2007 

Assessment of 

Demand Response and Advanced Metering 

Staff Report 

Federal Energy Regulatory Commission 

September 2007 

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 Commission Staff Team 

David Kathan, Team Lead 

George Godding 

Ryan Irwin 

Carey Martinez 

Norma McOmber 

Aileen Roder 

Kenneth Thomas 

Carol Brotman White 

This report can be downloaded from 

http://www.ferc.gov/industries/electric/indus-act/demand-response.asp
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Executive Summary 

The level of and interest in electric demand response and advanced metering increased significantly 

beyond the activities discussed in the first report by the staff of the Federal Energy Regulatory 

Commission. The Commission staff’s first report, Assessment of Demand Response and Advanced 

Metering, August 2006,1

 presented the results of a comprehensive nationwide survey of these 

activities. This year’s report provides an informational update on developments and reflects on 

activity since issuance of the 2006 report. 

The Commission staff intends to publish another comprehensive report on demand response and 

advanced metering in 2008 and every even year thereafter, with informational update reports in the 

intervening years. 

Demand Response 

An electric demand-response activity is an action taken to reduce electricity demand in response to 

price, monetary incentives, or utility directives so as to maintain reliable electric service or avoid high 

electricity prices. Demand reduction activities occur principally during the summer when electricity 

demand is highest in most regions, and demand reductions from these demand-response activities 

proved crucial to the reliable operation of electric markets during the record-setting peaks that 

occurred in July and August of 2006. Estimates of demand reductions in Regional Transmission 

Organization (RTO) and Independent System Operator (ISO) regions with organized wholesale 

markets lowered system peaks between 1.4 and 4.1 percent on these peak days. These demand 

reductions resulted from a combination of RTO/ISO demand-response programs, utility retail demand 

response, and voluntary customer demand reductions. 

Several states and individual utilities took actions to introduce more opportunities for demand 

response and price-responsiveness. These actions include the adoption of time-based rates and the 

adoption of demand-response policies (which includes deployment of enabling technologies such as 

advanced metering). States such as California, Connecticut, Illinois, Maryland, and Michigan have 

encouraged more demand response and customer access to information about their energy 

consumption. Utilities like Pepco and Wisconsin Public Service introduced or revised demandresponse programs. 

Two important new developments since the 2006 report at the wholesale level are the inclusion of 

demand resources in forward capacity markets and ancillary services markets at RTOs and ISOs and 

the development of new reliability-based demand-response programs. 

The Commission in the past year has actively encouraged the use of demand response in several ways. 

It has encouraged organized wholesale power markets to use demand response as they would use 

generation where it is technically capable. Over the last year, it addressed demand response in a 

number of orders addressing wholesale market design proposals filed by the various RTOs and ISOs. 

The Commission revised its Open Access Transmission Tariff regulations in Order No. 890 to require 

transmission service providers to incorporate demand response into their transmission planning 

 1

 The Energy Policy Act of 2005 (EPAct 2005) section 1252(e)(3) requires the Federal Energy Regulatory 

Commission (Commission) to prepare and publish an annual report that assesses electric demand-response resources and 

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

1252(e)(3)). The first report is available on line at http://www.ferc.gov/legal/staff-reports/demand-response.pdf. 
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processes and to require them to allow demand resources to provide certain ancillary services, where 

appropriate, on a comparable basis to generation resources. It also directed that NERC’s mandatory 

reliability standards, addressed in Order No. 693, be revised to incorporate demand response. A 

recently issued Advance Notice of Proposed Rulemaking by the Commission proposed several 

measures to enhance competition in organized wholesale markets, including demand-response 

enhancements. 

In addition to its direct regulatory actions, the Commission has encouraged demand response through 

public conferences and collaborative efforts with its state regulatory colleagues. Among other 

activities, the Commission held a technical conference on April 23, 2007 to examine problems and 

possible solutions for increased use of demand response in wholesale markets. In November of 2006, 

the Commission and the National Association of Regulatory Utility Commissioners began a demandresponse collaborative effort, co-chaired by Commissioner Jon Wellinghoff, to coordinate the efforts 

of the state and federal electric regulators to integrate demand response into retail and wholesale 

markets and planning. 

Based on this review of various demand-response activities in the last year, Commission staff has 

identified the following demand-response trends: 

• Increased participation in demand-response programs 

• Increased ability of demand resources to participate in RTO/ISO markets 

• More attention to the development of a smart grid that can facilitate demand response 

• More interest in multistate and state-federal demand-response working groups 

• More reliance on demand response in strategic plans and state plans 

• Increased activity by third parties to aggregate retail demand response. 

Advanced Metering 

A number of utilities are planning an installation of advanced metering in the next several years; and 

indications from state regulatory proceedings suggest that the interest in advanced metering will 

continue. Although not all announced plans will necessarily go into effect, in the last year utilities 

announced new deployments of more than 40 million advanced meters between 2007 and 2010. 

Advanced metering refers to technologies and communications systems necessary to record customer 

consumption at least hourly and allow for daily or more frequent retrieval of the consumption data. 

Advanced metering can enhance an electric customer’s ability to reduce demand in response to a 

higher price and an electric utility’s ability to meter and monitor the customer’s electricity use. Such 

metering can also allow an electric utility to provide a variety of innovative services to benefit 

customers and to reduce the utility’s costs of operations. 
Table of Contents 

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Table of Contents 

Executive Summary _________________________________________________________ i

Demand Response _______________________________________________________________i

Advanced Metering _____________________________________________________________ ii

Table of Contents __________________________________________________________iii

I. Introduction ____________________________________________________________ 1

II. Demand Response _______________________________________________________ 3

Definition of Demand Response ___________________________________________________ 3

Demand Response Developments__________________________________________________ 3

Levels of Demand Response in Wholesale Markets ___________________________________________4

Developments in Retail Markets _________________________________________________________13

Trends and Observations _______________________________________________________ 16

III. Advanced Metering ____________________________________________________ 23

Definition and Background______________________________________________________ 23

AMI Functions _______________________________________________________________________25

Developments in Advanced Metering _____________________________________________ 27

Recent AMI Initiatives by States and Utilities_______________________________________________27

Issues and Challenges __________________________________________________________ 34

Technological Obsolescence Concerns ____________________________________________________34

Deployment Decisions _________________________________________________________________34

Interoperability and Open Standards ______________________________________________________34

Appendices 

Appendix A: 

Glossary for the Report 

Appendix B: 

Documentation of 2006 Demand Response Estimates 

Appendix C: 

North American Electric Reliability Corporation Estimates of Demand Response 

Availability 

Appendix D: 

Overview of Demand Response in RTO and ISO Markets 

Appendix D: 

EPAct 1252 AMI Proceedings Update 

Appendix F: 

Utility AMI Implementation Projection 
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I. Introduction 

The Energy Policy Act of 2005 (EPAct 2005) section 1252(e)(3)2

 requires the Federal Energy 

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

appropriate region, that assesses electric demand-response resources, including those available from 

all consumer classes.3

 The Commission published its first report, Assessment of Demand Response 

and Advanced Metering (“2006 FERC Demand Response Assessment”), in August 2006.4

 The 2006 

report was comprehensive and reported on first-of-their-kind surveys of demand response and 

advanced metering. 

This year’s report provides information on demand response and advanced metering, with an emphasis 

on results, activities, and regulatory actions taken over the last year. Information was compiled from 

readily accessible data and reports, Regional Transmission Organization (RTO) and Independent 

System Operator (ISO) annual reports, and discussions with market participants and industry experts. 

For this year, and every odd numbered year thereafter, Commission staff will publish an informational 

report on demand response and advanced metering that largely utilizes publicly available information. 

Next year’s report will feature the results of another comprehensive nation-wide survey on demand 

response and advanced metering. (Commission staff will conduct a comprehensive survey every other 

year thereafter.) Staggering the reporting in this way will allow FERC staff to provide a more 

informed analysis in each bi-yearly report while still reporting on the advances in demand response on 

an annual basis. In keeping with this publishing plan, the 2008 report will include the results of the 

next comprehensive surveys of national demand response and advanced metering. 

This informational report has two substantive chapters. Chapter II includes a review of the estimated 

2006 demand response in RTO and ISO markets and programs, developments in the use of demand 

response at the state and federal levels, a discussion of the issues associated with the level of demand 

response achieved, trends in the use of demand response, a summary of activity on demand response 

in the retail and wholesale sectors that occurred in the past year, and a discussion of barriers to 

increased demand response. This chapter also contains a summary of Commission demand-response 

activities. 

Chapter III discusses developments associated with advanced metering in the past year. In particular, 

it includes a summary of state activity in response to EPAct 2005 requirements for states to hold 

proceedings on advanced metering, a discussion of recent changes in the definition and functionality 

 2

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

1252(e)(3)). 

3

 EPAct 2005 directs the Commission to identify and review: 

(A) saturation and penetration rates of advanced meters and communications 

technologies, devices and systems; 

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

(C) the annual resource contribution of demand resources; 

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

regional planning purposes; 

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

provided equitable treatment as a quantifiable, reliable resource relative to the resource obligations of any 

load-serving entity, transmission provider, or transmitting party; and 

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

critical period pricing programs. 4

 FERC, Assessment of Demand Response & Advanced Metering: Staff Report, Docket No. AD06-2, August 7, 

2006, available at: http://www.ferc.gov/industries/electric/indus-act/demand-response.asp. 
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associated with advanced metering, a review of state and utility advanced metering initiatives and 

meter installations, and a discussion of issues associated with advanced metering. 

