2014 

 

 

Assessment of 

 

 

Demand Response and Advanced Metering 

 

 

 

 

Staff Report 

 

 

 

 

Federal Energy Regulatory Commission 

 December 2014 

 

 

 

 

 

 

 

 

 

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

Energy Regulatory Commission, its Chairman, or individual Commissioners, and are not binding on the 

Commission. 

 
ACKNOWLEDGEMENTS

Federal Energy Regulatory Commission Staff Team

Michael P. Lee, Team Lead

Omar Aslam

Ben Foster

David Kathan

Christopher Young

 

 
Federal Energy Regulatory Commission Page i

TABLE OF CONTENTS

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

Chapter 2 : Saturation and penetration rate of advanced meters ................................................ 3

Developments and issues in advanced metering..................................................................... 5

Federal programmatic support for advanced meters........................................................... 5

Demonstrated benefits of advanced meters ........................................................................ 5

State legislative and regulatory activity.............................................................................. 6

Chapter 3 : Annual resource contribution of demand resources................................................. 9

Role of Demand Response during Winter 2013/14 extreme weather events ....................... 12

Chapter 4 : The potential for demand response as a quantifiable, reliable resource for regional 

planning purposes..................................................................................................................... 14

Chapter 5 : 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............... 16

FERC demand response orders and activities....................................................................... 18

Other federal demand response activities............................................................................. 19

CEQ Presidential Memorandum on Energy Management................................................ 19

DOD and GSA activities................................................................................................... 20

ERCOT activities.................................................................................................................. 21

State legislative and regulatory activities related to demand response................................. 21

Industry demand response actions........................................................................................ 28

Chapter 6 : Regulatory barriers to improved customer participation in demand response, peak 

reduction, and critical period pricing programs........................................................................ 29
Page ii Federal Energy Regulatory Commission

LIST OF TABLES & FIGURES

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

Table 2-2: Estimated Advanced Meter Penetration by Region and Customer Class (2012).......... 4

Table 3-1: Potential Peak Reduction from Retail Demand Response Programs by NERC Region 

(2011 & 2012)................................................................................................................................. 9

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

and Customer Class (2012)........................................................................................................... 10

Table 3-3: Potential Peak Reduction from U.S. ISO and RTO Demand Response Programs..... 11

Table 5-1: Customer Enrollment in Incentive-based Demand Response Programs, by NERC 

Region (2011 & 2012) .................................................................................................................. 17

Table 5-2: Customer Enrollment in Time-based Demand Response Programs, by NERC Region 

(2011 & 2012)............................................................................................................................... 18
Assessment of Demand Response and Advanced Metering December 2014

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)

December 2014

Chapter 1: Introduction

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

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

EPAct 2005. It is based on publicly-available information and discussions with market 

participants and industry experts. Based on the information reviewed, it appears that:

• The penetration of advanced meters continues to climb.1 According to the Energy 

Information Administration (EIA), an additional 5.9 million advanced meters were 

installed and operational between 2011 and 2012, resulting in advanced meters 

representing almost 30 percent of all meters in the United States;2

• Potential peak reduction from demand response in the Regional Transmission 

Organizations (RTOs), Independent System Operators (ISOs), and Electric Reliability 

Council of Texas (ERCOT) markets increased by 2,451 MW to 28,503 MW from 2012 to 

2013 or 9.3 percent;3 and, 

• Demand response resources made significant contributions to balancing supply and 

demand during the late 2013 and early 2014 extreme cold weather events and helped 

preserve Eastern RTO and ISO reserve levels.4

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

(AMI) Meters are 

“Meters 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.” 

See: U.S. EIA, Form EIA-861: Annual Electric Power Industry Report Instructions, available at

http://www.eia.gov/survey/form/eia_861/instructions.pdf. 2 U.S. EIA, Electric Power sales, revenue, and energy efficiency Form EIA-861 detailed data files,

available at http://www.eia.gov/electricity/data/eia861/index.html. 3 See infra Table 3-3 (citing referenced data). 4 See the section below titled “Role of Demand Response during Winter 2013/2014 extreme weather 

events,” for a complete list of references.
December 2014 Assessment of Demand Response and Advanced Metering

Page 2 Federal Energy Regulatory Commission

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 December 2014

Federal Energy Regulatory Commission Page 3

Chapter 2: Saturation and penetration rate of advanced meters

This chapter reports on saturation and penetration rates for advanced meters, as well as 

developments and issues in advanced metering through July 2013. As summarized in Table 2-1, 

recent data indicates that advanced meter penetration rates and the number of advanced meters in 

operation continue to increase in the United States. 

Table 2-1: Estimates of Advanced Meter Penetration Rates

Data Source

Data As 

Of

Number of 

Advanced

Meters

(millions)

Total 

Number of 

Meters

(millions)

Advanced Meter

Penetration Rates

(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 (re-released) 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%

Sources:

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

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

3 FERC, Assessment of Demand Response and Advanced Metering staff report (December 2012).

4 U.S. 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. Advanced meters are 

defined as advanced metering infrastructure (AMI) meters.

5 The Edison Foundation Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals (May 

2012).

6 U.S. EIA, Form EIA-861 and Form EIA-861S: retail_sales_2012 and advanced_meters_2012 data files (October 29, 2013).

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

meters. Advanced meters are defined as advanced metering infrastructure (AMI) meters. 7 The Edison Foundation Institute for Electric Innovation, Utility-Scale Smart Meter Deployments: A Foundation for 

Expanded Grid Benefits (August 2013).

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

data are rounded for publication. 

According to 2012 EIA data,5 43.2 million advanced meters were operational and there were 

145.3 million ultimate electric utility customers,6 indicating a 29.7 percent penetration rate. EIA 

data for the previous year reports 37.3 million advanced meters were operational out of a total of 

144.5 million customers, representing a 25.8 percent penetration rate for 2011.7 Certain industry 

organizations predict that use of advanced meters will continue to grow. For example, The 

 5 U.S. EIA, Electric Power sales, revenues, and energy efficiency Form EIA-861 data files, 

(retail_sales_2012 and advanced_meters_2012 data files). 6 Form EIA-861 collects data on the number of customers served by each respondent, which staff used as a 

proxy for the number of meters. EIA defines customers as the average of the 12 close-of-month customer accounts 

(See Form EIA-861 Instructions, General Instructions). 7 U.S. EIA, Electric Power sales, revenues, and energy efficiency Form EIA-861 data files (2011 Data File 

2 and File 8).
December 2014 Assessment of Demand Response and Advanced Metering

Page 4 Federal Energy Regulatory Commission

Edison Foundation’s Institute for Electric Innovation projects more than half of all U.S. 

households will have advanced meters by 2015.8

Table 2-2 below provides estimated advanced metering penetration rates by North American 

Electric Reliability Council (NERC) region9 and retail customer class.10 Specifically, advanced 

meters represent more than half of the meters in three regions: 69.6 percent of meters in Texas 

Reliability Entity (TRE),11 52.3 percent in Florida Reliability Coordinating Council (FRCC), and 

50.7 percent in Western Electricity Coordinating Council (WECC). A slightly higher percentage 

of residential customers have an advanced meter (30.4 percent) than do customers in the 

commercial (25.2 percent) or industrial (24.5 percent) classes.

Table 2-2: Estimated Advanced Meter Penetration by Region and Customer Class (2012)

NERC Region

Customer Class

Residential Commercial Industrial All Classes

AK 1.3% 0.8% 0.0% 1.2%

FRCC 54.4% 36.6% 41.3% 52.3%

HI 0.0% 0.0% 4.1% 0.0%

MRO 14.3% 11.1% 17.9% 13.9%

NPCC 11.9% 11.9% 7.7% 11.9%

RFC 17.7% 13.6% 14.5% 17.3%

SERC 22.0% 17.6% 7.3% 21.4%

SPP 24.3% 21.4% 41.9% 24.2%

TRE 69.3% 73.0% 45.0% 69.6%

WECC 51.8% 43.6% 31.7% 50.7%

Unspecified 0.9% 0.3% 1.4% 0.8%

All Regions 30.4% 25.2% 24.5% 29.7%

Sources: U.S. EIA, 2012 Form EIA-861: advanced_meters_2012, utility_data_2012, and 

retail_sales_2012 data files. 

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

one NERC region designation per entity. The "unspecified" category includes short form 

respondents, some power marketers (excluding those in TX), unregulated entities and some federal 

entities. The number of ultimate customers served by full-service and energy-only providers is 

used as a proxy for the total number of meters. Commission staff has not independently verified 

the accuracy of EIA data. 

 8 Institute for Electric Innovation, Powering the People: Next Generation Utility – Opening Animation

(video), (Mar. 6, 2014), available at http://www.edisonfoundation.net/iei/Pages/IEIHome.aspx 9 NERC is comprised of eight regional reliability councils in the lower 48 states: the Florida Reliability 

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

(NPCC), ReliabilityFirst Corporation (RFC), SERC Reliability Corporation (SERC), Southwest Power Pool RE 

(SPP), Texas Reliability Entity (TRE), and Western Electricity Coordinating Council (WECC). The states of Alaska 

(AK) and Hawaii (HI) are not subject to NERC oversight and are separately presented for the report. 10 Table 2-2 includes data from the 2012 Form EIA-861 long and short forms. See U.S. EIA, Survey 

Forms: Electricity Survey Form Changes in 2013, available at http://www.eia.gov/survey/changes/electricity/2013/ 11 To more accurately estimate advanced meter penetration in the TRE, power marketers in Texas that did 

not specify a NERC region have been assigned to the TRE.
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 5

Developments and issues in advanced metering 

The American Recovery and Reinvestment Act of 2009 (Recovery Act),12 through partnerships 

with more than 200 electric utilities and other organizations, accelerated the deployment of 

advanced meters throughout the nation’s electric system.13 Deployment of advance meters in the

U.S. continues to progress as one component of electric grid modernization efforts. Industry 

stakeholders and policy makers are gaining experience with these new technologies, utilities are 

undertaking hardware and network integration efforts, and new grid and consumer applications 

are being explored and developed. Presented below are examples of continued programmatic 

support for advanced meters, reported demonstrated benefits of advanced meters, and state 

legislative and regulatory activities. 

