2011 

 

 

Assessment of 

 

 

Demand Response and Advanced Metering 

 

 

 

 

Staff Report 

 

 

 

 

Federal Energy Regulatory Commission 

 November 2011 

 

 

 

 

 

 

 

 

 

 

 

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

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

Commission. 
ACKNOWLEDGEMENTS

Federal Energy Regulatory Commission Staff Team 

David Kathan, Team Lead 

Jordan Kwok 

Michael P. Lee 

Lisa Medearis 

Pamela Sporborg 

Michael Tita 

Dean Wight 
 

Federal Energy Regulatory Commission Page 1

FERC Staff Report 

ASSESSMENT OFDEMAND RESPONSE AND ADVANCED METERING

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

 

November 2011 

 

The Federal Energy Regulatory Commission staff (Commission staff) presents information in 

this sixth annual Assessment of Demand Response and Advanced Metering (report). This report 

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

Commission staff reviewed information from a variety of sources3

 to develop this year’s report, 

which provides information on demand response and advanced metering with an emphasis on 

results, activities, and regulatory actions taken over the last year. Based on the information 

reviewed, it appears that: 

 The penetration of advanced meters is up from 8.7 percent in 2009 to 13.4 percent; 

 Demand response potential in organized markets operated by the Electric Reliability 

Council of Texas (ERCOT), Regional Transmission Organizations (RTOs) and 

Independent System Operators (ISOs) increased by more than 16 percent since 2009; 

 Demand responded to peak load emergency conditions in ERCOT and the RTO and ISO 

organized markets; and 

 Federal and state regulators and others continue to focus on demand response, taking 

actions to remove barriers to wholesale demand response and develop policies to address 

smart grid. 

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: 

 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), 

available at http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. The 2007, 2008, 2009 and 

2010 annual reports are also available at http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. 3

 Information was compiled from readily accessible data and reports, Energy Information Administration 

surveys, Regional Transmission Organization (RTO) and Independent System Operator (ISO) annual reports, and 

discussions with market participants and industry experts. Commission staff has not independently verified the 

accuracy of all data presented herein. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 2 Federal Energy Regulatory Commission 

(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 state, federal and industry activities is also provided. 

(A) Saturation and penetration rate of advanced meters

Recent data from various sources give differing estimates of the penetration rate4 of advanced 

meters, but all estimates increase over the period 2007 to 2011. A U.S. Energy Information 

Administration (EIA) sample of 420 utilities reported 9.7 million (or 13.4 percent) advanced 

meters as of June 2011.5 EIA also collects information on advanced meters annually on the 

Form EIA-861.6 In 2009, entities reported that 9.6 million advanced meters were in use out of 

approximately 148.4 million meters in total, indicating a penetration rate for 2009 of 6.5 percent. 

The most recent FERC Survey of advanced meters showed a penetration rate of 8.7 percent in 

2009.7

 

Other sources also report increasing numbers of advanced meter installations over the past year. 

For example, data collected by the Institute for Electric Efficiency (IEE) indicates that advanced 

meters represent about 18 percent of all meters in the U.S. as of September 2011. 8 The high 

penetration rate from IEE data may be because, unlike the Commission and EIA, its data include 

 4

 In this report, “penetration rate” means the percentage of all installed meters that are advanced meters. 5

 The Form EIA-826, "Monthly Electric Utility Sales and Revenue Report with State Distributions," is used 

to collect data on retail sales of electricity and associated revenue, each month, from a statistically chosen sample of 

electric utilities in the United States. The respondents to the Form EIA-826 are chosen from the Form EIA-861, 

"Annual Electric Utility Report." (http://205.254.135.24/cneaf/electricity/page/eia826.html). The EIA-826 sample 

population was not designed specifically to collect the number of advanced meters. The data items for advanced 

meters are a recent addition to the preexisting EIA-826 form. 6

 The Form EIA-861 is completed by electric power industry entities including: electric utilities, all DSM 

(Demand-Side Management) Program Managers (entities responsible for conducting or administering a DSM 

program), wholesale power marketers (registered with the Federal Energy Regulatory Commission), energy service 

providers (registered with the States), and electric power producers. Responses are collected at the operating 

company level (not at the holding company level). 7

 2010 FERC Demand Response Report. 

8

 Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals (September 

2011) (“IEE Deployments”). Penetration rate based on 27.3 million installed smart meters (IEE) and 148.4 million 

U.S. electric consumers (Energy Information Administration, Form EIA-861 Data, 2009). 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 3

advanced meters that have been installed but which have not yet been activated for advanced 

metering purposes. 

The growth in advanced meter installations may be attributable in part to funding for advanced 

meters and advanced meter systems through the Smart Grid Investment Grant (SGIG) program 

provided for under the American Recovery and Reinvestment Act of 2009 (Recovery Act).9 As 

of September 28, 2011, approximately 7.2 million advanced meters have been installed using 

Recovery Act funding. Ultimately, 15.5 million advanced meters are expected to be installed 

under SGIG.10 IEE predicts that about 65 million advanced meters will be installed nationwide 

by 2015.11 

Table 1 summarizes the available information on advanced meter installations. 

Table 1: Estimates of Advanced Meter Penetration Rates 

Source of No. of Advanced 

Meters 

Reference Date 

(Month/Year) 

Advanced Meter 

Penetration Rates 

(advanced meters 

as a % of total 

meters) 

Number of 

Advanced 

Meters 

(millions) 

Total 

Number of 

Meters 

(millions) 

2008 FERC Survey Dec 2007 4.7% 6.7 1 144.4 1

2010 FERC Survey Dec 2009 8.7% 12.8 2 147.8 2

EIA-861 Annual Survey Dec 2009 6.5% 9.6 3 148.4 3

EIA-826 Monthly Survey June 2011 13.4% 9.7 4 72.4 4

Institute for Electric 

Efficiency Sept 2011 18.4% 27.3 5

 148.4 3

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

 Energy Information Administration, Form EIA-861 Final Data File for 2009 

(http://www.eia.gov/cneaf/electricity/page/eia861.html). 4

 EIA-826 Advanced Metering Spreadsheets (June 2011), 

(http://www.eia.gov/Ftproot/pub/electricity/netmetering_green_pricing/f826advancedmetering2011.xls). 5 Institute for Electric Efficiency, Utility-Scale Smart Meter Deployments, Plans & Proposals (September 2011). 

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 2011. Federal, state and local governmental entities as well as industry stakeholders 

have been actively developing policies and supporting infrastructure to facilitate and address 

issues concerning the deployment and use of advance metering. As advanced metering 

deployment continues and achieves greater penetration, issues associated with use of advanced 

metering and associated smart grid technologies have gained in importance. Discussed below 

are federal and state developments, privacy concerns and health issues. 

 9

 American Recovery and Reinvestment Act of 2009, Pub. L. No. 111-5. 

10 U.S. Department of Energy, 

http://www.smartgrid.gov/recovery_act/tracking_deployment/ami_and_customer_systems. 11 IEE Deployments. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 4 Federal Energy Regulatory Commission 

Interoperability standards

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

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

framework that includes protocols and model standards for information management to achieve 

interoperability of smart grid devices and systems...” In addition to the issue of meter 

upgradeability which was addressed in 200912, meter data formats and translation facilitation, 

and meter communication with retail devices involve advanced metering. 

