2013 

 

 

Assessment of 

 

 

Demand Response and Advanced Metering 

 

 

 

 

Staff Report 

 

 

 

 

Federal Energy Regulatory Commission 

 October 2013 

 

 

 

 

 

 

 

 

 

 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

Jordan Kwok

Lisa Medearis

Ray Palmer

Pamela Sporborg

Michael Tita

 

 
Federal Energy Regulatory Commission Page i

TABLE OF CONTENTS

Introduction................................................................................................................................. 1

(A) Saturation and penetration rate of advanced meters............................................................. 2

Developments and issues in advanced metering..................................................................... 3

Federal and state programmatic support for advanced meters............................................ 3

Collaborative industry-government efforts......................................................................... 4

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

Privacy and other customer concerns ................................................................................. 6

Other state legislative and regulatory activity .................................................................... 7

(B) Existing demand response programs and time-based rate programs.................................. 10

(C) Annual resource contribution of demand resources........................................................... 10

Summer 2013 demand response deployments...................................................................... 12

California activities............................................................................................................... 13

ERCOT activities.................................................................................................................. 14

NERC’s Demand Response Availability Data System......................................................... 15

(D) Potential for demand response as a quantifiable, reliable resource for regional planning 

purposes.................................................................................................................................... 15

(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 17

FERC demand response orders and activities....................................................................... 17

Order No. 745 ................................................................................................................... 17

Order No. 1000 ................................................................................................................. 17

NAESB Demand Response and Energy Efficiency M&V Standards.............................. 18

Other federal demand response activities............................................................................. 18

National Forum on Demand Response ............................................................................. 18

DOE Smart Grid Investment Grants................................................................................. 19

DOE Smart Grid Demonstrations..................................................................................... 19

Wholesale Demand Response Communication Protocols................................................ 20

DOD & GSA federal efforts............................................................................................. 21

Other state legislative and regulatory activities related to demand response ....................... 22

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

Leadership in Energy and Environmental Design (LEED) .............................................. 28

(F) 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

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

Table 2: Demand Response Resource Potential at U.S. ISOs and RTOs..................................... 11
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)

October 2013

Introduction

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

annual report on demand response and advanced metering. It fulfills a requirement of the Energy 

Policy Act of 2005 (EPAct 2005) section 1252(e)(3)1 that the Federal Energy Regulatory 

Commission (FERC or Commission) prepare and publish an annual report, by appropriate 

region, that assesses electricity demand response resources, including those available from all 

consumer classes.2

 

Since 2006, Commission staff has published a series of annual reports assessing demand 

response and advanced metering in the U.S. In support of these reports, the FERC staff has 

conducted comprehensive nationwide surveys every other year. For reports in intervening years, 

including this report, the information is based on publicly-available information and discussions 

with market participants and industry experts. 

Based on the information reviewed, it appears that:

• Data from several sources show that the penetration of advanced meters is up, from 

approximately nine percent in 2009 to nearly 25 percent in late 2011/early 2012;

3

• Since 2009, demand response potential in organized markets operated by the Regional 

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

Reliability Council of Texas (ERCOT) increased by more than 4.1 percent; and, 

• Demand response resources made significant contributions to balancing supply and 

demand during system emergencies for several RTOs and ISOs in the summer of 2013.

 1 Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(e)(3), 119 Stat. 594 (2005) (EPAct 2005 section 

1252(e)(3)). 2 The Commission submitted the first report, the Assessment of Demand Response and Advanced Metering: 

Staff Report, Docket No. AD06-2, August 7, 2006 (referred to here as the 2006 FERC Demand Response Report), 

http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. The 2007 through 2012 annual reports are 

also available at http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. 3 FERC uses the term advanced meter as synonymous with advanced AMI meters (i.e., smart meters). As 

defined by the EIA, advanced AMI meters have built-in two-way communication capable of recording and 

transmitting instantaneous data (measured and recorded usage data at minimum, in hourly intervals, provided to both 

consumers and energy companies at least once daily). See EIA, EIA Form-826 and EIA Form-861 Frequently 

Asked Questions (FAQs), http://www.eia.gov/survey/faqs/electricity.html.
October 2013 Assessment of Demand Response and Advanced Metering

Page 2 Federal Energy Regulatory Commission

The report is organized according to 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;

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

(C) the annual resource contribution of demand resources;

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

planning purposes;

(E) steps taken to ensure that, in regional transmission planning and operations, demand 

resources are provided equitable treatment as a quantifiable, reliable resource relative 

to the resource obligations of any load-serving entity, transmission provider, or 

transmitting party; and

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

reduction and critical period pricing programs.

Each of the above requirements is addressed below in a separate section. Within that section, 

information concerning relevant state, federal and industry activities is also provided.

(A) Saturation and penetration rate of advanced meters

Recent data from various sources provide consistent estimates of advanced meter penetration 

rates. The Energy Information Administration (EIA) reports that in 2011, approximately 37.3 

million advanced meters were in use out of 151.7 million meters nationwide, indicating a 24.6 

percent penetration rate.4 The most recent FERC Survey of advanced meters, conducted in 2012

and reported in the 2012 Demand Response and Advanced Metering Report, showed a 

penetration rate of 22.9 percent.5 Other sources report similar numbers. For example, data 

collected by the Institute for Electric Efficiency (IEE) in May 2012 indicate that advanced meters 

represent approximately 23.5 percent of all meters.6 More recently, IEE, which has changed its 

name to Innovation Electricity Efficiency, released an August 2013 report indicating that as of 

July 2013 almost 46 million smart meters have been installed in the U.S.7

 IEE’s recent data

implies an advanced meter penetration rate of approximately 30 percent. 

Table 1 summarizes the available information on advanced meter installations.

 4 Energy Information Administration, Form EIA-861, 2011 Data File 2 and File 8, 

http://www.eia.gov/cneaf/electricity/page/eia861.html. 5 FERC, 2012 Assessment of Demand Response and Advanced Metering: Staff Report, December 2012, 

http://www.ferc.gov/legal/staff-reports/12-20-12-demand-response.pdf. 6 Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals, May 2012, 

http://www.edisonfoundation.net/iee/Documents/IEE_SmartMeterRollouts_0512.pdf. Penetration rate based on 

35.7 million installed advanced meters (IEE) and 151.7 million U.S. electric consumers (Energy Information 

Administration, Form EIA-861 Data, Data File 2, 2011). IEE predicts that if present trends continue, about 65 

million advanced meters will be installed nationwide by 2015. 7 IEE, Utility-Scale Smart Meter Deployments: A Foundation for Expanded Grid Benefits, August 2013, 

http://www.edisonfoundation.net/iee/Documents/IEE_SmartMeterUpdate_0813.pdf. 
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 3

Table 1: Estimates of Advanced Meter Penetration Rates

Source of No. of Advanced 

Meters

Reference Date

(Month/Year)

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%

EIA-861 Annual Survey Dec 2011 37.3 4 151.7 4 24.6%

Institute for Electric Efficiency May 2012 35.7 5 151.7 4 23.5%

Innovation Electricity Efficiency July 2013 45.8 6 151.7 4 30.2%

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 Energy Information Administration, Form EIA-861 Data File 2 and Data File 8 for 2011 

(http://www.eia.gov/cneaf/electricity/page/eia861.html).

5 Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals (May 2012). 6 Innovation Electricity Efficiency, 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 IEE data.

Developments and issues in advanced metering

As indicated above, there has been an increase in the penetration of advanced meters between 

2007 and 2013. Federal, state and local governmental entities as well as industry stakeholders 

continue to develop policies and infrastructure to facilitate deployment of advanced metering and 

address issues concerning its use. What follows are examples of continued programmatic 

support for advanced meters, demonstrated benefits of advanced meters, and continued public 

concerns with deployment of advanced meters.

Federal and state programmatic support for advanced meters

Support for the deployment of advanced meters continues at the federal and state levels. The 

American Recovery and Reinvestment Act of 2009 (Recovery Act)8 appropriated $4.5 billion to 

the U.S. Department of Energy (DOE) for grid modernization programs, with $3.4 billion of that 

amount devoted to the Smart Grid Investment Grant (SGIG) program, a public-private 

partnership initiative for leveraging investments in grid modernization. As of June 30, 2013, 

approximately 12.8 million advanced meters were installed and operational using Recovery Act 

funding of the SGIG program.9 Ultimately, 15.5 million advanced meters are expected to be 

installed and operational under SGIG. All SGIG projects are expected to reach completion 

between 2013 and 2014.

 8 American Recovery and Reinvestment Act of 2009, Pub. L. No. 111-5 (2009). 9 U.S. Department of Energy, SmartGrid.gov, “Advanced Metering Infrastructure and Customer Systems, 

Smart Meters Deployed and Operational,” http://www.smartgrid.gov/recovery_act/deployment_status. Note 

responses were provided by 78 entities. SGIG recipients have reported approximately 15.4 million advanced meters 

physically installed as of June 30, 2013.
October 2013 Assessment of Demand Response and Advanced Metering

Page 4 Federal Energy Regulatory Commission

Collaborative industry-government efforts

Industry has worked with the National Institute of Standards and Technology (NIST), DOE, state 

public utility commissions, and organizations such as the North American Energy Standards 

Board (NAESB) to standardize the types and format of data made available from advanced 

meters and to use that information to develop new customer services and products. For example, 

Green Button initiated by NIST, DOE and the White House’s Office of Science and Technology 

Policy (OSTP),

10 is now an industry-led effort to provide electricity customers with secure 

energy-usage data in a standardized, easy-to-understand format that is accessible from personal 

computers and mobile devices. A consumer who has a smart meter need only click on a “Green 

Button” icon at a participating utility’s website to download his/her own hourly electricity usage 

information, typically for up to 13 months.11 As of May 2013, 27 utilities with operations in 17 

states and the District of Columbia have voluntarily committed to participate in the program, and 

an additional seven utilities have activated programs that allow their customers to securely 

download their usage data using Green Button.12 In addition, demand response providers (i.e., 

curtailment service providers, aggregators or retail customers) can use Green Button data as a 

verification tool for their demand response programs.13

In late 2012, after considerable additional work by utilities and others within the Smart Grid 

Interoperability Panel (SGIP) framework,

14 SDG&E launched Green Button Connect My Data, 

which allows customers to automatically send their energy usage data to third-party providers, 

giving customers additional options to view their previous day’s usage data using a smartphone 

application.15 In addition, some federal agencies are working to incorporate Green Button data 

into their programs. For example, the Environmental Protection Agency’s (EPA) Home Energy 

Yardstick tool is now compatible with Green Button data.16 To help promote the widespread 

standardization and adoption of Green Button software, NIST established a new Priority Action 

Plan (PAP) to standardize the testing and certification protocols for utility and vendor Green 

Button implementations.

17

The wealth of information produced by advanced meters has spurred the increased development 

of customer services and products, such as home energy reports, home energy management 

software, and mobile software applications (e.g., notifications, outage/restoration mapping, usage 

 10 See Green Button, “About Green Button,” http://www.greenbuttondata.org/greenabout.html. 11 Ibid. Data are available from the date of smart meter installation up to 13 months, or even longer in 

some cases. 12 States currently participating include Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, 

Maryland, Massachusetts, Michigan, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, 

and West Virginia, as well as the District of Columbia. Green Button, “Adopters,” 

http://www.greenbuttondata.org/greenadopt.html. 13 NIST webinar, April 2013, http://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/PAP20MeetingMinutesAndSlides. 14 NIST established the Smart Grid Interoperability Panel as a public-private partnership to help manage the 

development of smart grid interoperability standards in 2010. 15 SDG&E, “Green Button Connect My Data,” http://www.sdge.com/using-green-button-connect-my-data. 16 Energy Star, “Home Energy Yardstick,” 

https://www.energystar.gov/index.cfm?fuseaction=HOME_ENERGY_YARDSTICK.showGetStarted. 17 NIST, PAP20 Green Button ESPI Evolution, http://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/GreenButtonESPIEvolution.
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 5

profiles, billing, and service requests). Certain utilities18 have partnered with third-party 

software providers to develop interface applications that simplify and deliver energy 

consumption data directly to retail customers. For example, monthly energy consumption data 

reports can alert customers to potential cost-savings from energy efficiency measures, behavioral 

changes or alternative rate programs.