This informational report has six appendices. Appendix A is a glossary of terms used in the report. 

Appendix B contains documentation that supports the estimates of RTO and ISO demand response 

during summer 2006. Appendix C is a summary of NERC’s estimate of achievable and reliable 

demand response from interruptible demand and direct load control in 2006 and 2007. Appendix D 

provides a summary of demand-response participation in RTO/ISO markets. Appendix E includes a 

status report on state proceedings in response to EPAct 2005 section 1252(b) requirements. Appendix 

F lists major utility advanced metering implementation projects. 
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II. Demand Response 

This chapter reviews developments associated with demand response that have occurred since the 

issuance of the 2006 report. It provides a brief contextual definition and review of demand response and 

covers the following topics: 

• Demand Response Developments at the Wholesale and Retail Level 

• Observations about Demand Response Activity 

Definition of Demand Response 

In the 2006 FERC Demand Response Assessment, Commission staff noted that demand response refers to 

actions by customers that change their consumption (demand) of electric power in response to price 

signals, incentives, or directions from grid operators, and adopted the definition of “demand response” 

that was used by the U.S. Department of Energy (DOE) in its February 2006 report to Congress: 

Changes in electric usage by end-use customers from their normal consumption patterns in 

response to changes in the price of electricity over time, or to incentive payments designed to 

induce lower electricity use at times of high wholesale market prices or when system reliability is 

jeopardized.5

As such, the 2006 FERC Demand Response Assessment did not include energy efficiency in the 

definition of demand response; it relied on the idea that the changes in electricity use are designed to be 

short-term in nature, centered on critical hours during a day or year when demand is high or when reserve 

margins are low. In the intervening year, national and state legislative and regulatory bodies, as well as 

utility programs and tariff filings, have increasingly relied upon energy efficiency as a tool to reduce 

system peak demand and meet capacity requirements. In addition, at least one RTO, ISO New England 

(ISO-NE), has adopted (and the Commission has approved) market rules that allow energy efficiency to 

be bid into forward capacity auctions.6

 Consequently, while this section focuses on demand response, it 

occasionally discusses energy efficiency where appropriate. In addition, this report uses the phrase 

“demand resources” to refer to the set of demand-response and energy efficiency resources and programs 

that can be used to reduce demand or reduce electricity demand growth. 

Demand Response Developments 

Demand response plays an increasingly important role in energy markets. As discussed below, demand 

response played a key role in RTO/ISO energy markets in 2006. In addition, and as discussed later, the 

states and FERC advanced the role of demand response on several fronts. 

 5

 U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Recommendations for 

Achieving Them: A Report to the United States Congress Pursuant to Section 1252 of the Energy Policy Act of 2005, February 

2006, 6. 

6 ISO New England, Order Conditionally Accepting Market Rules and Requiring Compliance Filing, 119 FERC ¶ 

61,045 (2007). 
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Levels of Demand Response in Wholesale Markets 

During the summer of 2006, the use of demand response proved necessary to the reliable operation of 

electric markets during peak hours. Summer peak demand in 2006 broke load records across the country 

due to sustained and severe heat events. Demand reductions during the heat wave came from actions by 

and programs of a combination of RTOs and ISOs, utilities and load serving entities (hereinafter, referred 

to generally as “utilities”), and non-utility demand-response service providers. Many utilities, in and out 

of RTOs and ISOs, invoked emergency demand-response programs, interruptible programs, and direct 

load control to manage their portfolios and maintain local or balancing area reliability. RTOs and ISOs 

activated reliability-based demand-response programs7

 and appealed for load reductions to reduce the 

system peak and to maintain system reliability. Participants in RTO and ISO demand bidding programs8

curtailed load in response to high wholesale prices during the heat events. 

NERC, in its 2007 Summer Assessment, concluded that NERC-wide application of demand-response 

programs increased to about 21,900 MW from the 2006 Summer Assessment estimate of about 20,700 

MW.9

 Using the 2006 peak demand of about 851 GW, this suggests that about three percent of NERCwide peak demand can be reduced from interruptible demand and direct load control. The level of 

interruptible demand in 2007 was about the same as in 2006; the increase came from direct load control in 

2007. The Western Electricity Coordinating Council region shows an increase in interruptible demand of 

approximately one-half percent and the Florida Reliability Coordinating Council region shows a similar 

increase in direct load control.10 

Focusing on RTO and ISO markets, which generally provide readily available information on demand 

response, demand-response reductions were between 1.4 and 4.1 percent of system peaks on recordbreaking peak days. Figure II-1 summarizes demand-response levels on peak days in each RTO and ISO, 

and also displays estimates of the level of customer enrollment11 in demand-response programs for each 

RTO and ISO for 2007. While the percent of total load was small, even small load reductions at system 

peak can have a large impact on reducing stress on electric delivery systems when operating reserves are 

in near-shortage conditions.12 

 7

 “Reliability-based” demand-response programs refer to programs that are activated during system emergencies or to 

maintain local or system reliability. Reliability-based demand-response programs typically include emergency demand-response 

programs, capacity market programs, direct load control, interruptible/curtailable rates, and ancillary-services market programs. 

See the 2006 FERC Demand Response Assessment for additional information on these programs. 

8

 “Demand bidding” programs encourage large customers to offer to provide load reductions at a price at which they 

are willing to be curtailed, or to identify how much load they would be willing to curtail at posted prices. These programs are 

sometimes referred to as “economic” programs. 

9

 NERC, 2007 Summer Assessment: The Reliability of the Bulk Power Systems in North America, June 2007, 8. 

10 See Appendix C for NERC’s estimate of achievable and reliable demand response from interruptible demand and 

direct load control in 2006 and 2007 as a percentage of total regional internal demand (total internal demand is defined by NERC 

as total regional peak demand). 

11 “Enrollment” is used in this report to refer to the amount of customer participation in a demand-response program. 

Participation refers to either the number of customers or the amount of MW registered for a program and meeting eligibility 

criteria. Customer participation in a program does not necessarily mean that the customer will actively adjust its consumption in 

response to grid operator direction or price signals. Consequently, enrollment typically measures potential demand reduction that 

could be achieved. 

12 Commission staff reviewed the levels of demand response achieved during the 2006 summer heat waves. 

Commission staff conducted numerous interviews with RTO and ISO representatives and other market participants, consulted 

RTO and ISO post-summer written evaluations and updated the data in these evaluations using recently published RTO and ISO 

“State of the Market Reports,” and periodic demand-response reports. Appendix B documents the information provided in 

Figure II-1, including sources, definitions, and calculations, where appropriate. 
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2006: Peak Day Demand Response: Known load response megawatts (MW) and as Percent of Peak Load2007: Estimate of Enrolled MW & % breakdown by program

ISO-NE2006: 597 MW: 2.1 % of peak2007: 1,037 MW: 

91% reliability

9% economic

NYISO2006: 948 MW: 2.8 % of peak2007: 2,199 MW: 

82% reliability18% economic 

CAISO2006: ~ 2,066 MW: 4.1 % of peak2007: 2,789 MW: 

58% IOU interruptibles38% IOU price-based

3% ISO reliability (PLP)1% ISO voluntary (VLRP)

PJM2006: 2,050 MW: 1.4 % of peak2007: 3,733 MW: 

50% reliability50% economic 

Midwest ISO2006: 2,651 MW: 2.3 % of peak2007: 4,099 MW: 

62% interruptibles38% direct load control 

ERCOT2006: Demand response not called on

peak day 

2007: 1,125 MW

SPP2006: 70 MW known; 

negligible % of peak

2007: not available

Figure II-1. Summer 2006 demand response contributions and summer 2007 program enrollments

Notes: Estimates and calculations of demand response in summer 2006 include conservation, interruptible resources, and price-based responses.Midwest ISO 2006 data is based on August 1, its 2nd peak day, when it called on and measured demand response.

Source: See Appendix B for details; includes data from RTOs/ISOs, NERC, FERC staff analysis of data.