NIST’s Priority Action Plan 5 (Standard Meter Data Profiles) and Priority Action Plan 6 

(Translate ANSI C12.19 to and from a Common Semantic Model) are efforts to develop a 

common format for retrievable meter data and to develop a common form to which meter 

information may be translated. According to NIST, these standards are intended to greatly 

reduce the time needed by utilities (and others requiring meter data) to implement smart grid 

functions such as demand response and real-time usage information. Both plans are expected to 

be completed in late 2011. 

 

NIST’s Priority Action Plan 18 (SEP 1.x to SEP 2.0 Transition and Coexistence) will develop 

requirements for the coexistence of and migration between two versions of a system used to 

communicate between meters and consumer devices. According to NIST, the earlier version 

supports home area networking, pricing of multiple commodities, encryption, direct load control, 

and demand response; and the newer version will add support for multiple types of networking 

and security, international standards, electric vehicles, and distributed energy resources. Priority 

Action Plan 18 is expected to be completed late in 2011.13

State and Federal regulatory bodies have encouraged stakeholders to engage in the NIST process 

for developing standards. The National Association of Regulatory Utility Commissioners 

(NARUC) in a resolution issued in July 2011 emphasized the desirability of smart grid standards 

and encouraged parties to participate in the Smart Grid Interoperability Panel process.14 The 

Commission in a July 2011 order encourages utilities, smart grid product manufacturers, 

regulators and others to actively participate in the NIST interoperability framework process. 

Development of state‐based progress and performance metrics

Progress and performance metrics allow states to gauge installation rates and performance results 

for numerous components of a utility’s advanced metering infrastructure deployment and 

operational strategy. 

Since the last Commission staff annual report, several states made progress on developing these 

metrics. The Illinois Commerce Commission established the Illinois Statewide Smart Grid 

 12 National Electrical Manufacturers Association, NEMA Smart Grid Standards Publication SG-AMI 1-

2009, September 25, 2009, available at http://www.nema.org/stds/sg-ami1.cfm. 13 NIST Smart Grid Collaborative, http://collaborate.nist.gov/twikisggrid/bin/view/SmartGrid/PAP18SEP1To2TransitionAndCoexistence. 14 NARUC, Policy Resolutions Passed by the Board of Directors of the National Association of Regulatory 

Commissioners (July 11, 2011 p. 6). 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 5

Collaborative (ISSGC), which issued a final report in October 2010.15 In February 2011, the 

California Public Utilities Commission (California PUC) received comments on a “Report on 

Consensus and Non-Consensus Smart Grid Metrics” that was submitted by three investor-owned 

utilities.16 In May 2011, the Maryland Public Service Commission received an Advanced 

Metering Infrastructure Performance Metrics Reporting Plan submitted by two investor-owned 

utilities on behalf of a working group led by public service commission staff. The metrics in the 

Maryland plan consider cost, project execution and delivery, operational benefits, and consumer 

education.17

Other state legislative and regulatory activity

 Colorado. On January 20, 2011, the Colorado Smart Grid Task Force published a set of 

recommendations for the Governor, General Assembly, and the Colorado Public Utilities 

Commission (Colorado PUC) to consider. Among its consensus findings, it 

recommended open communication standards for metering protocols (as defined by 

NIST), the exploration of time-based pricing, and a “technology ‘platform,’ or base 

operating system of protocols and communications ...such that all new software systems, 

hardware devices and new products can be ‘plugged in’ to the network and immediately 

recognize and be recognized by the network.”18 The task force also noted that AMI can 

facilitate distributed generation, variable energy resources, and demand response for 

consumers. 

 Kentucky. In March 2011, multiple stakeholders provided a joint response to Kentucky 

Public Service Commission (KPSC) staff’s Smart Meter and Smart Grid Guidance 

document. The response recommended that the Kentucky Commission undertake pilots 

and trials, focus on customer education, and resist implementing prescriptive 

requirements.19

 15 ISSGC, Illinois Statewide Smart Grid Collaborative: Collaborative Report, September 30, 2010, 

available at http://www.ilgridplan.org/Shared%20Documents/ISSGC%20Collaborative%20Report.pdf. 16 California Public Utilities Commission, Report on Consensus and Non-Consensus Smart Grid Metrics, 

Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, and 

the Environmental Defense Fund, (submitted per Decision No.10-06-047), available at 

http://docs.cpuc.ca.gov/efile/RULINGS/129001.pdf. 17 Maryland Public Service Commission, BGE Advanced Metering Infrastructure Performance Metrics 

Reporting Plan, May 18, 2011, Case 9207: In the Matter of the Application of Baltimore Gas And Electric Company 

for Authorization to Deploy a Smart Grid Initiative and to Establish a Surcharge Mechanism for the Recovery of 

Cost; Case 9208: In the Matter of the Application of Potomac Electric Power Company and Delmarva Power and 

Light Company Request for the Deployment of Advanced Meter Infrastructure, available at 

http://webapp.psc.state.md.us/Intranet/home.cfm. 18 Colorado Smart Grid Task Force, Deploying Smart Grid in Colorado: Recommendations and Options

(undated), p. 10; available at 

http://rechargecolorado.com/images/uploads/pdfs/Deploying_Smart_Grid_in_Colorado_Recommendations_and_Op

tions.pdf. 

19 KPSC, Joint Case Participant Response: Consideration of the New Federal Standards of the Energy 

Independence and Security Act: In response to Kentucky PSC’s February 19, 2010 Guidance Document Letter, 

March 25, 2011, Case No. 2008-00408: Consideration of the New Federal Standards of the Energy Independence 

and Security Act of 2007, p. 50, available at http://psc.ky.gov/pscscf/2008%20cases/2008-

00408/20110325_lg&e%20and%20ku_response.pdf. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 6 Federal Energy Regulatory Commission 

 New Jersey. New Jersey’s draft Energy Master Plan issued in June 2011 calls for the 

expansion of advanced metering and dynamic pricing, the reduction of peak demand, and 

the assessment of smart grid demonstration projects.20 

In addition, several other states, including Massachusetts, Michigan, New York, Ohio, 

Oklahoma, Pennsylvania, and Texas have smart grid task forces, collaboratives or other groups, 

or specific proceedings evaluating advanced metering issues.21 

Privacy of advanced metering data

The need for safeguards and standards to protect the privacy and security of customer usage data 

continues to be a key issue associated with advanced metering systems. While one of the 

potential benefits associated with advanced metering is the ability to measure and communicate 

customer usage at a much greater level of detail than traditional electro-mechanical meters, 

various stakeholder groups have raised concerns at the state and national levels regarding the 

use, privacy and security of the vast amount of detailed usage data produced by advanced 

meters.22 In response to these concerns, states and the federal government are working on 

privacy standards and policies. Policies under consideration include procedures and rules 

governing customer ownership, consent, access and use, delineation of responsibilities, security, 

as well as the sale and transfer of data. 