Demonstrated benefits of advanced meters

Recent storm activity and extreme weather events have provided utilities that have deployed

advanced meters with an opportunity to assess the meters’ ability to contribute to power system 

resiliency and help facilitate efficient restoration of electric service following outages caused by

storm damage. Electric system outages can be the result of small, medium, and very large scale 

events spanning several states that often impact other infrastructure systems (e.g., 

communication, financial, and health care).19 State regulators and utilities continue to review 

system hardening and resiliency measures designed to combat and mitigate future storm damage 

and outages, and the application of new information and communication technologies, including

advanced meters, are now a featured component of storm response discussions.20 Some of the 

early reports on how advanced meters integrated with other technologies have helped keep the 

lights on and enabled faster service restorations during recent weather events include the 

following:

June 2012 “Derecho” and Other Storm Events: During the June 2012 “Derecho” wind storm, 

advanced meters installed in Atlantic City Electric’s New Jersey service territory helped the 

utility predict the location and extent of the outages, and deploy repair crews to areas where they 

were most effective.21 Also in June 2012, Electric Power Board Chattanooga (EPB 

Chattanooga) employed automated switches working in tandem with advanced meters to reduce 

the total number of customer power outages by at least half, and avoided 58 million minutes of 

power disruptions for their customers.22 EPB Chattanooga was also able to restore power one 

and a half days sooner than would have been possible prior to the switch and meter upgrades,

and the municipality realized $1.4 million in operational savings. Similarly, during a separate 

storm event in April 2013, Commonwealth Edison reported that the use of automated switches 

and advanced meters prevented 20,000 service interruptions.

23

 18 Examples include Florida Power & Light, Southern California Edison, and San Diego Gas & Electric.

19 The GridWise Alliance, Improving Electric Grid Reliability and Resilience: Lessons Learned from 

Superstorm Sandy and other Extreme Events, Workshop Summary and Key Recommendations, June 2013, 

http://www.gridwise.org/documents/ImprovingElectricGridReliabilityandResilience_6_6_13webFINAL.pdf. 20 Edison Electric Institute, Before and After the Storm, January 2013, pp. 1, 7, 12, 

http://www.eei.org/issuesandpolicy/electricreliability/mutualassistance/Documents/Before%20and%20After%20the

%20Storm.pdf. 21 Tom Johnson, “Smart Grid, Meters, No Magic Bullet for Damage Done by Major Storms,” NJ 

Spotlight, http://www.njspotlight.com/stories/12/12/03/smart-grid-meters-no-magic-bullet-for-damage-done-bymajor-storms/. 22 Katherine Tweed, “Smart Grid Saves EPB Chattanooga $1.4M in One Storm,” Greentechgrid, October 

17, 2012, http://www.greentechmedia.com/articles/read/distribution-automation-saving-epb-millions. 23 ComEd, “ComEd’s ‘Smart Switches’ Reducing Service Interruptions,” April 30, 2013 [Press release], 

https://www.comed.com/newsroom/news-releases/Pages/newsroomreleases_04302013.pdf.
October 2013 Assessment of Demand Response and Advanced Metering

Page 6 Federal Energy Regulatory Commission

Hurricane Sandy: In October 2012, after the landing of Hurricane Sandy, Baltimore Gas and 

Electric (BGE) and Pepco noted that advanced meters assisted with efficient storm restoration, as 

well as customer outreach efforts, in Maryland and the District of Columbia. BGE was able to 

dispatch crews more efficiently by quickly identifying areas where power was already restored. 

Both BGE and Pepco noted that potential communication barriers were avoided by using 

advanced meter signals, instead of calling residential customers to confirm restoration of electric 

service.24,

25

In November 2012, San Diego Gas & Electric (SDG&E) announced plans to integrate advanced 

meters with an advanced Outage Management System to track multiple outages during large 

storms and to better organize planned outages.26 This will allow SDG&E to reach an outage site 

prior to customer calls and better manage and monitor power flow and undertake planned 

outages.27

Privacy and other customer concerns

New and emerging technologies can modernize the electric grid, while also providing customers 

with new tools that engage and meet customer needs. However, concerns about the security and 

privacy of customer data remain. To this end, policy makers and industry continue to work 

through NIST and other forums to develop privacy policies and procedures.28

Interval usage data from advanced meters in conjunction with other enabling technologies can 

expand opportunities for demand response and energy efficiency programs. Facilitated by the 

DOE and the EPA, the State & Local Energy Efficiency Action Network (SEE Action) issued an 

analysis of state approaches to data access, security and privacy when utilities provide customer 

data to a third party for energy efficiency programs. California, Colorado, Oklahoma, Oregon, 

Texas, Vermont, Washington, and Wisconsin have adopted rules governing third-party access to 

customer data, and seven state commissions have open dockets as of December 2012.29 The 

National Association of Regulatory Utility Commissioners (NARUC) released an updated primer

concerning, in part, the security of data. The primer addresses cybersecurity for the electric grid 

 24 Jeannette M. Mills, “Working to put this storm behind us offers glimpse ahead to smarter grid,” 

November 2012, http://www.bge.com/Blog/archive/tags/Smart%20Grid/default.aspx. 25 Martin LaMonica, “Smart Meters Help Utility Speed Sandy Restoration,” MIT Technology Review, 

October 31, 2012, http://www.technologyreview.com/view/506711/smart-meters-help-utility-speed-sandyrestoration/. 26 SDG&E, “SDG&E Launches Advanced Outage Management System To Benefit Region,” November 12, 

2012 [Press release], http://www.sdge.com/newsroom/press-releases/2012-11-14/sdge-launches-advanced-outagemanagement-system-benefit-region. 27 Katherine Tweed, “SDG&E Pushes the Envelope on Cutting Outages,” Greentechgrid, November 21, 

2012, http://www.greentechmedia.com/articles/read/sdge-pushes-the-envelope-on-cutting-outages. 28 For example, the SGIP includes a cybersecurity working group with a subgroup to address privacy 

issues. The SGIP work on privacy can be found at http://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/CyberSecurityCTG. 29 State and Local Energy Efficiency Action Network, A Regulator’s Privacy Guide to Third-Party Data 

Access for Energy Efficiency, December 18, 2012, 

http://www1.eere.energy.gov/seeaction/pdfs/cib_regulator_privacy_guide.pdf.
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 7

and provides conceptual cybersecurity basics, the jurisdictional landscape, and best-practices for 

policymakers’ consideration.30

To address customer issues with deployment of advanced meters, states continue to develop 

“opt-out policies”, which may include a fee for customers who object to the installation of an 

advanced meter to actually “opt-out” of having the meter installed. Many utilities have argued 

that opt-out fees are justified due to costs associated with having a mix of traditional and 

advanced meters on a utility’s system. For example, the Nevada Public Utility Commission 

ruled in January 2013 that NV Energy may charge opt-out fees for a trial period.31 The 

Michigan Public Service Commission also allowed opt-out fees in a May 2013 order approving a 

Detroit Edison advanced metering residential opt-out program.32 In contrast to the above, New 

Hampshire enacted legislation in June 2012 prohibiting electric utilities from installing and 

maintaining advanced meter gateway devices without the property owner's consent, thereby 

establishing an opt-in approach for the state.

33

An Illinois nonprofit consumer advocacy group sued the City of Naperville to prevent advanced 

meters from being installed due to concerns over privacy, property rights and the health effects 

of radio frequency waves associated with the meters’ wireless technology. However, the U.S. 

District Court dismissed the complaint, finding that the factual evidence presented on the health 

effects of radio frequencies was not sufficient to justify cancelling the City of Naperville’s 

advanced metering rollout. The court also found that the City of Naperville’s privacy

protections—including anonymous customer ID numbers, data aggregation, and a customer bill 

of rights34—were not proven insufficient to protect customers’ right to privacy.35

Other state legislative and regulatory activity

• California. In October 2012, the California Public Utilities Commission (CPUC) 

directed the state’s investor-owned utilities to ensure interoperability between in-home 

energy monitoring devices and their advanced meters. In conjunction, the CPUC directed 

 30 NARUC, Cybersecurity for State Regulators 2.0, 

http://www.naruc.org/grants/Documents/NARUC%20Cybersecurity%20Primer%202.0.pdf. 31 Public Utilities Commission of Nevada, Joint Application of the Sierra Pacific Power Company d/b/a NV 

Energy and Nevada Power Company d/b/a NV Energy for authority to establish and implement three separate trial 

non-standard metering option riders pursuant to the Order issued in Docket No. 11-10007, Docket No. 12-05003, 

Order on Reconsideration, January 9, 2013, 

http://pucweb1.state.nv.us/PDF/AxImages/DOCKETS_2010_THRU_PRESENT/2012-5/22672.pdf. 32 Michigan Public Service Commission, In the matter of the application and request of The Detroit Edison 

Company seeking approval and authority to implement its proposed Advanced Metering Infrastructure Opt Out 

Program, Case No. 17053, May 15, 2013, http://efile.mpsc.state.mi.us/efile/viewcase.php?casenum=17053. 33 New Hampshire General Court, Bill Status System, Senate Bill No. 266, AN ACT prohibiting electric 

utilities from installing and maintaining smart meter gateway devices without the residential or business property 

owner’s consent, Enacted June 7, 2012, 

http://www.gencourt.state.nh.us/bill_status/Bill_docket.aspx?lsr=2999&sy=2012&sortoption=&txtsessionyear=201

2&txtbillnumber=SB266. 34 Naperville Smart Grid Initiative, Naperville Smart Grid Customer Bill of Rights, undated, 

http://www.naperville.il.us/emplibrary/Smart_Grid/NSGI-CBoR-web.pdf. 35 Naperville Smart Meter Awareness v. City of Naperville, Memorandum Opinion and Order, Case No. 

1:11-cv-09299, (Illinois Northern District Court, March 22, 2013). Accessed: The Daily Herald, 

https://www.dailyherald.com/assets/pdf/DA124298323.pdf. 
October 2013 Assessment of Demand Response and Advanced Metering

Page 8 Federal Energy Regulatory Commission

the state’s largest utilities to facilitate a competitive, third-party retail market where 

customers can select from a variety of in-home energy management devices capable of 

communicating utility-sponsored energy conservation measures and enabling consumers 

to respond to demand response events.36 

• Connecticut. In February 2013, the Connecticut Department of Energy and 

Environmental Protection (DEEP) issued the first Comprehensive Energy Strategy for the 

state as required by Public Act 11-80. Advanced metering technology, facilitated by 

dynamic pricing policies, is a central component of the report’s multi-pronged strategy 

for achieving sustainable, day-to-day reductions of peak electricity demand.37 

• Illinois. In June 2013, the Illinois Commerce Commission (ICC) approved updated 

cost-recovery rates for ComEd and Ameren Illinois in conjunction with the advanced 

meter deployment required by the Energy Infrastructure and Modernization Act 

(EIMA).38,39 The ICC action is in response to the May 2013 enactment of Illinois Senate 

Bill 9,40 which amended the EIMA41 to include cost-recovery rates for the law’s 

mandated advanced meter rollout.42

• Kentucky. In October 2012, the Kentucky Public Service Commission (KPSC) initiated 

an administrative proceeding to consider the implementation of advanced metering 

infrastructure (AMI) technologies and time-of-use electricity prices.43 The proceedings 

investigate implementation costs, interoperability standards, and societal impacts related 

to recommendations made in the state’s Smart Grid Roadmap Initiative issued in June 

 36 California Public Utilities Commission (CPUC), Resolution E-4527, Pacific Gas and Electric (PG&E), 

Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E), September 27 

2012, http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M028/K949/28949960.PDF Note the CPUC 

resolution directs investor-owned utilities to satisfy the intent and requirements of Ordering Paragraph 11 of the 

CPUC’s Customer Data Access & Privacy Decision, 11-07-056, Issued July 28 

2011, http://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/140369.pdf. 37 Connecticut Department of Energy and Environmental Protection, 2013 Connecticut Comprehensive 

Energy Strategy, February 19, 2013, http://www.ct.gov/deep/lib/deep/energy/cep/2013_ces_final.pdf. 38 Illinois Commerce Commission, “ICC Approves New ComEd AMI Schedule for Smart Meters,” 

December 6, 2012 [Press release], 

http://www.icc.illinois.gov/downloads/public/ComEdAMIorderonrehearingrevise.doc. 39 Illinois Commerce Commission, “ICC Approves Ameren Illinois Advanced Meter Plan, Schedule,” 

December 7, 2012 [Press release], http://www.icc.illinois.gov/downloads/public/AmerenAMIrehearingedit.doc. 40 SB 9 was enacted with legislative override of the governor’s veto. State of Illinois, 98th General 