2006: Peak Day Demand Response: Known load response megawatts (MW) and as Percent of Peak Load2007: Estimate of Enrolled MW & % breakdown by program

ISO-NE2006: 597 MW: 2.1 % of peak2007: 1,037 MW: 

91% reliability

9% economic

NYISO2006: 948 MW: 2.8 % of peak2007: 2,199 MW: 

82% reliability18% economic 

CAISO2006: ~ 2,066 MW: 4.1 % of peak2007: 2,789 MW: 

58% IOU interruptibles38% IOU price-based

3% ISO reliability (PLP)1% ISO voluntary (VLRP)

PJM2006: 2,050 MW: 1.4 % of peak2007: 3,733 MW: 

50% reliability50% economic 

Midwest ISO2006: 2,651 MW: 2.3 % of peak2007: 4,099 MW: 

62% interruptibles38% direct load control 

ERCOT2006: Demand response not called on

peak day 

2007: 1,125 MW

SPP2006: 70 MW known; 

negligible % of peak

2007: not available

Figure II-1. Summer 2006 demand response contributions and summer 2007 program enrollments

2006: Peak Day Demand Response: Known load response megawatts (MW) and as Percent of Peak Load2007: Estimate of Enrolled MW & % breakdown by program

ISO-NE2006: 597 MW: 2.1 % of peak2007: 1,037 MW: 

91% reliability

9% economic

NYISO2006: 948 MW: 2.8 % of peak2007: 2,199 MW: 

82% reliability18% economic 

CAISO2006: ~ 2,066 MW: 4.1 % of peak2007: 2,789 MW: 

58% IOU interruptibles38% IOU price-based

3% ISO reliability (PLP)1% ISO voluntary (VLRP)

PJM2006: 2,050 MW: 1.4 % of peak2007: 3,733 MW: 

50% reliability50% economic 

Midwest ISO2006: 2,651 MW: 2.3 % of peak2007: 4,099 MW: 

62% interruptibles38% direct load control 

ERCOT2006: Demand response not called on

peak day 

2007: 1,125 MW

SPP2006: 70 MW known; 

negligible % of peak

2007: not available

2006: Peak Day Demand Response: Known load response megawatts (MW) and as Percent of Peak Load2007: Estimate of Enrolled MW & % breakdown by program

ISO-NE2006: 597 MW: 2.1 % of peak2007: 1,037 MW: 

91% reliability

9% economic

NYISO2006: 948 MW: 2.8 % of peak2007: 2,199 MW: 

82% reliability18% economic 

CAISO2006: ~ 2,066 MW: 4.1 % of peak2007: 2,789 MW: 

58% IOU interruptibles38% IOU price-based

3% ISO reliability (PLP)1% ISO voluntary (VLRP)

PJM2006: 2,050 MW: 1.4 % of peak2007: 3,733 MW: 

50% reliability50% economic 

Midwest ISO2006: 2,651 MW: 2.3 % of peak2007: 4,099 MW: 

62% interruptibles38% direct load control 

ERCOT2006: Demand response not called on

peak day 

2007: 1,125 MW

SPP2006: 70 MW known; 

negligible % of peak

2007: not available

Figure II-1. Summer 2006 demand response contributions and summer 2007 program enrollments

Notes: Estimates and calculations of demand response in summer 2006 include conservation, interruptible resources, and price-based responses.Midwest ISO 2006 data is based on August 1, its 2nd peak day, when it called on and measured demand response.

Source: See Appendix B for details; includes data from RTOs/ISOs, NERC, FERC staff analysis of data.
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In addition to emergency procedures invoked by RTOs and ISOs, there were calls for voluntary 

conservation in many areas, to which customers responded by reducing their electricity use, often 

without being compensated. We note that quantifying voluntary conservation is difficult with current 

measurement techniques. Thus, total reductions may have been greater than 1.4 to 4.1 percent of 

system peaks on record-breaking days. 

Focusing more narrowly, demand response in certain load pockets, such as southwest Connecticut and 

New York City-Long Island, was even higher, at six percent and four percent of regional peak load on 

record-breaking days, respectively.13 The significance of the need to target response in areas with the 

highest need led the New York ISO (NYISO) to file a proposed rule change with the Commission to 

enhance its dispatch of reliability-based demand response when the system is stressed. Effective July 

1, 2007, the NYISO can activate its Emergency Demand Response Program (EDRP) and Special Case 

Resources (SCR) in one or more of eight sub-load pockets in New York City to reduce load either 

when reserve shortfalls are anticipated, or when low voltage conditions exist or are anticipated.14 

These programs were activated on July 19, 2007 to reduce use of damaged cables in midtown 

Manhattan due to a steam pipe explosion.15

In addition to supporting reliability, operation of demand response can facilitate inter-system sales. 

For example, operation of NYISO’s demand-response programs on August 2, 2006 allowed the ISO to 

support the reliability and market needs of its neighboring RTOs. On its peak day, not only did 

demand response support the reliable operation of the NYISO, the demand-response programs also 

allowed for the export of 1,300 MW of emergency energy to New England during the afternoon.16 

The NYISO also operated demand-response programs in three western New York zones to provide 

voltage support for scheduled sales to PJM. These inter-system sales would likely not have been 

possible without demand response.17

According to various RTOs and ISOs that reported on summer 2006 market prices, the 2006 demandresponse reductions reduced wholesale electricity prices. Reductions in wholesale prices varied 

regionally. PJM reported that demand response achieved on August 2, its record peak day, “reduced 

wholesale energy prices by more than $300 per megawatt-hour (MWh) during the highest usage 

hours.” It estimated that the reductions in use resulted in system-wide savings in energy payments of 

$230 million during the peak hours that day, and more than $650 million in energy payments for the 

week.18 ISO-NE analyzed the effect of demand reductions on locational marginal prices (LMPs) for 

the months of April to September, during the hours with interruptions when demand response was 

called. It estimated a $1.74/MWh average decrease in LMPs for those months.19 The Midwest ISO 

 13 Southwest Connecticut curtailments: phone conferences and emails between FERC staff and H. Yoshimura, 

ISO-NE; SWCT peak load from Connecticut Valley Electric Exchange, www.cvx.com. Peak load data for New York City 

(Zone J)-Long Island (Zone K) from NYISO: http://www.nyiso.com/public/market_data/load_data.jsp, link for “Integrated 

Real-Time Actual Load.” Peak curtailment calculated by FERC staff using data in NYISO 2006 Demand Response Programs, 

submitted to the Commission, January 16, 2007. 

14 NYISO, Docket No. ER07-862-000 (July 3, 2007). 

15 Personal communication with NYISO staff, July 19, 2007. 

16 Mark Lynch (NYISO) described the ISO’s reliability-based program participants: “one-half of these customers, 

representing one-third of the total megawatt load reduction potential, are located in New York City.” FERC Technical 

Conference on Demand Response in Wholesale Markets, April 23, 2007 (hereinafter, “FERC Wholesale Demand Response 

Technical Conference”), transcript, 23. 

17 Monthly conference call between Commission staff and NYISO staff, September 13, 2006.

18 PJM Interconnection, LLC, press release, August 17, 2006. 

19 ISO-New England, “2006 Annual Markets Report,” June 11, 2007, 11. 
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found that there was a decline of $100-$200/MWh in market clearing prices on August 1 when 2,650 

MW responded to its call for demand reductions in response to a Maximum Generation Warning.20

While demand reduction resources can benefit both the reliable operation and the economically 

efficient operation of the power system, recent analysis by the Lawrence Berkeley National 

Laboratory (LBNL) on the role of demand response in the summer of 2006 suggests that there were 

differences in response rates21 between reliability-based programs and “economic” programs such as 

demand bidding programs.22 Reliability-based programs, which carry penalties for not responding 

when called, had high participation rates: the response rate in the California utility interruptible rates 

programs and the California Power Authority’s Demand Reserves Partnership was 83 percent; the 

response rate in NYISO’s capacity market program, ICAP/Special Case Resources, was 62 percent.23 

Demand bidding programs had lower response rates: maximum load reduction achieved in the 

Demand Bidding Programs offered by California utilities was 19 percent of enrolled resources; in the 

PJM Day-Ahead Load Response Program, maximum load reduction was four percent of enrolled 

resources.24

The LBNL analysis also highlighted the differences in system operator confidence between these two 

types – that dispatchable or reliability-based programs play a system reliability role, whereas 

economic programs play a market efficiency role. According to the study: 

However, a number of utility representatives indicated that they did not yet regard 

economic DR programs [such as demand bidding] or dynamic pricing [such as realtime pricing or critical peak pricing] as “firm” resources based on their experience to 

date. In interviews, some described these options as fulfilling a different role than 

reliability programs: improving the overall efficiency of electricity markets, rather 

than providing a specific demand-response resource. Others were simply more 

comfortable with their ability to count on reliability options – particularly for more 

traditional programs such as [interruptible or curtailable] rates and DLC programs – to 

provide load reductions that could compete with (and supplant) supply-side peaking 

resources.25

While LBNL found these results, Midwest ISO and ERCOT nonetheless have taken action to improve 

the ability to utilize reliability-based demand response during system emergencies and reserve 

shortages. These improvements were based on their experiences with demand response during the 

spring and summer 2006 heat waves. 

 20 “Independent Market Monitor Review: 2006 Peak Load Event,” presentation by David B. Patton to the Midwest 

ISO Board of Directors’ Markets Committee, September 20, 2006, 16. In his review, Patton noted that wholesale prices on 

July 31, when demand response was not called, ranged from $200 to $350 per megawatt-hour (MWh). On August 1, 

however, when emergency conditions were declared and demand response was activated, “prices generally ranged from $50 

to $150 per MWh and were less than $100 in the highest demand hour.” By inference, there was a price difference of at least 

$100-$200/MWh on August 1. 

21 I.e., percent of the potential demand reductions that could be achieved from demand-response programs, based 

on customer enrollment in the programs, that were actually achieved. 

22 E.g., NYISO’s Day-Ahead Demand Response Program. 

23 Nicole Hopper, Charles Goldman, Ranjit Bharvirkar and Dan Engel, “The Summer of 2006: A Milestone in the 

Ongoing Maturation of Demand Response,” The Electricity Journal (June 2007), 67. 

24 Hopper, et al., 68. 

25 Hopper, et al., 69. 
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After its summer 2006 experience with demand response, the Midwest ISO sent a survey to its 

balancing authorities to assess the amount, geographic diversity, and type of demand response in its 

market footprint. Midwest ISO subsequently changed its Emergency Event Rules to align them with 

NERC Emergency steps for conservation, interruptible resources, and customer-sited generation. 

