advanced meters are now the dominant metering 

technology type, and the number of advanced meters in operation continues to increase in the 

United States. This trend is robust across several data sets.

Table 2-1: Estimates of Advanced Meter Penetration Rate

Source

Data As 

Of

Number of 

Advanced 

Meters

(millions)

Total Number of 

Meters

(millions)

Advanced Meter

Penetration Rate

(advanced 

meters as a % of 

total meters)

2008 FERC Survey Dec 2007 6.7 1 144.4 1 4.7%

2010 FERC Survey Dec 2009 12.8 2 147.8 2 8.7%

2012 FERC Survey Dec 2011 38.1 3 166.5 3 22.9%

2011 Form EIA-861 Dec 2011 37.3 4 144.5 4 25.8%

Institute for Electric Efficiency May 2012 35.7 5 144.5 4 24.7%

2012 Form EIA-861 Dec 2012 43.2 6 145.3 6 29.7%

Institute for Electric Innovation July 2013 45.8 7 145.3 6 31.5%

2013 Form EIA-861 Dec 2013 51.9 8 138.1 8 37.6%

Institute for Electric Innovation July 2014 50.1 9 138.1 8 36.3%

2014 Form EIA-861 Dec 2014 58.5 10 144.3 10 40.6%

2015 Form EIA-861 Dec 2015 64.7 11 150.8 11 42.9%

Institute for Electric Innovation Dec 2015 65.6 12 150.8 11 43.5%

2016 Form EIA-861 Dec 2016 70.8 13 151.3 13 46.8%

Institute for Electric Innovation Dec 2016 72.0 14 151.3 13 47.6%

Sources:

1 FERC, Assessment of Demand Response and Advanced Metering staff report (2008). 2 FERC, Assessment of Demand 

Response and Advanced Metering staff report (2011). 3 FERC, Assessment of Demand Response and Advanced Metering staff 

report (2012). 4 EIA, Form EIA-861 file_2_2011 and file_8_2011 (re-released May 20, 2014). The number of ultimate 

customers served by full-service and energy-only providers is used as a proxy for the total number of meters. 5 The Edison 

Foundation Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals (2012). 6 EIA, Form 

EIA-861 and Form EIA-861S: retail_sales_2012 and advanced_meters_2012 data files (October 29, 2013). 7 The Edison 

Foundation Institute for Electric Innovation, Utility-Scale Smart Meter Deployments: A Foundation for Expanded Grid 

Benefits (2013). 8 EIA, Form EIA-861: Advanced_Meters_2013 data file (re-released June 8, 2015). The number of total 

meters—including AMI, AMR and standard electromechanical meters—was reported for the first time in 2013. Therefore, 

we no longer use the number of customers as a proxy. See source note 4 above and Form EIA-861Annual Electric Power 

Industry Report Instructions, Schedule 6, Part D, http://www.eia.gov/survey/form/eia_861/proposed/2013/instructions.pdf. 9 

The Edison Foundation Institute for Electric Innovation, Utility-Scale Smart Meter Deployments: Building Block Of The 

Evolving Power Grid (2014). 10 EIA, Form EIA-861: Advanced_Meters_2014 data file (re-released January 13, 2016). 11

EIA, Form EIA-861: Advanced_Meters_2015 data file (re-released November 1, 2016). 12 The Edison Foundation Institute 

for Electric Innovation, Electric Company Smart Meter Deployments: Foundation for A Smart Grid (2016). 13 EIA, Form 

EIA-861: Advanced_Meters_2016 data file (re-released November 6, 2017). 14 The Edison Foundation Institute for Electric 

Innovation, Electric Company Smart Meter Deployments: Foundation for a Smart Grid (2017).

Note: Commission staff has not independently verified the accuracy of EIA or Edison Foundation data. Values from source 

data are rounded for publication.
November 2018 Assessment of Demand Response and Advanced Metering

Page 4 Federal Energy Regulatory Commission

According to 2016 EIA data,3 70.8 million advanced meters were operational out of a total of 

151.3 million meters nationwide, representing a 46.8 percent penetration rate. This number of 

advanced meters represents an increase of approximately six million advanced meters, or an 

almost four percent increase, from 2015 to 2016.4 Data from the Edison Foundation shows 

similar figures for the number and penetration rate of advanced meters. 

Figure 2-1 shows the growth of advanced meters over time. Over the period 2007-2016, the 

number of advanced meters in operation has increased more than ten-fold.

Figure 2-1: Advanced Meter Growth (2007 – 2016)

Table 2-2 below provides estimated advanced meter penetration rates by NERC region, Alaska 

(AK) and Hawaii (HI),5 and retail customer class. Advanced meters represent more than half of 

all meters in four regions: approximately 86 percent of meters in Texas RE, 60 percent in 

WECC, and approximately 58 percent in SPP RE6 and in FRCC. The largest absolute growth in 

advanced meters from 2015 to 2016 occurred in RF and SERC, where 2.3 million and 1.5 

million additional advanced meters, respectively, went into operation. The highest percentage 

growth in advanced meters took place in AK, with an increase of about 17 percent, and SPP RE, 

 3 EIA, Form EIA-861: Advanced_Meters_2016 data file (re-released November 6, 2017). 4 Id. EIA data also reveals that advanced meters are the predominant metering technology installed and operational throughout 

the United States.

5 For the time period examined, NERC comprised eight regional entities in the lower 48 states: the Florida Reliability 

Coordinating Council (FRCC), Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), 

ReliabilityFirst (RF), SERC Reliability Corporation (SERC), Southwest Power Pool Regional Entity (SPP RE), Texas Reliability 

Entity (Texas RE), and Western Electricity Coordinating Council (WECC). The states of Alaska (AK) and Hawaii (HI) are not 

subject to NERC oversight. See Appendix and NERC, NERC Regions Map, 

http://www.nerc.com/AboutNERC/keyplayers/PublishingImages/2017_NERC_Regions_May2017.jpg. 6 On May 4, 2018, FERC approved a joint petition to transfer NERC registered entities within the SPP RE footprint to MRO and 

SERC. NERC, MRO and SERC, 163 FERC ¶ 61,094 (2018).

6.7

12.8

38.1 37.3 35.7

43.2

45.8

51.9 50.1

58.5

64.7 65.6

70.8 72.0

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

Dec

2007

(FERC)

Dec

2009

(FERC)

Dec

2011

(FERC)

Dec

2011

(EIA)

May

2012

(IEE)

Dec

2012

(EIA)

July

2013

(IEI)

Dec

2013

(EIA)

July

2014

(IEI)

Dec

2014

(EIA)

Dec

2015

(EIA)

Dec

2015

(IEI)

Dec

2016

(EIA)

Dec

2016

(IEI)

Penetration Rate 

Number of Advanced Meters (millions)

Advanced Meter 

Penetration Rate
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 5

with an increase of about nine percent. Advanced meter penetration increased in all regions from 

2015 to 2016. 

Table 2-2 indicates that, nationwide, advanced meters are slightly more common among 

residential and commercial sectors compared to the industrial sector. In 2016, advanced meters 

accounted for approximately 47 percent of all residential meters, 45 percent of all commercial 

meters, and 41 percent of all industrial meters. Within regions, there is noticeable variation in 

advanced meter penetration by customer class. For example, in AK, RF, SERC, SPP RE, Texas 

RE, and WECC, the residential sector has a higher rate of advanced meter penetration than the 

commercial or industrial sector. In contrast, in FRCC, HI, and MRO, advanced meter

penetration is highest in the industrial sector.

Table 2-2: Advanced Meter Penetration Rate by Customer Class and NERC Region

Region

Customer Class

Residential Commercial Industrial All Classes

AK 30.8% 17.5% 10.4% 28.7%

FRCC 56.9% 62.2% 72.2% 57.6%

HI 6.2% 7.2% 16.1% 6.3%

MRO 22.4% 19.0% 26.9% 22.0%

NPCC 10.1% 9.1% 11.9% 10.0%

RF 44.4% 37.7% 29.8% 43.6%

SERC 43.8% 41.6% 37.8% 43.5%

SPP RE 58.6% 53.9% 51.1% 57.8%

Texas RE 86.1% 85.8% 58.0% 85.9%

WECC 60.6% 59.9% 44.9% 60.4%

Unspecified 34.7% 32.3% 27.8% 34.4%

All Regions 47.1% 44.8% 40.5% 46.8%

Sources: EIA, 2016 Form EIA-861 Advanced_Meters_2016 data file. 

Note: The transportation sector data collected by EIA contain a relatively small number of meters, and are not 

reported separately here. In addition, although some entities may operate in more than one NERC Region, 

EIA data have only one NERC region designation per entity. The "unspecified" category represents 

respondents to the EIA-861 short form, which were not required to report a NERC region, as well as other 

respondents that did not specify a single NERC region. Commission staff has not independently verified the 

accuracy of EIA data.

Figure 2-2 shows increases in the number of advanced meters in all NERC regions from 2013-

2016. All regions experienced year-on-year growth in the number of advanced meters from 2013 

to 2016, while RF experienced the most growth since 2013. WECC continues to have the largest

number of advanced meters installed overall. Large increases in the total number of advanced 

meters were seen in SERC and RF from 2015 to 2016, a continuation of the trend seen since 2013

in these regions, while AK and SPP experienced the greatest annual percentage increases from 

2015 to 2016. 
November 2018 Assessment of Demand Response and Advanced Metering

Page 6 Federal Energy Regulatory Commission

Figure 2-2: Number of Advanced Meters by NERC Region (2013 – 2016)

Developments and issues in advanced metering 

State legislative and regulatory activity related to advanced metering

Presently, state regulators and utilities appear to be past the early adoption stage of advanced 

meter deployment, as the penetration rate of advanced meters nears 50 percent. Over the past 

year, electric utilities in a number of states received approval for, or proposed, large-scale 

deployment of advanced meters, in some cases as part of grid modernization efforts. Elsewhere, 

state regulators and utilities are taking more targeted or cautious approaches to advanced meter 

deployment, while other states are seeking to get more benefits out of their existing advanced 

meters by leveraging those investments through, for example, data sharing mechanisms. Below 

we provide updates on these activities. 

• Arizona. On September 12, 2017, the Arizona Public Service Company (APS) received 

approval from the Arizona Corporation Commission (ACC) to charge residential 

customers a fee to voluntarily opt out of receiving an advanced meter and to instead 

receive a non-AMI meter. Through a settlement agreement with stakeholders and 

interested parties, the original APS proposal was reduced from a one-time fee of $70 plus 

$15 a month, to a one-time fee of $50 plus $5 a month.7

• Florida. On November 20, 2017, the Florida Public Service Commission (Florida PSC)

approved a settlement agreement between Duke Energy Florida (DEF) and organizations 

 7 In the Matter of the Application of Arizona Public Service Company for a Hearing to Determine the Fair Value of the Utility 

Property of the Company for Ratemaking Purposes, to Fix a Just and Reasonable Rate of Return Thereon, to Approve Rate 

Schedules Designed to Develop Such Return, Docket No. E-01345A-16-0036, Decision No. 76374 (ACC Sept. 19, 2017) at 6,

http://docket.images.azcc.gov/0000182797.pdf.

0

2

4

6

8

10

12

14

16

18

20

Advanced Meters (millions)

2013 2014 2015 2016
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 7

representing DEF’s major customer groups increasing base rates for the utility.8 As part 

of the settlement agreement, DEF will invest $1.2 billion in grid modernization,9 which 

includes full deployment of advanced meters and services like usage alerts, outage 

notifications, and customized billing options, and will launch a five-year electric vehicle 

charging station pilot program for at least 530 vehicles with no more than $8 million of 

operating and maintenance expenses.10

• Hawaii. On June 21, 2018, Hawaiian Electric Company (HECO Companies) filed an 

application requesting approval to implement Phase 1 of its Grid Modernization 

Strategy,

11 which the Hawaii Public Utilities Commission (Hawaii PUC) previously 

approved on February 7, 2018.