At the federal level, the Obama Administration examined privacy issues in depth in its June 2011 

smart grid policy framework report.23 The report recommends that “State and Federal regulators 

should consider, as a starting point, methods to ensure that consumers’ detailed energy usage 

data are protected in a manner consistent with federal Fair Information Practice Principles and 

develop, as appropriate, approaches to address particular issues unique to energy usage.”24

A number of states also took action in the past year to protect consumer data privacy. For 

example, as a result of legislation enacted in 2010 (SB 1476), the California PUC adopted 

privacy rules for the three investor-owned utilities addressing disclosure and protection of 

customer energy usage data generated by advanced metering, and the investor-owned utilities 

must file tariff changes that will provide third parties with access to a customer’s usage and 

billing information (e.g., 15-minute or hourly price, usage and cost data) when authorized by the 

 20 State of New Jersey, 2011 Draft Energy Master Plan, June 2011, available at 

http://www.nj.gov/emp/docs/pdf/2011%20Draft%20Energy%20Master%20Plan.pdf. 21 Association for Demand Response and Smart Grid, “Demand Response & Smart Grid—State Legislative 

and Regulatory Policy Action Review: May 2010 – June 2011”, June 2011. Also, the Edison Electric Institute 

maintains a summary of state decisions, i.e., EEI Summary of State Regulatory Smart Grid Decisions, August 2011, 

available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Pages/StatePolicyResearch.aspx. 22 See U.S. Department of Energy, Data Access and Privacy Issues Related to Smart Grid Technologies, 

October 5, 2010, available at 

http://www.doe.gov/sites/prod/files/gcprod/documents/Broadband_Report_Data_Privacy_10_5.pdf. 23 Executive Office of the President, A Policy Framework for the 21st Century Grid: Enabling Our Secure 

Energy Future, June 2011, available at http://www.whitehouse.gov/sites/default/files/microsites/ostp/nstc-smartgrid-june2011.pdf. 24 Id. at 46. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 7

customer.25 The decision adopts the Fair Information Practice Principles. In addition to the 

privacy rules for the three investor-owned utilities, the California PUC also ruled that if specific 

electric utilities26 file applications to deploy advanced metering systems, these utilities must also 

address how the privacy rules should apply to their operations. 

The Colorado PUC issued proposed amendments to the state’s smart data privacy rules, which 

would change or add new definitions to the rules, provide standards for data collection with a 

smart meter, require approval to disclose customer data to affiliates and third parties, limit smart 

meter reading to kilowatt and kilowatt-hours, and establish specific amounts for civil penalties 

for infringement of the new rules.27 After two hearings and a workshop, the matter was referred 

to an Administrative Law Judge (ALJ), who ultimately issued a decision on August 29, 2011 

recommending adoption of the amendments.28 

The ALJ addressed issues including the definition of “customer data,” the availability of analog 

meters, customers’ ability to “freeze” data sharing even after granting consent to share data, 

limited liability for utilities that disclose customer information in compliance with Commission 

rules, and the form by which customers consent to third-party access to their data.29 

In February 2011, the Public Utilities Commission of Ohio (PUCO) issued an order requesting 

comments to identify issues or topics to be considered regarding consumer privacy protection or 

customer data access, and advanced specific questions for stakeholder input.30 Oklahoma enacted 

the Electric Usage Data Protection Act in May 2011, which establishes standards to govern the 

access to and use of customer usage data by electric utilities, customers of electric utilities, and 

third parties.31 In June 2011, Maine enacted legislation requiring the Maine Public Utilities 

 25 California Public Utilities Commission, (Date of Issuance, 7/29/2011), Rulemaking 08-12-009: Order 

Instituting Rulemaking to Consider Smart Grid Technologies Pursuant to Federal Legislation and on the 

Commission's own Motion to Actively Guide Policy in California's Development of a Smart Grid System, available 

at http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/140369.htm. 26 Bear Valley Electric Service, Mountain Utilities, PacifiCorp, and the California Pacific Electric 

Company. 27 Colorado Public Utilities Commission, Docket No. 10R-799E, In the Matter of the Proposed Rules 

Relating to Smart Grid Data Privacy for Electric Utilities, 4 Code of Colorado Regulations 723-3, Notice of 

Proposed Rulemaking, November 3, 2010, Decision No. C10-1192. 28 Colorado Public Utilities Commission, Recommended Decision of Administrative Law Judge G. Harris 

Adams Adopting Rules, August, 29, 2011, Decision No. R11-0922. 

29 Colorado also intends to have a future rulemaking on data access and sharing, including how to value 

aggregated data sold to marketers. 30 See PUCO, Case No: 11-277-GE-UNC: In the Matter of the Review of the Consumer Privacy Protection, 

Customer Data Access, and Cyber Security Issues Associated with Distribution Utility Advanced Metering and 

Smart Grid Programs, available at http://dis.puc.state.oh.us/CaseRecord.aspx?CaseNo=11-0277, and PUCO, 

Consumer Privacy and Customer Data Access Issues, available at

http://www.puco.ohio.gov/emplibrary/files/media/smartgrid/CONSUMER%20PRIVACY%20AND%20CUSTOME

R%20DATA%20ACCESS%20ISSUES.pdf. 31 Oklahoma State Legislature, HB 1079 of 2011, Electric Utility Data Protection Act, available at 

http://www.oklegislature.gov/BillInfo.aspx?Bill=HB1079&Tab=0. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 8 Federal Energy Regulatory Commission 

Commission to examine state and federal cyber security and privacy requirements, monitor 

federal cyber security initiatives, and report findings and recommendations to the legislature.32

Radio frequencies and health

Another publicly noted concern regarding the deployment of advanced metering is the possible 

linkage between the radio frequencies used to transmit meter data wirelessly and human health.33 

The radio frequency (RF) emissions associated with advanced metering have not been proven to 

present a risk to human health, but concerns about a possible linkage continue.34 

In response to customer concerns, several states examined the health concerns raised by some 

customers and developed policies to address these concerns. For example, in December 2010, 

the California Public Utilities Commission dismissed a motion to consider the potential danger 

of advanced metering, concluded that RF emissions are under the purview of the FCC, and the 

RF emissions from advanced meters are “one/six thousandth of the Federal health standard at a 

distance of 10 feet from the Smart Meter and far below the RF emissions of many commonly 

used devices.”35 Nevertheless, in March 2011, California Public Utilities Commission President 

Peevey asked Pacific Gas & Electric to develop a customer opt-out proposal to address customer 

concerns. PG&E’s initial proposal identified two options as economic and technically feasible: 

turning off the radio transmitter in the customers’ meters or relocating the meter to a different 

location on the property at the customer’s expense.36 

In May 2011, the Maine Public Utilities Commission required Central Maine Power to offer a 

similar opt-out program due to RF concerns. Under this opt-out program, customers can either 

have the radio transmitter turned off or may continue to use the existing electro-mechanical 

meter.37 Central Maine Power customers can select either of these customized metering options 

as a non-standard option and pay associated charges. The Maine Commission made no 

determination on the merits of health and safety concerns.38 

 32 Maine State Legislature, Chapter 82 of the 125th Maine Legislature, available at 

http://www.mainelegislature.org/legis/bills/bills_125th/chapters/RESOLVE82.asp. 33 See California Council on Science and Technology, Health Impacts of Radio Frequency from Smart 