Midwest ISO created three regional zones – West, Central, and East – to allow it to target response 

reductions geographically. It also created two levels of interruptions beyond conservation, 50% and 

100%, to be called by balancing authorities. The procedures were “tested” during a February 2007 

cold spell, and were being refined prior to summer 2007, based on that experience.26

 

Following the rolling blackouts on April 17, 2006, ERCOT petitioned the Texas Public Utilities 

Commission (PUC) for expedited review of a proposed emergency service, meant to bridge its calling 

on its “Load Acting as a Resource” program (LaaRs) and involuntary load shedding. In April, the 

Texas PUC approved the Emergency Interruptible Load Service (EILS) as an interim option. Texas 

has so far issued two RFPs for emergency resources under EILS, with a 500 MW minimum 

subscription level. The second RFP received more response than the first, but less than half the 

minimum. It plans a third RFP. Third party aggregators may participate in the RFP, but there may be 

insufficient value for these aggregators to participate.27 Providers in this plan are not paid regular 

capacity payments, as has proven attractive in other ISOs, but are paid for performance only. ERCOT 

envisions needing this program only rarely. 

Commission Demand Response Actions in the Last Year 

The Commission continues to assess demand response as it relates to ensuring wholesale competitive 

markets and reliable grid operations. The Commission’s actions were both reactive and proactive. 

The Commission positively responded to RTO and ISO applications concerning demand-response 

programs; some of the same programs that were relied upon by RTOs and ISOs in meeting the peak 

needs in 2006. It also took up the issue of demand response generically when it addressed the role of 

demand response in several rulemakings, including in transmission planning, provision of ancillary 

services, and reliability standards. Outreach activities continued, with the Commission holding two 

technical conferences on demand-response issues and continuing the state-federal collaborative. 

Key Demand Response Commission Orders (August 2006 to July 2007) 

• California ISO MRTU Order - The Commission’s order allows loads with demand-response 

capability to participate in the California ISO (CAISO) day-ahead, real-time, and ancillary 

services markets under comparable requirements as supply, and receive the equivalent market 

value.28

• Midwest ISO Resource Adequacy - The Commission required Midwest ISO to explain any 

pre-conditions for its Energy Only Market implementation, such as demand-response 

programs and longer term energy contracts. The Commission further directed Midwest ISO to 

describe how load-serving entities (LSEs) can react to wholesale prices when managing their 

load in the aggregate, or when and how retail demand response behind an LSE can participate 

directly in the wholesale market.29

 26 Midwest ISO, “Emergency Procedures Workshop,” March 12, 2007 and Conference call between Midwest ISO 

and Commission staff, March 28, 2007. 

27 Phone interview with Dan Jones, ERCOT IMM, June 5, 2007. 

28 Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274, at P 10 (2006) (CAISO MRTU Order), order on reh’g, 

119 FERC ¶ 61,076 (2007). 

29 Midwest Indep. Transmission Sys. Operator Corp., 116 FERC ¶61,292, at P 1, 55 (2006). 
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• Southwest Power Pool Rehearing - The Commission directed the Southwest Power Pool 

(SPP) to make tariff modifications to put in place a $1,000/MWh bid cap until such time that 

there are sufficient demand-response programs in SPP’s market to permit the lifting of the bid 

cap. In addition, the Commission directed SPP to work with utilities and state regulators to 

consider how to allow the participation of demand resources in the imbalance market (e.g., as 

interruptible demand or behind the meter generation).30

• ISO-New England Forward Capacity Market (FCM) - The Commission approved a 

settlement that provided ISO-NE with a FCM in which demand resources can compete with 

supply-side resources for capacity payments.31

• PJM Regional Transmission Expansion Planning (RTEP) - The Commission accepted 

PJM’s commitment to evaluate the extent to which demand response could eliminate the need 

for an economic-based upgrade to PJM’s RTEP protocol.32 The Commission directed PJM to 

make a compliance filing describing how generators and demand-response providers will be 

incorporated into the economic planning process.33

• PJM Reliability Pricing Model (RPM) - The Commission clarified that demand-response 

resources may participate in RPM auctions, may set the market clearing price, and may 

receive revenues for load reductions as Interruptible Load Resources.34 The Commission also 

directed PJM to examine in a compliance report barriers to entry to energy efficiency.35

The Commission recently stated, “our goal is for RTOs and ISOs to develop rules to ensure the 

treatment of supply and demand resources on a comparable basis to the extent each is technically 

capable of providing the service.”36 By allowing demand to be on an equal footing with supply, 

wholesale markets are opened to demand response, helping to keep wholesale prices and wholesale 

price volatility in check. Demand response can also diminish the potential for market manipulation by 

reducing generator market power. The extent to which demand response is in the organized markets is 

captured in Appendix D. 

Recent Rulemakings 

In the last year, the Commission issued two final rules directly addressing aspects of demand response. 

In doing so, the Commission recognized the role of demand resources in wholesale markets, and in the 

reliable operation of the bulk power system. 

Order No. 890: Preventing Undue Discrimination and Preference in Transmission Service

On February 16, 2007, the Commission issued Order No. 890,37 which addresses and remedies 

opportunities for undue discrimination under the pro forma Open Access Transmission Tariff 

(OATT), adopted in 1996 by Order No. 888.38 In Order No. 890, the Commission adopted several 

 30 Southwest Power Pool, 116 FERC ¶ 61,289, at P 44, 62 (2006). 

31 Devon Power LLC, 115 FERC ¶61,340, at P 22, order on reh’g, 117 FERC ¶ 61,133 (2006). 

32 PJM Interconnection, L.L.C., 117 FERC ¶ 61,218, at P 3 (2006), reh’g pending. 33 Id. P 24. 

34 PJM Interconnection, L.L.C., 117 FERC ¶ 61,331, at P 31 (2006). 

35 PJM Interconnection, L.L.C., 119 FERC ¶ 61,318, at P 204 (2007). 

36 Wholesale Competition in Regions with Organized Electric Markets, 72 Fed. Reg. 36,276 (July 2, 2007), FERC 

Stats. & Regs. ¶32,617 , P 35 (2007) (Competition ANOPR). 

37 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12,266 

(March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), reh’g pending. 38 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public 

Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order 
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critical reforms. Of them, reforms addressing transmission planning and ancillary services included 

roles for demand resources. Specifically, the Commission modified its open access transmission 

policies to allow for the incorporation of demand response in local and regional planning processes, if 

they “are capable of providing the functions assessed in a transmission planning process, and can be 

relied upon on a long-term basis.”39 Similarly, the Commission found that the sale of other ancillary 

services, including energy imbalance, operating reserve, and spinning reserve by load resources 

“should be permitted where appropriate on a comparable basis to service provided by generation 

resources.”40 The Commission modified its pro forma OATT to effectuate the inclusion of these 

resources. 

Order No. 693: Mandatory Reliability Standards 

The Commission certified NERC as the Electric Reliability Organization responsible for the 

development of mandatory, enforceable reliability standards, pursuant to the Energy Policy Act of 

2005.41 On March 16, 2007, in Order No. 693, the Commission approved the first set of 83 mandatory 

and enforceable Reliability Standards and directed modification to 58 of these standards, in 

accordance with the provisions of new section 215 of the Federal Power Act (FPA)42 and part 39 of 

the Commission’s regulations.43 Of importance to demand-response resources, the Commission 

directed the incorporation of additional resources and technologies, such as demand-side management 

(DSM) and demand response, in the revisions to various reliability standards.

Of the 83 approved reliability standards and the Glossary of Terms Used provided by NERC, the 

following twelve standards directly relate to demand-side issues and demand response. 

 Standard BAL-002-0: Disturbance Control Performance 

 Standard BAL-005-0: Automatic Generation Control 

 Standard EOP-002-2: Capacity and Energy Emergencies 

 Standard MOD-016-01: Actual and Forecast Demands, Net Energy for Load, 

Controllable DSM 

 Standard MOD-019-0: Forecasts of Interruptible Demand and DCLM Data 

 Standard MOD-020-0: Providing Interruptible Demands and DCLM Data 

 Standard MOD-021-0: Accounting Methodology for Effects of Controllable DSM in 

Forecasts 

 Standard TPL-001-0: System Performance Under Normal Conditions 

 Standard TPL-002-0: System Performance Following Loss of a Single BES 

Element 

 Standard TPL-003-0: System Performance Following Loss of Two or More BES 

Elements 

 Standard TPL-004-0: System Performance Following Extreme BES Events 

 Standard VAR-001-0: Voltage and Reactive Control 

 

In approving the reliability standards, the Commission took the first steps in recognizing the need for 

consistency in the inclusion of demand response in system modeling. The approved modeling, data, 

 No. 888-A, 62 Fed. Reg. 12,274 (March 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997). order on reh’g, Order No. 888-B, 

81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998). 

39 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, at P 479. 

40 Id. P 888. 

41 N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062, order on reh’g, 117 FERC ¶ 61,126 (2006). 

42 16 U.S.C. 824o.