12 Phase 1 of the strategy consists of advanced meter 

deployment on an “opt-in”13 basis, as well as deployment of related software and 

telecommunications systems, and is proposed to run from 2019 to 2023 at a cost of 

approximately $86.3 million.14

• Illinois. On August 16, 2018, the Seventh Circuit Court of Appeals ruled that data 

collected by the Naperville City-owned electric utility through advanced meter readings 

at 15-minute intervals are a reasonable search under the state’s constitution and the 

Fourth Amendment of the U.S. Constitution. Naperville Smart Meter Awareness, a 

group of concerned citizens, argued that the utility’s collection of advanced meter data 

could reveal intimate personal details of members’ actions while in their homes, and that 

collection of this data violates the state and Federal constitution.15 While the court found 

that the data collection constitutes a warrantless search, it balanced the intrusion on 

individuals’ privacy interests with the legitimate government interests behind installing 

advanced meters, such as faster outage restoration, reduction of utility labor costs, 

 8 In Re: Application for Limited Proceeding to Approve 2017 Second Revised and Restated Settlement Agreement, Including 

Certain Rate Adjustments, by Duke Energy Florida, LLC, Order No. PSC-2017-0451-AS-EU (Florida PSC Nov. 20, 2017), 

http://www.floridapsc.com/library/filings/2017/09951-2017/09951-2017.pdf. 9 Duke Energy Florida, 2017 Settlement Agreement at a Glance, https://www.duke-energy.com/annual-report/_/media/pdfs/foryour-home/def-settlement-overview.pdf?la=en. 10 In Re: Application for Limited Proceeding to Approve 2017 Second Revised and Restated Settlement Agreement, Including 

Certain Rate Adjustments, by Duke Energy Florida, LLC, Order No. PSC-2017-0451-AS-EU (Florida PSC Nov. 20, 2017) at 33-

34, http://www.floridapsc.com/library/filings/2017/09951-2017/09951-2017.pdf. 11 In the Matter of the Application of Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., and Maui Electric 

Company, Limited for Approval to Commit Funds in Excess of $2,500,000 for the Phase 1 Grid Modernization Project, to Defer 

Certain Computer Software Development Costs, to Recover the Capital and Deferred Costs through the Major Project Interim 

Recovery, and Related Requests, Docket no. 2018-0141 (Hawaii PUC June 21, 2018), 

https://www.hawaiianelectric.com/Documents/about_us/our_commitment/20180621_grid_mod_strategy_application_filing.pdf. 12 Instituting a Proceeding Related to the Hawaiian Electric Companies’ Grid Modernization Strategy, Docket No. 2017-0226, 

Order No. 35268 (Hawaii PUC Feb. 7, 2018), 

https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A18B08B13014I00232. 13 HECO Companies contrasts the proposed “opt-in” approach, through which customers can choose whether to receive an 

advanced meter, to previous applications in which it sought to deploy advanced meters to all customers. In the Matter of the 

Application of Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., and Maui Electric Company, Limited for 

Approval to Commit Funds in Excess of $2,500,000 for the Phase 1 Grid Modernization Project, to Defer Certain Computer 

Software Development Costs, to Recover the Capital and Deferred Costs through the Major Project Interim Recovery, and 

Related Requests, Docket no. 2018-0141 (Hawaii PUC June 21, 2018) at 34, 

https://www.hawaiianelectric.com/Documents/about_us/our_commitment/20180621_grid_mod_strategy_application_filing.pdf. 14 Id. at 4. 15 Naperville Smart Meter Awareness v. City of Naperville, 900 F.3d 521, 524 (7th Cir. 2018).
November 2018 Assessment of Demand Response and Advanced Metering

Page 8 Federal Energy Regulatory Commission

increased grid stability, and the priority to modernize the electric grid.16 Although the 

court found that the City of Naperville’s interests outweighed the individuals’ in this 

case, it cautioned that were the city to collect data at shorter intervals, or the data were

more easily accessible to law enforcement or other city officials, its conclusion could 

change.17

• Kentucky. On August 30, 2018, the Kentucky Public Service Commission (Kentucky 

PSC) rejected Louisville Gas & Electric Company (LG&E) and Kentucky Utilities 

Company’s (KU) jointly-filed application to install 1.3 million advanced meters across 

their service territories.18 The Kentucky PSC found that LG&E and KU failed to present 

sufficient evidence to support a demonstration that there is a need for advanced meters, 

particularly considering the substantial remaining service lives of their existing meters.

19 

Accordingly, the Kentucky PSC found that the utilities failed to demonstrate that a full 

deployment of advanced meters would not lead to wasteful duplication of investments in 

their existing meters.

20 In spite of that finding, the Kentucky PSC stated that it sees 

benefits in advanced metering, encouraged LG&E and KU to expand their current pilot

program for advanced meters from 10,000 total customers to 20,000 total customers, and

also encouraged the utilities to consider real-time pricing options.21

• Massachusetts. On May 10, 2018, the Massachusetts Department of Public Utilities 

(Massachusetts DPU) rejected Eversource and National Grid’s grid modernization plans,

and a similar proposal by Unitil, stating that the companies’ proposals to install advanced 

meters “revealed weaknesses in the business case for advanced metering functionality.”22 

Specifically, the Massachusetts DPU found that recent technological advances may 

permit interval data collection without the need to replace existing meters, although those

meters would still require additional devices to enable two-way communications.23 As 

stated by the DPU, any decision to prematurely retire the existing meters would come at a 

significant cost.24 Additionally, the DPU found that the primary benefit of advanced 

meters lies in reduced peak usage as customers respond to price signals. However, 

without wide customer adoption of time-based rates, the benefits of advanced meters 

remain uncertain.25 The order noted that the Massachusetts DPU intends to open an 

investigation into how to remove barriers to time-based rates for customers, and provide 

 16 Id. at 528–529. 17 Id. at 529. 18 In the Matter of Electronic Joint Application of Louisville Gas and Electric Company and Kentucky Utilities Company for 

Certificates of Public Convenience and Necessity for Full Deployment of Advanced Metering Systems, Case No. 2018-00005 

(Kentucky PSC Aug. 30, 2018), https://psc.ky.gov/pscscf/2018%20Cases/2018-00005//20180830_PSC_ORDER.pdf. 19 Id. at 7. 20 Id. at 7. 21 Id. at 14-15. 22 Petition of Massachusetts Electric Company and Nantucket Electric Company, d/b/a National Grid for Approval by the 

Department of Public Utilities of its Grid Modernization Plan, et. al., Mass DPU Order Nos. 15-120, 15-121, 15-122 

(Massachusetts DPU May 10, 2018) at 1-2, 

https://eeaonline.eea.state.ma.us/EEA/FileService/FileService.Api/file/FileRoom/9163509. 23 Id. at 133. 24 Id. at 134. 25 Id. at 1-2.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 9

certainty that the benefits justify the costs for implementation of advanced meters.26 

Specifically, the Massachusetts DPU will consider (1) whether it is cost-effective to 

undertake targeted deployment of advanced meters to customers most likely to be 

engaged and participate in time-based rate programs, and (2) technology options that 

could enable cost-effective deployment of advanced meter functionality without 

necessitating replacement of existing meters.27

• Minnesota. On May 31, 2018, the Minnesota Public Utilities Commission (Minnesota 

PUC) approved a pilot program proposed by Xcel Energy that includes deployment of 

advanced meters, including the provision of increased energy usage information, 

education, and support to encourage shifting energy usage to off-peak hours to customers 

with advanced meters.28 The program also includes a pilot for time-of-use rates,

29

discussed further in Chapter 5 of this report. The program is scheduled to begin in early 

2020, and will be deployed to about 10,000 customers.30

• Mississippi. On April 10, 2018, the Mississippi Public Service Commission (Mississippi 

PSC) approved a Mississippi Power Company proposal to deploy advanced meters in 

their service territory.31 The plan will deploy approximately 193,000 advanced meters 

across 23 counties throughout its service territory,32 at a cost of $39 million over the next 

two years.33

• New York. The New York State Energy Research and Development Authority

(NYSERDA) and the state’s Clean Energy Fund, will provide $15 million in funding for 

“High Performing Grid” projects like advanced monitoring and controls, advanced 

sensors, devices, and systems, and advanced system modeling.34 In order to achieve the 

 26 Id. at 2-3. 27 Id. at 135-136. 28 Staff Briefing Papers, Docket Nos. E-002/M-17-775, E-002/M-17-776 (Minnesota PUC May 31, 2018) at 28, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={009E9263-0000-

C016-8875-BD1FFA2ED2C5}&documentTitle=20185-143296-01. 29 Order Approving Pilot Program, Setting Reporting Requirements, and Denying Certification Request, Docket Nos. E-002/M17-775, E-002/M-17-776 (Minnesota PUC Aug. 7, 2018), 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={90C81565-0000-

C411-A2FE-612297DE478D}&documentTitle=20188-145592-01. 30 Staff Briefing Papers, Docket Nos. E-002/M-17-775, E-002/M-17-776 (Minnesota PUC May 31, 2018) at 29, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={009E9263-0000-

C016-8875-BD1FFA2ED2C5}&documentTitle=20185-143296-01. 31 In Re: Petition of Mississippi Power Company for a Certificate of Public Convenience and Necessity Authorizing the 

Acquisition, Construction, and Operation of Advanced Metering Infrastructure Equipment, Technology, and Related Facilities, 

Docket No. 2009-UA-398 (Mississippi PSC Apr. 10, 2018), 

http://www.psc.state.ms.us/InSiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=402

804. 32 Itron, Itron Signs Agreement with Mississippi Power to Deploy and Manage Nearly 200,000 Smart Meters across the Magnolia 

State (May 2018), https://www.itron.com/cn/newsroom/press-releases/2018/05/14/itron-signs-agreement-with-mississippi. 33 In Re: Petition of Mississippi Power Company for a Certificate of Public Convenience and Necessity Authorizing the 

Acquisition, Construction, and Operation of Advanced Metering Infrastructure Equipment, Technology, and Related Facilities, 

Docket No. 2009-UA-398 (Mississippi PSC Apr. 10, 2018), 

http://www.psc.state.ms.us/InSiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=402

804. 34 New York State, Governor Cuomo Announces $15 Million to Support Modernization of New York’s Electric Grid (Apr. 2018), 

https://www.governor.ny.gov/news/governor-cuomo-announces-15-million-support-modernization-new-yorks-electric-grid.
November 2018 Assessment of Demand Response and Advanced Metering

Page 10 Federal Energy Regulatory Commission

goals of the Reforming the Energy Vision (REV) initiative, the program seeks to 

incentivize investments that result in, among other things, increased use of distributed 

energy resources, and that make the grid more efficient and reliable.

35

• North Carolina. On June 22, 2018, the North Carolina Utilities Commission (NCUC) 

rejected36 the Duke Energy Carolinas (DEC) Power/Forward grid modernization 

initiative,

37 and instructed the utility instead to use existing dockets such as the Integrated 

Resource Planning and Smart Grid Technology Plan to recover costs. However, the 

NCUC order did approve cost recovery for DEC’s full deployment of advanced meters 

throughout its service territory.38

• Rhode Island. On November 27, 2017, the Narragansett Electric Company (National 

Grid) filed an application with the Rhode Island Public Utilities Commission (Rhode 

Island PUC) to increase its revenue requirements in order to, among other things, 

complete a full deployment of advanced meters across its service territory over a three 

year period after approval, and introduce customers to time-of-use rates two years after 

that,

39 as part of the Power Sector Transformation Initiative reported in the 2017 version 

of this report.40 On June 6, 2018, National Grid submitted a settlement agreement 

between the utility and interested parties to the Rhode Island PUC.41 The Rhode Island 

PUC approved the settlement agreement on August 24, 2018.42

• Texas. On July 12, 2018, the Public Utility Commission of Texas (PUCT) approved the 

plan for implementation of the Smart Meter Texas web portal, an interoperable, webbased information system that, among other things, (1) stores retail customers’ data in 15-

minute intervals recorded by advanced meters, and (2) provides authorized stakeholders 

with secure access to that data in order to sell services such as energy efficiency and

demand response.