Federal programmatic support for advanced meters

As of March 31, 2014, approximately 15.3 million advanced meters were installed and 

operational through the Department of Energy (DOE) Smart Grid Investment Grant (SGIG) 

program.14 Ultimately, 15.5 million advanced meters are expected to be installed and 

operational under SGIG. All SGIG projects are expected to reach completion in 2014 with 

continued reporting requirements through 2016.15 

Demonstrated benefits of advanced meters 

A majority of the public and privately supported Recovery Act projects fund installation of

advanced metering infrastructure that provide electricity usage data on an hourly or sub-hourly 

basis, communications networks that transmit this meter data to the utility and back to customers, 

and the utility office management systems (such as meter data management systems) that 

receive, store, and process the meter data.16 Advanced metering infrastructure facilitates several 

beneficial applications which can lead to improvements in operational efficiency, reliability and 

asset utilization. The applications include:

• Remote meter reading and remote connects/disconnects,

• Tamper detection and notification,

• Outage detection and notification,

• Voltage monitoring,

 12 American Recovery and Reinvestment Act of 2009, Pub. L. No. 111-5 (2009). The Recovery Act 

appropriated $4.5 billion for grid modernization programs, with $3.4 billion of that amount devoted to the Smart 

Grid Investment Grant program, a public-private partnership initiative for leveraging investments in grid 

modernization. 13 U.S. Department of Energy (DOE), American Recovery and Reinvestment Act of 2009: Smart Grid 

Investment Grant Program, Progress Report II at iv (Oct. 2013), available at

https://www.smartgrid.gov/sites/default/files/doc/files/SGIG_progress_report_2013.pdf. 14 U.S. DOE, SmartGrid.gov, Deployment Status: Advanced Metering Infrastructure and Customer 

Systems, https://www.smartgrid.gov/recovery_act/deployment_status. SGIG recipients reported approximately 16.2 

million advanced meters physically installed as of July 10, 2014. 15 See Smart Grid Investment Grant Program, Progress Report II, supra note 13 at iv. 16 Id. at 19. Recovery Act funding resulted in the implementation of 131 smart grid projects representing 

over $9 billion in combined public and private investments under two programs: the SGIG program and the Smart 

Grid Demonstration Program (SGDP). Seventy four projects deploy advanced metering infrastructure.
December 2014 Assessment of Demand Response and Advanced Metering

Page 6 Federal Energy Regulatory Commission

• Enabling integration of distributed energy systems through net metering, and

• Enabling the application of time-based rates.

Several utilities have employed Recovery Act funding to initiate advanced metering projects 

which include technologies and systems designed to help customers better understand and 

manage their electricity consumption and costs. These technologies include direct load control 

devices, web portals (through which customers can access information via the Internet, in-home 

displays), and programmable communicating thermostats. In addition, as part of their respective 

Recovery Act funded projects, nine utilities are conducting eleven consumer behavior studies

designed to evaluate the timing and magnitude of changes in peak demand and/or energy usage

patterns through time-based rate programs, either in addition to, or as replacements for, 

traditional rates to further motivate customer demand response.17 Demand‐side objectives, 

achieved through advanced metering, customer systems, and time-based rates, can provide

several benefits:18

• Deferred capital expenditures and improved capital asset utilization,

• Reduced electricity generation and environmental impacts, and

• Expanded options for customers to manage electricity consumption and costs.

Utilities are experimenting with different design techniques, such as randomized controlled 

trials, to improve their understanding of the magnitude of demand response, customer 

acceptance, and customer retention in various retail rate programs. Results indicate significant 

peak demand reductions, as well as bill savings for customers.19

State legislative and regulatory activity

• Illinois. In June 2014, Commonwealth Edison Company (ComEd) received approval 

from the Illinois Commerce Commission to accelerate the timetable for installing 

advanced meters.20 ComEd will install more than four million advanced meters with full 

deployment expected by 2018, which is three years ahead of the originally publicized 

2021 completion date.

 17 U.S. DOE, Analysis of Customer Enrollment Patterns in Time-Based Rate Programs – Initial Results 

from SGIG Consumer Behavior Studies at 4-5 (July 2013), available at

https://www.smartgrid.gov/sites/default/files/doc/files/DOE_CBS_report_final_draft-7-10-13_0.pdf. 18 U.S. DOE, Demand Reductions from the Application of Advanced Metering Infrastructure, Pricing 

Programs, and Customer-Based Systems – Initial Results at ii (Dec. 2012), available at

https://www.smartgrid.gov/sites/default/files/doc/files/peak_demand_report_final_12-13-2012.pdf 19 Reports are accessible via Smartgrid.gov, which is available at https://smartgrid.gov. Additional material 

includes American Council for an Energy-Efficient Economy, ACEEE Field Guide to Utility-Run Behavior 

Program, Report No. B132, (Dec. 2013) Mazur-Stommen and Farley; In Minnesota, ‘behavior’ programs show 

energy-saving results, Midwest Energy News, July 23, 2014. 20 Press Release, Commonwealth Edison Company (ComEd), ComEd Receives Approval to Accelerate 

Smart Meter Installation, Benefits, (June 11, 2014), available at

https://www.comed.com/newsroom/Pages/newsroomreleases_06112014.pdf.
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 7

• Maryland. In February 2014, the Maryland Public Service Commission (Maryland 

PSC) issued an order setting customer opt-out fees and ruled that Baltimore Gas and 

Electric, Delmarva Power and Light Company, Potomac Electric Power Company, and 

Southern Maryland Electric Cooperative must give customers the opportunity to opt-out 

of an advanced meter.21 In the order, the Maryland PSC states it was “cognizant of the 

costs imposed by extending this choice to individual ratepayers...[and would] allocate to 

these opt-out customers the appropriate costs associated with their choice[.]” Opt-out 

customers will be able to either keep their existing analog meter, or if a smart meter has 

already been installed, may have a non-smart digital meter installed instead.

• Massachusetts. In a June 2014 order, the Massachusetts Department of Public Utilities 

(DPU) established four grid modernization objectives for the distribution system in the 

state, including (1) reducing the effects of outages, (2) “optimizing demand” through 

time-based pricing and reducing peak demand, (3) integrating distributed resources, and 

(4) improving workforce and asset management. The order requires electric distribution 

companies to submit 10-year grid modernization plans that meet these objectives. Initial 

grid modernization plans must include, among other things, a five-year investment plan 

outlining how companies will implement “advanced metering functionality,” which the 

DPU views as the technological foundation of the state’s grid modernization goals.22 The 

DPU also concluded that a targeted cost recovery framework is necessary for grid 

modernization investments to overcome barriers to such investment under traditional 

cost-of-service ratemaking. Specifically, utilities may request a capital expenditure 

tracking mechanism that speeds up cost recovery for advanced metering investments that 

“accelerate progress in achieving the grid modernization objectives.”23 

• Missouri. In February 2014, Missouri Public Service Commission (MPSC) staff 

updated the Missouri Smart Grid Report.24 Among other things, staff recommends the 

opening of a new docket to address cost recovery issues and periodic workshops or 

technical conferences to share best practices.

 21 In the Matter of Potomac Electric Power Company and Delmarva Power and Light Company Request for 

the Deployment of Advanced Meter Infrastructure, Case Nos. 9207, 9208, and 9294, Order No. 86200, Maryland 

Public Service Commission (Feb. 26, 2014), available at

http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfm?ServerFilePath=C:\Casenum\9200-

9299\9207\\307.pdf. 22 Advanced metering functionality means: (1) the real-time collection of customers’ interval usage data, to 

enable participation in ISO-NE’s energy and ancillary services markets; (2) automated notification of outages and 

restorations; (3) two-way communication between the utility and the customer; and (4) with a customer’s 

permission, communication with and control of appliances. Investigation by the Department of Public Utilities on its 

own Motion into Modernization of the Electric Grid, D.P.U. 12-76-B, (Massachusetts Department of Public Utilities 

June 12, 2014), available at http://www.mass.gov/eea/docs/dpu/electric/12-76-a-order.pdf. 23 Id. at 19-22. 24Missouri Smart Grid Report, File No. EW-2011-0175 (Missouri Public Service Commission Feb. 2014), 

available at http://psc.mo.gov/CMSInternetData/Electric/Missouri%20Smart%20Grid%20Report%20-

%20February%202014.pdf.
December 2014 Assessment of Demand Response and Advanced Metering

Page 8 Federal Energy Regulatory Commission

• Oregon. Idaho Power Company25, PacifiCorp26 and Portland General Electric27

submitted their 2014 smart grid and advanced metering reports with the Oregon Public 

Utilities Commission (OPUC) between June and October 2014. Most of Idaho Power’s 

meters now have advanced metering capabilities and the company is applying these 

capabilities to enhance controls and services including remote connection and 

disconnection, direct load control, and time-variable pricing (which is available to 

qualifying residential customers through a pilot program).28 PacificCorp expects to 

release its advanced metering solution for Oregon by the end of 2014 and is evaluating

vendor proposals for advanced metering system implementation. Portland General

Electric’s Smart Grid Report, which was revised to include PUC recommendations and 

subsequently made effective by the Oregon PUC in October 2014,29 includes smart grid 

initiatives to raise customer awareness, improve customer engagement, offer pricing 

options and partner with customers to reduce usage during critical system peaks. 

 25 Idaho Power Company, Smart Grid Report, Docket No. UM 1675 (Oregon PUC Oct. 1, 2014), available 

at http://edocs.puc.state.or.us/efdocs/HAQ/um1675haq12121.pdf 26 PacifiCorp, Smart Grid Annual Report, Docket No. UM 1667 (Oregon PUC Oct 31, 2014), available at

http://edocs.puc.state.or.us/efdocs/HAQ/um1667haq163543.pdf. 27 Portland General Electric, Smart Grid Report, Docket No. UM 1657 (Oregon PUC June 1, 2014) 

available at http://edocs.puc.state.or.us/efdocs/HAQ/um1657haq162736.pdf. 28 Idaho Power, Time of Day: Pilot Study Status Report, (June 20, 2013), available at

https://www.idahopower.com/pdfs/AboutUs/CompanyInformation/SmartGrid/2013SmartGridReport.pdf; Idaho 

Power, Smart Grid Report for the Public Utility Commission of Oregon at app. D-6 (Oct. 1, 2013) available at

http://edocs.puc.state.or.us/efdocs/HAA/um1675haa94950.pdf. 29 In the Matter of Portland General Electric Company, Annual Smart Grid Report, Order No. 14333, 

(Oregon PUC Oct. 1, 2014), available at http://apps.puc.state.or.us/orders/2014ords/14-333.pdf
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 9

Chapter 3: Annual resource contribution of demand resources 

This chapter summarizes the annual resource contribution of demand resources from retail 

demand response programs and RTO and ISO demand response programs on a national and 

regional basis in 2011 through 2013, and also discusses the role of demand response in certain 

regions of the country during extreme weather events. According to data collected by EIA, total 

U.S. potential peak reduction30 from retail demand response programs increased by 1,907 MW 

between 2011 and 2012 (7.2 percent). Demand response programs within the Western 

Electricity Coordinating Council (WECC) accounted for 1,253 MW of potential peak reduction 

or nearly two-thirds (65.7 percent) of the increase in the U.S. total. Table 3-1 presents 2011 and 

2012 potential peak reduction from retail demand response programs within each of the nine 

regional electricity councils, as well as Alaska and Hawaii. 