Assembly, Senate Bill 9, 

http://www.ilga.gov/legislation/BillStatus.asp?DocNum=0009&GAID=12&DocTypeID=SB&LegID=68374&Sessi

onID=85&GA=98&SpecSess=0. 41 State of Illinois, Energy Infrastructure Modernization Act, Public Act 097-0616, Senate Bill 1652, 97th

General Assembly (2011), http://www.ilga.gov/legislation/publicacts/fulltext.asp?Name=097-0616. 42 Rafael Guerrero, “Lawmakers override Quinn on ComEd veto,” Chicago Tribune, May 23 2013, 

http://www.chicagotribune.com/news/local/ct-met-illinois-legislature-com-ed-rate-hike-0523-

20130523,0,5365404.story. 43 Kentucky Public Service Commission, Consideration of the Implementation of Smart Grid and Smart 

Meter Technologies, Case No. 2012-00428, October 2012, http://psc.ky.gov/PSCSCF/2012%20cases/2012-

00428/20121001_PSC_ORDER.pdf.
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 9

2012.44 The KPSC, in collaboration with a consortium of state utilities, is examining 

various smart grid technologies and pricing structures that encourage greater energy

efficiency.45 In May 2013, the ongoing Joint Parties Collaborative proposed to issue a 

report on utility industry recommendations by June 2014.46

• Maine. By the end of 2012, the Central Maine Power Company, Bangor Hydroelectric, 

and the Maine Public Service Company had almost completed installation of advanced 

metering devices, as well as associated communication and data management systems.47 

Concomitant with near full advanced meter deployment, the Maine Public Utilities 

Commission approved plans for the Central Maine Power Company to initiate a time-ofuse pricing program for residential and small commercial customers.48

• Pennsylvania. In December 2012, the Pennsylvania Public Utility Commission

(PAPUC) issued a final order requiring electric utilities to establish a standard electronic 

format for providing consenting customers and third-parties with direct access to 

customer data. The PAPUC established the Electric Data Exchange Working Group, 

comprised of utilities and stakeholders, to oversee development of standards for acquiring 

interval usage data via a secure web portal. The Working Group is expected to reach 

consensus on standards for “bill quality” interval data by March 2015.49 In December 

2012, the Metropolitan Edison Company, Pennsylvania Electric Company, Pennsylvania 

Power Company, and West Penn Power Company submitted their advanced meter

deployment plans for approval to the PAPUC,50 as required by Act 129.51 Beginning in 

 44 Kentucky Public Service Commission, Smart Grids in the Commonwealth of Kentucky: Final Report of 

the Kentucky Smart Grid Roadmap Initiative, June 2012, 

http://energy.ky.gov/generation/Documents/Smart%20Grids%20in%20the%20Commonwealth%20of%20Kentucky.

pdf. 45 Kentucky Public Service Commission, “PSC Opens Case to Look at Smart Grid and Smart Meters,” 

October 2012 [Press release], http://psc.ky.gov/agencies/psc/press/102012/1001_r02.PDF. 46 Kentucky Public Service Commission, Joint Comments on the Consideration of the Implementation of 

Smart Grid and Smart Meter Technologies, KPUC Case No. 2012-00428, May 2013, 

http://psc.ky.gov/PSCSCF/2012%20cases/2012-00428/20130520_Joint%20Comments.pdf. 47 Maine Public Utilities Commission, 2012 Annual Report, February 2013, 

http://www.maine.gov/tools/whatsnew/attach.php?id=495712&an=1. 48 Maine Public Utilities Commission, “MPUC: New Time-Of-Use Prices for CMP Residential and Small 

Commercial Customers,” December 5, 2012, http://www.maine.gov/tools/whatsnew/index.php?topic=pucpressreleases&id=463166&v=article08. 49 Pennsylvania Public Utilities Commission, Smart Meter Procurement and Installation Order, Docket 

No. M-2009-2092655, December 2012, 

http://www.puc.pa.gov/filing_resources/issues_laws_regulations/act_129_information/smart_meter_technology_pro

curement_and_installation.aspx. 50 Pennsylvania Public Utilities Commission, Joint Petition of Metropolitan Edison Company, 

Pennsylvania Electric Company, Pennsylvania Power Company, and West Penn Power Company, PPUC Docket 

No. M-2009-2123950, December 2012, 

https://www.firstenergycorp.com/content/dam/customer/Customer%20Choice/Files/PA/tariffs/FE%20SMIP%20De

ployment%20Plan%20Petition%20-%20Complete.pdf. 51 Act 129 requires electric utilities to provide access to electronic meter data between customers, 

designated third parties, and providers of conservation and load management services. Pennsylvania General 

Assembly, Act 129, 66 Pa. C.S. § 2807(f)(3) (2008), 

http://www.legis.state.pa.us/WU01/LI/LI/CT/HTM/66/00.028.006.001..HTM. 
October 2013 Assessment of Demand Response and Advanced Metering

Page 10 Federal Energy Regulatory Commission

January 2013, the companies expect to install approximately 98.5 percent of all advanced 

metering devices by 2019.52 In January 2013, PECO Energy Company submitted its

Phase II Smart Meter Implementation Plan to the PAPUC. PECO expects to have 

600,000 advanced metering devices installed by June 2013, with 1.2 million devices 

installed before 2015 and full deployment achieved by 2019.53

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

Commission staff surveyed existing demand response and time-based rate programs in 2012 (see

2012 FERC Demand Response and Advanced Metering Report) and intends to conduct another 

survey during 2014. In addition, the U.S. Energy Information Administration (EIA) collects 

specific data for demand-side management programs designed to modify patterns of electricity 

usage, including the timing and level of electric demand.54 EIA expects to release 2012 data in 

October 2013.55

In March 2013, NERC released initial Demand Response Availability Data System (DADS) data 

results through the 2011-2012 winter (October 2, 2011 to March 31, 2012) periods.56 NERC 

states that 80 entities reported demand response program data for the 2011 summer reporting 

period and 74 entities reported for the 2011-2012 winter reporting period. Aggregate data is 

presented for reporting entities operating in both the U.S. and Canada, and NERC states the total 

number of reporting entities may grow to over 200 with the completion of subsequent phases of 

DADS that are designed to include reliability programs and data on economic demand response 

and time-based pricing programs.57

(C) Annual resource contribution of demand resources 

The FERC survey of demand resources is undertaken on a biennial basis, as noted above. As a 

result, Table 2 compares the survey data for calendar year 2011 as reported in the 2012 Demand 

Response and Advanced Metering Report to separate values for 2012 from Regional 

Transmission Organization (RTO) and Independent System Operator (ISO) information

sources.

58 Based on publicly available sources of information, the potential resource

 52 See supra note 50. 53 Pennsylvania Public Utilities Commission, PECO Smart Meter Universal Deployment Plan, PPUC 

Docket No. M-2009-2123950, January 2013, 

https://www.peco.com/CustomerService/RatesandPricing/RateInformation/Documents/PDF/New%20Filings/Petitio

n%20-%20PECO%20Phase%20II%20Smart%20Meter%20Plan%20-%20Petition.pdf. 54 EIA, Form EIA-861 Annual Electric Power Industry Report Instructions, 

http://www.eia.gov/survey/form/eia_861/instructions.pdf. 55 EIA, Form EIA-861 data files, http://www.eia.gov/electricity/data/eia861/. 56 See infra pp. 4, 17-18. DADS is a system developed by NERC to collect and analyze semi-annual 

demand response data from several categories of industry participants. Note that NERC states “issues may be 

identified that require review and modification of the reported data.” NERC data is discussed below. 57 NERC, 2011 Demand Response Availability Report, March 2013, p. 12, 

http://www.nerc.com/docs/pc/dadswg/2011%20DADS%20Report.pdf. 58 Because the data are taken from different sources, caution must be exercised when making direct 

comparisons between 2011 and 2012 data. 
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 11

contribution by demand response in U.S. RTO/ISO markets increased by 6.3 percent from 2010 

to 2011 to 32,488 MW, but fell in 2012 to 28,303 MW, a year-on-year decrease of 12.9 percent. 

As a percentage of peak load, demand response potential decreased by 0.7 percentage points 

from 2011 to 2012. Overall, the demand response resources’ potential contribution in U.S. 

RTO/ISO markets has increased by 4.1 percent since 2009.59

Table 2: Demand Response Resource Potential at U.S. ISOs and RTOs

RTO/ISO

2011 2012

Demand 

Response

(MW)

Percent 

of Peak 

Demand9

Demand 

Response

(MW)

Percent 

of Peak 

Demand9

California ISO (CAISO) 2,270 1 5.0% 2,430 1 5.2%

Electric Reliability Council of Texas (ERCOT) 1,570 2 2.3% 1,750 3 2.6%

ISO New England, Inc. (ISO-NE) 1,231 2 4.4% 2,769 4 10.7%

Midcontinent Independent System Operator (MISO) 9,529 2 9.2% 7,197 5 7.3%

New York Independent System Operator (NYISO) 2,247 2 6.6% 1,888 6 5.8%

PJM Interconnection, LLC (PJM) 14,127 2 8.9% 10,825 7 7.0%

Southwest Power Pool, Inc. (SPP) 1,514 2 3.2% 1,444 8 3.1%

Total RTO/ISO 32,488 6.7% 28,303 6.0%

Sources:

1 California ISO 2012 Annual Report on Market Issues and Performance

2 2012 Assessment of Demand Response and Advanced Metering, FERC Staff Report

3 ERCOT Quick Facts (May 2013)

4 2012 Assessment of the ISO New England Electric Markets, Potomac Economics

5 2012 State of the Market Report for the MISO Electric Markets, Potomac Economics

6 2012 State of the Market Report for the New York ISO Markets, Potomac Economics 7 PJM Load Response Activity Report, July 2012, "Delivery Year 2012-2013 Active Participants in PJM Load 

Response Program"

8 SPP Fast Facts (March 1, 2013)

9 Estimates based on peak demand data from the following: California ISO 2012 Annual Report on Market Issues 

and Performance; ERCOT 2011 & 2012 State of the Market Reports; 2011 Assessment of the ISO New England 

Electricity Markets; ISO-NE Net Energy and Peak Load Report (April 2013); 2011 & 2012 State of the Market 

Reports for the MISO Electricity Markets; 2011 & 2012 State of the Market Reports for the New York ISO 

Markets; 2011 & 2012 PJM State of the Markets Reports, Vol. 2; SPP 2011 & 2012 State of the Market Reports.

Recognizing that separate data sets are utilized for 2011 and 2012 in Table 2, general results

indicate that CAISO, ERCOT, ISO-NE realized increases in demand response, while other RTO 

markets realized declines. Significant decreases in demand response potential60 were realized in 

the PJM markets. According to the market monitor’s report for the 2012/2013 delivery year, a 

marked decrease in clearing prices in PJM’s forward capacity auction caused the number of 

credits for demand response to fall sharply in 2012.61 The market monitor also concluded that 

the decrease in demand response potential was influenced by the discontinuation of the 

Interruptible Load for Reliability program after the 2011/2012 planning year. The decrease in 

 59 The megawatts reported here represent the megawatts of demand response “registered” for participation 

and potential deployment in the relevant markets and programs, e.g., capacity markets, economic- and reliabilitybased programs. 60 In general, demand response resource potential is the potential peak reduction attributable to demand 

response resources participating in a demand response program. Additional information can be obtained from the 

FERC-731 General Instructions and Information, http://www.ferc.gov/industries/electric/indus-act/demandresponse/2012/instructions.pdf. 61 Monitoring Analytics, LLC, State of the Market Report for PJM: Volume 2: Detailed Analysis, March 

14, 2013, http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2012.shtml.
October 2013 Assessment of Demand Response and Advanced Metering

Page 12 Federal Energy Regulatory Commission

registrations in PJM’s load management programs was partially offset by an increase in 

registrations under its economic programs.

Summer 2013 demand response deployments

Demand response resources made significant contributions to balancing supply and demand for 

several RTOs and ISOs in the summer of 2013. A heat wave in the Eastern United States during 

the third week of July and in mid-September drove demand for electricity to record levels in 

some areas.