43 Smart Meter Texas is jointly maintained by four transmission and 

 35 NYSERDA, Electric Power Transmission and Distribution High Performing Grid, 

https://portal.nyserda.ny.gov/CORE_Solicitation_Detail_Page?SolicitationId=a0rt000000DbjBFAAZ. 36 In the Matter of Application of Duke Energy Carolinas, LLC, for Adjustment of Rates and Charges Applicable to Electric 

Utility Service in North Carolina, Docket No. E-7, Sub 1146 (NCUC June 22, 2018) at 19, 

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=80a5a760-f3e8-4c9a-a7a6-282d791f3f23. 37 Duke Energy, Duke Energy Embarks on a 10-year Initiative to Strengthen North Carolina’s Energy Grid (Apr. 2017), 

https://news.duke-energy.com/releases/duke-energy-embarks-on-a-10-year-initiative-to-strengthen-north-carolina-s-energygrid?_ga=1.192735209.238488252.1492423359. 38 In the Matter of Application of Duke Energy Carolinas, LLC, for Adjustment of Rates and Charges Applicable to Electric 

Utility Service in North Carolina, Docket No. E-7, Sub 1146 (NCUC June 22, 2018) at 19, 

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=80a5a760-f3e8-4c9a-a7a6-282d791f3f23. 39 Power Sector Transformation Panel Book 1 of 3, Docket No. 4770 (Rhode Island PUC Nov. 27, 2017) at 74-75, 

http://www.ripuc.org/eventsactions/docket/4770-NGrid-PSC-Book1of3.pdf. 40 FERC, Assessment of Demand Response and Advanced Metering at 14 (2017), https://www.ferc.gov/legal/staffreports/2017/DR-AM-Report2017.pdf. 41 Proposed Power Sector Transformation Vision and Implementation Plan Settlement Agreement, Docket Nos. 4770, 4780 

(Rhode Island PUC June 6, 2018), http://www.ripuc.org/eventsactions/docket/4770-4780-NGrid-TransmittalSettlementAgreement(6-6-18).pdf. 42 State of Rhode Island, Public Utilities Commission Approves Power Sector Transformation Settlement in National Grid Rate 

Case (Aug. 2018), http://www.ripuc.ri.gov/consumerinfo/Settlement_Release.pdf. 43 Commission Staff’s Petition to Determine Requirements for Smart Meter Texas, Docket No. 47472 (PUCT July 12, 2018), 

http://interchange.puc.texas.gov/Documents/47472_138_986459.PDF.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 11

distribution utilities: AEP Texas, CenterPoint Energy Houston Electric, Oncor Electric 

Delivery Company, and Texas-New Mexico Power Company.44

• Virginia. On July 1, 2018, Virginia’s Grid Transformation and Security Act went into 

effect.45 Among other things, the law ends a freeze on utility rates and creates a model 

that allows utilities to invest in projects that are deemed “in the public interest,” such as 

grid modernization programs.46

On July 24, 2018, Dominion Energy filed Phase I of its Grid Transformation Plan with 

the State Corporation Commission for the Commonwealth of Virginia (Virginia SCC), 

which includes full deployment of advanced meters across its service territory by the end 

of 2023. The plan also includes among other things, proposals for a customer 

information platform (CIP) to leverage information provided by advanced meters. For 

example, the CIP will provide customers with access to detailed energy usage 

information, enabling them to select rate structures—including time-based rate options—

to meet their needs.

47

 44 Commission Staff’s Petition to Determine Requirements for Smart Meter Texas, Docket No. 47472 (PUCT July 12, 2018) at 3, 

http://interchange.puc.texas.gov/Documents/47472_138_986459.PDF. 45 State of Virginia, SB 966, HB 1558, 2018 Session, approved on March 9, 2018, https://lis.virginia.gov/cgibin/legp604.exe?181+ful+CHAP0296. 46 Code of Virginia, § 56-585.1(A)(6), https://law.lis.virginia.gov/vacode/title56/chapter23/section56-585.1/. 47 Petition of Virginia Electric and Power Company, for Approval of a Plan for Electric Distribution Grid Transformation 

Projects Pursuant to § 56.585.1(A)(6) of the Code of Virginia, Case No. PUR-2018-00100 (Virginia SCC July 24, 2018), 

https://www.dominionenergy.com/library/domcom/media/about-us/electric-projects/grid-transformation/gtsa-072418.pdf?la=en.
November 2018 Assessment of Demand Response and Advanced Metering

Page 12 Federal Energy Regulatory Commission

: Annual resource contribution of demand resources 

Using the latest publicly available data, this chapter summarizes the annual resource contribution

from retail and wholesale demand response programs on a national and regional basis.

48 

Retail demand response programs

Table 3-1 presents data collected by EIA on 2015 and 2016 potential peak demand savings from 

retail demand response programs within each of the eight NERC regional entities, as well as 

Alaska (AK) and Hawaii (HI).

49 Potential peak demand savings refers to “the total demand 

savings that could occur at the time of the system peak hour assuming all demand response is 

called.”50 Nationwide, total potential peak demand savings from retail demand response 

programs increased by almost 3,050 megawatts (MW), or approximately nine percent, between 

2015 and 2016, to 35,924 MW.

51 

Table 3-1: Potential Peak Demand Savings (MW) from Retail Demand Response Programs 

by NERC Region (2015 & 2016)

Region

Annual Potential Peak Demand 

Savings (MW)

Year-on-Year Change

2015 2016 MW %

AK 27.0 27.0 0.0 0.0%

FRCC 3,246.5 3,259.4 12.9 0.4%

HI 35.2 33.5 -1.7 -4.8%

MRO 4,508.9 5,231.3 722.4 16.0%

NPCC 787.4 1,120.2 332.8 42.3%

RF 5,372.2 5,505.1 132.9 2.5%

SERC 9,259.1 8,265.6 -993.5 -10.7%

SPP RE 1,922.7 5,004.4 3,081.7 160.3%

Texas RE 696.4 773.3 76.9 11.0%

WECC 7,019.2 6,625.3 -393.9 -5.6%

Unspecified 0.0 79.0 79.0 --

Total 32,874.6 35,924.1 3,049.5 9.3%

Sources: EIA, EIA-861 Demand_Response_2015, Demand_Response_2016, Utility_Data_2015, and 

Utility_Data_2016 data files.

Note: Although some entities may operate in more than one NERC region, EIA data have only one NERC 

region designation per entity. Commission staff has not independently verified the accuracy of EIA data.

 48 The latest publicly available retail and wholesale data sets are used to determine the annual resource contributions from 

demand response programs; these include EIA retail data for 2015 and 2016, as well as RTO/ISO wholesale data for 2016 and 

2017.

49 This section categorizes potential peak demand savings from retail demand response programs by NERC region because such 

programs exist in regions both with and without organized wholesale markets.

50 See EIA, Form EIA-861 Instructions, Schedule 6, Part B. 51 The Smart Electric Power Alliance (SEPA) also conducts an annual survey to estimate capacity enrolled in retail demand 

response programs. Based on responses from 155 utilities representing 62.4% of total U.S. customer accounts, SEPA reports that 

there was 18.3 GW of demand response capacity enrolled in retail programs in 2017. See SEPA, 2018 Utility Demand Response 

Market Snapshot, at 12-13, https://sepapower.org/resource/2018-demand-response-market-snapshot/.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 13

Figure 3-1: Potential Peak Demand Savings (MW) from Retail Demand Response 

Programs by NERC Region (2013 – 2016)

Regionally, however, there were large differences in the change in potential peak demand 

savings from 2015 to 2016. Table 3-1 and Figure 3-1 above show that potential peak demand 

savings increased in SPP RE by more than 3,000 MW from 2015 to 2016, attributable primarily 

to a 2,800 MW increase in peak demand savings reported by Oklahoma Gas & Electric. Peak 

demand savings in MRO increased by over 700 MW, with greater reported savings by 

MidAmerican Energy and Northern States Power Company-Minnesota (Xcel Energy). In 

contrast, net retail demand response potential fell sharply in SERC in 2016 due primarily to 

lower reported savings in Tennessee Valley Authority’s industrial demand response program. 

Figure 3-1 also generally shows a trend of increasing retail peak demand response savings in 

most regions over the period 2013-2016. 

Table 3-2 shows that the amount of potential peak demand savings from retail demand response 

differs by customer class in 2016. Industrial customer demand response represented 14,339 

MW, or 40 percent, of total potential peak demand savings. Residential customer demand 

response accounted for approximately 10,518 MW, or 29 percent, and programs in the 

commercial sector accounted for almost 11,053 MW, or 31 percent, of total potential peak 

demand savings. The relative contribution by customer class varies by region. For example, 

residential demand response programs account for the largest portion of potential peak demand 

savings in WECC (47 percent) and MRO (approximately 40 percent). In contrast, commercial 

programs account for the majority of potential peak demand savings in AK, HI, SPP RE, and 

Texas RE. In FRCC, residential and commercial programs represent approximately the same 

proportion of potential peak savings, at 47 and 48 percent, respectively. Finally, industrial 

programs account for the majority in NPCC (60 percent), RF (55 percent), and SERC (71 

percent).

 -

 1,000

 2,000

 3,000

 4,000

 5,000

 6,000

 7,000

 8,000

 9,000

 10,000 MW

2013 2014 2015 2016
November 2018 Assessment of Demand Response and Advanced Metering

Page 14 Federal Energy Regulatory Commission

Table 3-2: Potential Peak Demand Savings (MW) from Retail Demand Response 

Programs by Region and Customer Class (2016)

Region

Customer Class

Residential Commercial Industrial Transportation All Classes

AK 5.0 13.0 9.0 0.0 27.0

FRCC 1,548.2 1,573.2 138.0 0.0 3,259.4

HI 14.8 18.7 0.0 0.0 33.5

MRO 2,083.6 1,434.6 1,713.1 0.0 5,231.3

NPCC 77.9 359.2 669.1 14.0 1,120.2

RF 1,644.8 828.2 3,032.1 0.0 5,505.1

SERC 1,652.6 755.8 5,857.2 0.0 8,265.6

SPP RE 149.3 3,751.3 1,103.8 0.0 5,004.4

Texas RE 213.5 406.5 153.3 0.0 773.3

WECC 3,116.6 1,867.2 1,641.5 0.0 6,625.3

Unspecified 12.0 45.0 22.0 0.0 79.0

All Regions 10,518.3 11,052.7 14,339.1 14.0 35,924.1

Sources: EIA, EIA-861 Demand_Response_2016 and Utility_Data_2016 data files.

Note: Although some entities may operate in more than one NERC Region, EIA data have only one NERC region designation 

per entity. Commission staff has not independently verified the accuracy of EIA data. 

Wholesale demand response programs

Table 3-3 below presents demand resource participation in wholesale demand response programs 

operated by RTOs/ISOs in 2016 and 2017.52 Given changes in the structure of demand response 

programs in some RTOs/ISOs over the past several years, as well as changes in the way that 

demand resource participation is reported in some regions, Commission staff has updated the 

methodology used in this section of the report.53 Demand response participation figures for 2016 

have been updated from those reported previously to provide an accurate comparison to 2017 

figures.