Meters, January 2011, available at http://www.ccst.us/publications/2011/2011smartA.pdf. 34 The Federal Communications Commission (FCC) advises that “exposure to very high RF intensities can 

result in heating of biological tissue and an increase in body temperature...[and] at relatively low levels of exposure 

to RF radiation, i.e., levels lower than those that would produce significant heating; the evidence for production of 

harmful biological effects is ambiguous and unproven.” Federal Communications Commission, Office of 

Engineering and Technology, Radio Frequency Safety, available at http://transition.fcc.gov/oet/rfsafety/rf-faqs.html. 35 California Public Utilities Commission, Decision Granting Motion of Pacific Gas and Electric Company 

to Dismiss Application, Decision 10-12-001, December 6, 2010, available at 

http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/127604.pdf. 36 California Public Utilities Commission, PG&E Smart Meter Opt-Out Proposal, available at 

http://www.cpuc.ca.gov/PUC/energy/Demand+Response/pgeoptout.htm. 37 Maine Public Utilities Commission, Press Release, “MPUC Decides Smart Meter Investigation,” May 

17, 2011, available at http://www.maine.gov/tools/whatsnew/index.php?topic=pucpressreleases&id=245859&v=article08. 38 Maine’s Center for Disease Control published a final review concluding little evidence exists supporting 

health effect concerns. See Maine Center for Disease Control, Executive Summary of Review of Health Issues 

Related to Smart Meters, November 8, 2010, available at 

http://www.maine.gov/dhhs/boh/documents/Smart_Meters_Maine_CDC_Executive_Summary_11_08_10.pdf. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 9

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

Commission staff surveyed existing demand response and time-based rate programs in 2010 (see 

2010 FERC Demand Response Report) and intends to conduct another survey during 2012. 

Staff has not identified any additional data on levels of participation in demand response and 

time-based rate programs since the release of the 2010 FERC Survey. 

(C) Annual resource contribution of demand resources  

Based on publicly available sources of information, the potential resource contribution by 

demand response in Regional Transmission Organization (RTO) and Independent System 

Operator (ISO) markets operated in the U.S. increased by more than 16 percent from 27,189 

megawatts (MW) in 2009 to 31,702 MW in 2010. 

RTOs and ISOs publish recent data on demand response potential in their respective areas. 

Table 2 compares the reported data for calendar year 2009 to values for 2010 (or more recent 

values, where available) from RTO/ISO sources. Overall, the demand response resources’ 

potential contribution in U.S. RTO/ISO markets increased by about 16 percent since 2009.39 

Demand response resources active during 2011  

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

during system emergencies for several RTOs and ISOs in 2011. For example, very hot weather 

during July 2011 in the Eastern U.S. caused demand for electricity to approach record-setting 

levels. On July 21, the New York Independent System Operator (New York ISO) activated all of 

its registered demand response in the downstate region (more than 800 MW), and activated more 

than 2,000 MW of demand resources statewide the following day.40

In the PJM Interconnection, L.L.C. (PJM) region, economic (non-emergency) demand response 

reached a peak reduction of 105 MW in reaction to high prices on July 21. On July 22, PJM 

activated demand resources in six Mid Atlantic zones, resulting in about 2,400 MW of peak 

reduction, mostly from emergency demand resources.41 ISO New England called for 643 MW of 

demand response on July 22, and estimated that about 663 MW of peak reduction resulted.42

 

 39 The MW reported here represent the MW of demand response “registered” for participation and potential 

deployment in the relevant markets and programs, e.g., capacity markets, economic- and reliability-based programs. 40 New York ISO, Press release, “Heat Pushes Power Demand to Near Record Level,” July 22, 2011, 

available at http://www.nyiso.com/public/webdocs/newsroom/press_releases/2011/NYISO_-

_Heat_Pushes_Power_Demand_to_Near_Record_Level_-_07_22_11_-_FINAL_FINAL.pdf. 41 PJM, 2011 Preliminary Emergency Load Management (ILR/DR) and Economic Demand Response 

summary, October 7, 2011, available at http://www.pjm.com/markets-and-operations/demandresponse/~/media/markets-ops/dsr/2011-preliminary-emergency-load-management-ilr-dr-and-economic-drsummary.ashx. 42 ISO Newswire, “Heat wave pushes NE demand to second-highest peak,” July 28, 2011, available at 

http://www.isonewswire.com/updates/2011/7/28/heat-wave-pushes-ne-demand-to-second-highest-peak.html. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 10 Federal Energy Regulatory Commission 

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

2009 

(MW) 

Percent of 

2009 Peak 

Demand9

2010 

except as noted 

(MW) 

Percent of 

2010 Peak 

Demand9

California ISO 3,2671 7.1% 2,1351 4.5% 

Electric Reliability Council of 

Texas 1,3092

 2.1% 1,4843 2.3% 

ISO New England, Inc. 2,1832 8.7% 2,1164 7.8% 

Midwest Independent 

Transmission System Operator 5,3002

 5.5% 8,6635 8.0% 

New York Independent System 

Operator 3,2912

 10.7% 2,4986 7.5% 

PJM Interconnection, LLC 10,4542 7.2% 13,3067 10.5% 

Southwest Power Pool, Inc. 1,3852 3.5% 1,5008 3.3% 

Total RTO/ISO 27,189 6.1% 31,702 7.0% 

Sources: 

1

California ISO 2010 Annual Report on Market Issues and Performance 

2

2010 FERC Survey 

3

ERCOT Quick Facts (June 2011) 

4

2010 Annual Markets Report, ISO New England Inc. 

5

2010 State of the Market report, Potomac Economics (Midwest ISO) 

6

2010 State of the Market report, Potomac Economics (New York ISO) 7

PJM Load Response Activity Report, July 2011, “delivery year 2011-2012 active participants” 8

Informational Status Report Concerning Incorporation of Demand Response In SPP Markets and 

Planning (September 2, 2011) 

9

Estimated based on peak demand data from the following: California ISO 2010 Annual Report on 

Market Issues and Performance, 2010 State of the Market Report for the ERCOT Wholesale Electricity 

Markets, 2010 Assessment of the Electricity Market in New England, 2010 State of the Market Report 

for the MISO Electricity Markets, New York ISO 2010 State of the Market Report, 2009 State of the 

Market Report for PJM and 2011 Quarterly State of the Market Report for PJM: January through June, 

and the Southwest Power Pool 2010 State of the Market. 