Table 3-1: Potential Peak Reduction from Retail Demand Response Programs by NERC 

Region (2011 & 2012)

NERC 

Region

Annual Potential Peak 

Reduction (MW)

Year-on-Year Change

2011 2012 MW %

AK 28 27 -1 -3.6%

FRCC 3,360 3,306 -54 -1.6%

HI 43 42 -1 -2.1%

MRO 5,450 5,567 117 2.1%

NPCC 613 606 -7 -1.2%

RFC 5,529 5,836 307 5.6%

SERC 5,937 6,046 109 1.8%

SPP 1,215 1,323 108 8.9%

TRE 340 480 140 41.3%

WECC 4,016 5,269 1,253 31.2%

Unspecified 63 0 -63 -100.0%

Total 26,596 28,503 1,907 7.2%

Sources: U.S. EIA, EIA-861 file3_2011, dsm_2012 and utility_data_2012 data files. 

Note: Figures from source data are rounded to the nearest megawatt for publication. The 

percentage change is calculated based on the unrounded figures. 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. 

Industrial customer demand response represents 47 percent of the 2012 national potential peak 

reduction from retail programs, but the relative contribution by customer class varies by region 

(Table 3-2). For example, in FRCC the majority (53 percent) of potential peak reduction from 

retail programs in the region came from residential customer demand response. In contrast,

 30 Potential peak reduction (or 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.” U.S. EIA, Form EIA-861 

Instructions, Schedule 6, Part B.
December 2014 Assessment of Demand Response and Advanced Metering

Page 10 Federal Energy Regulatory Commission

commercial customers accounted for the majority of potential peak reduction in Alaska, Hawaii, 

NPCC and TRE; and industrial customers accounted for the majority in MRO, RFC, SERC, SPP, 

and WECC. Overall, residential and commercial customer demand response account for 30 and 

23 percent of the 2012 national potential peak reduction from retail programs, respectively.

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

Region and Customer Class (2012)

NERC Region

Customer Class

Residential Commercial Industrial Transportation All Classes

AK 5 13 9 0 27

FRCC 1,762 1,097 447 0 3,306

HI 17 25 0 0 42

MRO 1,869 1,141 2,557 0 5,567

NPCC 84 421 88 14 606

RFC 1,520 815 3,502 0 5,836

SERC 1,399 1,170 3,475 2 6,046

SPP 172 391 760 0 1,323

TRE 88 333 59 0 480

WECC 1,684 1,056 2,365 165 5,269

All Regions 8,600 6,462 13,261 180 28,503

Source: U.S. EIA, EIA-861 dsm_2012 and utility_data_2012 data files.

Note: Figures from source data are rounded to the nearest megawatt for publication. 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 shown in Table 3-3, potential peak reduction from RTO and ISO demand response programs

increased by 9.3 percent or 2,452 MW since 2012, to reach a total potential peak reduction of 

28,798 MW in 2013. The potential peak reduction from customers participating in RTO and ISO 

programs also increased as a percentage of total peak demand, increasing from 5.6 percent of 

peak demand in 2012 to 6.1 percent in 2013.

Potential peak reduction increased by 2,600 MW in MISO from 2012 to 2013, largely due to 

increased demand response from behind-the-meter generation and load modifying resource 

programs run by utilities. This increase in demand response participation, coupled with a decline 

in peak demand in the region due to milder summer temperatures, resulted in potential peak 

reduction as a percentage of peak demand increasing by almost 3 percent in 2013, compared to 

2012.31

 31 Potomac Economics, 2013 State of The Market Report for the MISO Electricity Markets at 6, 72 (June 

2014), available at

https://www.idahopower.com/pdfs/AboutUs/CompanyInformation/SmartGrid/2013SmartGridReport.pdf.
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 11

Table 3-3: Potential Peak Reduction from U.S. ISO and RTO Demand Response Programs

RTO/ISO

2012 2013

Potential

Peak 

Reduction

(MW)

Percent of 

Peak 

Demand8

Potential

Peak 

Reduction

(MW)

Percent of 

Peak 

Demand8

California ISO (CAISO) 2,430 1 5.2% 2,180 9 4.8%

Electric Reliability Council of Texas (ERCOT) 1,800 2 2.7% 1,950 10 2.9%

ISO New England, Inc. (ISO-NE) 2,769 3 10.7% 2,100 11 7.7%

Midcontinent Independent System Operator (MISO) 7,197 4 7.3% 9,797 12 10.2%

New York Independent System Operator (NYISO) 1,925 5 5.9% 1,307 13 3.8%

PJM Interconnection, LLC (PJM) 8,781 6 5.7% 9,901 14 6.3%

Southwest Power Pool, Inc. (SPP) 1,444 7 3.1% 1,563 15 3.5%

Total ISO/RTO 26,346 5.6% 28,798 6.1%

Sources:

1 California ISO 2012 Annual Report on Market Issues and Performance

2 ERCOT Quick Facts (Nov. 2012) 3 2012 Assessment of the ISO New England Electricity Markets 4 2012 State of the Market Report for the MISO Electricity Markets 5 2012 Annual Report on Demand Side Management programs of the New York Independent System Operator, Inc. under 

ER01-3001, et al. (Jan, 15, 2013). Figure includes ICAP/Special Case Resources (1,744 MW), Emergency DR (144 MW), 

and Day-Ahead Demand Response (37 MW) 6 PJM 2012 Load Response Activity Report, Delivery Year 2012-2013 Active Participants in PJM Load Response Program

at 2-3, (Apr. 9, 2013). Figure includes all resources registered as Emergency DR (8,552 MW), plus the difference between 

resources registered as Economic DR and both Emergency & Economic DR (229 MW) 7 SPP Fast Facts (Mar. 1, 2013) 8 Peak demand data are from the following: California ISO 2012 & 2013 Annual Reports on Market Issues and Performance; 

ERCOT 2013 Demand and Energy Report; ISO-NE Net Energy and Peak Load Report (Apr. 2013 & Apr. 2014); 2012 & 

2013 State of the Market Reports for the MISO Electricity Markets; 2012 & 2013 State of the Market Reports for the New 

York ISO Markets; 2012 & 2013 PJM State of the Markets Reports, Vol. 2; SPP 2012 & 2013 State of the Market Reports 9 CAISO 2013 Annual Report on Market Issues & Performance

10 ERCOT Quick Facts (Nov. 2013)

http://www.ercot.com/content/news/presentations/2013/ERCOT_Quick_Facts_November%202013.pdf

11 ISO-NE Demand Response Asset Enrollments at 2, (Jan. 2014) 12 2013 State of the Market Report for the MISO Electricity Markets at 72. This figure excludes 366 MW of emergency 

demand response that is also classified as LMR

13 2013 Annual Report on Demand Side Management programs of the New York Independent System Operator, Inc. under 

ER01-3001, et al. (Jan. 15, 2014) 14 PJM 2013 Demand Response Operations Markets Activity Report at 3-4 (Apr. 18, 2014), Figure represents “unique MW.” 15 SPP Fast Facts (as of Dec. 2013)

Note: Commission staff has not independently verified the accuracy of RTO, ISO and Independent Market Monitor data for 

purposes of this report. Values from source data are rounded for publication. 

Potential peak reduction in several RTOs and ISOs declined from 2012 to 2013. For the New 

York ISO (NYISO) fewer demand response resources registered as Special Case Resources

following NYISO’s implementation of its baseline calculation and auditing methods. This may 

be attributable to changes in NYISO’s methods that tightened criteria for qualification. 
December 2014 Assessment of Demand Response and Advanced Metering

Page 12 Federal Energy Regulatory Commission

Relatively low capacity prices in NYISO in recent years may have also contributed to less

participation in the SCR program.32

Demand response enrollments in ISO-NE declined by 669 MW—nearly 25 percent—in 2013. 

According to published reports and analyst comments, this decline may be at least partially due 

to Enernoc’s reduced presence in the Forward Capacity Market based on its customers’ view that

participation requirements out-weigh the value of participation.33 In CAISO, according to the 

market monitor’s report, reductions in capacity in two of SCE’s programs, while partially offset 

by an increase in capacity in PG&E’s programs, led to an overall the decline in potential peak 

reduction by demand response in 2013.34

Role of Demand Response during Winter 2013/14 extreme weather events

The January 2014 cold weather events caused numerous challenges for electricity system 

operators. In the eastern United States, the extreme cold weather of January 6-8 and January 17-

29 resulted in high demand, generation outages, and fuel disruptions that affected electric and 

fuel markets. Eastern RTO/ISO system operators utilized demand response during these high 

load periods to balance the electric system and prevent reserve shortages.

PJM activated about 2,000 MW of demand response for several hours during the morning and 

evening peaks of January 7th, and over 2,500 MW for several hours on January 23rd and January 

28th.35 PJM called on demand response to address issues with transfers, transmission limits and 

generating unit forced outages.36 Although demand resources were not obligated to respond 

during this period, close to 25 percent of registered demand response resources responded. PJM 

states that this experience demonstrates the year-round value of demand response.37 

As part of its 2013-2014 Winter Reliability Program, ISO-NE gained the ability to call on 

demand response assets up to 10 times during the winter. Demand response resources provided 

21 MW on five occasions between December 2013 and February 2014.38 ISO-NE included

demand response as a component of its 2014-2015 Winter Reliability Program.39

 32 Potomac Economics, 2013 State of the Market Report for the New York ISO Markets, at 91-93 (May 

2014), available at http://www.monitoringanalytics.com/reports/pjm_state_of_the_market/2013.shtml. 33 Platts, Enernoc thinning position in New England forward capacity market, (Apr. 9, 2013), available at

http://www.platts.com/latest-news/electric-power/washington/enernoc-thinning-position-in-new-england-forward21928104; Analysis Group, Capacity Markets in the Northeast: A Preview of Comments at the FERC Technical 

Conference on Centralized Capacity Markets in RTOs/ISOs at 16, Tierney, (Sept. 20, 2013) available at

http://www.ippny.org/uploads/PDF/1378921415_TierneyPresentation_Fall2013.pdf. 34 California ISO, Dep’t of Market Monitoring, 2013 Annual Report on Market Issues & Performance,

(Apr. 2014), available at http://www.caiso.com/Documents/2013AnnualReport-MarketIssue-Performance.pdf. 35 FERC Office of Enforcement, Technical Conference on Winter 2013-2014 Operations and Market 

Performance in RTOs and ISOs, Tr. 21, (April 1, 2014). 36 PJM, Analysis of Operational Events and Market Impacts during the January 2014 Cold Weather Events 

at 37, (May 8, 2014). 37 Id. at 20-21. 38 Letter from Gordon Van Welie, President, ISO-NE, to U.S. House Committee on Energy and Commerce, 

ISO-New England at 8 (April 18, 2014), available at http://www.iso-ne.com/pubs/pubcomm/corr/2014/2014-04-18-

iso-ne-response-to-house-energy-commerce.pdf. 39 ISO New England, Inc., 148 FERC ¶ 61,179, at PP 17-18, 39 (2014).
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 13

Other RTOs also utilized demand response during the winter peak load periods. NYISO has an 

Emergency Demand Response Program and a Special Case Resources capacity market program 

available for activation in energy shortage situations.40 Both programs were activated on

January 7, 2014 and NYISO called on reductions from about 900 MW of its demand resources.41