Demand resource participation in the wholesale markets increased by approximately three 

percent from 2016 to 2017, to a total of 27,541 MW, as shown in Table 3-3.54 The reported

 52 The RTOs/ISOs include California ISO (CAISO), Electric Reliability Council of Texas (ERCOT), ISO New England (ISONE), Midcontinent Independent System Operator (MISO), New York Independent System Operator (NYISO), PJM 

Interconnection (PJM), and Southwest Power Pool (SPP).

53 Specifically, the figures reflect the registration of demand response resources (but not energy efficiency resources) in 

wholesale demand response programs. This applies in particular to ISO-NE, where energy efficiency resources make up a large 

portion of demand resources participating in the market. Additionally, figures for CAISO reflect demand resource participation 

in wholesale demand response products rather than in retail programs, as reported previously. In NYISO, figures include demand 

resources participating in the ancillary services market. Finally, because the data source previously used for ERCOT is no longer 

available, Commission staff has estimated demand resource participation based on ERCOT’s 2016 and 2017 Annual Reports of 

Demand Response.

54 Commission staff estimates are based on demand resource enrollment in reliability, energy, and ancillary services products 

administered by each RTO/ISO. In contrast, SEPA estimates a total of 19,314 MW of demand resources participating in only 

RTO/ISO reliability programs in 2017; these figures are based on capacity market obligations or reliability program enrollment 
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 15

increase in wholesale demand resource participation is mainly attributable to an increase in 

demand resource participation in MISO and ERCOT, which was offset by small decreases in 

participation in other regions. Due to a decrease in peak demand levels in 2017, the contribution 

of demand resources to meeting peak demand also rose slightly from 5.3 percent in 2016 to 5.6 

percent in 2017. 

 

Table 3-3: Demand Resource Participation in RTO/ISO Demand Response Programs

RTO/ISO

2016 2017 Year-on-Year Change

Demand 

Resources

(MW)

Percent of 

Peak 

Demand8

Demand 

Resources

(MW)

Percent of 

Peak 

Demand8 MW Percent

CAISO 1,480 1 3.2% 1,293 9 2.6% -187 -12.6%

ERCOT 2,536 2 3.6% 3,009 10 4.3% 473 18.6%

ISO-NE 703 3 2.7% 684 11 2.9% -19 -2.7%

MISO 10,721 4 8.9% 11,682 12 9.7% 961 9.0%

NYISO 1,373 5 4.3% 1,353 13 4.6% -20 -1.4%

PJM 9,836 6 6.5% 9,520 14 6.5% -316 -3.2%

SPP 0 7 0.0% 0 7 0.0% 0 0.0%

Total 26,649 5.3% 27,541 5.6% 892 3.4%

Sources:

1 CAISO, 2016 Annual Report on Market Issues and Performance, Table 1.3, at 33 (May 2017). 2 Estimated based on ERCOT, 2016 Annual Report of Demand Response in the ERCOT Region, at 2-6 (Mar. 2017). 3 ISO-NE, Demand Response Enrollment Statistics, presented at Demand Resources Working Group Meeting (Jan. 9, 2017) 

(data as of Jan. 1, 2017), at 2. Figure represents enrolled MWs. 4 2016 State of the Market Report for the MISO Electricity Market (June 2016), Table 8, at 72. 5 2016 Annual Report on Demand Side Management Programs of the New York Independent System Operator, Inc., ER01-

3001 (Jan. 12, 2017), Attachment I, Table 1, at 7. 6 PJM 2016 Demand Response Operations Markets Activity Report (May 2017), at 3-4. Figure represents “unique MW.” 7 No load-reduction demand response activity has occurred in the Integrated Marketplace since it was established on March 1, 

2014. See SPP Compliance Filing, Docket No. ER12-1179-024, at 4 (May 24, 2016); and SPP Response to Request for 

Additional Information, Docket No. ER12-1179-025, at 1-2, 4 (Mar. 5, 2018). 8 Sources for peak demand data include: California ISO 2016 and 2017 Annual Reports on Market Issues and Performance; 

ERCOT 2016 & 2017 Demand and Energy Reports; ISO-NE Net Energy and Peak Load Report (May 2017 & May 2018); 

2016 and 2017 State of the Market Reports for the MISO Electricity Markets; NYISO Power Trends Reports 2017 and 2018; 

2016 and 2017 PJM State of the Markets Reports, Vol. 2; SPP 2017 State of the Market Report. 9 CAISO, 2017 Annual Report on Market Issues and Performance, at 36-37 (June 2018). 10 Estimated based on ERCOT, 2017 Annual Report of Demand Response in the ERCOT Region, at 2-6 (Mar. 2018). 11 ISO-NE, Demand Resource Asset Enrolled MWs, presented at Demand Resources Working Group Meeting (Dec. 18, 2017) 

(data as of Jan. 1, 2018), at 2. Figure represents enrolled MW. 12 2017 State of the Market Report for the MISO Electricity Market (June 2018), Table 11, at 78. 13 2017 Annual Report on Demand Side Management Programs of the New York Independent System Operator, Inc., ER01-

3001 (Jan. 12, 2018), Attachment I, at 6 (Table 1). 14 PJM 2017 Demand Response Operations Markets Activity Report (April 2018), at 3-4. Figure represents “unique MW.”

Note: Commission staff has not independently verified the accuracy of the sources listed. Values from source data are 

rounded for publication.

 or market awards, depending on the region. See SEPA, 2018 Utility Demand Response Market Snapshot, at 27, 

https://sepapower.org/resource/2018-demand-response-market-snapshot/.
November 2018 Assessment of Demand Response and Advanced Metering

Page 16 Federal Energy Regulatory Commission

In MISO, overall demand resource registrations increased by approximately nine percent, or 961 

MW from 2016 to 2017. Of this increase in enrollment, 1,496 MW was from Demand Resource 

Load Modifying Resources (LMR),

55 which, according to the MISO market monitor, are 

becoming increasingly important in planning and emergency operations.56 MISO also reported a 

95 MW increase in Type I Demand Response Resources (DRR) for 2017. These increases were 

slightly offset by a decrease of 80 MW of Behind-the-Meter Generation LMRs, a decrease in 

enrollment of 75 MW of Type II DRRs,

57 and a 475 MW decrease in enrollment of non-LMR 

Emergency DR resources.

In ERCOT, demand resource participation grew by 473 MW, or about 19 percent, from 2016 to 

2017. Most of this growth (456 MW) is due to increased participation in the Responsive Reserve 

Service (RRS).58 In addition, the capacity of resources participating in the Fast Responding 

Regulation Service (FRRS)59 increased by 20 MW, while participation in the Emergency 

Response Service (ERS)60 remained relatively flat. 

Demand resource participation in ISO-NE decreased from 703 MW to 684 MW, or about three 

percent, due to lower reported enrollment in the Real-Time Demand Response Program (RTDR). 

Decreases in RTDR enrollment were reported in five of ISO-NE’s eight load zones, while RTDR 

enrollment increased in two zones. RTDR enrollment decreased in the New Hampshire (6 MW), 

Vermont (3 MW), Connecticut (13 MW), Western and Central Massachusetts (9 MW), and 

Northeast Massachusetts (8 MW) zones while increases were reported in the Rhode Island (4 

MW) and Southeast Massachusetts (14 MW) zones. Real-Time Emergency Generation 

Resource enrollment, which has gradually declined for several years, was the same in 2017 as in 

2016 at 1.5 MW. 

In CAISO, participation fell by 187 MW in 2017 from the year before. Overall, 1,023 MW of 

demand resources were enrolled in the Reliability Demand Response program in 2017, a slight 

decrease from the 2016 total of 1,320 MW. In contrast, enrollment in the Proxy Demand 

Response program—through which resources can bid economically in the energy market—

increased from 160 MW in 2016 to 270 MW in 2017.61

 55 The vast majority of demand response capability in MISO consists of interruptible loads (Load Modifying Resources) 

developed under regulated utility programs that clear in MISO’s annual capacity auction. See Potomac Economics, 2017 State of 

the Market Report for the MISO Electricity Market (June 2018) at 79. 56 Id. 57 In 2016, only one resource was participating in the DRR – Type II product; by 2017 this resource was no longer participating 

in the market. See Potomac Economics, 2017 State of the Market Report for the MISO Electricity Market (June 2018) at 79. 58 Load resources with an under-frequency relay may participate in the RRS to provide frequency response. Commission staff 

estimated participation in the RRS program based on the average offers for December 2016 and 2017; resources must be 

registered and qualified to offer into the market. While ERCOT reports that as much as 4,715 MW of resources were capable of 

participating in RRS as of the end of 2017—a growth of 890 MW over 2016—not all of these resources were actively 

participating in the market. See ERCOT, 2017 Annual Report of Demand Response in the ERCOT Region (Mar. 2018) at 2-4. 59 ERCOT reports that several markets participants began offering FRRS in 2017 using energy storage resources. Average 

awards for FRRS increased by 20 MW in the last six months of 2017 to reach the hourly cap of 35 MW. See id. at 4. 60 The ERS provides 10- and 30-minute load reduction services. Commission staff estimated ERS capacity for 2016 and 2017 by 

averaging the capacity procured for the six time periods in the last contract term of each program year (i.e., October to January), 

and summing these averages for each of the four ERS products (i.e., 10- and 30-minute types of weather-sensitive and nonweather-sensitive ERS). See id. at 5-6. 61 In addition, in 2017, there were 1,759 MW of demand response capacity enrolled in programs administered by the three 

investor-owned utilities. Participation in utility-sponsored price-responsive programs has been gradually declining over the last 
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 17

Demand resource participation also decreased slightly in NYISO and PJM, by approximately one

percent and three percent, respectively. In NYISO, a 27 MW increase in Special Case Resource 

enrollment and a 10 MW increase in enrollment in the Demand-Side Ancillary Service Program 

were offset by a decrease in enrollment of 59 MW in the Emergency Demand Response 

Program.

PJM reports an overall decrease in demand resources enrollments of 316 MW from 2016 to 

2017. Specifically, there was a 221 MW drop in enrollment in PJM’s reliability programs

overall, with a large portion of resources enrolled in the Limited Demand Resource (Limited 

DR)

62 product moving to the Extended Summer63 and Annual Demand Resource (Annual DR)64

products. There was also a 328 MW decrease in demand resources participating in the economic 

demand response program.65 The overall decrease in demand resource registrations in PJM was 

likely due to a decrease in the quantity of demand resources offering into the 2017/2018 Base 

Residual Auction compared to the year before,

66 and the continued phasing out of legacy 

demand response products as PJM shifts to an annual capacity performance product.

SPP reports that no demand resources have participated in its Integrated Marketplace since the 

market was established in 2014.

67

2018 demand response deployments

High temperatures during the summer of 2018 led grid operators and utilities in several regions 

to issue notices for emergency demand response, critical peak pricing, and voluntary 

conservation.