Extended hot weather and high demand led the Electric Reliability Council of Texas (ERCOT) to 

activate approximately 1,500 MW of load resources and interruptible resources during a level 2 

emergency on August 4, 2011.43 ERCOT invoked another level 2 emergency on August 24, 

2011 and deployed interruptible loads.44 

 

ERCOT also called on demand response resources in response to severe cold weather during 

February 2-3, 2011. A significant number of electric generating facilities in the U.S. Southwest 

tripped off line, failed to start, or had their available capacity de-rated during the extreme cold 

weather. On February 2, 2011, a cumulative total of 14,702 MW of generation capacity was 

 43 ERCOT, Press release, “Power Warning - Conservation Critical,” August 4, 2011, available at 

http://www.ercot.com/news/press_releases/show/418. 44 ERCOT, Press release, “Update: Emergency procedures cancelled”, August 24, 2011, available at 

http://www.ercot.com/news/press_releases/show/431. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 11

unavailable in the ERCOT region.45 The grid operator responded by dispatching demand 

response, shedding loads and appealing for voluntary energy conservation by the public.46 

On February 2 more than 1,000 MW of non-controllable load resources responded to the Texas 

emergency. About 886 MW of load resources responded within 10 minutes of ERCOT’s call. 47 

Within the next thirty minutes a scheduling entity contacted ERCOT and shed an additional 140 

MW load that was not previously committed.48 Several demand response providers reduced 

more load than was committed. 

ERCOT also deployed all of its Emergency Interruptible Load Service (EILS), during the 

February 2-3, 2011 weather event. ERCOT normally procures EILS three times during the year, 

but decided to obtain supplemental EILS capacity via a one-time April-May solicitation to 

ensure the availability of demand response resources for the remainder of the year.49

 

The North American Electric Reliability Corporation (NERC) evaluates demand response 

resources for reliability purposes. In its 2011 Summer Reliability Assessment, NERC estimated 

that 35,600 MW of demand response resources would be available during summer 2011. This 

includes both U.S. and Canadian regions, and is about 5,300 MW more than was available in 

summer 2010, according to NERC. NERC notes that “the total NERC [demand response] value 

is only a general indicator or reference for growth in Demand Response resources.”50 NERC 

does not consider time-sensitive pricing (e.g., time of use, critical peak pricing) or demand 

bidding in energy markets in its reliability assessments. 

To improve its evaluation of demand response resources, NERC developed a system for regular 

reporting of demand response to more precisely measure its contribution to reliability. NERC’s 

Demand Response Availability Data System (DADS) collects and analyzes semiannual data 

from several categories of industry participants.51 Reporting entities are required to submit 

information about their individual demand response programs, and each event where demand 

response was deployed for reliability purposes, during a specified reporting period. 

Specifically, DADS collects (1) reporting entity information, (2) demand response program 

information, (3) contact information, (4) relationship with other programs (e.g., mutually 

 45 Staffs of the Federal Energy Regulatory Commission and the North American Electric Reliability 

Corporation, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 2011, 

August 2011, p. 79 (“Southwest Event Report”), available at http://www.ferc.gov/legal/staff-reports/08-16-11-

report.pdf. 

46 Id. at 73-79. 

47 Texas Reliability Entity, Inc., Protocol and Operating Guide Compliance Report For The February 2, 

2011, Energy Emergency Alert Level 3 Event, May 13, 2011, p. 20, available at 

http://www.puc.state.tx.us/agency/topic_files/TX_RE_EEA_Protocol_Comp_Report.pdf. 48 Id.

49 ERCOT, Emergency Interruptible Load Service, Apr-May 2011 Supplemental Contract Period, available 

at http://www.ercot.com/services/programs/load/eils/. 50 NERC, 2011 Summer Reliability Assessment, May 2011, pp. 10-11. 51 Balancing Authorities, Distribution Providers, Load-Serving Entities, and Purchasing-Selling Entities 

that are Registered NERC Entities. See the NERC Reliability Functional Model for more detail 

(http://www.nerc.com/page.php?cid=2|247|108). 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 12 Federal Energy Regulatory Commission 

exclusive, jointly enrolled), (5) program enrollment data and (6) demand response program 

performance. Reporting of data by all electricity organizations operating or administrating 

dispatchable and controllable demand response programs (greater than 10 MW and in service for 

more than one year) is mandatory. DADS will not collect data about non-dispatchable demand, 

such as time-sensitive pricing. NERC’s web-based data collection system began operation on 

October 4, 2011 and is being used to collect data for the period April through September 2011. 

NERC will publish the results from DADS beginning in 2012.52 

(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. 

Order No. 1000, issued July 2011, reaffirms Order No. 890’s requirement for public utility 

transmission providers to consider all types of resources, including demand response and energy 

efficiency, on a comparable basis in transmission planning.53 Order No. 1000 requires the 

comparable consideration of transmission and non-transmission alternatives in the regional 

transmission planning process. 

Independent of the Commission’s actions, a project sponsored by the Department of Energy is 

also considering demand response as one of the resources evaluated for options to transmission 

development in the Eastern and Western Interconnections. The Eastern Interconnection plan is 

being developed under a joint effort by the Eastern Interconnection States’ Planning Council 

(EISPC) representing 39 states, the District of Columbia and eight Canadian provinces, and the 

Eastern Interconnection Planning Collaborative (EIPC), consisting of 26 regional planning 

authorities. The first phase of the planning created an interconnectionwide transmission model 

based on current regional plans. Projections of various resources, including demand response 

resources, will be developed in the second phase to determine the appropriate combination of 

resources that will be required to meet load in future years. In July 2011 EISPC (through 

NARUC) issued a request for proposals for a contractor to evaluate demand-side resources, in 

part, to support the planning effort. The contractor will evaluate current and projected demand 

response programs, including price responsive demand and energy efficiency.54 The final phase 

of the Eastern Interconnection effort will model transmission systems to serve the resource 

scenarios created in the second phase.55

The Transmission Expansion Planning Policy Committee (TEPPC, a board committee of the 

Western Electricity Coordinating Council) oversees the Western Interconnection effort. As part 

of its study, TEPPC reviewed the effects of increased use of demand response and energy 

efficiency on the transmission system. For example, the studies for the 2020 time horizon 

 52 NERC, Demand Response Data Task Force Update, June 2, 2011. 

53 Order No. 1000, 136 FERC ¶ 61,051 at P 153-154. 

54 Available at 

http://www.naruc.org/SpecialDocs/NARUC%202011%20RFP%20EISPC_DSM%207_11_11.pdf. 55 Detailed information available at http://communities.nrri.org/web/eispc. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 13

include a high demand side management case in which peak demand, growth of peak demand, 

and energy consumption are significantly lower than in the base case.56

(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

The Commission continues to assess and monitor the wholesale electric power markets under its 

jurisdiction to ensure that demand response resources that are technically capable of providing a 

service are treated comparably to supply resources. This section summarizes FERC actions 

taken in the past year for wholesale markets, and also summary descriptions of recent state and 

industry actions taken at the retail level on demand response programs. 

FERC orders on demand response issues 

Order No. 74557

Order No. 745, issued in March 2011, requires that RTOs and ISOs pay demand response 

resources participating in the day-ahead and real-time wholesale energy markets the locational 

marginal price (LMP) when two conditions are met: demand response resources must be capable 

of balancing supply and demand in the wholesale energy markets, and dispatching and paying 

LMP to demand response resources must be cost-effective as determined by a net benefits test. 