On July 19, NYISO set a new record for peak demand of 33,955 MW.62 NYISO activated 

demand response resources statewide on July 18 and 19, as well as deploying these resources 

every day throughout the week to relieve historically congested areas of the lower Hudson 

Valley and southeastern New York.63 NYISO states it successfully met this record demand 

through strong performances by demand response, generation and transmission resources, 

coordination between NYISO and its neighboring regions, and high availability of wind 

resources.64

The high temperatures also resulted in deployment of demand response in PJM. On three days 

beginning July 15, PJM called long lead time emergency demand response resources for several

of its zones. PJM dispatched 652 MW of demand response resources for two consecutive days

on July 15 and 16, and dispatched 1,638 MW of demand response resources on July 18. 

Economic demand response also contributed to the PJM system during the week. The estimated 

hourly economic demand response reached levels of approximately 250 MW, 400 MW, 870 

MW, 630 MW and 625 MW on each day, respectively, from July 15 through July 19.65 The 

combination of emergency and economic demand response resources, in addition to other 

measures, helped PJM address the transmission constraints, high loads, and unplanned 

generation outages experienced during the week of July 15, 2013.66

On September 11, 2013 PJM called on and received approximately 5,949 MW of demand 

response resources, which represented the largest amount of demand response PJM has ever 

received. This demand response helped address the imbalance between supply and demand 

 62 NYISO, “NYISO Meets Record Demand with Balanced Array of Resources,” July 22, 2013 [Press 

release], 

http://www.nyiso.com/public/webdocs/media_room/press_releases/2013/NYISO%20Meets%20Record%20Demand

%20with%20Balanced%20Array%20of%20Resources%20-%2007_22_13%20-%20FINAL.pdf. 63 NYISO, “Heat Wave Drives Record Electricity Usage in New York,” July 19, 2013 [Press release], 

http://www.nyiso.com/public/webdocs/media_room/press_releases/2013/Heat_Wave_Drives_Record_Electricity_U

sage_in_New_York_07192013.pdf. 64 NYISO, “NYISO Meets Record Demand with Balanced Array of Resources,” July 22, 2013 [Press

release], 

http://www.nyiso.com/public/webdocs/media_room/press_releases/2013/NYISO%20Meets%20Record%20Demand

%20with%20Balanced%20Array%20of%20Resources%20-%2007_22_13%20-%20FINAL.pdf. 65PJM Estimated Demand Response Activity July 15-19, 2013, p. 2, http://www.pjm.com/~/media/marketsops/demand-response/pjm-hot-days-report-for-july-15-july-19-2013.ashx. 66PJM, Week of July 15th, 2013: PJM RTO Operations & Markets, Markets and Reliability Committee 

Meeting, August 29, 2013, p. 2,http://www.pjm.com/~/media/committeesgroups/committees/mrc/20130829/20130829-item-13-hot-weather-operations-presentation.ashx
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 13

caused by unusually hot weather and local equipment problems which created emergency 

conditions in four states. Consumer demand for electricity reached a record-setting 144,370 MW

on September 10 while, thanks in part to demand response resources, on September 11 the 

demand on PJM’s system was down to 142,071 MW. The September 10 and 11 peak demands 

reached 90 percent of PJM’s past July 18 summer peak demand of 157,509 MW. While PJM 

was forced to direct local utilities to curtail 150 MW to ensure reliability, PJM credited voluntary 

demand response resources with playing a vital role in keeping the power grid stable and air 

conditioners running during the September peaks.67

In ISO-NE, demand peaked at 27,359 MW in the late afternoon of July 19. ISO-NE dispatched 

approximately 200 MW of emergency demand resources that day in response to high 

temperatures, unexpectedly high demand and unit outages. On July 15 and 18, wholesale prices 

rose past $200 per MWh, and exceeded $400 per MWh on July 19.68 In addition to dispatching 

demand response resources, ISO-NE also made two requests to retail consumers to conserve 

electricity voluntarily.69

In CAISO, high temperatures in early July led CAISO to issue calls for consumers in the 

northern half of the state to voluntarily reduce their electricity use on July 1-2.70 Although 

forecast to hit an all-time high on July 1, peak demand came in significantly under the forecast, 

which CAISO attributed to the impact of demand response programs and voluntary 

conservation.71

California activities

The CAISO hosted a workshop on May 13, 2013,

72 and later released a whitepaper titled 

“California ISO Demand Response and Energy Efficiency Roadmap: Making the Most of Green 

Grid Resources.”

73 The demand response and energy efficiency roadmap comprises four parallel 

and roughly concurrent paths or tracks of activity that run from 2013 through 2020.74 The four 

 67 PJM, “PJM Meets High Electricity Demand During Unusual Heat Wave,” September 12, 2013 [Press 

release], http://www.pjm.com/~/media/about-pjm/newsroom/2013-releases/20130912-pjm-meets-high-electricitydemand-during-unusual-heat-wave.ashx. 68 ISO New England, Weekly Market Summary, July 15-21, 2013, http://www.isone.com/markets/mkt_anlys_rpts/wkly_mktops_rpts/2013/we_2013_07_21_weekly.pdf. 69 ISO New England, “ISO New England Requests Voluntary Electricity Conservation,” July 16, 2013 

[Press release], http://www.isone.com/nwsiss/pr/2013/iso_new_england_requests_voluntary_electricity_conservation_final.pdf; and “ISO New 

England Continues Request for Voluntary Electricity Conservation,” July 18, 2013 [Press release], http://www.isone.com/nwsiss/pr/2013/iso-ne_continues_request_for_voluntary_conservation_7.18.13.final.pdf. 70 CAISO, “Northern California-ONLY Flex Alert issued by California ISO as heat wave intensifies,” June 

30, 2013 [Press release], http://www.caiso.com/Documents/FlexAlert-UrgentConservationNeededNowNorthernCalifornia_July12013.pdf. 71 CAISO, “Reminder: Day 2 of Flex Alert!” July 2, 2013 [Press release], 

http://www.caiso.com/Documents/ReminderDay2_FlexAlertJul2_2013.pdf. 72 California ISO, “Demand Response,” Demand response and energy efficiency roadmap workshop, May 

13, 2013, http://www.caiso.com/informed/Pages/StakeholderProcesses/DemandResponseInitiative.aspx. 73 California ISO, Demand Response and Energy Efficiency Roadmap Draft, June 12, 2013, 

http://www.caiso.com/Documents/Draft-ISODemandResponseandEnergyEfficiencyRoadmap.pdf. 74 Ibid.
October 2013 Assessment of Demand Response and Advanced Metering

Page 14 Federal Energy Regulatory Commission

paths are: the load reshaping path; the resource sufficiency path; the operations path; and the 

monitoring path. The roadmap highlights the need for inter-agency coordination and specific 

areas where coordination and communication are necessary to build new market opportunities

for demand response and energy efficiency solutions.

75

On June 17, 2013, the California Energy Commission (CEC) conducted a workshop to gather 

input on public policies needed to expand the amount of automated demand response resources 

available to CAISO.76 At the CEC workshop, the CAISO indicated that the expected increase in 

solar and wind integration will alter the daytime load profile in the CAISO system as early as 

2015. CAISO expects the system will experience a deep daytime load trough with a rapid and 

significant escalation between 4 p.m. to 8 p.m. CAISO suggested that flexible demand response 

resources may be needed to address these unpredictable situations.

77

ERCOT activities

ERCOT launched two new demand response programs aimed at improving the reserve margin 

during summer peak events. The first program, launched in June 2012 and expanded in 

December 2012, is the 30-minute Emergency Response Service (ERS) program.

78 This pilot 

project will allow eligible participants a half hour to respond to ERCOT requests to reduce their 

electricity use, and is open to individual customers or an aggregated group of consumers who can 

reduce demand on the ERCOT grid by at least 100 kilowatts.79 The board authorized ERCOT to 

procure up to a total of 150 MW for the pilot.

The second pilot, launched in March 2013, is the Weather-Sensitive Emergency Response 

Service pilot.80 This pilot is open to electricity customers that can reduce power use by at least 

100 kilowatts. Through qualified scheduling entities, participants will be paid based on how 

much they reduce demand, either in testing or during an actual event.81 ERCOT can call on 

resources beginning with the first level of energy emergency alert (EEA 1), when operating 

reserves drop below 2,300 MW. Most ERCOT demand response programs go into effect during 

EEA 2 when reserves drop below 1,750 MW.

 75 CAISO intends to work through the California Demand Response Measurement and Evaluation 

Committee (DRMEC) to clarify and standardize terminology for classifying demand response programs and 

resources (e.g., load modifying resources and supply resources). The DRMEC, established by the California Public 

Utilities Commission (CPUC), is comprised of members from the CPUC, the CEC, and a representative from each 

of the three state investor-owned utilities, and provides oversight of all statewide and non-statewide demand 

response program evaluations. 76 CEC, “Lead Commissioner Workshop: Increasing Demand Response Capabilities in California,”

http://www.energy.ca.gov/2013_energypolicy/documents/2013-06-17_workshop/presentations/. 77 Heather Sanders, “CEC IEPR Demand Response Workshop,” presented at Lead Commissioner 

Workshop on Increasing Demand Response Capabilities in California, June 17, 2013, 

http://www.energy.ca.gov/2013_energypolicy/documents/2013-06-17_workshop/presentations/Panel_5/06_SandersISO_presentation_06172013.pdf. 78 ERCOT, “ERCOT board extends demand response pilot, approves price floor for generators,” December 

20, 2012 [Press release], http://www.ercot.com/news/press_releases/show/26365. 79 Ibid. 80 ERCOT, “New pilot program offers incentives to reduce electric use during summer peaks,” March 25, 

2013 [Press release], http://www.ercot.com/news/press_releases/show/26422. 81 Ibid.
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 15

NERC’s Demand Response Availability Data System

In March 2013 NERC published early stage DADS results for two time periods: the 2011 

summer (April 1, 2011 to September 30, 2011) and the 2011-2012 winter (October 2, 2011 to 

March 31, 2012) periods.82 For the U.S. and Canadian entities providing information about 

demand response programs that are deployed for reliability purposes, NERC reports there were 

527 demand response deployments during the summer of 2011. The average number of demand 

response resources enrolled during the 2011 summer months was 6.46 million resources, on 

average the combined capacity of these resources was 50,919 MW, and the average sustained 

response period was 3 hours and 6 minutes.83 The average number of demand response 

resources enrolled during the 2011-2012 winter period was 5.34 million resources, on average 

the combined capacity of these resources was 48,686 MW, and the average sustained response 

period was 1 hours and 43 minutes.84

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

planning purposes

The Commission continues to ensure that demand resources are provided comparable treatment

in jurisdictional transmission planning processes, processing compliance filings in response to 

Order No. 1000, which reaffirmed Order No. 890’s requirement that public utility transmission 

providers consider all types of resources, including demand response and energy efficiency, on a 

comparable basis in transmission planning.85 

As part of the Recovery Act, the DOE awarded funds for collaborative transmission planning 

efforts in the Western, Eastern and Texas Interconnections, and these efforts are taking demand 

response into account.

86 Transmission planning studies in the Western, Eastern and Texas 

Interconnections are conducted by the Western Electricity Coordinating Council (WECC), the 

Eastern Interconnection Planning Collaborative (EIPC), and the Electric Reliability Council of 

Texas (ERCOT), respectively. WECC,87 EIPC,88 and ERCOT89 have each undertaken 

collaborative work efforts that develop long-term electricity supply futures, estimate the 

 82 NERC, 2011 Demand Response Availability Report, March 2013, 

http://www.nerc.com/docs/pc/dadswg/2011%20DADS%20Report.pdf. Note: NERC states “issues may be identified 

that require review and modification of the reported data.” 83 Ibid., p. 12. 84 Ibid., p. 24. 85 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 

Order No. 1000, 136 FERC ¶ 61,051, at P 153-154 (2011). 86 DOE, Office of Electricity Delivery and Energy Reliability (OE), “Interconnection Transmission 

Planning: Awards,” http://energy.gov/oe/downloads/interconnection-transmission-planning-awards. 87 WECC, “Transmission Expansion Plans,” 

http://www.wecc.biz/committees/BOD/TEPPC/Pages/Plans_Home.aspx. 88 EIPC, “Phase II SSC Meeting Materials,” http://www.eipconline.com/Phase_II_SSC_Meetings.html; and 

“ Phase II Resources,” http://www.eipconline.com/Phase_II_Resources.html. 89 ERCOT, Long-Term System Assessment for the ERCOT Region, December 2012, 

http://www.ercot.com/content/news/presentations/2013/2012%20Long%20Term%20System%20Assessment.pdf; 

See also ERCOT Long-Term Study Task Force, ERCOT LTS Update, March 2012, 

http://www.ercot.com/content/committees/other/lts/keydocs/2012/LTS_Update_4_updated.pdf.
October 2013 Assessment of Demand Response and Advanced Metering

Page 16 Federal Energy Regulatory Commission

associated transmission requirements, and prepare long-term interconnection-wide transmission 

plans.90 Smart grid technologies and demand resources are considered as components within a 

broad range of alternative supply futures. 