43 18 C.F.R. 39. 
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and analysis (MODs) standards, MOD-019-0, MOD-020-0, and MOD-021-0, recognize the current 

lack of documentation of demand resources and direct proper reporting of demand response and the 

effects of time of use rates, interruptible demands, and direct load control management in forecasting 

peak demand and net energy. Order No. 693 found that standardizing the principles for reporting and 

validating demand-response information will provide consistent and uniform evaluation of demand 

response to facilitate system operator confidence in relying on such resources.44 

Under BAL-002-0, the reliability standard uses contingency reserves to balance resources and demand 

to return the interconnection frequency to within defined frequency limits following a reportable 

generator loss on the system.45 By directing modifications to this reliability standard, the Commission 

attempted to include other technologies that may be relied upon to provide contingency reserves in 

order to maintain the interconnection frequency. In doing so, the Commission chose to allow for the 

“comparable treatment of demand-side management with conventional generation or any other 

technology and to allow DSM to be considered as a resource for contingency reserves on this basis 

without requiring the use of any particular contingency reserve option.”46

BAL-005-0 aids in maintaining the interconnection frequency by requiring that all generation, 

transmission, and customer loads be within the metered boundaries of a balancing authority area, and 

establish the functional requirements for the balancing authority’s regulation service, including its 

calculation of Area Control Error.47 In this instance, the Commission directed modification to the title 

of the reliability standard to be “as neutral as to the source of regulating reserves and allow for the 

inclusion of a technically qualified DSM and direct control load management as regulating reserves.”48

The reliability standard, EOP-002-2,49 requires that a balancing authority may have the authority to 

bring all necessary generation on line, communicate about the energy and capacity emergency with the 

reliability coordinator and coordinate with other balancing authorities. The Commission determined 

that demand resources provide an additional tool for meeting this standard. The Commission also 

determined that the scope of demand response covers more resources than interruptible load and 

therefore directed the standard be modified to include demand-response resources if they meet 

technical requirements comparable to those required of other resources. 

MOD-019-0 and MOD-020-0 ensure that past and forecasted demand data are available for past event 

validation and future system assessment.50 In its assessment, the Commission determined that 

controllable load can be as reliable as other resources and directed that it be subject to the same 

reporting requirements. To meet these requirements, the ERO has been directed to modify the two 

MOD Standards to allow for the development of a process “to require reporting of the accuracy, error 

and bias of controllable load forecasts.”51 In doing so, the Commission stated that it believes that this 

will enable planners to paint a more reliable picture of the amount of controllable load available at the 

time, and allows for a more accurate assessment of system reliability. In MOD-021-0, the 

Commission directed the ERO to provide an additional requirement standardizing principles on 

reporting and validation of demand-response program information and “allow for resource planners to 

 44 Order No. 693, FERC Stats. & Regs. ¶ 31,241 at P 1298. 

45 Id. P 316. 

46 Id. P 333. 

47 Id. P 387. 

48 Id. P 404. 

49 Id. P 567. 

50 Id. P 1266, 1280. 

51 Id. P 1276. 
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identify any corrective actions” needed “to improve forecasted demand responses for future 

forecasts.”52 

Through directing modifications to the MOD reliability standards, the Commission continued to 

emphasize the importance of demand response and its contribution to the reliability of the system by 

directing modifications that will require system operators to accurately document the amount of 

demand-response resources available for planning purposes. Accurate documentation of demandresponse resources should provide assurances sought by some system operators and garner support for 

continued and possibly greater reliance on demand response in system planning and operations by 

demonstrating the dependability of demand resources. 

The Commission also directed modification to the transmission planning standards (TPL-001-0, TPL002-0, TPL-003-0, and TPL-004-0) and the voltage and reactive control standard (VAR- 001-0). In 

the TPL standards, the Commission included demand response and demand-side management as two 

of a range of variables that should be included in sensitivity studies of critical system conditions.53 In 

VAR-001-0, the Commission also noted that demand response and demand-side investment can 

reduce the need for reactive power capability, and directed the inclusion of demand response among 

permissible reactive resources.54 

Advanced Notice of Proposed Rulemaking on Wholesale Competition in Regions with Organized 

Electric Markets

The Commission recently issued the Wholesale Competition Advanced Notice of Proposed 

Rulemaking (ANOPR).55 In the ANOPR, the Commission examined possible reforms to enhance 

competition within organized wholesale markets, including reforms associated with demand-response 

polices. The Commission proffered four demand-response proposals: 1) allow demand resources to 

provide certain ancillary services (e.g., spinning and supplemental reserves and generator imbalance) 

in all RTO/ISO markets when demand resources meet the necessary technical requirements;56 2) 

eliminate charges for taking less energy in real-time than purchased in the day-ahead market during 

system emergencies;57 3) allow retail demand-response aggregators to bid demand reductions on 

behalf of retail customers directly into the organized markets;58 and 4) modify the market power 

mitigation rules when demand is nearing the amount of available supply.59 These proposed reforms 

have the potential to further the competitiveness of the RTO/ISO markets. 

Other 

The Commission has also encouraged demand response outside of its orders. Most recently, the 

Commission convened a technical conference on demand response on April 23, 2007.60 During this 

technical conference, panelists discussed the interplay between demand response and grid operations 

and markets, how to effectively evaluate and measure demand response, and how demand resources 

can be integrated into the transmission planning process, either as an alternative or a complement. 

 52 Id. P 1294. 

53 Id. P 1706. 

54 Id. P 1879. 

55 Competition ANOPR, FERC Stats. & Regs. ¶ 32,617. 

56 Id.P 59-61. 

57 Id.P 62-67. 

58 Id.P 68-74. 

59 Id.P 75. 

60 FERC Wholesale Demand Response Technical Conference. 
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Panel members provided the Commission with useful feedback concerning the benefits of demand 

response and where efforts may be required to encourage further penetration of demand-response 

programs into the market. An example offered was the Electric Power Research Institute’s (EPRI) 

Dynamic Energy Management initiative which attempts to meet the needs of utilities and other 

stakeholders in deploying technologies to help with smart power delivery, operation, load 

management, and end-use system.61 

Aside from sponsoring technical conferences, the Commission participates in a National Association 

of Regulatory Utility Commissioners (NARUC)-FERC Collaborative Dialogue on Demand 

Response.62 This collaborative, which began in November of 2006, explores the coordination of 

efforts between the states and federal government in order to promote and integrate demand response 

into retail and wholesale markets and planning.63 Participants at the initial meeting in November 

identified various issues and goals that supported the overall objective of removing regulatory and 

market barriers to demand-response integration. These goals included increased regional coordination, 

providing proper price signals, sponsoring demand-response studies, and educating customers. 

NARUC and the Commission continued their dialogue at the NARUC Winter Meetings in February 

2007 and the NARUC Summer Meetings in July 2007 to discuss demand-response policy and decide 

potential next steps.64

Developments in Retail Markets 

Since the 2006 FERC Demand Response Assessment, several states and individual utilities took 

actions to introduce greater demand response and price-responsiveness into retail markets. In 

particular, a growing number of states are directing the implementation of time-based rates. Activity 

in the retail sector should improve demand responsiveness and partially address the need for 

wholesale-retail coordination identified in the 2006 FERC Demand Response Assessment.65 A 

sampling of state actions follows.

State Legislative and Regulatory Activity 

• California. The California Public Utilities Commission (CPUC) continued its support of 

demand response, directing changes to 2007 utility demand-response programs, and 

initiating a rulemaking on measurement and verification and cost-effectiveness.66 

• New York. In April 2006, the New York Public Service Commission directed utilities to 

place their largest customers on real-time pricing (based on day-ahead NYISO LMPs) as 

their default tariff.67 The utilities phased in their start dates through January 2007. Most 

 61 Richard A. Spring (Kansas City Power & Light), Presentation at the FERC Wholesale Demand Response 

Technical Conference, 2. 

62 Competition ANOPR, FERC Stats. & Regs. ¶ 32,617 at P 45. 

63 Id. 

64 NARUC-FERC Demand Response Collaborative, available at: 

http://www.naruc.org/displaycommon.cfm?an=1&subarticlenbr=514. 

65 2006 FERC Demand Response Assessment, 133. 

66 CPUC Decision (D.) 06-11-049, November 2006 (“Order Adopting Changes to 2007 Utility Demand Response 

Programs”), and “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,” Rulemaking 07-01-041, Jan. 2007. 

67 New York State Public Service Commission (NYPSC) Order, Case 03-E-0641 (adopting mandatory hourly 

pricing for investor-owned utilities), April 24, 2006, available at: 

http://www.dps.state.ny.us/Mandatory_Hourly_Pricing.html. 
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utilities’ real-time tariffs apply to customers with demands greater than 1 or 2 MW 

(depending on the size of the customer). The PSC anticipates that utilities will lower these 

size thresholds over the next few years. Customers have the option of staying with their 

original utility (full service), or migrating to an energy service company (i.e., independent 

electricity retailers). There are currently 2,225 customers representing 5,348 MW subject 

to this real-time pricing tariff. It is also not yet clear how many of these customers will 

also participate in NYISO demand-response programs.68 

• Illinois. In 2006, Illinois enacted legislation requiring electric utilities to consider and 

evaluate the use of dynamic pricing to enable customer demand response,69 and directing 

the Illinois Commerce Commission to evaluate whether such pricing and advanced 

metering would produce net benefits (for customers).70 Illinois also mandated that large 

utilities in the state offer residential real-time pricing programs run by an independent 

program administrator. Commonwealth Edison proposed to continue and expand its 

residential hourly real-time pricing (RTP) in 2007 as the “Energy Smart Pricing Plan.”71 

ComEd’s default RTP rates for large customers “are indexed to the day-ahead energy 

market, for which hourly prices are published a day in advance.”72 Ameren Illinois chose 

the Community Energy Cooperative to run its “Power Smart Pricing” program. While 

Ameren’s program promotion will begin in earnest in the fall of 2007, the Community 