Order No. 745 requires that RTOs and ISOs submit compliance filings to accomplish these 

changes. RTOs and ISOs are required to include the following elements in their compliance 

filings: 

 A mechanism to identify a monthly price threshold to estimate where the dispatch of 

demand response resources will be cost-effective resulting in net benefits to organized 

wholesale energy market customers; 

 Tariff changes to allocate the costs of demand response payments among all customers 

who benefit from the lower LMP resulting from the demand response; 

 A review of the RTO’s or ISO’s current requirements in light of the changes in Order No. 

745 and appropriate revisions and modifications, if necessary, to ensure that their 

baselines remain accurate and that they can verify that demand response resources have 

performed. Specifically, the compliance filings must include an explanation of how RTO 

and ISO measurement and verification (M&V) protocols will continue to ensure that 

appropriate baselines are set and that demand response will continue to be adequately 

measured and verified as necessary to ensure the performance of each demand response 

resource; and 

 56 Western Electricity Coordinating Council Transmission Expansion Planning Policy Committee, Interim 

Study Report (draft) (June 2011). 57 Order No. 745, FERC Stats. & Regs. ¶ 31, 322. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 14 Federal Energy Regulatory Commission 

 A study examining the requirements for and impacts of implementing a dynamic 

approach to incorporation of the billing unit effect in the dispatch algorithm, into both the 

day-ahead and real-time energy markets. Results of the study must be filed with the 

Commission on or before September 21, 2012. 

PJM, California ISO, and Southwest Power Pool filed proposed tariff revisions in compliance 

with Order No. 745 on July 22, 2011. ISO New England, the New York ISO, and the Midwest 

ISO submitted Order No. 745 compliance filings on August 19, 2011. 

New York ISO’s SRC baseline and portfolio aggregation (Docket ER11‐2906)

The Commission conditionally accepted New York ISO’s proposed amendment to the Services 

Tariff to apply a new Special Case Resources (SCR) baseline load methodology as well as new 

performance factor calculations and performance deficiency penalties. Beginning with the 

winter 2011/2012 capability period, the New York ISO will calculate a demand response 

resource’s baseline utilizing the top 20 hours of the resource’s load that are coincident with the 

top 40 hours of New York ISO peak load during the prior equivalent capability period. 

Additionally, the tariff amendments include several changes that allow the aggregation of 

demand response resources. 

PJM Interconnection, L.L.C.’s additional product alternatives for demand response (Docket

ER11‐2288)

In January 2011, the Commission accepted PJM’s proposal to establish two additional demand 

resource products, one available throughout the year for an unlimited number of interruptions 

(Annual DR), and one available for an unlimited number of interruptions from May through 

October (Extended Summer DR), in addition to retaining its existing demand resources program. 

Both the Annual and Extended Summer DR products are available for up to ten hours per 

interruption. The addition of Annual DR and Extended Summer DR add flexibility to PJM’s 

ability to procure adequate capacity in the Reliability Pricing Model auctions and enhance PJM’s 

emergency dispatch options. The Commission directed PJM to file revised tariff provisions 

within 30 days to set the methodology for determining the reliability targets for the existing 

demand response product and the Extended Summer DR product. The Commission accepted 

PJM’s compliance filing in April 2011. 

Other FERC demand response activities 

Implementation Proposal for the National Action Plan on Demand Response

On July 5, 2011, FERC staff together with the U.S. Department of Energy (DOE) staff sent a 

comprehensive proposal to implement the National Action Plan on Demand Response 

(Implementation Plan) to Congress.58 As directed by section 529 of EISA, the Implementation 

Plan reaffirms the need for action identified in last year’s National Action Plan and identifies the 

appropriate roles and leadership required to accomplish action in three areas: technical assistance 

 58 FERC and DOE Staff, Implementation Proposal for the National Action Plan, July 5, 2011, available at 

http://www.ferc.gov/legal/staff-reports/07-11-dr-action-plan.pdf.
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 15

to states, a national communications program, and the identification or development of tools and 

materials for use by customers, states, and demand response providers. 

A key aspect of the Implementation Proposal is the reliance on non-federal organizations. The 

lead responsibility for implementing many of the activities has been left primarily to the private 

sector, ideally through a broad coalition of demand response stakeholders (such as the National 

Action Plan Coalition), or any private or non-federal governmental organizations that coordinate 

and cooperate to implement the National Action Plan. The Implementation Proposal also 

identifies areas where FERC staff and the DOE can leverage existing initiatives and public 

programs related to demand response to accomplish the actions identified in the National Action 

Plan. 

Retail demand response activities 

State governments and regulators developed, and with their utilities implemented, various 

demand response programs over the past year. These actions included passage of legislation, 

publication of state energy plans, issuance of regulatory commission decisions, and the 

deployment of demand response programs and enabling technologies by electric utilities. Some 

of the results from these activities suggest that there are still barriers to maximizing the demand 

response resource. A brief summary of recent activities in several states follows. 

Retail demand response in Texas

Retail competition is robust in Texas, with an increasing focus on developing demand response 

products. Over 86 retail providers operate in the Texas retail market, with several utilizing 

advanced metering and associated infrastructure to provide retail customers with a range of 

products and services including time of use pricing options.59 A web-based portal established by 

a consortium of transmission and distribution utilities, and managed by ERCOT, facilitates retail 

access and the development of pricing options by allowing retail electric providers and end-use 

customers to access, track and manage usage data and meter information.60 As a result, retail 

customers in Texas have the option of self-selecting and switching to time-of-use (TOU) rates, 

thereby facilitating new demand response product offerings. 

Reliant and TXU Energy are two Texas retail electric providers that offer TOU products, which 

are now supported by advanced metering.61 Initially, Reliant’s residential customers did not 

understand this TOU product and, as a result, did not subscribe to it. In particular, the customers 

were reluctant to subscribe to a TOU rate offering that had a large spread in rates between the 

on- and off-peak periods. The company has since narrowed the spread between the two time 

 59 Public Utility Commission of Texas Chairman Barry T. Smitherman, “Electrical and Telecom 

Infrastructure Investments...Made in Texas,” Texas Workforce Commission: Putting America Back to Work 2011, 

February 2, 2011, pp. 14, 16. 60 Smart Meter Texas, Frequently Asked Questions, available at 

https://www.smartmetertexas.com/CAP/public/home/home_faq.html#a2. 61 See Energy, Reliant e-Sense® Time-of-Use plan, available at 

http://www.reliant.com/PublicLinkAction.do?i_chronicle_id=090175228030fcfa&language_code=en_US&i_full_fo

rmat=jsp, and TXU Energy, TXU Energy Time-of-Use, available at 

http://www.txu.com/en/residential/promotions/dsm/TOU-savings.aspx. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 16 Federal Energy Regulatory Commission 

periods to gain new customer interest.62 The company also provides customers with a weekly 

summary of electric consumption data, including consumption to date, as well as expected usage 

forecasts. The TXU Energy demand response program is an example of a demand response 

program that does not require an advanced metering interface to provide demand response 

opportunities to the retail sector. Using a web-enabled programmable thermostat, TXU Energy 

offers a retail product that allows retail customers to manage and control home or business 

temperatures remotely over the internet or over smart phones.63

In May 2010, Texas enacted legislation to allow demand resources from all retail classes to 

participate in the wholesale energy market either directly or through aggregators of retail 

customers. In addition, the legislation directs ERCOT electric utilities to encourage and 

facilitate the involvement of retail electric providers in the delivery of efficiency programs and 

demand response programs.64 ERCOT is currently evaluating a real-time market upgrade project 

to enable demand resource participation in ERCOT’s real-time energy market and ancillary 

services market.65 Actions taken by the ERCOT ISO may further expand the use of demand 

response in Texas. According to ERCOT Chair Laura Doll, demand response resources could 

also participate in the real time energy market and all ancillary service markets in the future.66 

Other state legislative and regulatory activities related to demand response

Highlights of additional state activities undertaken with respect to demand response programs are 

provided below. States are examining how demand response programs can support resource 

adequacy, adopting various policies to support demand response programs, measuring how well 

utility programs are operating, and analyzing opportunities to expand and deploy additional 

demand response programs. 