For example, demand response study case inputs are to be analyzed in WECC’s 20-year plan,91

and the Western Interconnection SPSC has approved the formation of a task force to examine 

using demand response for integrating variable generation in the West.92

In the Eastern Interconnection, NARUC and the Eastern Interconnection States’ Planning 

Council funded an assessment of demand-side resources and their existing and forecasted 

deployments within the eastern United States.93 Additionally, the Oak Ridge National 

Laboratory (ORNL), working in part with the EIPC Stakeholder Steering Committee, modified 

and updated the Commission’s National Assessment of Demand Response (NADR) model to 

forecast system peak demand by state and census division.94

ERCOT, with the assistance of stakeholders, developed a set of three scenarios for use in the 

long term study of the Texas Interconnection. All three scenarios consider and model demand 

response resources.95 One of the three scenarios includes a sensitivity analysis that assumes a 

technology-specific mandate to expand demand response.96

 90 DOE, Office of Electricity Delivery and Energy Reliability (OE), “Learn More About Interconnections,” 

http://energy.gov/oe/recovery-act/recovery-act-interconnection-transmission-planning/learn-more-aboutinterconnections. 91 State-Provincial Steering Committee (SPSC), “Demand Side Management,” 

http://www.westgov.org/sptsc/site/workgroups/dsmwg.htm. 92 SPSC, Memorandum to the Committee on Regional Electric Power Cooperation and the State-Provincial 

Steering Committee, October 12, 2012, http://www.westgov.org/wieb/meetings/crepcfall2012/summary.pdf. 93 Navigant Consulting, Inc, Assessment of Demand-Side Resources within the Eastern Interconnection, 

Prepared for Eastern Interconnection States’ Planning Council and National Association of Regulatory Utility 

Commissioners, March 2013, https://eispctools.anl.gov/documents. 94 Baek, Y.S., et. al., Eastern Interconnection Demand Response Potential (ORNL/TM-2012/303), 

November 2012, prepared by ORNL, managed by UT-Battelle, LLC for the U.S. DOE (contract DE-AC05-

00OOR22725), http://info.ornl.gov/sites/publications/files/Pub37931.pdf.

95 The ERCOT LTS Task Force developed three main scenarios: 1) Business as Usual, 2) Drought, and 3) 

Environmental and sensitivity cases. All three scenarios include demand response resources and a Business as 

Usual case will be expanded to include new and emerging technologies. See ERCOT Long-Term Study Task Force, 

ERCOT LTS Update, March 2012, 

http://www.ercot.com/content/committees/other/lts/keydocs/2012/LTS_Update_4_updated.pdf. 96 Ibid.
Assessment of Demand Response and Advanced Metering October 2013

Federal Energy Regulatory Commission Page 17

(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

As part of its ongoing effort to remove barriers to entry and ensure a level playing field for all 

resources that are technically capable of providing a service to have access to wholesale and 

interstate markets, the Commission has taken a number of actions related to demand response. 

This section summarizes those actions taken in the past year, other actions taken at the federal 

level, and recent state and industry actions taken at the retail level on demand response 

programs.

FERC demand response orders and activities 

Order No. 745

In March 2011, the Commission issued Order No. 745 relating to demand response 

compensation in organized wholesale energy markets.97 The Commission has accepted filings 

that PJM and ISO-NE submitted in order to comply with the requirements of the rule.98 Both 

MISO and CAISO have filed multiple compliance filings, and the Commission has largely 

accepted their proposals, establishing limited requirements for further tariff revisions.99 The 

Commission issued an initial order on NYISO’s Order No. 745 compliance filing in May 2013,

requiring NYISO to make further tariff revisions.100 Rehearing of that order is currently pending 

before the Commission. Additionally, on August 14, 2013, NYISO submitted a second 

compliance filing, which is pending before the Commission. SPP also has an Order No. 745 

compliance filing before the Commission. The Commission rejected in part SPP’s initial

compliance filing and required more explanation on the remainder of that filing.101 In May 

2012, SPP submitted a second compliance filing, which is currently pending before the 

Commission. In January 2013, SPP replied to a request for additional information from 

Commission staff relating to certain aspects of its second compliance filing.

Order No. 1000

As noted above, Order No. 1000, issued in July 2011, reaffirmed Order No. 890’s requirement 

that public utility transmission providers consider all types of resources, including demand 

response and energy efficiency, on a comparable basis in transmission planning.

102 In the first 

 97 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 76 Fed. Reg. 

16,658 (Mar. 24, 2011), FERC Stats. & Regs. ¶ 31,322 (2011), order on reh’g, Order No. 745-A, 137 FERC ¶ 

61,215 (2011).

98 See PJM Interconnection, L.L.C., 139 FERC ¶ 61,256 (2012) and ISO New England Inc., 138 FERC ¶ 

61,042 (2012). 99 See Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ¶ 61,146 (2013) and California 

Independent System Operator Corp., 144 FERC ¶ 61,047 (2013). 100 New York Independent System Operator, Inc., 143 FERC ¶ 61,134 (2013). 101 Southwest Power Pool, Inc., 138 FERC ¶ 61,041 (2012). 102 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 

Order No. 1000, 136 FERC ¶ 61,051 (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).
October 2013 Assessment of Demand Response and Advanced Metering

Page 18 Federal Energy Regulatory Commission

half of 2013, the Commission issued 15 orders in response to compliance filings addressing the 

regional transmission planning and cost allocation requirements of Order No. 1000, addressing 

each transmission planning region’s compliance proposals and directing further compliance

filings. Currently, the Commission is in the process of receiving further compliance filings, and 

in some cases rehearing requests, with respect to each of the transmission planning regions. 

Moreover, the Commission has started to receive separate filings that include proposals for 

compliance with the interregional requirements of Order No. 1000.

NAESB Demand Response and Energy Efficiency M&V Standards

In February 2013, the Commission issued a final rule (Order No. 676-G) amending its 

regulations to incorporate by reference NAESB’s business practice standards on the 

measurement and verification of demand response and energy efficiency resources that 

participate in organized wholesale electricity markets.103 The NAESB demand response 

measurement and verification (M&V) standards revised existing NAESB standards by adding

specificity to the existing standards in several areas, including meter data reporting, advanced 

notification, telemetry and meter accuracy. The Final Rule concluded that these revisions to the 

NAESB demand response M&V standards represented an incremental improvement to the 

business practices for measuring and verifying demand resource products and services in the 

organized wholesale electric markets.

The new NAESB M&V standards for energy efficiency provide criteria that will support the

measurement and verification of energy efficiency products and services in organized wholesale 

electric markets. These new standards include four acceptable measurement and verification 

methodologies that energy efficiency resource providers may use to participate in organized 

wholesale electricity markets. They also provide criteria for determining which type of baseline 

to use in various situations, such as the installation of new energy efficient equipment and 

processes or the replacement of outdated equipment. The standards also contain rules regarding 

statistical methods used to accurately determine reduction values, specifications for equipment 

used to perform measurements, and data validation. The Final Rule concluded that these 

standards will reduce transaction costs and provide an additional opportunity and increased 

incentive for energy efficiency resources to participate in the wholesale markets established in 

RTO and ISO regions.

Other federal demand response activities

National Forum on Demand Response

As part of the Implementation Proposal for the National Action Plan on Demand Response,104

the U.S. Department of Energy (DOE) and FERC sponsored a National Forum on Demand 

Response. Within the National Forum, DOE and FERC staff worked with state officials, 

demand response industry representatives, members of a National Action Plan Coalition, and 

 103 FERC, Standards for Business Practices and Communication Protocols for Public Utilities, Docket No. 

RM-05-5-020, Order No. 676-G, February 21, 2013, http://www.ferc.gov/whats-new/comm-meet/2013/022113/E3.pdf. 104 FERC and DOE, Implementation Proposal for the National Action Plan on Demand Response, July 

2011, http://www.ferc.gov/legal/staff-reports/07-11-dr-action-plan.pdf.
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experts from research organizations to share ideas, examine barriers and explore solutions for 

advancing demand response. To help answer questions of what remains to be done with demand 

response, working groups were formed to focus on key demand response technical, 

programmatic and policy issues. DOE funding supported the efforts in all four areas.

In February 2013, DOE and FERC staff released a series of new reports prepared by National 

Forum working groups created to address four issues:105 

• Cost effectiveness

• Measurement and verification

• Program design and implementation

• Tools and methods

DOE Smart Grid Investment Grants

A series of Department of Energy (DOE) reports released in December 2012 confirm the 

operational and customer service benefits of AMI in select SGIG projects. The DOE’s Office of 

Electricity Deliverability and Energy Reliability reviewed SGIG projects at or near completing 

AMI integration with: 1) enterprise software (15 of 63 projects),

106 2) automated capacitor banks 

(eight of 26 projects),

107 and 3) automated feeder switching (four of 42 projects).108 Of the 15 

SGIG projects with AMI-enterprise software integration reviewed, representing approximately 

3.5 million advanced meters, all showed lower meter operation costs, primarily due to reduced 

labor and vehicle costs related to remote meter reading and automated billing services. Projects 

with lower customer densities per distribution line-mile observed the largest savings per 

customer served. Of the eight SGIG projects with automated AMI-capacitor bank integration, 

initial results indicate the potential of between 1 and 2.5 percent reductions in peak demand. Of 

the four SGIG projects with automated AMI-feeder switching, all showed a reduction in both the 

frequency of outages and in the amount of time customers were without power.

DOE Smart Grid Demonstrations

The Smart Grid Demonstration Program (SGDP), operated by DOE, includes nine projects that 

employ demand response technologies or otherwise enhance demand response.109 One SGDP 

project, the Battelle Memorial Institute’s Pacific Northwest project, which is being undertaken

 105 DOE, “A National Forum on Demand Response: What Remains To Be Done To Achieve Its Potential,” 

http://energy.gov/oe/services/electricity-policy-coordination-and-implementation/state-and-regional-policyassistanc-7. 106 DOE, Office of Electricity Deliverability and Energy Reliability, Operations and Maintenance Savings 

from Advanced Metering Infrastructure – Initial Results, Smart Grid Investment Grant Program, December 2012, 

http://www.smartgrid.gov/sites/default/files/doc/files/AMI_OM_report_final_12-13-2012[1].pdf. 107 DOE, Office of Electricity Deliverability and Energy Reliability, Application of Automated Controls for 

Voltage and Reactive Power Management – Initial Results, Smart Grid Investment Grant Program, December 2012, 

http://www.smartgrid.gov/sites/default/files/doc/files/VVO%20Report%20-%20Final.pdf. 108 DOE, Office of Electricity Deliverability and Energy Reliability, Reliability Improvements from the 

Application of Distribution Automation Technologies – Initial Results, Smart Grid Investment Grant Program, 

December 2012, http://www.smartgrid.gov/sites/default/files/doc/files/Distribution%20Reliability%20Report%20-

%20Final.pdf. 109 SmartGrid.gov, “Smart Grid Demonstration Program,” 

http://www.smartgrid.gov/recovery_act/overview/smart_grid_demonstration_program.
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by in five states by 12 utilities with more than 60,000 customers, is in part using new 

technologies to provide two-way communication between distributed generation, storage, and 

demand response assets. A second SGDP project, the National Rural Electric Cooperative 

Association’s (NRECA) Enhanced Demand and Distribution Management Regional 

Demonstration project is implementing new technologies at 27 cooperatives in 11 states with 

different geographies and climates. The NRECA project will conduct studies in advanced 

volt/volt-ampere reactive power for total demand, demand response, critical peak pricing, water 

heater and air conditioning load control, thermal storage, energy usage portal pilots, and 

consumer in-home energy display pilots. A third SGDP project, NSTAR Electric and Gas 

Corporation’s Automated Meter Reading-Based Dynamic Pricing, will enable residential 

dynamic pricing [time-of-use (TOU), critical peak rates, and peak time rebates] and two-way 

direct load control by capturing automated meter reading (AMR) data transmissions and 

communicating through existing customer-sited broadband connections in conjunction with 

home area networks. 