Energy Cooperative has already begun enrolling customers based on calls from interested 

customers. Ameren will also offer select customers a “PriceLight,” which delivers price 

signals via a glowing orb which changes colors based on current price levels.73

• Connecticut. Connecticut enacted a comprehensive energy act with features promoting 

energy efficiency, demand response, advanced metering, and renewable energy. The act 

removes key barriers to utility promotion of demand reductions (either from energy 

efficiency or demand response), by requiring distribution companies to decouple 

distribution revenues from sales in future rate cases. It requires the Connecticut 

Department of Public Utility Control to implement two tiers of time-of-use (TOU) rates 

by January 2008; the first is mandatory TOU rates for larger customers whose demand is 

350 kW or more and the second is voluntary critical-peak pricing or real-time pricing for 

all customer classes. All electric utilities must submit a plan to deploy advanced metering 

infrastructure systems as a prelude to TOU rates. Advanced metering infrastructure 

systems must be in place by January 2009, and any customer may obtain a meter on 

demand, with costs recoverable in distribution rates. Further, the act directs the 

Department of Public Utility Control to “develop a real-time energy report for daily use by 

television and other media” to inform the public about current real-time energy demand, 

real-time changes to energy demand, emphasize the importance of reducing peak and 

provide estimates of economic benefits from such reductions, and provide tips on energy 

efficiency measures. 

• Maryland. On June 8, 2007, the Maryland Public Service Commission (PSC) announced 

a public capacity planning conference and a collaborative process. The conference will 

include an examination of demand reduction potential, from the state and regional 

 68 Email and phone communications with Christopher L. Graves, NYPSC, June 8 and 14, 2007. 

69 220 ILL. COMP. STAT. 5/16-107(b-5) (2006). 

70 Commonwealth Edison Co., Illinois Commerce Commission Docket 06-0617 (filed September 13, 2006). 

(considering “Proposed revisions to Rate BES-H, Basic Electric Service-Hourly Energy Pricing”). 

71 www.knowledgeproblem.com, November 11, 2006. 

72 Galen Barbose, Ranjit Bharvirkar, et al., “Killing Two Birds with One Stone: Can Real-Time Pricing Support 

Retail Competition and Demand Response?,” LBNL-59739, August 2006, 5. 

73 Issue Alert, May 16, 2007. 
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perspectives.74 The collaborative process, prompted by three recent utility filings, was to 

consider four issues relating to advanced metering initiatives (AMI) and demand side 

management (DSM).75 The Office of Staff Counsel reported its findings to the PSC on 

areas of agreement and disagreement in the DSM/AMI collaborative on July 6, as 

required. The collaborative was unable to reach consensus on the four areas it examined: 

technical standards for advanced meters; the extent to which demand programs would be 

offered on a competitively-neutral basis; cost recovery of advanced metering and demandresponse programs; and, the appropriate measures of cost effectiveness in demandresponse programs.76 Separately, the Commission approved decoupling mechanisms as 

part of Delmarva’s and Pepco’s rate cases to encourage energy efficiency. This allows 

utilities to modify their distribution rates—to make up lost revenue and to cover fixed 

costs—if customers conserve more and demand for electricity drops.77

• Michigan. Michigan’s governor issued an executive directive for the Michigan Public 

Service Commission (Michigan Commission) to develop a comprehensive plan for 

meeting the state's electric power needs. The report, issued on January 31, 2007, 

recommended that the Commission be authorized to require the immediate use of active 

load management by utilities and that pilot programs be designed to assist customers in 

managing the electric load and reducing the costs.78 The Michigan Commission directed 

its staff on June 12 to begin a collaborative process to develop a demand-response 

program that would allow customers to lower their monthly bills by deciding to use power 

at less expensive off-peak hours.79

Utility Demand Response Activities 

In addition to actions at the state level since the 2006 report, there has been a spate of recent utility 

announcements of programs and tariffs that include demand response, time-based rates, energy 

efficiency, and advanced metering. Connecticut Light & Power supported its filed plan to implement 

advanced metering infrastructure (AMI) with the Connecticut DPUC by noting that advanced metering 

infrastructure will not only increase energy efficiency, but also help the company manage demand by 

giving its customers access to time-of-use rates.80 Pepco Holdings announced its plans to include 

energy efficiency and demand-response programs, coupled with “innovative technologies”, for nearly 

all their operating companies in Maryland,81 Delaware,82 and the District of Columbia.83 It intends to 

file soon in New Jersey. Energy East Corporation has announced its plan to implement advanced 

metering in New York and Maine, noting: “the end game with the metering is to drive down demand, 

 74 Maryland Planning Conference scheduled for July 26-27, 2007, resulting from Order No. 81423 in Case No. 

9099, issued May 23, 2007; conference notice issued June 8, 2007. 

75 Maryland Collaborative Process, Case No. 9111, Order No. 81448, issued June 8, 2007. 

76 Maryland PSC, Office of Staff Counsel, “Report on the Advanced Metering Initiative and Demand Side 

Management Collaborative,” Case 9111, July 2, 2007. 

77 Maryland PSC, Press Release, July 20, 2007. 

78 Michigan’s 21st Century Energy Plan, submitted to Governor Jennifer M. Granholm by J. Peter Lark, Chairman, 

Michigan Commission, January 31, 2007, and MPSC press release, January 31, 2007. All related documents available at

http://www.cis.state.mi.us/mpsc/electric/capacity/energyplan/index.htm. 79 Michigan Commission Press Release, June 12, 2007, available at: http://www.michigan.gov/mpsc/0,1607,7-

159-16400_17280-170116--,00.html. 80CL&P Press Release, April 2, 2007, available at: http://www.cl-p.com/companyinfo/newsreleases.asp. CL&P’s 

DPUC filing is in response to Docket No. 05-10-03. 

81 Pepco Press Release, March 21, 2007. 

82 Delmarva Press Release, March 21, 2007. 

83 Pepco Press Release, April 5, 2007. 
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get people to conserve more, and reduce need to build more power plants.”84 Upper Peninsula Power 

hoped to enroll its first customer in a real-time pricing program for industrial customers directly 

connected to the grid by July 1, 2007.85 

Baltimore Gas & Electric (BGE) won approval for its AMI pilot in April 2007. BGE states that it 

hopes to use the advanced metering system to send price and load control signals, enhance distribution 

automation and distributed generation control, and integrate demand response with smart thermostats 

and load control devices. Wisconsin Public Service modified its interruptible program to 

accommodate the Midwest ISO’s day-ahead market.86 Hawaii, Idaho, Missouri, and New Jersey are 

conducting other pilots.87

Trends and Observations 

Since Commission staff issued its 2006 report, demand response is increasingly incorporated into 

organized markets, including the successful bidding of demand response into RTO/ISO capacity 

markets and auctions and the growing participation of demand response in ancillary services markets. 

State and federal regulators continue to explore, initiate and respond to proposals for including 

demand-response resources in energy markets. Entities are increasingly including demand response in 

strategic plans and state plans; enrollment in RTO/ISO demand-response programs is on the rise (see 

Table II-2); and there is a renewed commitment to cross-jurisdictional demand-response working 

groups. 

Bidding of Demand into RTO/ISO Capacity Markets and Auctions 

PJM held the first capacity auction in its forward capacity market (known as the Reliability Pricing 

Model, or RPM) in April 2007, for the June 2007 to May 2008 planning year. Forty-one percent of 

cleared offers, or 127.6 MW, were demand-response offers.88 Demand-response cleared offers 

quadrupled to 536 MW in the second auction held for 2008-2009. The RPM auction process is 

designed to send locational price signals to attract resources to areas where they are most needed.89 

ISO-NE initiated its Forward Capacity Market this spring. The Forward Capacity Market allows five 

categories of demand resources to participate, including energy efficiency, load management, 

distributed generation, and real-time demand response. In the “show of interest” held in February 

2007, 2400 MW, or 20 percent of bids, were from demand resources. ISO-NE will evaluate these bids 

and hold the final auction in February 2008 for June 2010 delivery. 

Growing Participation of Demand Response in Ancillary Services Markets 

There is a growing ability of demand resources to participate in ancillary services markets. As shown 

in Table D-1 in Appendix D, several RTOs and ISOs include demand response in ancillary markets. 

Some of these continue to consider the ability of demand response to participate in other ancillary 

 84 Energy East Press Release, quoting Mark Siwak, Director of Investor Relations, June 15, 2007. 

85 Platts Megawatt Daily, May 23, 2007, 11. 

86 Dennis Derricks (Wisconsin Public Service Corporation), FERC Wholesale Demand Response Technical 

Conference, transcript, 86. 

87 Ahmad Faruqui, Ryan Hledik, Sam Newell, and Johannes Pfeifenberger, Power of Five Percent: How Dynamic 

Pricing Can Save $35 Billion in Electricity Costs, Brattle Group Discussion Paper, May 2007, 3. 

88 PJM news release, April 16, 2007, available at http://www.pjm.com/contributions/newsreleases/2007/20070416-rpm-auction-results.pdf. 