Demand response resources were put on notice for the New York City zone on January 27th for 

activation on January 28th, but ultimately were not needed to maintain reserve requirements.42

 40 New York ISO, Demand Response Programs, available at 

http://www.nyiso.com/public/markets_operations/market_data/demand_response/index.jsp 41 See: FERC Office of Enforcement, Technical Conference on Winter 2013-2014 Operations and Market 

Performance in RTOs and ISOs (April 1, 2014), Transcript at 21; New York State Reliability Council, NYISO 

Operations Report, (January 2014), available at

http://www.nysrc.org/pdf/MeetingMaterial/RCMSMeetingMaterial/RCMS%20Agenda%20170/January%202014%

20Ops%20Report.pdf. 42 Wes Yeomans, NYISO, Presentation at Technical Conference on Winter 2013-2014 Operations and 

Market Performance in RTOs and ISOs (April 1, 2014).
December 2014 Assessment of Demand Response and Advanced Metering

Page 14 Federal Energy Regulatory Commission

Chapter 4: The potential for demand response as a quantifiable, 

reliable resource for regional planning purposes

This chapter reports on the potential for demand response as a quantifiable, reliable resource for 

planning. The Department of Energy’s (DOE) Interconnection-wide Transmission Planning 

Initiative facilitated collaborative efforts to develop interconnection-wide transmission plans for 

the Western Interconnection, the Eastern Interconnection, and ERCOT under a broad set of 

alternative futures, including the intensive application of demand-side technologies.43 Funded 

by DOE grants, five organizations undertook efforts in the Western, Eastern and Texas 

Interconnections: Western Electricity Coordinating Council (WECC), Western Governors 

Association, the Eastern Interconnection Planning Collaborative (EIPC), the Eastern 

Interconnection States' Planning Council (EISPC), and ERCOT. After the completion of initial 

transmission planning efforts, these organizations continue to undertake enhanced studies of 

long-term interconnection-wide needs.

WECC, the Western Governors’ Association, and the Western Interstate Energy Board are 

working with stakeholders through the Regional Transmission Expansion Project to develop 

long-term, interconnection-wide transmission expansion plans.44 The Western Interstate Energy 

Board, along with the State-Provincial Steering Committee,45 released a report examining 

advanced demand response (i.e., “DR 2.0”) as a resource for integrating variable energy 

resources. 46 Advanced demand response resources are customer loads equipped with 

automation equipment that can increase and decrease while being available throughout the year

and frequently measured. The report focuses on the extent demand response resources can 

complement variable energy resources within a three to five year time frame and provides 

various estimates of the aggregate potential peak reduction from demand response for the 

Western Interconnection’s eleven states and two Canadian provinces.

EISPC and National Association of Regulatory Utility Commissioners (NARUC) are also 

providing general information to policy makers examining the use of planning models that not 

only compare transmission-only or generation-only solutions, but also integrate demand response 

and non-traditional resources to provide “more balanced and economic” resource mixes with fuel 

and environmental benefits.47 EISPC and NARUC discuss demand response modeling and data 

 43 U.S. DOE, Recovery Act Transmission Planning, available at http://energy.gov/oe/services/electricitypolicy-coordination-and-implementation/transmission-planning/recovery-act. 44 Western Governors’ Association, Regional Transmission Expansion Planning, available at

http://www.westgov.org/index.php?option=com_content&view=article&id=311&Itemid=81 45 SPSC was established in 2009 to execute the Recovery Act grant on interconnection-wide transmission

planning and was charged with providing input into transmission planning, improving grid utilization, and reducing 

the cost of integrating renewable energy resources. Minutes of the June 13, 2013 Meeting of the Western Interstate 

Energy Board, available at http://www.westgov.org/wieb/meetings/boardsprg2013/minutes.pdf. 46 Western Interstate Energy Board, The Role of Demand Response in Integrating Variable Energy 

Resource, (December 2013), available at http://www.westernenergyboard.org/sptsc/documents/12-20-

13SPSC_EnerNOC.pdf. 47 EIPC and NARUC, Co-optimization of Transmission and Other Supply Resources at 4, (September 

2013), available at http://www.westernenergyboard.org/sptsc/documents/12-20-13SPSC_EnerNOC.pdf. 
Assessment of Demand Response and Advanced Metering December 2014

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preparation requirements and the pros and cons associated with integrating various demand side 

and non-traditional resource options.48

ERCOT, in December 2013, released an expanded 20-year system assessment of the Texas 

Interconnect.49 Three different forecasts were created to support study scenarios: business-asusual scenario, drought, and an energy efficiency mandate. 50 In the ERCOT forecasts, various 

levels of demand response resources are modeled in future years to plan for various system 

conditions.51 

The Commission’s Order No. 1000 requires public utility transmission providers to comparably 

consider transmission and non‐transmission alternatives—such as energy efficiency, demand 

response, energy storage, distributed generation, and combined heat and power systems sited 

close to load—in the regional transmission planning process.52 Some regions in their Order No. 

1000 compliance planning processes have taken steps towards formalizing the consideration of 

non-transmission alternatives. For example, NYISO considers all resource types – including 

generation, transmission, demand response, or a combination of these resource types – on a 

comparable basis when evaluating proposed solutions in their regional transmission planning 

process. In addition, several regional transmission organizations, such as PJM, consider demand 

response and other non-transmission alternatives prior to determining what transmission projects 

to consider in their transmission planning process. PJM also allows demand response to 

participate in its capacity market and produce firm commitments to meet its capacity needs. On 

August 15, 2014, U.S. Court of Appeals for the D.C. Circuit issued its decision in South Carolina 

Public Service Authority v. FERC fully affirming Order No. 1000.53 

 48 Id. at 50. 49 ERCOT Interconnection, Long-Term Transmission Analysis (2012-2032) Final Report, Topic A and B 

Final Report, Volumes 1, at vi, 32 (December 2013), available at

http://www.ercot.com/content/committees/other/lts/keydocs/2014/DOE_LONG_TERM_STUDY_-_Final_Report_-

_Volume_1.pdf. 50 Id. at 43. 51 Id. app. H (Generation Expansion Summaries). 52 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 

Order No. 1000, FERC Stats. & Regs. ¶ 31,323 (2011) order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order 

on reh’g, Order No. 1000-B, 141 FERC ¶ 61,044 (2012). 53 No. 12-1232 (D.C. Cir., Aug. 15, 2014). 
December 2014 Assessment of Demand Response and Advanced Metering

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Chapter 5: 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

The chapter provides information on demand response programs and time-based rate programs in 

2011 and 2012, and summarizes recent federal, regional, state, and industry demand response

actions. Tables 5-1 and 5-2 show customer enrollment in incentive-based54 and time-based55

demand response programs in 2011 and 2012. As shown in Table 5-1, at a national level, the 

number of customers enrolled in incentive-based programs increased by 1.2 percent over this 

period, to more than 5.4 million. On a regional basis, the year-on-year changes ranged from a 

decline of 18 percent to an increase of 64 percent. 

For example, according to EIA data, customer enrollment increased by nearly 64 percent in TRE 

from 2011 to 2012, due to large increases in enrollment in residential programs run by 

Centerpoint Energy and the City of San Antonio. In contrast, customer enrollment in incentivebased programs fell by approximately 18 percent in SPP over the same period due to a drop in 

enrollment in several existing programs (e.g., Kansas Gas & Electric and Public Service Co. of 

Oklahoma), and the discontinuation of a residential program at North Arkansas Electric Coop.

The largest absolute change in incentive-based program enrollment occurred in RFC, where the 

introduction of new programs in 2012 by some utilities (e.g., Metropolitan Edison Co., PEPCO, 

Northern Indiana Public Service Co.) and increased enrollment in other utilities’ existing 

programs (e.g., PPL), was more than offset by the discontinuation of programs by some utilities 

and large drops in enrollment in other utilities’ existing residential programs (e.g., BGE, Duke 

Indiana, and Jersey Central Power & Light).

 54 Incentive-based demand response programs include direct load control, interruptible, demand 

bidding/buyback, emergency demand response, capacity market, and ancillary service market programs. See U.S. 

EIA, Form EIA-861 Instructions, Schedule 6-Part C. 55 Time-based rate programs include real-time pricing, critical peak pricing, variable peak pricing, and 

time-of-use rates administered through a tariff. See U.S. EIA, Form EIA-861 Instructions, Schedule 6-Part C.
Assessment of Demand Response and Advanced Metering December 2014

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Table 5-1: Customer Enrollment in Incentive-based Demand Response Programs, by NERC 

Region (2011 & 2012)

NERC 

Region

Enrollment in 

Incentive-based Programs Year-on-Year Change

2011 2012 Customers %

AK 2,460 2,432 -28 -1.1%

FRCC 1,283,904 1,328,487 44,583 3.5%

HI 37,304 36,703 -601 -1.6%

MRO 714,669 795,345 80,676 11.3%

NPCC 46,368 54,413 8,045 17.4%

RFC 1,546,608 1,398,341 -148,267 -9.6%

SERC 652,940 715,225 62,285 9.6%

SPP 112,041 91,585 -20,456 -18.3%

TRE 67,113 109,875 42,762 63.7%

WECC 903,063 884,299 -18,764 -2.1%

Unspecified 0 15,004 15,004 --

Total 5,366,470 5,431,709 65,239 1.2%

Sources: U.S. EIA, EIA-861 file3_2011, EIA-861 dsm_2012 and utility_data_2012 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 Table 5-2 shows, in contrast to incentive-based demand response programs, nationwide 

enrollment in time-based programs declined 6.1 percent from 2011 to 2012, although there was 

again much regional variation. According to EIA data, the large percentage change in 

enrollment in the “unspecified” region is due to increased enrollment in a residential program run 

by TXU Energy, a retail power marketer.56 WECC also experienced a large absolute and 

percentage change in enrollment, primarily due to creation of new programs by San Diego Gas &

Electric, Sacramento Municipal Utility District, Los Angeles Department of Water and Power, 

and Arizona Public Service. 

In addition, according to EIA data, SPP and RFC experienced significant absolute and 

percentage drops in enrollment in time-based programs. In SPP, this was due to the 

discontinuation of programs by Southwestern Electric Power and a large decline in enrollment in 

programs run by Public Service Co. of Oklahoma. In RFC, EIA data suggests the decline in 

enrollment was primarily due to attrition in Ohio Power’s residential program and in Duke 

Energy Indiana’s commercial program.