 Connecticut. In January 2011, Connecticut enacted legislation creating the Department 

of Energy and Environmental Protection.67 Under the new legislation, the Department of 

Energy and Environmental Protection – rather than the electric companies – will prepare 

 62 Reliant Vice President of Residential Segment Marketing Bill Harmon, Roundtable #6 – Regional 

Roundup: Focus on Texas, Association for Demand Response & Smart Grid’s National Town Meeting on Demand 

Response and Smart Grid, July 13, 2011. 63 Digi International, “TXU Energy Partners with Digi and Comverge to Launch Nation's First ZigBeeEnabled Demand Response Program over Broadband Internet,” June 18, 2008, available at 

http://www.digi.com/news/pressrelease?prid=515. 64 Texas Legislature Online, SB 1125 of 2011 Regular Session, available at 

http://www.capitol.state.tx.us/BillLookup/History.aspx?LegSess=82R&Bill=SB1125 65 ERCOT, “Load Participation in ERCOT’s Security Constrained Economic Dispatch,” August 2, 2011 

Whitepaper, Demand Side Working Group (DSWG) Meeting, August 9, 2011, available at 

http://www.ercot.com/calendar/2011/08/20110809-DSWG. 66 ERCOT Chair for the Board of Directors Laura Doll, “Smart Grids, Texas Style,” Association of Women 

in Water, Energy and Environment, May 19, 2011, p. 22, available at 

http://theawip.camp7.org/Resources/Documents/Laura%20Doll.pdf. 67 Connecticut General Assembly, Senate Bill 1243 of 2011 Regular Session, An Act Concerning the 

Establishment of the Department of Energy and Environmental Protection and Planning for Connecticut’s Energy 

Future, available at 

http://www.cga.ct.gov/asp/cgabillstatus/cgabillstatus.asp?selBillType=Bill&bill_num=1243&which_year=2011&S

UBMIT1.x=0&SUBMIT1.y=0&SUBMIT1=Normal. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 17

an integrated resource plan – using a mix of demand response, energy efficiency 

programs and power generation. The comprehensive plan will incorporate the state’s 

efficiency and renewable energy programs.68

 Illinois. The Illinois Power Agency (IPA), which develops and submits annual electricity 

procurement plans to the Illinois Commerce Commission (ICC), submitted the third 

annual 2011 Power Procurement plan in September 2010. In its December 2010 

modified approval of the procurement plan, the ICC directed the IPA not to procure 

demand response or energy efficiency as an energy supply resource.69 The ICC 

concluded that the IPA is not statutorily authorized to seek energy efficiency as a 

resource. The ICC also concluded that the IPA plan did not provide a sufficient analysis 

of the cost impacts. 

 Indiana. In May 2011, Indiana established a voluntary Clean Energy Portfolio Standard, 

which includes renewables, storage technologies, and demand side management 

programs, conservation programs, and measures to shift customers' electric loads from 

periods of higher demand to periods of lower demand.70

 Maryland. Maryland Public Service Commission staff, which monitors and reports on 

utility programs, advised in March 2011 that the energy savings and demand reductions 

for 2010 were “anemic,” with utilities generally performing at approximately a third of 

their forecasts for 2010. Staff predicted that the state’s utilities would not reach the 

energy consumption and demand reduction objectives for 2011 included in the EmPower 

Maryland Act of 2008.71

 Missouri. In February 2011, the Missouri Public Service Commission (Missouri 

Commission) concluded a formal rulemaking process and issued regulations for demand 

side management.72 In March 2011, the Missouri Commission released a statewide 

demand side management market potential study assessing the electric and natural gas 

demand side management potential for the state’s residential, commercial, and industrial 

sectors. The Missouri study specifically focused on cost-effective energy saving 

opportunities available from current programs and technologies, and found that the 

residential and commercial sectors provide the largest sources of potential energy 

 68 Connecticut General Assembly, Office of Legislative References (OLR ) Bill Analysis for SB-1243, as 

amended by Senate "A", available at http://www.cga.ct.gov/2011/BA/2011SB-01243-R01-BA.htm. 69 Illinois Commerce Commission, Case No. 10-0563: Illinois Power Agency Petition for Approval of 

Procurement Plan, available at http://www.icc.illinois.gov/edocket/reports/browse/document_view.asp?id=11119&no=10-0563&did=159790. 70 Indiana General Assembly, Senate Act 251 of the 2011 Regular Session, Chapter 37. Voluntary Clean 

Energy Portfolio Standard Program, available at http://www.in.gov/legislative/bills/2011/SE/SE0251.1.html. 71 Maryland Public Service Commission Staff, Annual EmPower Maryland Overall Implementation & 

EM&V Progress Report (Corrected Version).,Case Nos. 9153, 9154, 9155, 9156, and 9157, 03/25/2011, available at 

http://webapp.psc.state.md.us/Intranet/casenum/submit_new.cfm?DirPath=C:\Casenum\9100-

9199\9154\Item_173\&CaseN=9154\Item_173. 72 Missouri Public Service Commission, Final Orders of Rulemaking, February 9, 2011, Case No. EX2010-0368: In The Matter Of The Consideration And Implementation Of Section 393.1075, The Missouri Energy 

Efficiency Investment Act, available at https://www.efis.psc.mo.gov/mpsc/Docket.asp?caseno=Ex-2010-0368. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 18 Federal Energy Regulatory Commission 

efficiency savings, while demand response programs will continue to provide a large 

source of peak demand savings.73 

 New Jersey. In June 2011, the New Jersey Energy Master Plan Committee released a 

draft 2011 Energy Master Plan that includes goals to support innovative technologies, 

energy efficiency and conservation programs.74 New Jersey expects that smart grid 

technology will be deployed throughout the state. It notes that while “the technology is 

already widely used in the industrial and commercial sectors, the extension of this 

technology to the residential level has the potential to contribute to New Jersey’s 

economic, environmental and reliability objectives.”75 Moreover, with the 

implementation of advanced metering, the Energy Master Plan expects that customers 

may take advantage of dynamic pricing.76 The draft plan notes that the goal of reducing 

peak demand will require a substantial increase in demand response programs in the state, 

and any additional demand response endeavors must be evaluated for cost effectiveness.77