89 PJM news release, July 13, 2007, available at: http://www.pjm.com/contributions/newsreleases/2007/20070713-2nd-rpm-results.pdf. 
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services markets, while other RTOS and ISOs have open cases on the inclusion of demand response in 

these markets. PJM opened its ancillary services market to demand response on May 1, 2006, as 

Synchronized Reserves.90 Table II-1 shows there has been active participation in this market in terms 

of cleared megawatt-hours between August 2006 and June 2007; participation appears to vary 

seasonally. 

Table II-1. PJM synchronized reserve participation 

Month Cleared MWh 

August 2006 1,613 

September 2006 5,354 

October 2006 31,074 

November 2006 27,915 

December 2006 25,125 

January 2007 35,210 

February 2007 5,104 

March 2007 8,675 

April 2007 17,275 

May 2007 17,897 

June 2007 8,859 

Source: www.pjm.com: Demand Response Working Group 

ISO-New England implemented a demand-response reserves pilot program “to determine if small 

generation and demand response resources of less than 5 MW can provide a functionally-equivalent 

reserves product.”91 Because two-way communications and telemetry equipment used by larger 

resources (for measurement, control, and dispatch) can be cost-prohibitive to smaller resources, part of 

the pilot program’s goal is to evaluate lower-cost, two-way communications alternatives. This 

program, initiated in October 2006, will continue to run through the summer of 2007.92 

In the past year, ERCOT’s Independent Market Monitor (IMM) suggested changes to the way 

participants in their “Load Acting as a Resource” program (LaaRs) bid into the market.93 Current 

rules allow a maximum of 1,500 MW of LaaRs to be nominated, although at least 1,800 MW of LaaRs 

were qualified in the summer of 2006. The IMM believes the bidding rules are inefficient because 

they encourage bidding behavior that prevents competition from selecting the most efficient resources 

to provide responsive reserves. The changes it recommended in its 2005 State of the Market (SOM) 

Report “were not adopted in the zonal market because of timing and resource issues.” While they were 

initially approved for implementation in the nodal market (December 2008), the proposed changes 

failed to gain sufficient votes at the Technical Advisory Committee level. The IMM will be urging 

reconsideration of these recommendations in its 2006 SOM.94 

 90 114 FERC ¶61,201, February 24, 2006.

91 ISO-NE, 2006 Annual Markets Report, 118. 

92 Henry Yoshimura (ISO-NE), FERC Wholesale Demand Response Technical Conference, transcript, 15-17. 

93 Potomac Economics, Ltd., Advisor to Wholesale Market Oversight, Public Utility Commission of Texas, 2005 

State of the Market Report for the ERCOT Wholesale Electric Markets, July 2006, 106.

94 Email from and phone interview with ERCOT’s Independent Market Monitor, June 5, 2007.
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Increased Participation in ISO Demand Response Programs 

If one looks strictly at enrollment in terms of amount of potential demand reduction, the reliability 

programs in the three eastern RTOs had the greatest increases in the last few years (see Table II-2). 

ISO-NE nearly doubled its enrolled base between 2006 and 2007. RTO/ISO 2006 data demonstrate 

increased levels of energy reductions in the RTO and ISO demand bidding programs (labeled as 

“economic” in Table II-2), despite stable levels of customer participation and enrollment in programs. 

Energy reductions in the NYISO’s Day-Ahead Demand Response Program (DADRP) increased to 

3,479 MWh in 2006 from 2,100 MWh in 2005.95 Monthly energy demand reductions in PJM’s DayAhead and Real-Time Economic Programs increased from 24,395 MWh in August 2005 to 46,541 

MWh in August 2006. Annual demand reductions in PJM doubled, from 129,769 MWh in 2005 to 

260,417 MWh in 2006.96

Table II-2. Enrollment changes in eastern ISO reliability and economic 

programs97

(MW enrolled) PJM ISO-NE NYISO 

Year Reliability Economic Reliability Economic Reliability Economic

2003 1,631 651 263 117 1,531 354 

2004 2,622 876 248 103 1,570 411 

2005 3,424 2,210 277 190 1,605 395 

2006 2,410 1,101 580 168 1,720 389 

pre-summer '07 2,155 1,578 940 97 1,810 389 

change, 2003-07 32% 143% 257% -17% 18% 10% 

change, 2006-07 -11% 43% 62% -42% 5% 0% 

Source: ISO demand response presentations, “State of the Market” reports, and email correspondence with staff. 

More National and Regional Attention on Measurement and Verification of Demand 

Reductions 

The 2006 FERC Demand Response Assessment report identified the need for additional research on 

cost-effectiveness and measurement of demand reductions as a regulatory barrier. Important activities 

at the state, RTO/ISO, and national levels have begun to address this. The CPUC is actively 

examining cost-effectiveness and measurement in a rulemaking proceeding (R.07-01-041).98 The 

ISO-NE developed a measurement and verification protocol to support demand resource participation 

in the Forward Capacity Market.99 This protocol represents much of the latest research on 

measurement at the wholesale level. The NARUC-FERC demand response collaborative examined 

measurement and verification at its February 2007 meeting. The Commission convened a panel at its 

 95 David Lawrence, NYISO, in conference call with FERC staff and NYISO staff, December 14, 2006. 

96 PJM, “Load Response Activity Report: January through December (2005 and) 2006,” available at:

http://www.pjm.com/committees/working-groups/dsrwg/dsrwg.html. 97 Programs: PJM Reliability: Emergency Load Response Program; PJM Economic: Economic Load Response 

Program (real-time and day-ahead options); PJM "Load" is Load Management, was "ALM"; ISO-NE Reliability: Real-Time 

(RT) 30-minute, real-time 2-hour, and Profiled; ISO-NE Economic: real-time price response (RTPR), Day-ahead load 

response program (DALRP); NYISO Reliability: Emergency Demand Response Program (EDRP), Installed-capacity Special 

Case Resources (SCR); NYISO Economic: Day-Ahead Demand Response Program (DADRP). 

98 CPUC, Rulemaking 07-01-041, January 2007. 

99 ISO-NE, Measurement and Verification of Demand Reduction Value from Demand Resources, Manual MMVDR, April 2007, available at: http://www.isone.com/rules_proceds/isone_mnls/m_mvdr_measurement_and_verification_demand_reduction_(revision_0)_04_13_07.doc. 
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April 23, 2007 demand response technical conference to address measurement and verification in 

wholesale markets. Finally, the North American Energy Standards Board (NAESB) initiated a project 

to examine measurement and evaluation of demand resources at both the retail and wholesale levels.100

Increased Focus on the Development of the Smart Grid 

The use of a smart grid allows for greater implementation of demand response. Over the past year, the 

concept of the “smart grid” – or at least the term – was the subject of increased attention. Nationallevel meetings, such as the U.S. Department of Energy-sponsored GridWeek in April 2007, were held. 

Strategic planning documents like PJM’s April 2007 “Bringing the Smart Grid Idea Home” also 

emphasized the importance of a smart grid in the efficient operation of the electric system.101 

Congress has held several hearings on the subject during the 110th Congress, and there have been 

several pieces of draft legislation on the issue.102 

More Multistate and State-Federal Demand Response Working Groups 

The 2006 report noted that “greater clarity and coordination between wholesale and state programs is 

needed.” Since the issuance of that report, an increasing number of groups are working to promote 

cooperation and coordination across multiple jurisdictions to enhance demand response in retail and 

wholesale markets, and to promote intersecting policies that support common goals. 

For example, regulators in the Organization of MISO States convened the Midwest Demand 

Responsive Initiative (MWDRI) in February 2007 to examine demand-response issues, and have met 

several times.103 A collaborative effort in the Pacific Northwest, the Pacific Northwest Demand 

Response Project, also formed since the last Commission staff report and held its first meeting in May 

2007. The Mid-Atlantic Distributed Resources Initiative (MADRI) continues to meet to discuss and 

research demand-response issues in the Mid-Atlantic region. 

As was discussed earlier, federal and state regulators began a “Collaborative Dialogue on Demand 

Response” at the November 2006 NARUC Annual Convention. 

More Reliance on Demand Response in Strategic Plans and State Plans 

RTOs and ISOs, Public Power Authorities, and states increasingly incorporate elements of demand 

response, energy efficiency, advanced technologies, and the smart grid in their plans and policies. 

PJM’s 2007 Strategic Plan states that PJM should prepare its system to develop a communications 

protocol for a smart grid, work with states to encourage AMI deployment, and continue its work to 

implement demand response in its markets. The CAISO specifically identifies demand response as a 

critical item in its five-year strategic business plan. TVA’s latest strategic plan includes many energy 

efficiency and demand-response components. Both Connecticut and Michigan have recognized the 

importance of demand response and energy efficiency in the future of their own energy infrastructures. 

 100 See http://www.naesb.org/dsm-ee.asp for more information. 

101 PJM, Bringing the Smart Grid Idea Home, April 2007. 

102 Both the U.S. Senate and House have held hearings and markups of legislation to promote the development of a 

smart grid. For example, the Subcommittee on Energy and Air Quality of the Committee on Energy and Commerce held a 

hearing on “Facilitating the Transition to a Smart Electric Grid” on May 3, 2007. Also, the U.S. House of Representatives 

passed on August 4, 2007, H.R. 3221, “New Direction for Energy Independence, National Security, and Consumer Protection 

Act,” which contains the “Smart Grid Facilitation Act of 2007.” Text of bill available at: 

http://www.rules.house.gov/110/text/110_hr3221.pdf. 103 Midwest Demand Responsive Initiative, available at http://misostates.org/MWDRI%20list.htm. 
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Connecticut’s comprehensive energy act requires the consideration of conservation and loadmanagement standards and programs. The Michigan Public Service Commission’s “21st Century 

Energy Plan” recommends the immediate use of active load management and recommends that the 

state invest in energy efficiency. 