 56 Power marketers are not required to specify a NERC region when responding to the EIA-861 survey. 

U.S. EIA, Form EIA-861, Schedule 2, Part A.
December 2014 Assessment of Demand Response and Advanced Metering

Page 18 Federal Energy Regulatory Commission

Table 5-2: Customer Enrollment in Time-based Demand Response Programs, by NERC 

Region (2011 & 2012)

NERC 

Region

Enrollment in 

Time-based Programs Year-on-Year Change

2011 2012 Customers %

AK 0 38 38 --

FRCC 26,572 27,089 517 1.9%

HI 210 323 113 53.8%

MRO 76,921 82,310 5,389 7.0%

NPCC 244,837 293,721 48,884 20.0%

RFC 1,133,120 433,879 -699,241 -61.7%

SERC 180,507 180,619 112 0.1%

SPP 1,059,504 61,618 -997,886 -94.2%

TRE 669 604 -65 -9.7%

WECC 1,254,812 2,601,112 1,346,300 107.3%

Unspecified 3,844 57,435 53,591 1,394.1%

Total 3,980,996 3,738,748 -242,248 -6.1%

Sources: U.S. EIA, 2011: EIA-861 file3_2011; 2012: EIA-861 dsm_2012 and 

utility_data_2012 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. 

FERC demand response orders and activities 

On May 23, 2014, in a split ruling in the case of Electric Power Supply Association v. FERC, 

No. 11-1486 (D.C. Cir. May 23, 2014), the U.S. Court of Appeals for the D.C. Circuit (D.C. 

Circuit) vacated and remanded FERC’s final rule on demand response compensation in 

organized wholesale electric markets (Demand Response Compensation in Organized Wholesale 

Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322, order on reh’g, Order No. 745-

A, 137 FERC ¶ 61,215 (2011), order on reh’g, Order No. 745-B, 138 FERC ¶ 61,148 (2012)). 

After denying petitions for rehearing en banc of the decision, on October 20, 2014, the D.C. 

Circuit granted FERC’s motion to stay the issuance of the mandate until December 16, 2014, or 

if a petition for writ of certiorari is filed, until the Supreme Court’s final disposition.57 On 

December 5, 2014, the Solicitor General at the U.S. Department of Justice announced that he has 

authorized the filing of a petition for a writ of certiorari seeking review of the decision by the 

U.S. Supreme Court.

Prior to the decision in Electric Power Supply Association v. FERC, the Commission responded 

to a number of regional filings related to the participation of demand response resources in 

wholesale and interstate markets. This section briefly summarizes those Commission decisions.

 57 EPSA v. FERC, No. 11-1486 (D.C. Cir. Oct. 20, 2014) (order granting motion to stay issuance of 

mandate).
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• PJM Interconnection. In an order issued May 9, 2014,58 the Commission accepted 

PJM revisions to its tariffs to enhance the “operational flexibility” of demand response 

resources that clear its capacity market.59 Among other things, the revisions are intended 

to make it easier for PJM to use demand response resources with a capacity supply 

obligation when approaching system emergencies.60

• Midcontinent Independent System Operator. In an order issued March 14, 2014,61

the Commission accepted a MISO proposal to revise how demand response and energy 

efficiency is credited as part of MISO’s resource adequacy requirements. Load serving 

entities (LSEs) meet their planning reserve margin requirement in the MISO region by 

demonstrating that enough capacity has been acquired to meet their respective coincident 

peak demand forecasts, plus transmission losses, plus the Planning Reserve Margin. 

Prior to the change, LSEs had the ability to net demand response and energy efficiency 

resources from coincident peak demand. In order to address problems associated with 

tracking and assigning demand response and energy efficiency resources when customers 

switch LSEs during a planning year, MISO will now require LSEs to explicitly account 

for demand response and energy efficiency resources as capacity in the same manner as 

all other Planning Resources.

• New York Independent System Operator. On November 22, 2013, the Commission 

issued an order finding NYISO’s tariff provisions that excluded demand response 

facilitated by behind-the-meter generation from participation in the Day-Ahead Demand 

Response Program (DADRP), while permitting participation by similarly-situated 

demand response accomplished without the use of such behind-the-meter generation, 

were unduly discriminatory. The Commission ordered NYISO to develop rules that 

address appropriate eligibility, measurement, verification, and control requirements to 

ensure that demand response facilitated by behind-the-meter generation is provided in a 

manner that maintains system reliability and ensures that the resources are compensated 

only for the demand response service that they actually provide. Requests for rehearing, 

and action on NYISO’s compliance filings, are pending.

 

Other federal demand response activities

CEQ Presidential Memorandum on Energy Management

On December 5, 2013, President Obama released the Presidential Memorandum on Federal 

Leadership on Energy Management.62 This Presidential Memorandum directs federal agencies 

 58 PJM Interconnection, L.L.C., 147 FERC ¶ 61,103 (2014). 59 PJM Filing, Docket No. ER14-822-000 (filed December 24, 2013) (revising PJM OATT, OA & RAA 

with respect to Demand Response as a Capacity Resource). 60 There are outstanding compliance issues and other issues subject to rehearing in this preceding.

61 Midcontinent Indep. Sys. Operator, Inc., 146 FERC ¶ 61,180 (2014). 62 The White House, Presidential Memorandum – Federal Leadership on Energy Management: 

Memorandum for the Heads of Executive Departments and Agencies (Dec. 5, 2013), available at

http://www.whitehouse.gov/the-press-office/2013/12/05/presidential-memorandum-federal-leadership-energymanagement.
December 2014 Assessment of Demand Response and Advanced Metering

Page 20 Federal Energy Regulatory Commission

to increase their use of renewable energy and to implement several innovative energy 

management practices. Specific federal agency directives in the Memorandum include: (a) 

requiring agencies to consume 20 percent of their total agency electricity consumption by 2020 

from renewable sources; (b) completion of the installation of building energy meters and submeters as required by the National Energy Conservation Policy Act; (c) installation of water 

meters at agency buildings where cost-effective and appropriate; (d) directing that agency 

performance benchmarking conducted with the EPA Energy Star Portfolio Manager; (e) public 

disclosure of annual benchmark energy performance data through the Department of Energy 

web-based tracking system; (f) incorporation, where feasible, of the Green Button data standard 

into reporting, data analytics and automation, and processes, in consultation with local utilities; 

and (g) consideration of participation in demand response programs where available. These 

directives should update agency building-performance and energy-management practices to 

encourage increased energy efficiency and demand responsiveness.

DOD and GSA activities

In part because of the size of its infrastructure size and wide diversity of building types, the 

Department of Defense (DOD) recognizes it is “in a unique position to play a significant role in 

the development and deployment of the next generation of energy technologies.”63 DOD 

manages more than 300,000 buildings on some 500 installations throughout the United States,64

and consumes more than three-quarters of the energy used by the federal government.65 DOD’s 

Strategic Environmental Research and Development Program (SERDP) and Environmental 

Security Technology Certification Program (ESTCP)66 continue to support demonstration 

projects to facilitate DOD’s participation in wholesale demand response programs.67

The U.S. General Services Administration (GSA) owns and leases over 9,600 federal buildings,

including an inventory of more than 370 million rentable square feet of workspace,68 and over 30

federal agencies rely on the GSA to help with energy procurement strategies.69 In February 

2014, GSA noted that its partnership with the curtailment service provider, NuEnergen, resulted 

 63 U.S. Dep’t of Defense (DOD), Strategic Environmental Research and Development Program (SERDP) 

and Environmental Security Technology Certification Program (ESTCP), Energy, available at http://www.serdpestcp.org/64 DOD, SERDP and ESTCP, Energy and Water, available at http://www.serdp-estcp.org/ 65 DOD, SERDP and ESTCP, Energy and Water; DOD, SERDP and ESTCP, Energy. 66 DOD, SERDP and ESTCP, About SERDP and ESTCP, available at http://www.serdp-estcp.org/AboutSERDP-and-ESTCP. SERDP invests in basic and applied research and advanced development; ESTCP identifies 

and demonstrates cost-effective technologies. 67 SERDP and ESTCP projects include Automated Demand Response for Energy Sustainability (EW201256), Demonstrating Enhanced Demand Response Program Participation for Naval District Washington (EW201343), and Market Aware High Performance Buildings Participating in Fast Load Response Utility Programs with 

a Single Open Standard Methodology (EW-201401). SERDP and ESTCP maintain a database of active and 

completed energy projects that is available at http://www.serdp-estcp.org/Program-Areas/Energy-andWater/Energy/(list)/1/. 68 U.S. General Services Admin. (GSA), Review of the President’s Climate Action Plan, Senate Committee 

on Environment and Public Works (Jan. 16, 2014) available at http://www.gsa.gov/portal/content/184679. 69 Press Release, WorldEnergy, GSA Awards World Energy 5-Year Energy Management Contract (Sept. 8, 

2010), available at http://www.worldenergy.com/news/gsa-awards-world-energy-5-year-energy-managementcontract/.
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 21

in the enrollment of 19 federal buildings in NYISO and PJM demand response programs. In 

2013, GSA realized its largest demand response rebates.70

The U.S. Agriculture Department (USDA) continues to assist rural electric utilities with 

infrastructure upgrades, including smart grid investments, through the Rural Utilities Service 

Program. Since the fall of 2013, the USDA has announced a series of loans that include more 

than $65 million for smart grid projects to improve rural electric system communications 

technology.71 Since 2011, the USDA has invested more than $580 million in smart grid 

technologies nationwide.72

ERCOT activities

ERCOT established a program on June 1, 2014 that enables specific loads from the residential 

and small commercial sectors to participate and be economically dispatched within the real-time 

energy market.73 ERCOT also launched the Weather-Sensitive Emergency Response Service 

(ERS),74 which allows aggregations of residential and other weather-sensitive consumers to 

offer demand response capabilities during summer month peak hours in exchange for a capacity 

payment.75 The Weather-Sensitive ERS program has enrolled more than 60,000 accounts and is 

expected to provide as much as 21.6 MW of capacity. Additionally, ERCOT surveyed the 

number of retail customers in the ERCOT region subject to retail price response/demand 

response products to quantify expected demand reductions from these retail programs and 

products during various ERCOT events.76

State legislative and regulatory activities related to demand response

This section highlights developments in retail demand response and time-based pricing activities 

since staff’s 2013 report. These developments suggest that many states consider demand 

 70 Press Release, GSA, Region 2 Facilities Again Earn Largest Demand Response Rebate (Feb. 14, 2014), 

available at http://www.gsa.gov/portal/content/186379. 71 Press Releases, U.S. Depart. of Agriculture (USDA), Rural Development, Utilities, (See September 5, 

2013, September 12, 2013, October 24, 2013, December 13, 2013, and May 5, 2014), available at

http://www.rurdev.usda.gov/NR_Utilities_LP.html. 72 Press Release, USDA, Agriculture Secretary Announces Electric System Improvements in Eight States,

(September 5, 2013), available at http://www.usda.gov/wps/portal/usda/usdahome?contentid=2013/09/0170.xml.

The 2013 and 2014 USDA press releases announce over $54 million in subsequent funding. 73 Paul Wattles, ERCOT Senior Analyst, Board of Directors Meeting, Item 9: Demand Response Update,

(Aug. 12, 2014), available at

http://www.ercot.com/content/meetings/board/keydocs/2014/0812/9_Demand_Response_Update.pdf. 74 Press Release, ERCOT, As programs mature, ERCOT evaluates impact of demand-response services

(Aug. 13, 2014), available at http://www.ercot.com/news/press_releases/show/26654. 75 ERCOT, Governing Document for Weather-Sensitive Emergency Response Service Pilot Project

(undated), available at 

http://www.ercot.com/content/mktrules/pilots/wsers/Weather_Sensitive_ERS_Governing_Document_(Board_Appro

ved)1.doc.