In response to high temperatures across the Western United States, high fire risk, and tight gas 

supply in Southern California in late July, CAISO issued a state-wide Flex Alert68 calling for 

 several years as participation in wholesale programs has grown. See CAISO, 2017 Annual Report on Market Issues and 

Performance (June 2018) at 36, 39. 62 Limited DR (effective through the 2017/2018 delivery year) is available for interruption for at least 10 times during the 

summer period of June through September in the Delivery Year, and will be capable of maintaining each such interruption for at 

least a 6-hour duration. At a minimum, the Limited Demand Resource shall be available for such interruptions on weekdays, 

other than NERC holidays, from 12:00PM (noon) to 8:00PM Eastern Prevailing Time. PJM, Manual 18: PJM Capacity Market, 

Revision 40 (Feb. 22, 2018), at 71, https://www.pjm.com/-/media/documents/manuals/m18.ashx. 63 Extended Summer DR (effective through the 2017/2018 delivery year ) is available for an unlimited number of interruptions 

during an extended summer period of June through October and the following May, and will be capable of maintaining each such 

interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM Eastern Prevailing Time. Id. 64 Annual DR (effective through 2017/2018 delivery year) is available for an unlimited number of interruptions during the 

Delivery Year, and will be capable of maintaining each such interruption between the hours of 10:00AM to 10:00PM Eastern 

Prevailing Time for the months of June through October and the following May, and 6:00AM through 9:00PM Eastern Prevailing 

Time for the months of November through April unless there is an Office of the Interconnection approved maintenance outage 

during October through April. Id. 65 Some resources participate in both PJM’s reliability and economic programs. 66 PJM, 2017/2018 Base Residual Auction Results, at 10, https://www.pjm.com/~/media/markets-ops/rpm/rpm-auction-info/2017-

2018-base-residual-auction-report.ashx. 67 Submission of Tariff Revisions to Implement Order No. 745 in the SPP Integrated Marketplace, Docket No. ER12-1179-024, 

at 4 (filed May 24, 2016); and SPP Response to Request for Additional Information, Docket No. ER12-1179-025, at 1-2, 4 (filed 

Mar. 5, 2018).

68 Flex Alerts are voluntary calls for consumers to conserve electricity when there is a predicted shortage of energy supply. See

CAISO, What Is a Flex Alert, http://www.flexalert.org/what-is-flex-alert.
November 2018 Assessment of Demand Response and Advanced Metering

Page 18 Federal Energy Regulatory Commission

voluntary electricity conservation during the evening on July 24 and 25.69 These measures 

resulted in demand savings of 450 MW on July 24 and 540 MW on July 25, when CAISO posted 

a new peak demand record of 46,424 MW.70 Southern California Edison (SCE) separately called 

on customers participating in its Summer Discount Plan to allow the utility control over their air 

conditioning units for several hours from July 23-25 and August 6-7,

71 in exchange for a 

payment. More than 200,000 residential and 9,000 commercial customers are reported to have 

participated in the July event.

72 In addition, all three investor-owned utilities in California called

critical peak pricing days on several occasions this summer: SCE in July and August,

73 Pacific 

Gas & Electric (PG&E) in mid-June and throughout July,

74 and San Diego Gas & Electric 

(SDG&E) on August 6 and 7.75

On July 2, NYISO activated an estimated 495 MW of emergency demand response for several 

hours in Zone J (New York City),76 due to an extended heat wave in the region and the 

unexpected outage of a 345 kV transmission line in the city.77 An estimated 481 MW of 

emergency demand response was again activated in Zone J on August 28 and 29, when NYISO 

experienced its 2018 summer peak load.

78

On July 19, demand in ERCOT reached an all-time peak of 73,259 MW, approximately 2,100 

MW higher than the previous record set in 2016.79 Despite record demand and an estimated 

reserve margin this summer of 11 percent80—lower than normal—ERCOT did not issue notices 

for conservation or emergency demand response on this day.81

 69 CAISO, Flex Alert Notices, http://www.caiso.com/informed/Pages/Notifications/Flex-Alerts.aspx. 70 Greentech Media, Californians Slash Energy Use to Protect the Electric Grid (July 31, 2018), 

https://www.greentechmedia.com/articles/read/californians-slash-energy-use-to-protect-the-electric-grid. 71 SCE, Event History, https://www.sce.openadr.com/dr.website/scepr-event-history.jsf. 72 Greentech Media, Californians Slash Energy Use to Protect the Electric Grid (July 31, 2018), 

https://www.greentechmedia.com/articles/read/californians-slash-energy-use-to-protect-the-electric-grid. 73 SCE, Event History, https://www.sce.openadr.com/dr.website/scepr-event-history.jsf. 74 PG&E, Review Peak Day Pricing Event Day History, https://www.pge.com/en_US/business/rate-plans/rate-plans/peak-daypricing/event-day-history.page. 75 SDG&E, Demand Response Program Status, https://www.sdge.com/demand-response-program-status. 76 NYISO, NYISO Summer 2018 Hot Weather Operations, presented to Management Committee Sept. 26, 2018, at 10, 

http://www.nyiso.com/public/webdocs/markets_operations/committees/mc/meeting_materials/2018-09-

26/04%20Summer%202018%20NYISO%20Hot%20Weather%20Operating%20Cond.pdf. See also NYISO, Historic EDRP and 

SCR Activation Information (Aug. 30, 2018), 

http://www.nyiso.com/public/webdocs/markets_operations/market_data/demand_response/Demand_Response/Demand_Respons

e_Activations/EXT-DR-Events-and-Tests-History-With-CPs.pdf. 77 RTO Insider, NYISO Management Committee Briefs: July 25, 2018 (July 29, 2018), https://www.rtoinsider.com/nyisosummer-peak-demand-96986/. See also NYISO, Operations Performance Metrics Monthly Report: July 2018 Report, at 3, 

https://www.nyiso.com/public/webdocs/markets_operations/committees/mc/meeting_materials/2018-08-

29/03%20OperationsReport.pdf. 78 NYISO, NYISO Summer 2018 Hot Weather Operations, presented to Management Committee Sept. 26, 2018, at 15, 

http://www.nyiso.com/public/webdocs/markets_operations/committees/mc/meeting_materials/2018-09-

26/04%20Summer%202018%20NYISO%20Hot%20Weather%20Operating%20Cond.pdf. See also NYISO, Operations 

Performance Metrics Monthly Report: August 2018 Report, at 2, 

http://www.nyiso.com/public/webdocs/markets_operations/committees/mc/meeting_materials/2018-09-

26/03%20Operations_Report.pdf. 79 EIA, Electricity Reliability Council of Texas Surpassed All-Time Peak Hourly Load In July (July 31, 2018), 

https://www.eia.gov/todayinenergy/detail.php?id=36775. 80 ERCOT, ERCOT Expects Record-Breaking Peak Demand This Summer (Apr. 30, 2018), 

http://www.ercot.com/news/releases/show/155101. 81 ERCOT, Public Notices, http://www.ercot.com/services/comm/mkt_notices/notices/2018/07.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 19

Due to higher than expected temperatures and unplanned generator outages, ISO-NE experienced

an operating reserve shortage on September 3, the Labor Day holiday. In response, ISO-NE 

implemented several existing operating procedures, including a request for market participants to 

voluntarily reduce electricity consumption at their facilities.82

In addition, MISO activated emergency demand response (LMRs) on the evening of January 17, 

2018—for only the second time since 2007—in response to unusually cold conditions in MISO 

South.

83

 82 ISO Newswire, Labor Day was No Holiday for New England’s Power Grid: Weather and Resource Outages Led to Capacity 

Shortage Conditions (Sept. 7, 2018), http://isonewswire.com/updates/2018/9/7/labor-day-was-no-holiday-for-new-englandspower-grid-weather.html. 83 Potomac Economics, 2017 State of the Market Report for the MISO Electricity Market (June 2018) at 6-10.
November 2018 Assessment of Demand Response and Advanced Metering

Page 20 Federal Energy Regulatory Commission

: Potential for demand response as a quantifiable, reliable 

resource for regional planning purposes

NERC’s Demand Response Availability Data System

The North American Electric Reliability Corporation (NERC), as the Commission-certified 

Electric Reliability Organization (ERO) of North America, develops and enforces mandatory 

reliability standards that provide for reliable operation of the bulk power system.84 NERC uses 

transmission, generation, and demand response data systems to analyze past performance of the 

bulk power system and to identify performance trends.85 Specifically, NERC’s Demand 

Response Availability Data System (DADS), measures demand response performance, in part, to 

gauge the extent to which the resource reliably and consistently performs to ensure reliable 

planning and operations. In its latest State of Reliability report, NERC notes that demand 

response “can support reliability during forecast or actual reserve shortages, reliability events, or 

assisting with frequency control.” 86 For example, NERC reports that deployment of demand 

response resources increased during extreme heat conditions on the East Coast and Northeast 

during 2013, the Polar Vortex of 2014, and the West Coast during summer of 2015.87

In the past year, the NERC DADS working group continued efforts to improve data collection, 

quality control, and reporting through outreach and development of training materials. 

Specifically, the working group has taken steps to ensure the implementation of a uniform 

approach to reporting and measuring performance, including developing a data quality control 

document at the end of 2017.

88 With respect to demand response, the objective of the data 

quality control document is to define the types of quality controls that are applied to the demand 

response data reporting process “to ensure that application data are complete, accurate, and 

timely to support analysis and compute metrics for evaluating the performance of the bulk 

electric system.”89 In addition, NERC expects to complete a training video for, and to provide 

software-based training to, NERC DADS users in 2018.90

 84 16 U.S.C. §§ 824o(a)(2), 824o(c) (2005). 85 NERC, State of Reliability 2018 (June 2018) at vi, xii, 

https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/NERC_2018_SOR_06202018_Final.pdf. Specifically, 

these are NERC’s Transmission Availability Data System (TADS), the Generation Availability Data System (GADS), and the 

Demand Availability Data System (DADS). DADS collects three categories of demand response data: Program Type, Registered 

Capacity, and Events. 

86 Id. at 6. 87 Id. at 105. In addition, PJM’s analysis of the 2014 Polar Vortex states that PJM called on demand response three times during 

the event, and that the “availability and response of voluntary demand response” exceeded PJM’s expectations in real-time. 

Further, PJM’s analysis notes that voluntary demand response, “although not required to respond during the winter [of 

2013/2014], did respond and assisted in maintaining the reliability of the system.” See PJM, Analysis of Operational Events and 

Market Impacts During the January 2014 Cold Weather Events (May 8, 2014) at 20-21, 

https://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-analysis-of-operational-events-and-marketimpacts-during-the-jan-2014-cold-weather-events.ashx. 88 Donna Pratt, Data Quality Control Process, presented to Generating Availability Data System Working Group, Sept. 19-20, 

2017), 

https://www.nerc.com/comm/PC/Generating%20Availability%20Data%20System%20Working%20Gro1/Item%205%20%20GA

DSWG-Sept%202017-Data%20Quality%20Document.pdf. 89 Id. at 3. 90 NERC, DADS working group, January 11, 2018 meeting notes.
Assessment of Demand Response and Advanced Metering November 2018

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: Existing demand response programs and time-based rate 

programs and 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

Based on EIA survey data and program definitions, this chapter provides information on retail 

demand response91 and time-based rate programs92 in 2015 and 2016, and summarizes recent 

actions taken at the federal, regional, and state levels, and by industry, related to demand 

response. 

Enrollment in retail demand response and time-based rate programs

As shown in Table 5-1 below, in 2016 the number of retail customers enrolled in (incentivebased) demand response programs nationwide increased by eight percent to approximately 9.8

million customers, the highest number of customers enrolled in demand response programs since 

2013.

On a regional basis, the largest percentage increase in customer enrollment in retail demand 

response programs occurred in the RF region, where enrollments increased by about 50 percent 

from 2015 to 2016 to 2.4 million total customers. According to EIA data, this increase was 

primarily due to higher reported enrollment in programs run by Potomac Electric Power 

Company, Delmarva Power, and DTE Electric Company. Other regions also reported an 

increase in the number of customers enrolled in demand response programs. The number of 

customers in WECC rose by about six percent, or approximately 176,000 customers, due 

primarily to increases in the number of commercial customers enrolled in San Diego Gas & 

Electric Company’s territory. In addition, Texas RE reported an increase of 26,000 customers, 

or about a nine percent increase from 2015. 