Wholesale Demand Response Communication Protocols

The Smart Grid Interoperability Panel110 formed a Priority Action Plan (PAP) 19 working group 

to develop and enhance data exchange between RTOs and demand response aggregators. The 

PAP 19 working group completed work on the Wholesale Demand Response Communication 

Protocol (WDRCP) on September 21, 2012.111 The WDRCP defines use cases and creates 

model extensions for the modeling of distributed demand resources,112 as well as ways to deploy, 

measure, and evaluate distributed demand resources in wholesale markets. One of the key 

features of the WDRCP is the direct use of the Requirement Specification for Wholesale 

Standard DR Signals (published by NAESB) and the International Electrotechnical 

Commission’s (IEC) Common Information Model, a set of standards widely used by utilities and 

transmission organizations around the world, including North American RTOs/ISOs.

A working group within the IEC’s Technical Committee 57, Power System Communications, is 

considering the WDRCP for possible incorporation into the Common Information Model 

standards. The WDRCP protocol has been mapped to two leading demand response 

standards/applications, namely Open Automated Demand Response (OpenADR), a system for 

utility and third party communications with building automation systems in commercial and 

industrial buildings, and MultiSpeak, a system of standardized terminology and data objects used 

in systems integration for smaller utility operations, including many electric cooperatives. 

 110 The Smart Grid Interoperability Panel was established by the National Institute of Standards and 

Technology, which is responsible for coordinating the development of a framework to achieve interoperability of 

smart grid devices and systems, including protocols and model standards for information management. 111 See NIST Smart Grid Collaboration Wiki for Smart Grid Interoperability Standards, “PAP19: Wholesale 

Demand Response (DR) Communication Protocol,” https://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/PAP19WholesaleDR in the section “PAP19 Artifacts, Output and Next Steps,” 

subsection “Overview.” 112 Modeling is undertaken within the International Electrotechnical Commission’s Common Information 

Model.
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DOD & GSA federal efforts

Managing more than 300,000 buildings on some 500 installations, including barracks, data 

centers, office buildings and hospitals,113 the Department of Defense (DOD) is the single largest 

energy consumer in the Nation.114 Because of its size, the DOD recognizes it can use its own 

facilities to overcome development and deployment barriers for promising technologies, 

including demand response and advanced metering infrastructure.115 DOD environmental 

research programs foster technological innovations, assist in developing technologies, and 

accelerate cost-effective technology transitions into commercial markets through collaborative 

efforts among federal agencies, academia and industry. For example, DOD is demonstrating 

enhanced demand response program participation for Naval District Washington (NDW), the 

regional provider of common operating support to Naval installations within a 100-mile radius of 

the Pentagon. NDW installations encompass more than 4,000 square miles in portions of 

Maryland, Virginia and the District of Columbia.116 NDW has invested in advanced meters and 

meter data systems, and, as a part of its overall energy reduction strategy, plans to integrate its 

energy management systems and tools to demonstrate the ability to cost-effectively and securely 

participate in demand response programs.117 The NDW project will also determine how to 

transfer the technology and processes to other DOD services.

The U.S. General Services Administration (GSA) owns and leases over 354 million square feet 

in 9,600 federal buildings,118 and more than 30 federal agencies depend on the GSA’s Energy 

Division to assist with energy procurement.119 In 2012, the GSA Energy Division assisted with 

two separate wholesale demand response transactions for approximately “24 MW of demand 

response (~8 MW annually over a three year term)” for U.S. Department of Veterans Affairs 

facilities in NYISO and GSA facilities in PJM.120

 113 DOD, Strategic Environmental Research and Development Program (SERDP) and Environmental 

Security Technology Certification Program (ESTCP), “New Installation Energy and Water Technology 

Demonstrations Announced for FY 2013,” December 13, 2012 [Press release], http://www.serdp.org/News-andEvents/News-Announcements/Program-News/New-installation-energy-and-water-technology-demonstrationsannounced-for-FY-2013. 114 DOD, SERDP and ESTCP, “Energy,” http://www.serdp.org/Program-Areas/Energy-and-Water/Energy. 115 Jeffrey Marqusee, “The Contribution of Technology to Sustainable Energy Panel Discussion,” presented 

at the 2013 J.B. and Maurice C. Shapiro Conference: Laying the Foundation for a Sustainable Energy Future: Legal 

and Policy Challenges, George Washington University Law School, April 11, 1013, 

http://www.law.gwu.edu/News/2012-

2013Events/Pages/LayingtheFoundationforaSustainableEnergyFutureLegalandPolicyChallenges.aspx. 116 Commander, Navy Installations Command (CNIC), “About Naval District Washington,” 

http://www.cnic.navy.mil/ndw/About/index.htm. 117 DOD, SERDP and ESTCP, “Demonstrating Enhanced Demand Response Program Participation for 

Naval District Washington (EW-201343),” http://docs.serdp-estcp.org/Program-Areas/Energy-andWater/Energy/Microgrids-and-Storage/EW-201343/EW-201343/(language)/eng-US. 118 GSA, “Facilities Management Overview,” 

http://www.gsa.gov/portal/content/104476?utm_source=PBS&utm_medium=printradio&utm_term=HDR_1_Bldgs_facilities&utm_campaign=shortcuts. 119 WorldEnergy, “GSA Awards World Energy 5-Year Energy Management Contract,” September 8, 2010 

[Press release], http://staging.worldenergy.com/news/gsa-awards-world-energy-5-year-energy-managementcontract/. 

120 WorldEnergy, “Demand Response Auctions help GSA Generate More Competition and Keep More 

Revenue from Energy Curtailment Participation,” March 1, 2012 [Press release], 
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Other state legislative and regulatory activities related to demand response

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

activities since the publication of the previous report. In most cases, the developments reviewed 

for this report point to a continued expansion of demand response programs at the retail level, 

including, in some cases, an evolution of recent time-based pricing pilots into full program 

offerings.

• Arkansas. Act 1078 (Regulation of Electric Demand Response Act), approved on April 

11, 2013, specifies the authority possessed by the Arkansas Public Service Commission

(APSC) to establish the terms and conditions for marketing and selling demand response 

to retail customers or into wholesale electricity markets. The latter is prohibited unless 

the APSC determines that doing so is in the public interest. The marketing and selling of 

demand response by a municipal electric utility or a consolidated municipal utility 

improvement district is regulated by the local governing body rather than the APSC.121

• California. There have been several developments related to demand response in 

California over the past year. As previously noted, the CEC conducted a workshop on 

June 17, 2013 to gather input on public policies needed to expand the amount of 

automated demand response resources available to CAISO.

122 Prior to the CEC 

workshop and in a November 29, 2012 decision, the California Public Utilities 

Commission (CPUC) resolved certain policy issues related to its proposed Electric Rule 

No. 24, allowing retail customers to bid demand response resources, on their own or 

through an aggregator, directly into CAISO’s wholesale energy markets.123

The CPUC also issued Decision 12-04-045 on April 30, 2012, directing the state’s 

Demand Response Measurement and Evaluation Committee (DRMEC)124 to submit a 

detailed process evaluation plan that lists all demand response programs to be evaluated 

during 2012-2014, along with an explanation of the necessity of each evaluation.

125 The 

DRMEC is required to conduct annual statewide studies assessing the load impacts of 

demand response programs, but no guidance was provided on process evaluations—

which assess how effectively programs are designed and delivered—until the issuance of 

 http://www.worldenergy.com/news/demand-response-auctions-help-gsa-generate-more-competition-and-keep-morerevenues/.

121 State of Arkansas, Regulation of Electric Demand Response Act, SB 795 (2013), 

http://www.arkleg.state.ar.us/assembly/2013/2013R/Acts/Act1078.pdf. 122 CEC, “Lead Commissioner Workshop: Increasing Demand Response Capabilities in California,”

http://www.energy.ca.gov/2013_energypolicy/documents/2013-06-17_workshop/presentations/. 123 California Public Utilities Commission, Order Instituting Rulemaking Regarding Policies and Protocols

for Demand Response Load Impact Estimates, Cost-Effectiveness Methodologies, Megawatt Goals and Alignment 

with California Independent System Operator Market Design Protocols, Decision 12-11-025, November 29, 2012, 

http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M037/K494/37494080.PDF. 124 The DRMEC is composed of staff from the California Public Utilities Commission, the California 

Energy Commission, and a representative from each of the investor owned utilities in the state. 125 Demand Response Measurement and Evaluation Committee, Process Evaluation Plan, PY 2012-2014, 

November 16, 2012, http://www.cpuc.ca.gov/NR/rdonlyres/7222644F-9FE2-44DA-AD27-

09D27313AA82/0/DRMECprocessevaluationplan20122014redacted.pdf.
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Decision 12-04-045. The process evaluation studies will be available for review by Fall 

2014.126 

In addition, prior to the announced retirement of Southern California Edison’s (SCE) San 

Onofre Nuclear Generating Station (SONGS),127 the CPUC issued Decision 13-04-017

on April 18, 2013 approving San Diego Gas & Electric’s (SDG&E) and SCE’s proposed

revisions to their existing demand response programs to mitigate the effects of the 

continuing outage of SONGS Units 2 and 3.128 Changes to SCE’s programs are 

estimated to amount to an additional 58 MW of load reduction; the incremental impact of 

changes to SDG&E’s programs was not specified.

In May 2012, the CEC approved the latest version of its Title 24 Building Energy 

Efficiency Standards, which include requirements for automated demand response 

controls in certain new buildings. The standards are to take effect on January 1, 2014.129 

As defined in Title 24, “demand responsive controls” allow lighting levels in buildings to 

be automatically reduced in response to a demand response signal from a local utility. 

The revisions to Title 24 specify that the lighting controls must be able to receive and 

respond to “at least one standards based messaging protocol.”130

• Connecticut. In its Comprehensive Energy Strategy, released earlier this year, the 

Connecticut Department of Energy & Environmental Protection (DEEP) recommended 

“increased participation in [demand response] programs to help control the costs for 

Connecticut ratepayers and to allow ISO New England greater flexibility in managing the 

[wholesale electricity] system.”131 Specifically, the strategy recommended that, in 

addition to increasing the penetration of advanced meters, the state expand time-of-use 

pricing and other dynamic rate mechanisms to provide customers with financial 

incentives to shift their electricity use to lower-price periods. 

• Georgia. Georgia Power has put in place a time-of-use rate specifically for homes with 

plug-in electric vehicles. The rate is structured with on-peak, off-peak and “super off-

 126 Demand Response Measurement and Evaluation Committee, “The DRMEC Process Evaluation Plan for 

2012-2014,” Presented at Fall 2012 Workshop on Non-Impact Studies (San Francisco, CA), December 6, 2012, 

http://www.cpuc.ca.gov/NR/rdonlyres/0D9CE50F-7C12-4ABD-B027-

5E7DB6878916/0/20122014ProcessEvaluationPlanPowerPoint.pdf. 127 SCE, “Powering SoCal,” http://www.songscommunity.com/. 128 California Public Utilities Commission, Decision Approving Demand Response Program Revisions for 

Years 2013 through 2014, Decision 13-04-017, April 18, 2013, 

http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M064/K206/64206104.PDF. 129 California Energy Commission, “Energy Commission Approves More Efficient Buildings for 

California’s Future,” May 31, 2012 [Press release], http://www.energy.ca.gov/releases/2012_releases/2012-05-

31_energy_commission_approves_more_efficient_buildings_nr.html. 130 California Energy Commission, Proposed 2013 Energy Efficiency Standards: Title 24, Part 6, and 

Associated Administrative Regulations in Part 1, p. 182, http://www.energy.ca.gov/2012publications/CEC-400-

2012-004/CEC-400-2012-004-15DAY.pdf. 131 Connecticut Department of Energy and Environmental Protection, 2013 Connecticut Comprehensive 

Energy Strategy, February 19, 2013, http://www.ct.gov/deep/lib/deep/energy/cep/2013_ces_final.pdf.
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peak” times; the latter provides a significant discount over peak hours during the summer 

season, and a smaller discount during the rest of the year.132

• Idaho. Based on the results of its 2013 Integrated Resource Plan, which estimated no 

peak hour capacity shortages until 2016, Idaho Power filed a petition with the Idaho 

Public Utilities Commission (IPUC) to temporarily suspend two of its demand response 

programs. The IPUC approved a settlement stipulation to the petition, which specifies 

that existing customers will receive a “continuity payment” to encourage them to remain 

enrolled in the two suspended programs and that no new customers will be enrolled while 

the suspensions are in effect. The status of the suspended programs will be reconsidered 

ahead of the 2014 summer season.133

• Illinois. The Energy Infrastructure Modernization Act requires participating utilities to 

file proposed tariffs offering optional peak-time rebate programs to their residential 

customers within 60 days after approval of the utilities’ advanced metering plans by the 

Illinois Commerce Commission (ICC).134 In a February 2013 Interim Order, the ICC 

approved ComEd’s proposed Peak Time Rebate (PTR) program, conditioned on the 

utility making slight amendments to the program plan. The Order notes that the PTR 

program’s first curtailment will take place after June 1, 2015.135 Because Ameren Illinois 

does not yet have a Commission-approved AMI plan, it does not have a statutory 

obligation to file a PTR tariff at this time.136

• Maine. The Maine Public Utilities Commission (MPUC) approved a time-of-use rate 

for Central Maine Power Company (CMP) for the one-year period beginning March 1, 

2013. The optional program is available to residential and small commercial customers, 

and is delivered by NB Power, which services approximately one-third of CMP’s 

residential and small commercial load.137 In addition, the MPUC approved the 

establishment of a pilot program to test the ability of cost-effective “non-transmission 

alternatives,” such as distributed generation, energy efficiency and demand response, to 

defer or eliminate the need for new transmission while meeting reliability requirements. 