76 Frontier Associates, Results from the 2013 Survey of LSEs to Obtain Retail DR and Dynamic Pricing 

Information, ERCOT Demand-Side Working Group presentation (June 25 2014), available at 

http://www.ercot.com/calendar/2014/06/20140625-DSWG.
December 2014 Assessment of Demand Response and Advanced Metering

Page 22 Federal Energy Regulatory Commission

response an important resource in meeting state policy goals related to modernization of the grid 

and the electric industry.

• California. In a September 2013 Order Instituting Rulemaking, the California Public 

Utilities Commission (CPUC) launched a proceeding to consider several changes to 

demand response programs in the state, including dividing current utility demand 

response programs into demand-side and supply-side resources, creating a competitive 

procurement mechanism for supply-side demand response resources, and determining 

funding and procurement processes for programs. The CPUC notes that “bifurcating” 

existing demand response programs would enable providers to competitively bid supplyside demand response resources into the CAISO wholesale markets, allowing CAISO to 

see and dispatch these resources as other generation resources are dispatched. The 

rulemaking also proposes three pilot programs to test the integration of retail demand 

response into the CAISO markets.77 The CPUC is addressing each of the issues raised in 

the September 2013 order separately.78

The CPUC is also working with CAISO and the California Energy Commission (CEC) to 

create a market for demand response and energy efficiency resources.79 CAISO advises 

that almost all of California’s current demand response consists of load management 

programs operated by the state’s three investor-owned utilities and overseen by the 

CPUC.80 Demand response resources currently meet about five percent of CAISO’s total 

system resource adequacy capacity requirements.81 

The CPUC, CAISO and CEC are developing a cross-agency work plan to align and track 

progress in four areas through 2020: load reshaping, resource sufficiency, operations and 

monitoring.82 A 2014 objective is for CPUC, CAISO and CEC to reach consensus on a 

process to track the development of the state’s demand response and energy efficiency 

 77 Order Instituting Rulemaking To Enhance The Role Of Demand Response In Meeting The State’s 

Resource Planning Needs And Operational Requirements, Rulemaking 13-09-011, (CPUC Sept. 25, 2013), available 

at http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M077/K151/77151993.PDF. 78 Decision Addressing Foundational Issue of the Bifurcation Of Demand Response Programs, Decision 14-

03-026, (CPUC Apr. 4, 2014), available at

http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M089/K480/89480849.PDF; Decision Approving TwoYear Bridge Funding For Demand Response Programs, Decision 14-01-004, (CPUC Jan. 16, 2014) available at

http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M086/K608/86608147.PDF. Decision Approving Demand 

Response Program Improvements and 2015-2016 Bridge Funding Budget, Decision 14-05-025, (CPUC May 15, 

2014), available at http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M091/K392/91392798.PDF; Proposed 

Decision Resolving Several Phase Two Issues and Addressing The Motion for Adoption of Settlement Agreement 

on Phase Three Issues, (CPUC Oct. 28, 2014) available at 

http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M129/K396/129396744.PDF. 79 California ISO, Demand Response and Energy Efficiency Roadmap: Maximizing Preferred Resources at 

2 (Dec. 2013), available at http://www.caiso.com/documents/dr-eeroadmap.pdf. 80 California ISO, Department of Market Monitoring, 2013 Annual Report on Market Issues & Performance

at 32 (Apr. 2014), available at http://www.caiso.com/Documents/2013AnnualReport-MarketIssue-Performance.pdf. 81 Id. 82 California ISO, Demand Response and Energy Efficiency Roadmap: Maximizing Preferred Resources

(Dec. 2013).
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Federal Energy Regulatory Commission Page 23

resources.83 Current CAISO efforts include developing approaches for conveying signals 

to customers to elicit beneficial shifts in energy consumption, work with stakeholders to 

consider these resources as alternatives to local transmission upgrades or power plant 

development, and working with the CPUC and CEC to establish a clear classification of 

each demand response program type as either a load-modifier or a supply-side resource.84

• Hawaii. In April 2014, the Hawaii Public Utilities Commission (HI PUC) released four 

orders that “provide major policy, resource planning, and operational directives to the 

Hawaiian Electric Company (HECO)” and strategic guidance for modernizing the electric 

system in the state.85 One of the orders rejected HECO’s proposed Integrated Resource 

Plan, finding that, among other things, the plan consisted of a series of unrelated projects 

without a strategy for moving toward a more sustainable business model. In a white 

paper attached to the order, the HI PUC lays out its vision of the future of Hawaii’s 

electric utilities. In the HI PUC’s view, the state has “entered a new paradigm” in which 

the best way to deliver least-cost electricity, expand customer options, and meet state 

policy goals is to aggressively pursue new clean energy sources, including utility-scale 

renewables, distributed generation, and demand response. Among the many 

recommendations in the report, the HI PUC states that HECO should implement an 

advanced metering program that focuses on delivering immediate value to customers by 

enabling them to access energy consumption data and to install distributed energy 

resources, including broader use of demand response technologies. The HI PUC also 

notes that, going forward, it will require Hawaii’s electric utilities to employ demand 

response technologies and dynamic pricing structures to manage customer loads in real 

time.86

In a related order, the HI PUC found that HECO’s current demand response programs in 

the state are uncoordinated and do not fully capture the benefits of demand response. The 

HI PUC ordered HECO (and its subsidiaries) to establish comprehensive goals and 

performance metrics for demand response programs, and to consolidate existing and 

planned programs into an integrated portfolio. The HI PUC specified objectives HECO 

must incorporate into its program design, such as providing quantifiable benefits to 

ratepayers, reducing energy consumption and peak demand, mitigating the variability of 

renewable generators, assuring system reliability, providing ancillary services, and giving 

 83 Id. at 21 84 Id. at 8, 11, 13. 85 Press Conference, Gov. Neil Abercrombie and Hawaii Public Utilities Commission (HI PUC), 

Announcement of Decisions Relating to Energy Policy in Hawaii, (Apr. 29, 2014) available at

http://www.youtube.com/watch?v=MeHmZ6E5GhM&index=3&list=PLS0iu_gsq8HspYCWpCSi1rXiBUMnY1S2; 

Press Release, “PUC Orders Action Plans to Achieve State’s Energy Goals,” (HI PUC Apr. 29, 2014), available at

http://puc.hawaii.gov/news-release/puc-orders-action-plans-to-achieve-states-energy-goals/. 86Regarding Integrated Resource Planning, Decision and Order No. 32052, Docket No. 2012-0036, (HI

PUC Apr. 28, 2014), Ex. A, available at http://puc.hawaii.gov/wp-content/uploads/2014/04/Decision-and-OrderNo.-32052.pdf.
December 2014 Assessment of Demand Response and Advanced Metering

Page 24 Federal Energy Regulatory Commission

customers greater control over their energy use.87 Pursuant to the HI PUC order, HECO 

filed its Integrated Demand Resource Portfolio Plan on July 28, 2014.88

• Maryland. Some utilities in Maryland are in the process of rolling out dynamic pricing 

programs. In the summer of 2013, Baltimore Gas and Electric (BGE) delivered its new 

Smart Energy Rewards program to 315,000 customers with advanced meters. The 

program provides a rebate for reducing energy use during times of highest demand along 

with personalized energy savings tips, communication through multiple channels, 

immediate feedback on individual results, and comparisons with similar households. 

BGE plans to roll out the program to all of its 1.1 million residential customers by 

summer 2015.89 In addition, the Maryland Public Service Commission approved

Delmarva Power and Light’s request90 to phase in, and recover the costs of, a dynamic 

pricing program for residential customers, beginning in June 2014.91

• Massachusetts. In January 2014, the Massachusetts Department of Public Utilities

(MA DPU) opened an investigation to examine how to implement time-varying rates, 

asking for stakeholder comment on, among other things, whether basic service and 

distribution rates should become or include time-varying rates.92 In June 2014, the MA 

DPU issued an order proposing a framework for time-varying rates, concluding that such

rates are essential to meeting the state’s grid modernization goals and supporting state

energy and environmental policies. Under the proposed framework, electric distribution 

companies in the state would be required to offer two time varying rates as their basic 

service products to all rate classes: (1) default time of use pricing with a critical peak 

pricing component, and (2) an option for a flat rate with a peak time rebate.93 In a 

 87 Policy Statement and Order Regarding Demand Response Programs, Order No. 32054, Docket No. 2007-

0341, (HI PUC April 28, 2014) available at http://puc.hawaii.gov/wp-content/uploads/2014/04/Order-No.-

32054.pdf.

88 Integrated Demand Response Portfolio Plan, Docket No. 2007-0341, (HECO July 28, 2014) available at 

http://dms.puc.hawaii.gov/dms/OpenDocServlet?RT=&document_id=91+3+ICM4+LSDB15+PC_DocketReport59+

26+A1001001A14G29B04851H0000418+A14G29B32630J102051+14+1960. 89 Press Release, Opower, How Baltimore Gas and Electric is Solving the Dynamic Pricing Puzzle (Jan. 13, 

2014), available at http://blog.opower.com/2014/01/how-baltimore-gas-and-electric-is-solving-the-dynamic-pricingpuzzle/. 