In contrast, enrollment fell by 16 percent, or almost 230,000 customers, in SERC due to reported 

decreases in enrollment in programs run by Duke Energy Progress and Virginia Electric & 

Power Company (Dominion). Enrollment in SPP RE fell by 11 percent, or approximately 

21,000 customers, primarily due to lower reported enrollment in the residential program run by

Kansas Gas & Electric Company. Enrollment also fell in FRCC, NPCC, and for entities that did 

not specify a NERC region. These entities reported a net decrease in enrollment of 

 91 Demand response programs include direct load control, interruptible, demand bidding/buyback, emergency demand response, 

capacity market, and ancillary service market programs. Previously, EIA referred to these programs as “incentive-based” 

demand response programs. See EIA, Form EIA-861 Instructions, Schedule 6-Part B, 

https://www.eia.gov/survey/form/eia_861/instructions.pdf; and FERC, A National Assessment of Demand Response Potential

(2009), http://www.ferc.gov/legal/staff-reports/06-09-demand-response.pdf. 92 Time-based rate programs include real-time pricing, critical peak pricing, critical peak rebate, variable peak pricing, and timeof-use rates administered through a tariff. EIA now refers to these programs as “dynamic pricing” programs. See EIA, Form 

EIA-861 Instructions, Schedule 6-Part C, https://www.eia.gov/survey/form/eia_861/instructions.pdf.
November 2018 Assessment of Demand Response and Advanced Metering

Page 22 Federal Energy Regulatory Commission

approximately 4,000 customers due primarily to a decline in reported enrollment by TXU Energy 

Retail Company LP. 

Table 5-1: Customer Enrollment in Retail Demand Response Programs, by Region 

(2015 & 2016)

Region

Enrollment in Retail Demand 

Response Programs Year-on-Year Change

2015 2016 Customers Percent

AK 2,431 2,403 -28 -1.2%

FRCC 1,271,487 1,245,403 -26,084 -2.1%

HI 36,008 36,160 152 0.4%

MRO 1,205,568 1,239,580 34,012 2.8%

NPCC 80,884 72,969 -7,915 -9.8%

RF 1,591,730 2,390,143 798,413 50.2%

SERC 1,410,799 1,180,884 -229,915 -16.3%

SPP RE 204,020 182,576 -21,444 -10.5%

Texas RE 307,089 333,236 26,147 8.5%

WECC 2,972,779 3,148,899 176,120 5.9%

Unspecified 11,343 7,102 -4,241 -37.4%

Total 9,094,138 9,839,355 745,217 8.2%

Sources: EIA, EIA-861 Demand_Response_2015, Utility_Data_2015, 

Demand_Response_2016, and Utility_Data_2016 data files. 

Note: Although some entities may operate in more than one NERC Region, EIA data have 

only one NERC region designation per entity. Commission staff has not independently 

verified the accuracy of EIA data. 

As described above, despite decreases in some regions since a peak in 2013, 2014, or 2015, the 

number of customers enrolled in retail demand response programs nationwide has increased 

since 2013, as shown in Figure 5-1.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 23

Figure 5-1: Customer Enrollment in Retail Demand Response Programs by NERC Region

(2013 – 2016)

As Table 5-2 below indicates, there were almost eight million customers enrolled in retail timebased rate programs in the United States in 2016, an increase of approximately 361,000 

customers, or 4.8 percent, from 2015. The bulk of this increase in absolute terms occurred in the 

RF and WECC regions, with approximately 154,000 and 124,000 new customer enrollments, 

respectively. EIA data indicate the increase in time-based rate program enrollments for the RF

region is primarily due to an increase in enrollment in existing residential programs run by 

Baltimore Gas & Electric and Commonwealth Edison. The increase in enrollment in WECC is 

primarily due to significant enrollment increase in existing residential and commercial programs 

run by SDG&E and SCE. Texas RE reported the highest percentage increase from 2015, with 

the increase primarily attributable to over 2,300 new customers enrolled in commercial programs 

run by MP2 Energy LLC, a power marketer. 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

Number of Customers

2013 2014 2015 2016
November 2018 Assessment of Demand Response and Advanced Metering

Page 24 Federal Energy Regulatory Commission

Table 5-2: Customer Enrollment in Retail Time-based Rate Programs, by Region

(2015 & 2016)

Region

Enrollment in Retail 

Time-based Rate Programs Year-on-Year Change

2015 2016 Customers Percent

AK 53 55 2 3.8%

FRCC 21,444 27,578 6,134 28.6%

HI 538 568 30 5.6%

MRO 129,558 146,396 16,838 13.0%

NPCC 262,030 265,619 3,589 1.4%

RF 2,923,239 3,077,442 154,203 5.3%

SERC 198,627 230,997 32,370 16.3%

SPP RE 1,198,489 1,222,479 23,990 2.0%

Texas RE 1,867 4,720 2,853 152.8%

WECC 2,683,400 2,807,596 124,196 4.6%

Unspecified 169,815 166,777 -3,038 -1.8%

Total 7,589,060 7,950,227 361,167 4.8%

Sources: EIA, EIA-861 Dynamic_Pricing_2015 and Dynamic_Pricing_2016 data files.

Note: Although some entities may operate in more than one NERC Region, EIA data have only 

one NERC region designation per entity. Commission staff has not independently verified the 

accuracy of EIA data. 

Figure 5-2 below shows annual customer enrollment in retail time-based rate programs. SPP, 

WECC, and RF have reported annual increases in the number of customers from 2013 through 

2016. SERC and NPCC reported higher enrollment in 2016 than in 2015. Similar to customer 

enrollment in demand response programs in Figure 5-1, the number of customers enrolled in 

time-based rate programs nationwide has increased in most regions since 2013. 
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 25

Figure 5-2: Customers Enrolled in Retail Time-based Rate Programs by NERC Region

(2013-2016)

FERC demand response orders and activities

Since the last staff report, the Commission issued several demand response-related orders. 

AEE’s Petition for Declaratory Order on Energy Efficiency (Docket No. EL17-75)

Based on a petition for declaratory order filed by Advanced Energy Economy (AEE) on the 

Commission’s jurisdiction to regulate the participation of certain energy efficiency resources 

(EERs) in the wholesale electricity markets, the Commission issued on December 1, 2017 an 

order granting in part and denying in part AEE’s petition.93 In the order, the Commission found

that it has exclusive jurisdiction to regulate the participation of EERs in organized wholesale 

electric markets; found that a relevant electric retail regulatory authority may not bar, restrict, or 

otherwise condition the participation of EERs in wholesale electricity markets unless the 

Commission expressly gives relevant electric retail regulatory authorities such authority; and 

held that Order No. 719 does not provide for a relevant electric retail regulatory authority to 

exercise an opt-out with respect to EERs. On April 17, 2018, on rehearing, among other things, 

the Commission affirmed its finding that it has exclusive jurisdiction over the participation of 

EERs in the organized wholesale electricity markets, and granted requested clarifications that the 

Commission did not assert the authority to preempt the terms and conditions established by 

relevant electric retail regulatory authorities for retail customers to receive retail service.94

 93 Advanced Energy Economy, 161 FERC ¶ 61,245 (2017). 94 Advanced Energy Economy, 163 FERC ¶ 61,030 (2018).

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

Number of Customers

2013 2014 2015 2016
November 2018 Assessment of Demand Response and Advanced Metering

Page 26 Federal Energy Regulatory Commission

PJM Seasonal Aggregation (ER17-367)

On February 23, 2018, the Commission approved a set of proposed modifications to PJM’s tariff

to improve the ability of certain resource types95 to participate in PJM’s capacity market.

96 The 

approved modifications include enhancements to PJM’s aggregation rules to allow these types of 

resources to form aggregations across different deliverability areas and among different seasonal 

products. In addition, the approved modifications increase the ability of certain limited resources 

to obtain additional Capacity Interconnection Rights for the winter period to support aggregation,

and improve the measurement and verification of demand resource performance during winter 

periods.

MISO Exemption from Withholding for Demand Resources (ER17-806)

On August 17, 2017, the Commission approved MISO’s proposed tariff revisions related to 

market monitoring and mitigation in its annual Planning Resource Auction.97 In the order, the 

Commission found that it is reasonable for MISO to exempt Demand Resources, Energy 

Efficiency Resources, and External Resources from market monitoring and mitigation in the 

context of the annual Planning Resource Auction. The Commission stated that these resource 

types can already decide on an annual basis whether to register to participate in the market, and 

that encouraging the participation of these resources is beneficial to the annual Planning 

Resource Auction.

Electric Storage Resource Participation in Markets Operated by Regional Transmission 

Organizations and Independent System Operators (Order No. 841)

The Commission issued Order No. 841 on February 15, 2018.98 In Order No. 841, the 

Commission acted on the proposals included in the Commission’s Notice of Proposed 

Rulemaking (NOPR) issued in November 2016 with respect to the participation of electric 

storage resources in the capacity, energy, and ancillary service markets operated by RTOs and 

ISOs, while not taking final action on the proposed distributed energy resource aggregation 

reforms in the NOPR. To remove barriers to the participation of electric storage resources in the 

RTO and ISO markets, Order No. 841 requires each RTO and ISO to revise its tariff to establish 

a participation model consisting of market rules that, recognizing the physical and operational 

characteristics of electric storage resources, facilitates their participation in the RTO and ISO 

markets. The Commission made two clarifications regarding the relationship between demand 

response programs and the requirement to establish a participation model for electric storage 

resources. First, where an RTO/ISO already has a separate participation model that electric 

storage resources may use (such as for pumped-hydro resources or demand response), the 

Commission did not require the RTO/ISO to consolidate that participation model with the 

participation model for electric storage resources required by the order. Second, the Commission 

clarified that electric storage resources are not precluded from continuing to participate in 

demand response programs or under other participation models through which they are eligible 

to participate.99 Order No. 841 required each RTO/ISO to file any tariff changes needed to 

 95 Such as Capacity Storage Resources, Intermittent Resources, Demand Resources, Energy Efficiency Resources, and 

Environmentally-Limited Resources. 96 PJM Interconnection, L.L.C., 162 FERC ¶ 61,159 (2018). 97 Midcontinent Independent System Operator, Inc., 160 FERC ¶ 61,005 (2017). 98 Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System 

Operators, Order No. 841, 162 FERC ¶ 61,127 (Feb. 15, 2018). 99 Id. PP 55-56.
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 27

implement the requirements of the Final Rule within 270 days of its publication in the Federal 

Register.

While the November 2016 NOPR also proposed reforms related to distributed energy resource 

aggregations, Order No. 841 found that more information was needed with respect to those 

proposals. Consequently, the Commission chose not to take final action on those proposed 

reforms. Instead, the Commission convened a technical conference on distributed energy 

resource aggregation on April 10-11, 2018 in Docket Nos. RM18-9-000 and AD18-10-000 to 

collect additional information. 

Other federal demand response activities

U.S. Department of Defense

The Department of Defense’s (DoD) Defense Logistics Agency Energy (DLA Energy) provides 

the DoD and other government agencies with comprehensive energy solutions,100 including 

administering incentive-based demand response programs. In fiscal year 2017, DLA Energy 

operated 39 demand response installations in eight states and the District of Columbia—all of 

which are within organized wholesale markets—and had 115 MW of demand response enrolled 

in its programs.101 These figures are lower than fiscal year 2016, when DLA Energy reported 

having 68 installations and approximately 200 MW of demand response enrolled.102

In addition, the DoD is procuring behind-the-meter battery storage systems to provide peak 

shaving, among other services, at several installations. These include a 4.25 MW / 8.5 MWh

lithium-ion battery energy storage system under construction at Fort Carson, Colorado—the 

largest stand-alone commercially contracted battery at an army base—and a 1 MW / 1 MWh 

system at a U.S. Army depot in Tooele, Utah.