Industry Retail Demand Response Actions 

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

Green Building Council established a new credit to incent demand response efforts in 

buildings.78 LEED is a third-party green building certification program that recognizes buildings 

that have undertaken projects such as energy efficiency and on-site renewable energy projects 

that provide environmental and human health benefits. The LEED rating system offers various 

certification levels (e.g., certified, silver, gold, platinum) based upon a building’s construction 

type. LEED certification levels are based upon the number of credits accrued for a project. The 

LEED demand response credit is designed to act as an incentive for new construction and 

existing buildings to participate in demand response programs. In part, LEED demand response 

credits are broken down into types and levels of automated response: manual, semi-automated, 

and fully automated options. The program credit, at present in the pilot and market feedback 

phase, is currently slated for a national roll out in 2012.79 

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

peak reduction, and critical period pricing programs

While the federal government, the Commission, and state and local governments continue to 

work on removing regulatory barriers to customer participation in demand response programs, 

several of the regulatory barriers identified in past annual assessments and in the 2009 National 

 73 Missouri Public Service Commission, Missouri Statewide DSM Market Potential Study: Final Report, 

prepared by KEMA, Inc. March 4, 2011, rev 4/14/2011, available at http://psc.mo.gov/electric/missouri-dsmpotential-study. 74 New Jersey Draft Energy Master Plan, June 2011. 

75 Id. at 121. 

76 Id. at 23. 

77 Id. at 105. 

78 LEEDuser, “Pilot Credit 8: Demand Response,” available at http://www.leeduser.com/credit/PilotCredits/PC8. 79 Peter Weigand et al., “LEED Credits for Demand Response Participation,” Peak Load Management 

Alliance Spring Conference, Las Vegas, NV, April 12, 2011, available at 

http://www.skippingstone.com/PLMA%20pres.pdf. 
Assessment of Demand Response and Advanced Metering November 2011 

Federal Energy Regulatory Commission Page 19

Assessment of Demand Response Potential still remain.80 Key outstanding barriers along with 

efforts to resolve the barriers include: 

 Barriers to Third-Party Demand Response. The use of third-party demand response 

providers in both wholesale and retail markets continues to grow. As a percentage of 

total demand response potential, wholesale demand response grew from 35 percent in 

2008 to 39 percent in 2010. Similarly, states and local jurisdictions increasingly have 

turned to third-party demand response providers to provide capacity resources and meet 

resource adequacy requirements.81 Nevertheless, barriers remain for third-party demand 

response providers to aggregate customer demand response and bid demand response into 

wholesale RTO organized energy, ancillary services and capacity markets. Due to 

concerns about reliability, disruption of successful utility demand response programs, 

cost-shifting, inefficient dispatch, and duplication of administrative costs, a number of 

states and local jurisdictions have either prohibited third-party aggregation of customer 

demand response into organized RTO or ISO wholesale markets or have ongoing 

proceedings examining third-party aggregation.82 

 Cost Recovery. Recovery of the costs of demand response technologies and programs 

and the payments made to demand response providers continues to be an issue. 

Significant progress has been made at the state level to develop policies for the recovery 

of smart grid and demand response technologies, but there are issues such as advanced 

meter opt-out (i.e., California and Maine) and recovery of cost-overruns.83 The issuance 

of Order No. 745 in the past year provides clarity on the Commission’s policies on the 

allocation and recovery of demand response payments in organized RTO and ISO energy 

and ancillary services markets. 

 Measurement and Cost-Effectiveness of Reductions. As identified in past annual reports, 

barriers associated with the measurement and cost-effectiveness of demand reductions 

remain. Nevertheless, efforts to standardize measurement and verification of wholesale 

demand response are underway. After months of discussions and review, the North 

American Energy Standards Board’s (NAESB) Wholesale Demand Response Work 

Group developed a set of changes to the Phase I wholesale demand response M&V 

standards. These changes were approved by NAESB membership on March 21, 2011, 

and subsequently filed with the Commission.84 In addition, two exhaustive analyses of 

methods to estimate customer baselines prepared by KEMA for PJM and ISO New 

 80 FERC, A National Assessment of Demand Response Potential, June 2009, available at 

http://www.ferc.gov/legal/staff-reports/06-09-demand-response.pdf (National Assessment). 81 For example, see EnerNOC, “FirstEnergy Pennsylvania Selects EnerNOC Demand Response to Reduce 

Peak Energy Use” (September 27, 2011) available at http://www.enernoc.com/press/. 82 For example, see proceedings in Indiana, Iowa, Michigan, Minnesota, Missouri, North Dakota, South 

Dakota, and Wisconsin. 83 For example, in response to cost overruns experienced by Xcel Energy’s SmartGrid City (SGC) project 

in Boulder, Colorado, the Colorado Public Utility Commission capped recovery of the overruns “until the Company 

demonstrates to our satisfaction that it has completed the unfinished aspects of the SGC project.” See decision at 

https://www.dora.state.co.us/pls/efi/efi_p2_v2_demo.show_document?p_dms_document_id=97559&p_session_id=. 84 NAESB, available at http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=12653735. 
November 2011 Assessment of Demand Response and Advanced Metering 

Page 20 Federal Energy Regulatory Commission 

England identified best practices for baseline calculations.85 As discussed earlier, states 

continue to work on cost-effectiveness as part of their ongoing proceedings, task forces, 

and metrics development. Nevertheless, as the Implementation Proposal for the National 

Action Plan on Demand Response (discussed above) identified, additional work on tools 

to assist in the measurement and determination of cost-effectiveness is needed. 

 Better coordination of Federal-State policies. Work on developing better coordination of 

federal and state regulation of demand response continues, with specific actions being 

taken at the state level to align state retail demand response programs and policies with 

RTO and ISO wholesale markets.86 

 Limited number of customers on time-based rates. While time-based rates are not 

necessary for the continued development of additional demand response resources, 

greater deployment of time-based rates would support the development of new 

technologies and programs. For example, the 188 GW demand response potential 

identified in the Full Participation scenario in the 2009 National Assessment relates to the 

full deployment of time-based rates and enabling technologies.87 Nevertheless, the 

deployment of these rates at the state and local level has been slow. As described above, 

the introduction of new pricing products in Texas and the implementation of the pricing 

experiments funded by the Recovery Act88 should provide information and experience to 

support further deployment of time-based rates. 

 85 KEMA, Analysis and Assessment of Baseline Accuracy, prepared for ISO-NE, August 4, 2011, and 

KEMA, PJM Empirical Analysis of Demand Response Baseline Methods, prepared for the PJM Markets 

Implementation Committee, April 20, 2011. 86 For example, the Indiana Utility Regulatory Commission (IURC) directed its utilities to file tariff 

changes to authorize the participation of their retail customers in Midwest ISO demand response offerings through 

the utility. See, for example, the IURC order on Duke Energy Indiana’s programs at 

https://myweb.in.gov/IURC/eds/Modules/Ecms/Cases/Docketed_Cases/ViewDocument.aspx?DocID=0900b631801

533f3. 87 National Assessment, p. 27. 88 For more information on these customer behavior studies, see 

http://www.smartgrid.gov/recovery_act/program_impacts/consumer_behavior_studies.