90 Delmarva Power & Light, Delmarva Power & Light Company's Proposed Phase-In Of Residential 

Dynamic Pricing Beginning June 1, 2014, Case No. 9207, (filed Mar. 14, 2014), available at

http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfm?ServerFilePath=C:\Casenum\9200-

9299\9207\\309.pdf. 91 Letter to Parties noting that it has accepted tariff pages filed by DP&L - 5/7/14 AM, Case No. 9207, (MD 

PUC May 8, 2014), available at

http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfm?ServerFilePath=C:\Casenum\9200-

9299\9207\\318.pdf. 92 Investigation by the Department of Public Utilities upon its own motion into Time Varying Rates, Order 

Opening Investigation, D.P.U. 14-04, (MA DPU Jan. 23, 2014), available at

http://web1.env.state.ma.us/DPU/FileRoomAPI/api/Attachments/Get/?path=14-04%2f12314dpuord.pdf. 93 Anticipated Policy Framework for Time Varying Rates, D.P.U. 14-04-B, (MA DPU June 12, 2014), 

available at http://www.mass.gov/eea/docs/dpu/orders/d-p-u-14-04-b-order-6-12-14.pdf. As of this writing, the MA 

DPU is seeking comments on this proposed framework.
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Federal Energy Regulatory Commission Page 25

November 5, 2014 order, the MA DPU adopted without modification the proposed policy 

framework for the implementation of time-varying rates for basic service.94

• New York. In April 2014, the New York Public Service Commission opened the 

Reforming the Energy Vision (REV) proceeding to consider how to align electric utility 

practices and the state’s regulatory framework with technological advances in 

information management and power generation and distribution.95 In a white paper 

attached to the order,96 the New York Department of Public Service (NYDPS) staff 

proposed to transform New York’s electric industry to “make energy efficiency and other 

distributed resources a primary tool in the planning and operation of an interconnected 

modernized power grid.” The NYDPS proceeding consists of two tracks. The first track 

involves a collaborative process to examine the role of distribution utilities in enabling 

market-based deployment of distributed energy resources to promote load management 

and greater system efficiency, including peak load reductions. The second track, 

undertaken in parallel with the first stage, but on a later timeline, will examine changes in 

current regulatory, tariff, and market designs and incentive structures to better align 

utility interests with achieving the Commission’s policy objectives.97

In the April 2014 white paper, NYDPS staff identified several issues related to demand 

response under this proposed framework: (1) how to align various wholesale and retail 

market rules for demand response to fully capture the value of distribution-level markets; 

(2) how to address the potential for multiple payments for demand response resources 

called simultaneously by the Distributed System Platform Provider (DSPP) and the 

NYISO; and (3) whether participation in New York ISO’s demand response programs 

could fall as the DSPP takes on the role of demand response aggregator.98 In August 

2014, NYDPS staff released its straw proposal on Track One issues, finding, among other 

things, that the New York Public Service Commission should adopt the basic elements of 

the REV vision and proceed with implementation as proposed.99 A policy decision on 

 94 Order Adopting Framework for Time Varying Rates, D.P.U. 14-04-C, (MA DPU Nov. 5, 2014), 

available at http://web1.env.state.ma.us/DPU/FileRoomAPI/api/Attachments/Get/?path=14-

04%2fOrder_1404C.pdf. 95 Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Order Instituting 

Proceeding, Case 14-M-0101, (NY PSC Apr. 25, 2014), available at

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7b9CF883CB-E8F1-4887-B218-

99DC329DB311%7d. 96 Reforming the Energy Vision, Case 14-M-0101, (NYDPS Apr. 25, 2014), available at

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7b9CF883CB-E8F1-4887-B218-

99DC329DB311%7d. 97 More information on the REV proceeding is available at 

http://www3.dps.ny.gov/W/PSCWeb.nsf/ArticlesByTitle/26BE8A93967E604785257CC40066B91A?OpenDocume

nt. 98 Reforming the Energy Vision, Case 14-M-0101, (NYDPS Apr. 25, 2014), available at

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7b9CF883CB-E8F1-4887-B218-

99DC329DB311%7d. 99 Developing the REV Market in New York: DPS Staff Straw Proposal On Track One Issues, Case 14-M0101, (NYDPS Aug. 22, 2014), available at

http://documents.dps.ny.gov/public/Common/ViewDoc.aspx?DocRefId=%7BCA26764A-09C8-46BF-9CF6-

F5215F63EF62%7D. Note: the acronym for Distributed System Platform Provider was shortened to DSP in this 

straw proposal, and refers to both the platform function and the platform entity.
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Page 26 Federal Energy Regulatory Commission

Track One is expected in early 2015. Proposals and decisions in Track Two will occur 

later in 2015, starting with a NYDPS staff straw proposal that is expected to be issued on 

January 30, 2015.

• Pennsylvania. In a February 20, 2014 order,100 the Pennsylvania Public Utilities 

Commission (PAPUC) proposed a new methodology for setting peak reduction targets 

under Act 129, based on the Statewide Evaluator’s conclusion that programs under the 

current method101 are not cost-effective, even when including benefits from price 

suppression in the wholesale markets.102 Specifically, the PAPUC proposes, in line with 

the Statewide Evaluator’s recommendation, to replace the current 100 hour methodology 

with one that bases demand response hours on a comparison of day-ahead and peak load 

forecasts, calling an event if the day-ahead load forecast is above a certain percentage of 

the peak load forecast. The order also directs the Statewide Evaluator to conduct a 

demand response potential study for the state using both the current and proposed 

methods. Additionally, the PAPUC directed the Statewide Evaluator to exclude potential 

revenue from bidding demand response resources into PJM’s capacity market when 

estimating program cost-effectiveness.

• Rhode Island. The Rhode Island Public Utilities Commission (RIPUC) approved 

National Grid’s proposal to continue its Load Curtailment Pilot in the Tiverton/Compton 

Area, which tests whether demand response can manage local distribution capacity 

requirements during peak periods.103 Demand response events under the pilot begin in 

2014, and use the demand response capabilities of wifi thermostats, lighting ballasts, and 

smart plugs installed in previous years of the pilot, along with certain new technologies to 

be offered to customers. Participation in demand response events is voluntary; however,

customers opting out forfeit their annual bill credit. National Grid estimates that the pilot 

will result in lifetime demand savings of more than 2 MW in the Tiverton/Compton 

area.104 

• Texas. Development of retail demand response continues in Texas. CPS Energy in San 

Antonio, in partnership with Honeywell, will offer a new automated demand response 

(ADR) program to its commercial and industrial customers. Based on pilot program 

achievements, the full-fledged program is expected to be the largest ADR program

 100 Peak Demand Cost Effectiveness Final Order, Docket Nos. M-2012-2289411 and M-2008-2069887, 

(PAPUC Feb. 20, 2014), available at http://www.puc.pa.gov/pcdocs/1269801.doc. 101 Currently, under Phase I of Pennsylvania’s Energy Efficiency and Conservation (EE&C) program, the 

Pennsylvania Commission required each utility to reduce annual peak demand by 4.5 percent in its 100 highest 

hours of demand. See Energy Efficiency and Conservation Program Implementation Order, Docket No. M-20008-

2069887, (PAPUC Jan. 16, 2009) available at

http://www.puc.pa.gov/electric/pdf/Act129/EEC_Implementation_Order.pdf. 102 GDS Associates, Act 129 Demand Response Study: Final Report, (Nov. 1, 2013), preparing report for 

PAPUC, available at http://www.puc.pa.gov/pcdocs/1256728.docx. 103 In Re: the Narragansett Electric Company d/b/a National Grid’s Energy Efficiency Program Plan for 

2014 and 2014 System Reliability Procurement Report, Order No. 21298, Docket Nos. 4451 & 4453, (RIPUC Dec. 

24, 2013), available at http://www.ripuc.org/eventsactions/docket/4451-4453-NGrid-Ord21298_12-24-13.pdf. 104 National Grid, 2014 Reliability System Procurement Report, Submitted to the RIPUC, Docket No. 4453, 

(Nov. 1, 2013), available at http://www.ripuc.org/eventsactions/docket/4453-Ngrid-SRP2014_11-1-13.pdf.
Assessment of Demand Response and Advanced Metering December 2014

Federal Energy Regulatory Commission Page 27

offered by a municipal utility, if the target of 6 MW of potential reduction is realized.105 

In the residential market, Austin Energy’s “Rush Hour Rewards” program takes 

advantage of the capabilities of the Nest smart thermostat to provide demand response 

services to homeowners. Enrollees receive a one-time $85 rebate for allowing the utility 

to manage air conditioning usage on event days through the Nest thermostat.106 The 

process is automatic: the thermostat receives upcoming demand response event

information from the utility and adjusts temperature settings accordingly: precooling the 

home before an event and turning the temperature up afterwards. Customers receive

event notification through multiple channels, and can override temperature settings.107

• Virginia. Dominion Virginia Power is conducting an ongoing dynamic pricing pilot, 

approved by the State Corporation Commission in 2011 and expanded and modified in 

2013.108 The pilot allows a limited number of residential and small and medium 

commercial customers to voluntarily enroll in dynamic rate plans that divide the year into 

high-, medium-, and low-priced days, and have a different number of pricing periods 

(i.e., on-peak/off-peak or on-peak/shoulder/off-peak) each day, depending on the time of 

year. Residential customers pay a demand charge each month. Commercial customers 

pay a demand charge that may include a ratchet above 30 MW, and may also be subject 

to critical peak pricing charges. An evaluation of the pilot estimates that, on high-priced

summer days, the average residential program participant reduced electricity demand 

(kW) by 6.5% during on-peak hours, 3.9% during shoulder hours, and 1.3% during offpeak hours, compared to a control group. In addition, residential participants shifted a 

small amount of demand to off-peak periods. The evaluation found no statistically 

significant reductions in usage by commercial customers. Dominion plans to continue 

the pilot through January 2016.109

 105 Press Release, Honeywell, Honeywell and CPS Energy Expand Efforts to Help Make the Electrical Grid 

Smarter, More Reliable, (Mar. 26, 2014), available at https://www.honeywellsmartgrid.com/enUS/NewsEvents/PressR/Pages/Honeywell-and-CPS-Energy-Expand-Efforts-to-Help-Make-the-Electrical-GridSmarter,-More-Reliable.aspx. 106 MIT Technology Review, The Lowly Thermostat, Now Minter of Megawatts, (May 20, 2014), available 

at http://www.technologyreview.com/news/527366/the-lowly-thermostat-now-minter-of-megawatts/. 107 Nest, What is Rush Hour Rewards, (June 2, 2014), available at http://support.nest.com/article/What-isRush-Hour-Rewards. 108 In re: Virginia Electric and Power Company's proposed pilot program on dynamic rates, Case No. PUE2010-00135 (VA State Corp. Comm’n Aug. 26, 2013), available at

http://docket.scc.state.va.us/CyberDocs/Libraries/Default_Library/Common/frameviewdsp.asp?doc=132115&lib=C

ASEWEBP_LIB&mimetype=application%2Fpdf&rendition=native. 109 Annual Report to the State Corporation Commission Of Virginia Electric and Power Company On its 

Dynamic Pricing Pilot, Case No. PUE-2010-00135 (VA State Corp. Comm’n July 31, 2014), available at

http://docket.scc.state.va.us/CyberDocs/Libraries/Default_Library/Common/frameviewdsp.asp?doc=138188&lib=C

ASEWEBP_LIB&mimetype=application%2Fpdf&rendition=native. See also Appendix 5, Dominion Virginia 

Power’s Dynamic Pricing Pilot: Evaluation Report – Final, prepared by DNV GL, Inc., July 7, 2014. 
December 2014 Assessment of Demand Response and Advanced Metering

Page 28 Federal Energy Regulatory Commission

Industry demand response actions

Leadership in Energy and Environmental Design 

As part of the Leadership in Energy and Environmental Design (LEED) rating system, in 2010 

the U.S. Green Building Council (USGBC) began piloting a new credit to incent demand 

response efforts in new and existing commercial buildings. With the incorporation of the 

demand response credit in late 2013,110 the focus is now on identifying and overcoming barriers 

to the development of the automated demand response market. The USGBC and the 

Environmental Defense Fund founded the Demand Response Partnership Program to conduct 

research on the implementation of automated demand response; create a forum for utilities, 

service providers, and managers of LEED registered buildings to discuss their experiences with 

the credit program; and to publish case studies. In addition to incorporating the demand response 

credit, LEED is moving towards a more performance-based, less prescriptive approach to 

building management.111 Along these lines, the USGBC launched its LEED Dynamic Plaque in 

late 2013, a performance benchmarking system that aggregates and displays near real-time 

information about the building’s energy and water use, waste production, and occupant 

experience.112 

 110 U.S. Green Building Council, About LEED v4, available at http://www.usgbc.org/articles/about-leedv4. 111 Heather Langford, USGBC and Ross Malme, Skipping Stone, Peak Load Management Alliance 

Demand Response Dialogue, DR Trailblazing in Commercial Buildings (May 1, 2014), available at

http://www.peakload.org/?page=DRDialogueGBC. 112 ECOBuilding Pulse, Green for Life, (Jan. 28, 2014), available at

http://www.ecobuildingpulse.com/leed/a-leed-dynamic-plaque-for-every-building-new-and-old_o.aspx. See also 

LEED, LEED Dynamic Plaque, available at http://www.leedon.io/.
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Federal Energy Regulatory Commission Page 29

Chapter 6: Regulatory barriers to improved customer participation in 

demand response, peak reduction, and critical period pricing 

programs

The 2009 National Assessment of Demand Response Potential113 and previous annual reports 

describe the barriers to customer participation in demand response. The federal government and 

state and local governments continue to address outstanding barriers to demand response. 