In its 2012 Annual Report, the Efficiency Maine Trust, the statewide energy efficiency 

program administrator, noted that the pilot is scheduled to issue a request for proposals

 132 Georgia Power, Electric Service Tariff: Time of Use – Plug-in Electric Vehicle Schedule: ‘TOU-PEV-3’, 

http://www.georgiapower.com/pricing/files/rates-and-schedules/2.30_tou-pev-3.pdf. 133 Idaho Public Utilities Commission, In the Matter of the Application of Idaho Power for Authority to 

Temporarily Suspend its A/C Cool Credit and Irrigation Peak Rewards Demand Response Programs, Case No. IPCE-12-29, Order No. 32776, April 2, 2013, http://www.puc.state.id.us. 134 State of Illinois, Energy Infrastructure Modernization Act, Public Act 097-0616, Senate Bill 1652, 97th

General Assembly (2011), http://www.ilga.gov/legislation/publicacts/fulltext.asp?Name=097-0616. 135 Illinois Commerce Commission, Petition for Approval of Tariffs Implementing ComEd’s Proposed Peak 

Time Rebate Program, Interim Order, Docket No. 12-0484, February 21, 2013, 

http://www.icc.illinois.gov/downloads/public/edocket/341974.pdf. 136 Illinois Power Agency, 2013 Electricity Procurement Plan, Docket No. 12-0544, April 5, 2013, 

http://www.icc.illinois.gov/downloads/public/edocket/345814.pdf. 137 Maine Public Utilities Commission, Order Designating Standard Offer Provider and Directing Utility to 

Enter Entitlement Agreements, Docket Nos. 2012-00456 and 2012-00409, November 7, 2012, 

http://www.maine.gov/mpuc/electricity/rfps/standard_offer/sosmall0912/docs/cmporder_smallMar2013.pdf.
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for non-transmission alternative resources in September 2013, and that resources are 

expected to be in operation by July 1, 2014.138

• Maryland. Baltimore Gas and Electric (BGE) and Delmarva Power and Light (DP&L) 

both have peak time rebate programs in place that provide a credit for reductions in 

electricity consumption during critical peak events. This dynamic rate structure is 

applicable to BGE’s residential customers and to DP&L’s residential and small 

commercial customers.139 In its June 2012 Request for Authorization, Southern 

Maryland Electric Cooperative (SMECO) suggested that it would offer a time-of-use rate 

once its advanced meter installation is approved.140 Utilities in Maryland have a goal of 

delivering 200 MW of demand response from dynamic pricing programs, in addition to 

approximately 700 MW from direct load control programs.141

Another factor potentially affecting demand response in the state is the status of the 

EmPOWER Maryland program. In its recent final report to the state Senate Finance and 

House Economic Matters Committees about the future of the program,142 the Maryland 

Energy Administration (MEA) noted, based on data about the performance of retail 

demand response programs,143 that the state is expected to exceed its target of a 15% 

reduction in per capita peak demand by 2015. MEA recommended that Maryland 

continue the EmPOWER program, with several significant changes to its structure and 

energy and demand savings targets. According to MEA, legislation to extend the 

EmPOWER program is expected to be introduced in 2014.144

• Minnesota. In November 2012, the Minnesota Public Utilities Commission (MPUC) 

approved Dakota Electric Association’s145 petition to implement a pilot time-of-use rate 

for residential electric vehicle charging. The proposed rate is intended to incent 

 138 Efficiency Maine Trust, 2012 Annual Report of the Efficiency Maine Trust, revised February 12, 2013, 

http://www.efficiencymaine.com/docs/reports/2012-Annual-Report.pdf. 139 Timmerman, C., “Maryland Smart Grid Update,” presented at the 28th Mid-Atlantic Distributed 

Resources Initiative Working Group meeting, May 7, 2013, 

http://sites.energetics.com/MADRI/pdfs/may2013/Timmerman.pdf. 140 SMECO, Request of Southern Maryland Electric Cooperative, Inc. For Authorization to Proceed With 

Implementation Of An Advanced Metering Infrastructure System, Case No. 9294, ML 140535, June 13, 2012, 

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

9299\9294\Item_1\&CaseN=9294\Item_1. 141 Timmerman, C., “Maryland Smart Grid Update,” presented at the Mid-Atlantic Distributed Resources 

Initiative Working Group meeting, May 7, 2013, 

http://sites.energetics.com/MADRI/pdfs/may2013/Timmerman.pdf. 142 The EmPOWER Maryland program was established in 2008 upon passage of the EmPOWER Maryland 

Energy Efficiency Act. The legislation set a goal of reducing per capita electricity consumption and peak demand 

by 15% by 2015. See EmPOWER Maryland Energy Efficiency Act of 2008, 2008 Md. Laws Ch. 131, 

http://mgaleg.maryland.gov/2008rs/chapters_noln/Ch_131_hb0374E.pdf. 143 The Maryland Energy Administration’s assessment of demand response program performance reflects 

actual savings from programs implemented from 2007 to 2011 and estimated performance of programs approved 

through 2015. 144 Maryland Energy Administration, “EmPOWER Planning Webinar,” March 15, 2013, 

http://energy.maryland.gov/empower3/documents/EmPOWERPlanningWebinar2013-03-15.pdf. 145 The Dakota Electric Association is an electric distribution cooperative.
October 2013 Assessment of Demand Response and Advanced Metering

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customers to charge their electric vehicles during off-peak hours.146 Also in November 

2012, the MPUC approved Minnesota Power’s petition to implement a residential timeof-day rate pilot. The pilot incorporates mechanisms for providing customers with 

feedback about their energy consumption at two time scales and also defines critical peak 

pricing periods. It is part of the utility’s broader Smart Grid Advanced Metering 

Infrastructure Pilot Project partially funded by the U.S. Department of Energy.147

• New York. In December 2012, Consolidated Edison of New York (ConEd) filed a 

petition seeking approval of changes to its existing demand response programs. Among 

other things, the utility sought to replace existing communicating thermostats in homes 

participating in its direct load control program with new wi-fi enabled communicating 

thermostats, and to increase the program budget to cover the cost of these installations 

over a five-year period. In addition, ConEd sought to expand the program by offering 

new participants a plug-in smart outlet to enable remote customer control of temperature 

settings.148 In an April 2013 order, the New York Public Service Commission (NYPSC) 

approved ConEd’s proposed program changes with significant changes. Instead of a 

wholesale replacement of existing communicating thermostats, the utility is allowed to 

replace thermostats with new wi-fi enabled versions only upon failure of the existing 

technology; the associated increase in budget was denied. The NYPSC found that the 

incorporation of the plug-in outlet technology into the direct load control program was 

premature. It ordered ConEd to continue refining the technology offering for another two 

years within its current pilot format.149

• Ohio. Duke Energy Ohio and AEP Ohio are offering new time-of-use rates to their 

residential customers. At the end of 2012, Duke Energy Ohio submitted an application 

for a new pilot time-of-use rate, which the Public Utilities Commission of Ohio approved 

on February 13, 2013.150 The pilot will target up to 5,000 homes with an advanced meter 

 146 Minnesota Public Utilities Commission, In the Matter of Dakota Electric Association’s Petition to 

Implement an Electric Vehicle Rate, Order Approving Electric Vehicle Rate As Modified and Requiring Filings, 

Docket Nos. E-111/M-12-874, November 8, 2012, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={C6A25

289-F680-4361-9861-ECC11A1DB71A}&documentTitle=201211-80479-01. 147 Minnesota Public Utilities Commission, In the Matter of Minnesota Power's Petition for Approval of a 

Temporary Rider for Residential Time-of-Day Rate for Participants of the Smart Grid Advanced Metering 

Infrastructure ("AMI") Pilot Project, Docket Nos. E-015/M-12-233, November 30, 2012, 

https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId={AB400

27B-94DE-49A5-BCA6-883DEDFD7250}&documentTitle=201211-81209-01. 148 This type of outlet was tested as part of the utility’s Residential Small Appliance Pilot Program (RSAP), 

which ran through the end of 2012. See New York Public Service Commission, Order Adopting Modifications and 

Tariff Revisions Related to Demand Response Programs, Case No. 09-E-0115, April 19, 2013, 

http://www3.dps.ny.gov/W/PSCWeb.nsf/All/A424588D473ED4EF85257687006F3900?OpenDocument. 149 Ibid. 150 Public Utilities Commission of Ohio, In the Matter of the Application of Duke Energy Ohio, Inc. for 

Approval of Pilot Tariff Rate TD 2013, Case No. 12-3281-EL-ATA, Finding and Order, 

http://dis.puc.state.oh.us/TiffToPDf/A1001001A13B13B40142J05994.pdf.
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installed and that meet certain conditions of baseline consumption.151 Customers electing 

to participate have a choice of three-hour blocks on summer and winter weekdays from 

which to select their preferred on-peak period.152 AEP Ohio is offering two new time-ofuse rates for customers living in its gridSMART Demonstration Project:153 the “SMART 

Shift” program offers a single on-peak and off-peak period, while the “SMART Shift 

Plus” rate incorporates time-of-use and critical peak pricing elements.154

• Pennsylvania. Under Act 129 of 2008, the Pennsylvania Public Utility Commission 

(PAPUC) was charged with establishing a state-wide energy efficiency and conservation 

(EE&C) program. Phase I of the program (2010-13) set a cumulative energy savings 

target of three percent of weather-adjusted sales, and a peak demand reduction target of 

4.5 percent of each utility’s 100 highest demand hours.155 Phase II of the EE&C program 

established additional cumulative energy savings targets, but not demand reduction 

targets, because an assessment of the cost-effectiveness of demand response programs 

was not available at the time the Implementation Order was issued.156 In May 2013, the 

Statewide Evaluator released its demand response study, as directed by the PAPUC. The 

study found that demand response programs were not cost-effective in 2012, due in part 

to “aggressive reduction targets” and to the stipulation that utilities reduce peak demand 

during the 100 hours of highest annual demand, which are difficult to predict. The 

Statewide Evaluator recommended several changes to the Act 129 demand response 

requirements and program evaluation for potential inclusion in Phase III of the EE&C 

program, which would begin in June 2016.157

Utilities continue to expand their time-of-use rate offerings for some customers. A timeof-day rate (“hourly pricing”) is the default service for large commercial and industrial 

customers in Pennsylvania, and is an option for medium C&I customers that have an 

 151 Schaefer, “Updates on Advanced Metering Infrastructure (AMI): Ohio Deployments,” presented at the 

28th Mid-Atlantic Distributed Resources Initiative Working Group meeting, May 7, 2013, 

http://sites.energetics.com/MADRI/pdfs/may2013/Schaefer.pdf. 152 Duke Energy Ohio, Rate TD-13: Optional Time-Of-Day Rate For Residential Service With Advanced 

Metering (Pilot), March 11, 2013, http://www.duke-energy.com/pdfs/Sheet.No.121.RATE.TD-13_3-13.pdf. 153 AEP Ohio, “gridSMART from AEP Ohio,” http://www.gridsmartohio.com/. 154 AEP Ohio, “Smart Meter Incentive Programs: SMART Shift,” 

https://aepohio.com/save/demoproject/SmartShift.aspx; and “Smart Meter Incentive Programs: SMART Shift Plus,” 

https://aepohio.com/save/demoproject/SmartShiftPlus.aspx. 155 Pennsylvania Public Utilities Commission, Energy Efficiency and Conservation Program 