103 

U.S. General Services Administration

The General Services Administration (GSA) provides centralized procurement services for the 

federal government, including helping federal agencies to build, acquire, operate, and maintain 

office space, and preserving historic federal properties.104 GSA continues to enable the 

participation of facilities it manages in various demand response and energy efficiency programs, 

 100 U.S. DoD, Defense Logistics Agency Energy, Fiscal Year 2017 Fact Book, at 3, 

http://www.dla.mil/Portals/104/Documents/Energy/Publications/E_Fiscal2017FactBookLowRes2.pdf?ver=2018-03-29-073051-

897. 101 Id. at 54. 102 U.S. DoD, Defense Logistics Agency Energy, Fiscal Year 2017 Fact Book, at 54, 

http://www.dla.mil/Portals/104/Documents/Energy/Publications/E_Fiscal2016FactBookWebResolution_170706.pdf. 103 Utility Dive, US Military Pushes Clean Energy with Largest On-Base Battery (Aug. 22, 2018), 

https://www.utilitydive.com/news/us-military-pushes-clean-energy-with-largest-on-base-battery/530671/. See also PR 

Newswire, AECOM and Lockheed Martin to enhance energy resilience at Fort Carson with DoD’s largest peak-shaving battery

(Aug. 21, 2018), https://www.prnewswire.com/news-releases/aecom-and-lockheed-martin-to-enhance-energy-resilience-at-fortcarson-with-dods-largest-peak-shaving-battery-300700033.html; and Go Electric, Go Electric Inc. Awarded $1.7M Contract to 

Deliver Battery Energy Storage System to Tooele Army Depot (Jul. 25, 2017), 

http://nebula.wsimg.com/c3bd5230b162c5ba82a8e3523e05212d?AccessKeyId=D97AF8D908DF87B827C4&disposition=0&all

oworigin=1. 104 GSA, Background and History, https://www.gsa.gov/about-us/background-and-history. 
November 2018 Assessment of Demand Response and Advanced Metering

Page 28 Federal Energy Regulatory Commission

earning revenues that offset facility costs. For example, GSA buildings in the agency’s

Northeast and Caribbean Region earned approximately $430,000 in 2017-2018 through 

participation in demand response programs in New York and New Jersey. The number of GSA 

buildings participating in demand response programs in the region, and associated revenues, 

have grown over time, totaling $2.3 million since participation began in fiscal year 2011.105

Developments and issues in demand response

State legislative and regulatory activities related to demand response and time-based rates

This section highlights developments in retail demand response and time-based rate activities. In 

the past year, regulators in several states have approved, or are considering, time-based rate

pilots, some in combination with proposed electric vehicle charging infrastructure investments, 

due to an interest in incenting off-peak charging of electric vehicles. In other states regulators 

are considering next steps for demand response and time-based rate programs.

• Arizona. As of July 5, 2018, the Arizona Corporation Commission (ACC) is considering 

a set of proposed rules for the Arizona Energy Modernization Plan.106 Specifically, the 

proposals include an 80 percent renewable energy target by 2050, a 3 GW energy storage 

target by 2030, and an electric vehicle infrastructure target to support one million electric 

vehicles by 2050.107

In mid-2018, the Salt River Project (SRP) rolled out a “bring your own thermostat” pilot 

program called Flex Rewards. Under the program, customers may buy their own utilitycompatible thermostat that allows SRP to reduce peak demand at a maximum of 15 

conservation events per summer, in exchange for a credit on program participants’

electric bills.

108 

• California. After the last round of its Demand Response Auction Mechanism (DRAM) 

pilot program109 in June 2018, the California Public Utilities Commission’s (CPUC) 

Energy Division staff presented preliminary results of their independent analysis of the 

program to the CPUC.110 The CPUC found that the results were too complex to be 

 105 GSA, GSA Region 2 Marks Earth Day with Millions in Taxpayer Savings (May 1, 2018), https://www.gsa.gov/aboutus/regions/welcome-to-the-northeast-caribbean-region-2/region-2-newsroom/press-releases/gsa-region-2-marks-earth-day-withmillions-in-taxpayer-savings. 106 Draft Set of Formal Rules for the Arizona Energy Modernization Plan (CREST), Docket No. E-00000Q-16-0289 (ACC July 5, 

2018), http://images.edocket.azcc.gov/docketpdf/0000189786.pdf. 107 Draft Set of Formal Rules for the Arizona Energy Modernization Plan (CREST), Docket No. E-00000Q-16-0289 (ACC July 

5, 2018) at 7, http://images.edocket.azcc.gov/docketpdf/0000189786.pdf. 108 SRP, SRP Flex Rewards: FAQ, https://enrollmythermostat.com/faqs/srpflexrewards/. 109 The CPUC required the three investor-owned utilities in the state to establish Demand Response Auction Mechanism pilots to 

test the viability of using a competitive procurement mechanism for aggregated demand response sources to provide local, 

system, and flexible capacity. See Order Instituting Rulemaking to Enhance the Role of Demand Response in Meeting the State’s 

Resource Planning Needs and Operational Requirements, Docket No. R.13-09-011 (CPUC June 9, 2016). 110 The CPUC had previously required Energy Division staff to conduct an assessment of the program to determine whether the 

DRAM should be the primary means of sourcing demand response in the state. See Order Instituting Rulemaking to Enhance the 

Role of Demand Response in Meeting the State’s Resource Planning Needs and Operational Requirements, Docket No. R.13-09-

011 (CPUC Sept. 29, 2016).
Assessment of Demand Response and Advanced Metering November 2018

Federal Energy Regulatory Commission Page 29

addressed quickly and informally, so it extended the deadline to decide whether the 

DRAM will become a permanent program to July 17, 2019.111

On June 26, 2018, Southern California Edison filed a proposal with the CPUC to expand 

its electric vehicle charging infrastructure pilot program, aiming for 48,000 charging 

stations costing $760 million over four years.112

On July 31, 2018, Honda introduced a SmartCharge program that shifts electric vehicle 

charging based on real-time grid conditions. The program enables electric vehicle 

customers to participate in wholesale demand response events, and to receive payments 

in exchange for allowing their vehicle charging to be optimized based on electricity 

prices, grid needs, and their charging preferences. The program is only available for 

customers with a Honda Fit electric vehicle, but Honda plans to study the results of the 

program with the possibility of applying it to its other electric vehicles in the future.113

• Hawaii. On April 18, 2018, the Hawaii Public Utilities Commission (Hawaii PUC)

opened a proceeding to investigate performance-based regulation for Hawaii utilities, in 

response to ongoing changes in the state’s electric power industry.

114 The Hawaii PUC 

states that performance-based ratemaking can be used to provide rewards for specific 

outcomes and objectives, such as integrating technological advances like advanced 

metering and demand response capabilities.115

• Maryland. On February 6, 2018, the Maryland Public Service Commission (Maryland 

PSC) opened a proceeding to consider the implementation of an electric vehicle 

infrastructure portfolio.

116 The portfolio—and associated utility programs—was 

proposed by the Public Conference 44 Electric Vehicle Working Group, a consortium led 

by Baltimore Gas & Electric Company and joined by other utilities and stakeholders.

117 

 111 Application of Pacific Gas and Electric Company (U39E) for Approval of Demand Response Programs, Pilots and Budgets 

for Program Years 2018-2022, Assigned Commissioner’s Amended Scoping Memo and Ruling, Application No. 17-01-012 

(CPUC May 18, 2018), http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M214/K798/214798344.PDF. 112 Application of Southern California Edison Company (U 338-E) for Approval of its Charge Ready 2 Infrastructure and Market 

Education Programs, Application No. 18-06-015 (June 26, 2018), 

http://www3.sce.com/sscc/law/dis/dbattach5e.nsf/0/AA563CC19C1B4586882582C200659158/$FILE/A1806015-

%20SCE%20Charge%20Ready%202%20Application.pdf. 113 Honda, Honda SmartCharge Beta Program Helps Electric Vehicle Drivers Save Money and Reduce Environmental Footprint

(July 31, 2018), http://hondanews.com/releases/honda-smartcharge-beta-program-helps-electric-vehicle-drivers-save-money-andreduce-environmental-footprint. 114 The proceeding will consist of two phases: one for evaluation and assessment of the state’s current regulatory framework for 

electric utilities; and a second to explore, among other things, regulatory frameworks that result in incentive-neutral utility 

decisions between investments in capital and services. See Instituting Proceeding to Investigate Performance Based Regulation, 

Docket No. 2018-0088, Order No. 35411 (Hawaii PUC Apr. 18, 2018), at 1, 5-6, 12-13, 

https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A18D18B60624J02464. 115 Instituting Proceeding to Investigate Performance Based Regulation, Docket No. 2018-0088, Order No. 35411 (Hawaii PUC 

Apr. 18, 2018) at 14, https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A18D18B60624J02464. 116 In the Matter of the Petition of the Electric Vehicle Work Group for Implementation of a Statewide Electric Vehicle Portfolio, 

Notice of Initiating a Proceeding and Request for Comments, Case Number 9478 (Maryland PSC Feb. 6, 2018), 

http://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:\Casenum\9400-9499\9478\\3.pdf. 117 PC44 Electric Vehicle Work Group Leader, Proposal to Implement a Statewide Electric Vehicle Portfolio (Jan. 19, 2018), 

https://webapp.psc.state.md.us/newIntranet/AdminDocket/NewIndex3_VOpenFile.cfm?ServerFilePath=C%3A%5CAdminDocke

t%5CPublicConferences%5CPC44%5C95%2Epdf.
November 2018 Assessment of Demand Response and Advanced Metering

Page 30 Federal Energy Regulatory Commission

Specifically, the group proposes, among other things, to install 24,000 electric vehicle 

chargers statewide at a cost of $104 million between 2018 and 2023, and to expand 

existing, and create new, residential time-of-use rates offered by participating utilities.118

• Massachusetts. In its order approving the grid modernization plans submitted by 

Eversource, National Grid, and Unitil, the Massachusetts Department of Public Utilities 

(Massachusetts DPU) declined to approve customer-facing advanced meter investments, 

noting that the benefits of full advanced meter deployment do not currently justify the 

costs. The order found that the primary benefits of advanced metering are due to reduced 

peak demand as customers respond to price signals under time-based rate programs, but 

that competitive suppliers in the state face several issues regarding the decision to offer 

time-based rate products. Given this uncertainty, the Massachusetts DPU will begin a 

process to consider how to remove barriers to the implementation of time-based rate

products for all customers.119 

• Michigan. In mid-2018, DTE Energy and Consumers Energy, the two largest utilities in 

the state, filed separate applications with the Michigan Public Service Commission 

(MPSC) proposing new time-of-use rates in conjunction with $20.5 million combined 

investments in electric vehicle infrastructure.120

• Minnesota. On May 31, 2018, the Minnesota Public Utilities Commission (Minnesota 

PUC) approved a pilot program for residential time-of-use rates proposed by Xcel 

Energy.121 The program is scheduled to begin in early 2020, and will be deployed to 

10,000 customers.122 The program uses an opt-out design and will offer three different 

rates: an on-peak rate, a mid-peak rate, and an off-peak rate.123

• Nevada. On May 11, 2018, the Public Utilities Commission of Nevada (Nevada PUC) 

adopted a rule implementing SB 145 to allow NV Energy to build electric vehicle 

infrastructure and systems and to administer $15 million in incentives for third-party 

 118 Id. at Attachment C. 119 Petition of Massachusetts Electric Company and Nantucket Electric Company, d/b/a National

Grid for Approval by the Department of Public Utilities of its Grid Modernization Plan, Order Nos.15-120, 15-121, 15-122 

(Massachusetts DPU May 10, 2018) at 1-3, 

https://eeaonline.eea.state.ma.us/EEA/FileService/FileService.Api/file/FileRoom/9163509. 120 In the matter of the application of CONSUMERS ENERGY COMPANY for authority to increase its rates for the generation 

and distribution of electricity and for other relief, Case No. U-20134 (MPSC May 14, 2018) at 7, https://mipsc.force.com/sfc/servlet.shepherd/version/download/068t00000023OKMAA2; and In the matter of the Application of DTE 

Electric Company for authority to increase its rates, amend its rate schedules and rules governing the distribution and 

supply of electric energy, and for miscellaneous accounting authority, Case No. U-20162 (MPSC July 6, 2018) at 3-4, https://mipsc.force.com/sfc/servlet.shepherd/version/download/068t00000023OKMAA2. 121 In the Matter of Xcel’s Residential Time of Use Rate Design Pilot Program, Docket Nos. E-002/M-17-775, E-002/M-17-776 

(Minnesota PUC Aug. 7, 2018) at 8, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={90C81565-0000-

C411-A2FE-612297DE478D}&documentTitle=20188-145592-01. 122 In The Matter of the Petition of Northern States Power Company for Approval of a Time of Use Rate Design Pilot Program, 

Petition, Docket No. E-002/M-17-775 (Minnesota PUC Nov. 1, 2017) at 16, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={40D77C5F-0000-

C614-A997-18C8C3D839F9}&documentTitle=201711-137092-01. 123 Id. at 19-22.
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Federal Energy Regulatory Commission Page 31

developers seeking to build such infrastructure.