Recent actions are presented below.

• Lack of Uniform Standards for Communicating Demand Response Pricing, 

Signals and Usage Information. The acceptance and deployment of common 

information models and protocols such as OpenADR, Smart Energy Profile 2.0, and 

Green Button gained momentum in the past year. For example, following the release of 

the more advanced OpenADR 2.0b standard in June 2013, acceptance and deployment of 

OpenADR accelerated, with the certification of devices such as Ecobee smart 

thermostats.114 In addition, the OpenADR 2.0b profile was successfully tested to provide 

ancillary services and regulation signaling in PJM.115 More importantly, the International 

Electrotechnical Commission (IEC) approved the OpenADR 2.0b Profile Specification as 

a Publicly Available Specification (PAS) as a basis for a new IEC standard to be 

developed, validating the global importance of the OpenADR smart grid specification.116

As mentioned earlier, Federal agencies were directed to adopt Green Button in a 

Presidential Memorandum in December 2014.

• Lack of Support for Enabling Technologies. The deployment of enabling 

technologies also gained momentum with the entry of many new companies and 

technology platforms into the home automation and “smart homes” market.117 For 

example, Google announced developer programs in June 2014 that will allow other 

devices within a home to share data with Nest thermostats. Apps and devices that 

develop interfaces to Nest devices will be able “to access what Nest detects through its 

sensors, including vague readings on temperature and settings that show if a person is 

 113 FERC, A National Assessment of Demand Response Potential, (June 2009), available at

http://www.ferc.gov/legal/staff-reports/06-09-demand-response.pdf. 114 The Ecobee smart thermostat is an example of a wifi-enabled smart thermostat intended for the 

residential market. 115 Press Release, IPKeys, PJM, Walmart, Berkeley Lab and Schneider Electric Demonstrate Energy 

Management Advances with OpenADR 2.0b Market Pilots, (May 13, 2014) available at

http://www.bloomberg.com/bb/newsarchive/a6zIY35HGwZE.html. 116 Barbara Vergetis Lundin, OpenADR smart grid specification approved, FierceSmartGrid, (Feb. 25, 

2014) available at http://www.fiercesmartgrid.com/story/openadr-smart-grid-specification-approved/2014-02-

25#ixzz31tYOJCho. 117 Stacey Higginbotham, Gigaom, There are many paths to a smart home. And that’s the problem, (July 27, 

2014), available at http://gigaom.com/2014/07/27/there-are-many-paths-to-a-smart-home-and-thats-the-problem/.
December 2014 Assessment of Demand Response and Advanced Metering

Page 30 Federal Energy Regulatory Commission

away from their home for long periods.”118 Nevertheless, the proliferation of 

incompatible technologies may prove challenging in the near term. 

• Opportunities for Customer Education and Engagement. Utilities currently have 

a very narrow window within which to communicate with and engage their customers. A 

recent Accenture survey estimates that utility customers interact with their utilities for 

only nine minutes per year.119 Lack of engagement may partially explain why residential 

customers have been slow to adopt time-based rates, where they have the option to 

participate. Navigant Research estimates that, overall, less than one percent of U.S. 

households are on dynamic rates.120 In response, some utilities have started to offer 

demand response programs that incorporate sophisticated strategies for engaging 

customers. For example, BGE’s behavioral demand response offering (supported by 

Opower) combines a peak time rebate with communication strategies specifically aimed 

to engage customers, such as personalized energy savings tips, communication through 

multiple channels, immediate feedback on individual results, and comparisons with 

similar households. BGE plans to roll out the program to its entire customer base by 

2015.121

New York is emphasizing utility customer engagement as part of its REV initiative. In 

its April white paper, the NYDPS identifies several best practices for customer education 

and outreach, including mixing traditional outreach methods (e.g., bill inserts) with social 

media and community-based marketing approaches, and accommodating customer 

diversity in the design of demand side management programs (i.e., through customer 

segmentation). NYDPS also notes the need for market participants to identify and 

account for the cultural and behavioral factors that affect energy use, and to design 

incentives and technologies that increase customers’ knowledge and ability to manage 

their energy bills.122 Research addressing many of these areas is ongoing. For example, 

proceedings from the annual Behavior, Energy and Climate Change (BECC) conference 

are one source for recent research on the application of customer outreach and 

 118 Parmy Olsen, Google's Nest Moves To Become Master Of The Smart Home, By Talking To Other 

Devices, Forbes, June 24, 2014, available at http://www.forbes.com/sites/parmyolson/2014/06/24/google-nestsmart-home-internet-of-things/. 119 Accenture, The New Energy Consumer Handbook, (June 6, 2013), available at

http://nstore.accenture.com/acn_com/PDF/Accenture-New-Energy-Consumer-Handbook-2013.pdf 120 Navigant Research, Less Than 1 Percent of Residential Electricity Customers Will Adopt Dynamic 

Pricing Rates by 2020 Unless Utilities Act Aggressively, (October 9, 2013), available at

http://www.navigantresearch.com/newsroom/less-than-1-percent-of-residential-electricity-customers-will-adoptdynamic-pricing-rates-by-2020-unless-utilities-act-aggressively. 121Press Release, Opower, How Baltimore Gas and Electric is Solving the Dynamic Pricing Puzzle, (Jan.

13, 2014), available at http://blog.opower.com/2014/01/how-baltimore-gas-and-electric-is-solving-the-dynamicpricing-puzzle/. 122 NYDPS, Reforming the Energy Vision: NYS Department of Public Service Staff Report and Proposal, 

Case 14-M-0101, (Apr. 24, 2014), available at

http://www3.dps.ny.gov/W/PSCWeb.nsf/96f0fec0b45a3c6485257688006a701a/26be8a93967e604785257cc40066b

91a/$FILE/ATTK0J3L.pdf/Reforming The Energy Vision (REV) REPORT 4.25. 14.pdf.
Assessment of Demand Response and Advanced Metering December 2014

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segmentation methods to the design of demand response and energy efficiency 

programs.123

• Implementing Time-based Pricing. As noted above, less than one percent of U.S. 

households are on dynamic rates. The availability of technology, however, is no longer 

the major factor limiting the deployment of time-based rates – by 2015, 50 percent of 

U.S. households are projected to have a smart meter.124 Some regulators, consumer 

advocates and others may still have open concerns about the effects of dynamic pricing 

on certain customer classes. 

Results from the Department of Energy’s Smart Grid Investment Grant Consumer 

Behavior Studies may help to address these concerns. Preliminary data shows that, on 

average, more customers are enrolled in default time-based rate programs that require the 

customer to opt out (84%) than are enrolled in programs that require that the customer to 

opt-in (11%).125 SMUD, a participant in DOE’s grant program, found in its interim 

program evaluation that customers in the default (opt-out) treatment group remained 

enrolled at a high rate (93-99%), while a relatively large share of customers in the opt-in 

treatment group enrolled (16.4-18.8%).126 Based on the results of this study, SMUD 

plans to make time-varying rates the default for most customers by 2018.127 

With few exceptions, such as Massachusetts, other states are not proposing to adopt

default time-based pricing plans, despite reported growing demand for such plans.128 As 

noted above, in November 2014, the Massachusetts DPU issued a Policy Framework for 

Time Varying Rates as part of their larger grid modernization investigation. In their 

policy framework, the Department responded to the comments received on time-varying 

rates, and sets forth the Department’s policy framework for time varying rates in 

Massachusetts. Core to the policy framework is that default electricity supply provided

 123 Behavior, Energy & Climate Change Conference, BECC Presentations 2013, available at

http://beccconference.org/2013-pre-conference-workshops/. 124 IEE, Powering the People: Next Generation Utility – Opening Animation (video), (Mar. 6, 2014), 

available at http://www.edisonfoundation.net/iee/ourwork/Pages/Videos.aspx. 125 DOE, Analysis of Customer Enrollment Patterns in Time-Based Rate Programs – Initial Results from 

the SGIG Consumer Behavior Studies, July 2013, available at

https://www.smartgrid.gov/sites/default/files/doc/files/DOE_CBS_report_final_draft-7-10-13.pdf. 126 Sacramento Municipal Utility District and Freeman, Sullivan & Co., SmartPricing Options Interim 

Evaluation: An interim evaluation of the pilot design, implementation, and evaluation of the Sacramento Municipal 

Utility District’s Consumer Behavior Study, (Oct. 23, 2013), available at

https://www.smartgrid.gov/sites/default/files/MASTER_SMUD CBS Interim Evaluation_Final_SUBMITTED TO 

TAG 20131023.pdf. 127 Catherine Wolfram, Smart Meters But Dumb Pricing? Not in Sacramento, (Nov. 18, 2013), available at

http://energyathaas.wordpress.com/2013/11/18/smart-meters-but-dumb-pricing-not-in-sacramento/. On October 7, 

2013, California enrolled Chapter 611 allowing utilities in the state to offer default time-based pricing plans 

beginning in 2018. California State Legislature, AB 327, Adopted October 7,013, available at

http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201320140AB327. 128 Ahmad Faruqui, Address to the 3rd Guangdong, Hong Kong, Macau Power Industry Summit, The 

Global Tao of the Smart Grid, (Nov. 7, 2013), available at

http://www.brattle.com/system/publications/pdfs/000/004/954/original/The_Global_Tao_of_the_Smart_Grid.pdf?13

83853471. 
December 2014 Assessment of Demand Response and Advanced Metering

Page 32 Federal Energy Regulatory Commission

by the distribution companies should include time varying rates for all rate classes 

following the deployment of advanced metering functionality.129

 129Anticipated Policy Framework for Time Varying Rates, D.P.U. 14-04-B, (MA DPU June 12, 2014) 

available at http://www.mass.gov/eea/docs/dpu/orders/d-p-u-14-04-b-order-6-12-14.pdf.