Implementation Order, Docket No. M-2008-2069887, January 16, 2009, 

http://www.puc.pa.gov/electric/pdf/Act129/EEC_Implementation_Order.pdf. 156 Pennsylvania Public Utilities Commission, Energy Efficiency and Conservation Program 

Implementation Order, Docket Nos. M-2012-2289411 and M-2008-2069887, August 2, 2012, 

http://www.puc.state.pa.us/pcdocs/1186974.doc. 157 GDS Associates, Act 129 Demand Response Study: Final Report, Prepared for Pennsylvania Public 

Utility Commission, May 16, 2013, http://www.puc.pa.gov/pcdocs/1230512.docx.
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advanced meter installed.158 On June 1, 2015, medium C&I customers with the 

appropriate meter will also default to hourly pricing service.159

• Rhode Island. In a February 2012 order, the Rhode Island Public Utilities Commission

(RIPUC) approved a National Grid proposal to conduct a “Load Curtailment Pilot” in the 

Tiverton/Little Compton area from 2012 - 2017.160 According to National Grid’s revised 

2012 System Reliability Procurement Plan, the pilot will test whether demand response 

can manage local distribution capacity requirements during peak periods.161 The pilot 

thus fulfills a requirement under the state’s revised System Reliability Procurement 

Standards to identify “potential non-wire alternative solutions that reduce, avoid, or 

defer” traditional transmission and distribution solutions.162 Over the course of the pilot, 

National Grid plans to install wi-fi programmable controllable thermostats and lighting 

with enhanced demand response ballasts, as well as some direct load control appliance 

measures in future years.163

In its 2013 System Reliability Procurement Report, National Grid sought approval to 

enhance the Load Curtailment Pilot by offering higher energy efficiency incentives, 

providing additional energy efficiency measures that would not otherwise have been 

offered through statewide programs, and increasing marketing and participation in the 

pilot. National Grid estimates that the pilot will deliver annual summer demand savings 

of 161 kW (1,914 kW lifetime) from the residential and C&I sectors, along with annual 

energy savings of 500 MWh (5,512 MWh lifetime).164 The RIPUC approved the 

continuation of the pilot and the proposed changes to marketing, participation and 

technology updates.165

Industry demand response actions

Leadership in Energy and Environmental Design (LEED) 

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. The demand response credit was

 158 Current tariffs are available at 

http://www.puc.state.pa.us/utility_industry/electricity/rates_tariffs/electric_tariffs.aspx. 159 Matheson, “MADRI Working Group Pennsylvania Update,” presented at the 28th Mid-Atlantic 

Distributed Resources Initiative Working Group meeting, May 7, 2013, 

http://sites.energetics.com/MADRI/pdfs/may2013/Matheson.pdf. 160 Rhode Island Public Utilities Commission, In Re: Narragansett Electric Company d/b/a National Grid’s 

2012 System Reliability Plan, Order 20662, Docket No. 4296, February 29, 2012, 

http://www.ripuc.org/eventsactions/docket/4296-NGrid-Ord20662(2-29-12).pdf. 161 National Grid, 2012 System Reliability Plan Report – Supplement, Docket No. 4296, February 1, 2012, 

http://www.ripuc.org/eventsactions/docket/4296-NGrid-SRP-Supp2012(%202-1-12).pdf. 162 Ibid. 163 Ibid. 164 Rhode Island Public Utilities Commission, 2013 System Reliability Procurement Report, Docket No. 

4367, November 2, 2012, http://www.ripuc.org/eventsactions/docket/4367-NGrid-SRP-2013Plan(11-2-12).pdf. 165 Rhode Island Public Utilities Commission, Re: Narragansett Electric Company d/b/a National Grid’s 

2013 System Reliability Procurement Plan, Order No. 20911, Docket Nos. 4366 and 4367, December 21, 2012, 

http://www.ripuc.org/eventsactions/docket/4366-4367-NGrid-Ord20911(12-21-12).pdf.
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incorporated into the LEED v4 program (the newest update to the rating system) when adopted 

by USGBC membership on July 2, 2013,166 and the LEED v4 program will be fully launched in 

late 2013.167 

A facility’s eligibility for the credit depends on whether there is an existing demand response 

program in place or not. For newly constructed facilities in areas with an existing program, 

credit is given based on several conditions: the capability for real-time, fully automated demand 

response based on external initiation; an intention to participate in the program for several years; 

and the ability to reduce peak demand by at least 10 percent. For newly constructed facilities in 

areas without an existing program, the eligibility requirements include: installing infrastructure 

to take advantage of future demand response programs or dynamic, real-time pricing programs; 

developing a plan to shed peak demand by at least 10 percent; and expressing an interest in 

future program participation to the local utility.168 Existing commercial buildings can also get 

credit for participation in demand response programs. The requirements are similar to newly 

constructed buildings, with the additional option of getting credit for having a system in place 

that can permanently shift load from peak to off-peak hours.169

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

peak reduction, and critical period pricing programs

The 2009 National Assessment of Demand Response Potential170 and previous annual reports 

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

Commission, and state and local governments continue to make progress in removing barriers to

demand response. Key outstanding barriers and recent actions taken to address these barriers are

presented below:

• Limited Number of Retail Customers on Time-Based Rates. As noted in past 

annual reports, greater deployment of time-based rates, while not necessary for the 

continued development of additional demand response resources, would support the 

development of new technologies and programs. Projects undertaken by Oklahoma Gas 

and Electric, Marblehead Municipal Lighting Department and Sioux Valley Energy, and 

deployed as part of the Recovery Act, are providing new business cases demonstrating 

that time-based rates can be used to empower consumers and reduce system peak 

demands.171 DOE is working closely with these and other recipients of Recovery Act 

 166 U.S. Green Building Council, “USGBC’s LEED v4 Passes Ballot and Will Launch This Fall,” 

http://www.usgbc.org/articles/usgbc%E2%80%99s-leed-v4-passes-ballot-and-will-launch-fall. 167 U.S. Green Building Council, “About LEED v4.” http://www.usgbc.org/articles/about-leed-v4. 168 U.S. Green Building Council, “New Construction, v4 draft: Demand response,” 

http://www.usgbc.org/node/2613001?return=/credits/new-construction/v4-draft. 169 U.S. Green Building Council, “Existing Buildings, v4 draft: Demand response,” 

http://www.usgbc.org/node/2613007?return=/credits/existing-buildings/v4-draft/energy-%26-atmosphere. 170 FERC, A National Assessment of Demand Response Potential, June 2009, 

http://www.ferc.gov/legal/staff-reports/06-09-demand-response.pdf. 171 DOE, Demand Reductions from the Application of Advanced Metering Infrastructure, Pricing 

Programs, and Customer-Based Systems – Initial Results, SmarGrid Investment Program, December 2012, 

http://www.smartgrid.gov/sites/default/files/doc/files/peak_demand_report_final_12-13-2012.pdf.
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funding to gain further information and insights, particularly in the areas of customer 

response to dynamic pricing and enabling technologies.

• Coordination of Federal and State Policies. A lack of coordination among policies 

at the federal and state levels could slow the development of demand response resources. 

Some states have taken action to coordinate state retail demand response programs and 

policies with organized wholesale markets so that programs at the retail and wholesale 

level are complementary. For example, the California Energy Commission conducted a 

workshop with CPUC staff, CAISO and stakeholders to gather input on public policies 

needed to expand the amount of automated demand response resources available to 

CAISO.172 On the other hand, some states have limited retail customers’ demand 

response participation in wholesale markets.

• Measurement and Cost-Effectiveness of Reductions. Previous annual reports have 

described barriers associated with the measurement and cost-effectiveness of demand 

reductions. As noted above, the Commission, NAESB, and the National Forum on the 

National Action Plan on Demand Response undertook steps to address the lack of 

consistency in the measurement and verification of demand reductions this past year. 

While providing guidance on measurement and verification methods for market 

settlement (including design considerations and continuing challenges), the National 

Forum’s Measurement and Verification Working Group identified outstanding issues 

associated with impact estimations.173 In addition, the National Forum’s Demand 

Response Cost-Effectiveness Working Group identified a number of additional research 

topics associated with quantifying program benefits and costs.174 

• Lack of Uniform Standards for Communicating Demand Response Pricing, 

Signals and Usage Information. Past annual reports have also identified the need for 

common information models and protocols to promote more efficient transfer of usage 

and pricing information between parties. Significant progress has been made within the 

NIST smart grid interoperability framework process with respect to demand response 

pricing, signals, and usage information. Organizations such as the North American 

Energy Standards Board, the Organization for Advancement of Structured Information 

Systems, and the ISO/RTO Council have generated or sponsored work products that offer 

standardized approaches to retail and wholesale demand response pricing, signals, and 

usage information. As a result, standards have been written, and some products such as 

OpenADR 2.0, Smart Energy Profile 2.0, and Green Button are in various stages of 

 172 California Energy Commission, “Presentations for June 17, 2013 Lead Commissioner Workshop on 

Increasing Demand Response Capabilities in California,” Docket No. 13-IEP-1F, 

http://www.energy.ca.gov/2013_energypolicy/documents/2013-06-17_workshop/presentations/. 173 Goldberg, M. and G. K. Agnew, Measurement and Verification of Demand Response, February 2013, 

prepared for the National Forum on the National Action Plan on Demand Response: Measurement and Verification 

Working Group, http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential/napdr-mv.pdf. 174 Woolf, T., E. Malone, L. Schwartz and J. Shenot, A Framework for Evaluating the Cost-Effectiveness of 

Demand Response, February 2013, prepared for the National Forum on the National Action Plan on Demand 

Response: Cost-effectiveness Working Group, http://www.ferc.gov/industries/electric/indus-act/demandresponse/dr-potential/napdr-cost-effectiveness.pdf.
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adoption for retail and wholesale markets. Other standards, such as those to facilitate

two-way power flow to allow plug-in electric vehicles within demand response programs 

to be used as electric storage and provide ancillary services, will take longer to finalize 

and perhaps even longer to reach utilities and consumers.

• Opportunities for Customer Education and Engagement. Surveys indicate that 

customer awareness of the smart grid is currently low.175 The experiences of several 

utilities demonstrate that successful customer engagement efforts can promote acceptance 

of smart grid technologies and increase interest in time-based pricing programs.176 

Ongoing research by the Smart Grid Consumer Collaborative is one source for best 

practices around customer engagement related to the smart grid and time-based pricing 

programs.177

• Lack of Demand Response Forecasting and Estimation Tools. The National 

Action Plan Forum’s Estimation Tools and Methods Working Group analyzed and 

identified gaps between stakeholder’s demand response needs (both immediate and 

anticipated) and the availability of various analytical capabilities, services and tools to 

meet these demand response needs.178 The results of their study indicate that existing 

analytic capabilities and services are sufficient to effectively address many demand 

response stakeholder needs. However, the Estimation Tools and Methods Working 

Group identified four areas where further development may be appropriate: (1) End-user 

settlement tools, (2) load serving entities/electric distribution companies (LSE/EDC) site 

opportunity assessment tools, (3) LSE/EDC program implementation tools, and (4) 

LSE/EDC impact assessment tools.

 175 Smart Grid Consumer Collaborative, 2013 State of the Consumer Report, January 21, 2013, 

http://smartgridcc.org/wp-content/uploads/2013/01/SoCR-2013_1.24.pdf. 176 Smart Grid Consumer Collaborative, Smart Grid Consumer Engagement Success Stories, 

http://smartgridcc.org/news-events/research-release-sg-customer-engagement-success-stories. See also Smart Grid 

Consumer Collaborative, 2013 State of the Consumer Report, January 21, 2013, http://smartgridcc.org/wpcontent/uploads/2013/01/SoCR-2013_1.24.pdf. 177 Consumer engagement is a key topic for the Smart Grid Consumer Collaborative. See “Consumer 

Engagement,” http://smartgridcc.org/category/consumer-engagement. 178 Satchwell, A., C. Goldman, H. Haeri and M. Lesiw, An Assessment of Analytical Capabilities, Services 

and Tools for Demand Response, February 2013, prepared for the National Forum on the National Action Plan on 

Demand Response: Estimation Tools and Methods Working Group, http://www.ferc.gov/industries/electric/indusact/demand-response/dr-potential/napdr-assessment-analytical-tools.pdf.
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