124 The rule defines electric vehicle 

infrastructure and systems as consisting of, among other things, vehicle chargers and 

time-based rates.125 Additionally, the rule authorizes NV Energy to invest in electric 

vehicle infrastructure of its own, but specifies that NV Energy may not use the $15 

million of incentives for this purpose.

126

• Ohio. On August 29, 2018, the Public Utilities Commission of Ohio (PUCO) released a 

roadmap as part of its PowerForward initiative that lays out the PUCO’s policy positions, 

principles, and objectives related to the state’s grid modernization effort. Among other 

things, the roadmap considers how the adoption of electric vehicles will potentially affect 

the operations of the distribution grid. To meet expected growth in electric vehicles, the 

PUCO anticipates the need for substantial deployment of charging infrastructure as well 

as the development of rate designs that incent electric vehicle charging during off-peak 

periods (such as time-of-use rates).

127

• Pennsylvania. In May 2018, the Pennsylvania Public Utility Commission (Pennsylvania 

PUC) issued a proposed policy statement that identifies factors it will consider in 

determining just and reasonable distribution rates that promote, among other things, the 

efficient use of electricity and distributed energy resources.

128 The policy statement 

discusses a number of alternative rate methodologies that utilities may consider 

proposing, including time-of-use rates and critical peak pricing.129

 124 Rulemaking to Implement the Provisions of Senate Bill 145 (2017), Docket No. 17-08021 (Nevada PUC May 11, 2018), 

http://pucweb1.state.nv.us/PDF/AxImages/DOCKETS_2015_THRU_PRESENT/2017-8/29834.pdf. 125 Id. at 11. 126 Id. at 12. 127 PUCO, PowerForward: A Roadmap to Ohio’s Electricity Future, at 19-21, https://www.puco.ohio.gov/industryinformation/industry-topics/powerforward/powerforward-a-roadmap-to-ohios-electricity-future/. 128 Fixed Utility Distribution Rates Policy Statement, Proposed Policy Statement Order, Docket No. M-2015-2518883 

(Pennsylvania PUC May 3, 2018), at 2, http://www.puc.state.pa.us/pcdocs/1568090.docx. 129 Id. at 20-21. See also Motion of Vice Chairman Andrew G. Place, Docket No. M-2015-2518883 (Pennsylvania PUC May 3, 

2018) at 1-2, http://www.puc.pa.gov/pcdocs/1565057.pdf.
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: Regulatory barriers to improved customer participation in 

demand response, peak reduction, and critical period pricing programs

The 2009 National Assessment of Demand Response Potential,

130 and previous annual staff 

reports, describe the barriers to customer participation in demand response. Outstanding barriers 

and recent actions taken to address them are presented below.

• Implementing Time-based Rates. One of the principal barriers to customer 

participation in demand response is relatively slow implementation of time-based rate

programs. As noted in the previous chapter, customer enrollment in time-based rate

programs increased by approximately five percent in 2016 from a year earlier primarily 

due to increased enrollment in programs in the RF and WECC regions. While customer 

participation in time-based rate programs has increased every year since 2013, only eight

million customers are participating in such programs—a relatively small amount. 

In the last year, several state commissions—including those in Minnesota and

Pennsylvania—have approved new pilots for, or are considering, time-based rates. Other 

states are taking additional actions that may result in an expansion in time-based rate

programs. The Massachusetts DPU, for example, intends to begin an investigation into 

removing the barriers to customer adoption of time-based rates as part of the state’s grid 

modernization effort. In addition, utilities in Michigan are proposing time-based rates to 

assist in managing the integration of electric vehicles into their systems.

In addition to these regulatory developments, there are nascent technological 

developments—such as the application of blockchain technology131 and associated 

“smart contracts”132 to the energy sector—that some industry experts believe could

support the ability of customers to meaningfully respond to prices. While the most wellknown application of the technology is to trade so-called cryptocurrencies such as bitcoin

or ether, there is emerging interest among stakeholders in the power sector to apply the 

technology to electricity transactions at the wholesale and retail levels. In addition, the 

National Institute of Standards and Technology (NIST) recently published an overview of 

blockchain technology that briefly discusses examples of use cases for the technology in 

the power sector.133

 130 FERC, A National Assessment of Demand Response Potential (2009), http://www.ferc.gov/legal/staff-reports/06-09-demandresponse.pdf. 131 A blockchain is a distributed ledger of transactions that provides a means of recording and verifying such transactions without 

requiring a central authority to maintain or validate the ledger. See David Livingston, et al. (Council on Foreign Relations), 

Applying Blockchain Technology to Electric Power System (July 2018), at 1, https://cfrd8-

files.cfr.org/sites/default/files/report_pdf/Discussion_Paper_Livingston_et_al_Blockchain_OR_0.pdf. 132 A smart contract is a piece of code capable of executing some function within a decentralized ledger. In the context of 

demand response, a smart contract could, for example, define the behavior of end-use devices during demand response events. 

See Claudia Pop, et al., Blockchain Based Decentralized Management of Demand Response Programs in Smart Energy Grids, 

Sensors 2018, 18, 162 (2018).

133 Daniel Yaga, et al. (National Institute of Standards and Technology) (2018), Blockchain Technology Overview (Draft), at 39, 

https://csrc.nist.gov/publications/detail/nistir/8202/draft.
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At the wholesale level, for example, Enel, a multinational firm, is conducting research

using blockchain technologies in place of proprietary, centralized market clearing 

software in the European wholesale market, which may lower transaction costs, increase 

the transparency of transaction data, and allow smaller entities to participate in the 

wholesale markets and respond directly to wholesale prices.134 In addition, Texas-based 

start-up Grid+ is developing a proprietary blockchain-based payment system and an 

artificial intelligence-enabled “smart agent” device capable of responding directly to 

wholesale prices and, among other things, controlling end-use technologies such as smart 

thermostats to provide demand response.135 Furthermore, utilities such as PG&E, Duke 

Energy, and Exelon are engaged in initiatives such as the Energy Web Foundation, an 

industry consortium that aims to apply blockchain technology in the energy sector.136

Across industries, almost all blockchain efforts are still in an experimental stage.137 

Power industry experts suggest a range of actions that policymakers might take to support 

the development of blockchain technology in the electricity sector. In addition to 

addressing cybersecurity and privacy concerns, these include establishing a process to 

develop interoperability standards for blockchain technology—perhaps convened by 

NIST—and allowing new blockchain ventures to pilot ideas and develop demonstration 

projects in a relaxed regulatory environment on a small scale (i.e., creating a “regulatory 

sandbox”).138

• Consumer Awareness and Engagement. Surveys indicate that, for the first time, the 

majority of U.S. consumers have heard of advanced meters (70 percent),

139 figures that 

have grown significantly since we last reported on this issue in the 2013 staff report.140 

In addition, nearly two-thirds of consumers are interested in receiving energy use 

information that is provided by advanced meters. Furthermore, 59 percent of those 

surveyed, and 75 percent of the segment of particularly engaged consumers, are either 

“probably interested” or “definitely interested” in participating in programs that reward 

them for reducing electricity use at peak times, such as peak-time rebates.141 According 

to research, millenials are particularly interested in these types of programs.142 This 

 134 IEEE Spectrum, Enerchain: A Decentralized Market on the Blockchain for Energy Wholesalers (May 25, 2017), 

https://spectrum.ieee.org/energywise/energy/the-smarter-grid/enerchain-a-decentralized-market-on-the-blockchain-for-energywholesalers. 135 Grid+, Welcome to the Future of Energy: White Paper (undated), at 32-33, https://gridplus.io/assets/Gridwhitepaper.pdf. See 

also David Livingston, et al. (Council on Foreign Relations), Applying Blockchain Technology to Electric Power System (July 

2018), at 15.

136 Energy Web Foundation, Affiliates https://energyweb.org/affiliates/. See also David Livingston, et al. (Council on Foreign 

Relations), Applying Blockchain Technology to Electric Power System (July 2018), Appendix Table A-2. 137 The Economist, Technology Quarterly: Cryptocurrencies and Blockchains (Sept. 1, 2018), at 12, 

https://www.economist.com/technology-quarterly/2018/09/01/dividing-the-cryptocurrency-sheep-from-the-blockchain-goats. 138 David Livingston, et al. (Council on Foreign Relations), Applying Blockchain Technology to Electric Power System (July 

2018), at 17-18. 139 Smart Energy Consumer Collaborative (SECC), SECC’s Customer Pulse and Market Segmentation Study – Wave 6 Summary

https://smartenergycc.org/research/secc-research/sgccs-consumer-pulse-and-market-segmentation-study-wave-6-summary/. 140 FERC, Assessment of Demand Response and Advanced Metering (2013), https://www.ferc.gov/legal/staff-reports/2013/octdemand-response.pdf. 141 SECC, 2018 State of the Consumer—Executive Summary, https://smartenergycc.org/research/secc-research/seccs-2018-stateof-the-consumer-report-summary/. See also SECC, Consumer Pulse and Market Segmentation Study - Wave 6, Executive 

Summary, at 6, https://smartenergycc.org/research/secc-research/sgccs-consumer-pulse-and-market-segmentation-study-wave-6-

summary/. 142 SECC, “SECC Research Brief: 2018 State of the Consumer,” (Mar. 20, 2018 webinar), https://vimeo.com/261003662.
November 2018 Assessment of Demand Response and Advanced Metering

Page 34 Federal Energy Regulatory Commission

research suggests that understanding the needs and degree of engagement of different 

consumer segments may be important to the success of demand response and time-based 

rate programs that leverage data from advanced meters.
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Appendix: Map of NERC Regional Entities (as of May 2017)

Note: On May 4, 2018, FERC approved a joint petition to transfer NERC registered entities 

within the SPP RE footprint to MRO and SERC. See NERC, MRO and SERC, 163 FERC ¶ 

61,094 (2018). A current map of NERC registered entities is here: 

https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/Regions24JUL18.jpg. 
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&

Demand Response and 

Advanced Metering

2018 Assessment of

Staff Report

Federal Energy Regulatory Commission

November 2018