Increased Activity by Third Parties in Aggregating and Providing Demand Response 

Third-party providers who generally aggregate demand reductions across customer groups and bid a 

percent of their enrolled base into the market provide an important avenue for customers to contribute 

to demand reduction that they might not otherwise have. Third-party providers provide a mechanism 

for customers to bid into energy markets without having to understand and track energy markets or 

multiple RTO/ISO or state rules. PJM’s Andy Ott stated: 

They’re actually providing a very valuable service, because each individual entity 

who can provide demand response, can’t afford to take the time to understand the 

market in depth, the wholesale market, so you have curtailment service providers 

actually providing a function to provide commonality, to allow those megawatts to 

come to the market. That’s absolutely valuable, and we see their actions every day.104

Demand-response aggregators delivered significant levels of demand reductions during the summer of 

2006.105 RTOs and ISOs estimate that aggregators’ contribution to load reductions comprise a sizable 

portion of the enrolled customers in their reliability-based programs. For example, in NYISO’s 

ICAP/Special Case Resources program, aggregators provided 91 percent of participating customers, 

and 53 percent of demand reductions in 2006.106

TVA similarly notes that third party aggregators are a big part of their business case in rolling out its 

pilot program for commercial and industrial customers, because the aggregators have the manpower, 

time, and money to run a program.107

Third-party aggregators have also been active in signing long-term demand contracts with utilities. 

The California PUC issued an order directing utilities to cooperate with aggregators, and to pursue 

requests for proposals for additional demand response.108 EnerNOC won two “Negawatt Network” 

contracts for 40 MW each with Pacific Gas & Electric (PG&E) and with Southern California Edison 

(SCE) that were approved by the CPUC.109 EnerNOC also entered into a ten year Negawatt Network 

contract with Public Service of New Mexico (amount not announced) in support of New Mexico’s 

Efficient Use of Energy Act.110 Comverge will provide San Diego Gas & Electric (SDG&E) and 

PG&E with up to 100 and 50 megawatts of capacity, respectively, for their residential and small 

commercial and industrial customers. The CPUC also approved a five-year agreement between PG&E 

 104 Andrew Ott (PJM), FERC Wholesale Demand Response Technical Conference, transcript, 11. 

105 Demand-response aggregators of retail customers, such as EnerNoc and Comverge, are also known as 

curtailment service providers or aggregators of retail customers (see Competition ANOPR, FERC Stats. & Regs. ¶ 32,617). 

In interviews with ISO-NE and NYISO, the growing importance of these aggregators was stressed by the RTO or ISO 

demand-response coordinators. 

106 NYISO, 2006 Demand Response Programs, filed with the Commission, January 16, 2007, 5. 

107 Conference call between Staff and members of the Demand Response Coordinating Committee, June 8, 2007. 

108 CPUC Decision (D.) 06-11-049, November 2006. 

109 EnerNOC press releases, March 2, 2007, and March 20, 2007. 

110 EnerNOC press release, March 15, 2007. 
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and Energy Curtailment Specialists, Inc., for a minimum of 40 MW from commercial and industrial 

customers.111

Barriers Remain 

A review of the experience with the development of demand-response policies since the publication of 

the 2006 FERC Staff Demand Response Assessment suggests that, in addition to the regulatory 

barriers identified in the 2006 report,112 there are two additional regulatory barriers. 

• Lack of sufficient real-time information sharing. A clear lesson from the summer 2006 heat 

waves and record system peaks is the need for greater real-time coordination and real-time 

information sharing on demand-response activities run by ISOs, utilities, and unregulated 

providers. Coordination issues were an issue in CAISO and Midwest ISO, less so in PJM and 

ERCOT. Staff undertook numerous interviews with multiple participants to piece together the 

picture of demand response this summer. For these four RTOs and ISOs, not one of them 

collected or had access to all responses. That is, they were unaware or unsure of the extent of 

participation by retail programs, conservation, or other resources which were central to their 

ability to maintain system reliability on peak days. 

• Continuing barriers to implementing critical peak pricing tariffs. Critical-peak pricing (CPP), 

a time-of-use rate which includes an extreme price to be used either during system emergencies or 

periods of high wholesale prices, dramatically reduced peak demand and was acceptable to smaller 

customers during a statewide pricing pilot in California.113 While the number of utilities which 

have announced plans for CPP programs has increased, they are reluctant to rely on elasticity data 

which came exclusively from the California pilot results, and many still feel they first need to 

conduct pilots to test customer response in their own service territories.114

 111 ECS press releases, March 7, May 8, and June 5, 2007. 

112 The 2006 FERC Staff Demand Response Assessment identified the following regulatory barriers: 

• Disconnect between retail pricing and wholesale markets. 

• Utility disincentives associated with offering demand response. 

• Cost recovery and incentives for enabling technologies. 

• The need for additional research on cost-effectiveness and measurement of reductions. 

• The existence of specific state-level barriers to greater demand response. 

• Specific retail and wholesale rules that limit demand response. 

• Barriers to providing demand-response services by third parties. 

• Insufficient market transparency and access to data. 

• Better coordination of federal-state jurisdiction affecting demand response. 

113 2006 FERC Demand Response Assessment, 57-60. 

114 Wayne Harbaugh, “BGE Pilot,” presentation to MADRI, May 14, 2007, available at:

http://www.energetics.com/MADRI/pdfs/MADRI_CPP_Pilot_0507_Harbaugh.pdf. 
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III. Advanced Metering 

Interest and investment in advanced metering (referred to here as advanced metering infrastructure or 

AMI) continues to gain momentum. A number of large utilities announced planned AMI deployments, 

filed with their state regulatory commissions, and/or received approval to recover AMI investments from 

ratepayers since the publication of the last report. In addition, a number of state legislatures and state 

public utility commissions have issued new rulemakings, orders, and/or initiatives in support of AMI 

investment (and time-based rates). These new announced deployments and state activity are important 

because they will create the necessary infrastructure and capability to support demand response. 

This chapter has four sections: 

• Definition and Background 

• Developments in Advanced Metering 

• Recent AMI Initiatives by States and Utilities 

• Issues and Challenges 

Definition and Background 

The 2006 FERC Demand Response Assessment defined advanced metering as follows: 

Advanced metering is a metering system that records customer consumption [and possibly other 

parameters] hourly or more frequently and that provides for daily or more frequent transmittal of 

measurements over a communication network to a central collection point.115

This report continues to so define advanced metering, but notes that functionality and capability of 

advanced metering (which includes advanced meters, communications networks, and data management 

systems) are evolving. 

What makes meters “advanced” or “smart” is the underlying technology. Advanced metering is based on 

digital electronic and fixed network communications technologies. Through the use of these 

technologies, advanced metering enables potential operational benefits and efficiencies and provides 

support for demand response and energy efficiency programs previously unsupported with older electromechanical meters. AMI’s most basic functions involve reading and recording customer electric (and/or 

gas or water) usage at programmed hourly intervals (or shorter term intervals or on-demand), and then 

storing and forwarding that information over fixed networks for use by customers and customer-based 

systems, grid operators, and utilities. Among the most valuable capabilities of AMI in terms of providing 

operational efficiencies and cost savings are automated remote meter readings and remote outage 

detection, diagnosis, and restoration. 

AMI is significant as a demand-response enabling technology, as well, because the capability to provide 

quality hourly or shorter-term interval data readings is needed to support time-based rates.116 Time-based 

rates, such as real-time pricing, allow customers to be charged rates that vary dynamically over some 

period, e.g., hourly, based on the underlying wholesale cost of electricity in the day-ahead (or real-time 

 115 2006 FERC Demand Response Assessment, 17. 

116 Demand Response and Advanced Metering Coalition (DRAM) comments before the State of New York Public 

Service Commission in the Matter of Competitive Metering, Case 00-E-0165. 
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market). AMI can also allow customers to see their usage and the corresponding price for that usage and 

to modify their usage in response to the price. AMI can also provide utilities and grid operators the 

capability to monitor electric usage by an individual customer as well as by groups of customers, and to 

perform automated or manual load control and distribution system operations and maintenance. 

The communications networks that advanced metering uses may either be configured to allow one-way or 

two-way communications.117 Two-way AMI networks allow communications between both the customer 

and the meter and between the grid operator and the meter. One-way communications networks, by 

comparison, are only designed to support reporting of customer usage from the meter out to the utility 

and/or to grid operators. Two-way AMI communications networks enable the grid operator to control a 

customer’s usage and remotely diagnose and repair outages. Additionally, two-way AMI 

communications networks can provide price information or system conditions to the customer and inhome devices, such as smart thermostats, air conditioning units, and computer networks that link to inhome appliances. Consequently, two-way AMI networks have greater capacity to support various forms 

of demand response. 

AMI requires the use of fixed networks to communicate usage data and should not be confused with 

mobile networking that requires drive-by or walk-by meter readings. Fixed networks used for advanced 

metering may be either wireless-based (e.g., radio frequency (RF)) or wired (such as power line 

communications or broadband over power line) or may be a combination of both wireless and wired 

networking. 

In contrast with AMI and its fixed communications networks, meters can also be read by drive-by or 

walk-by remote readers. These drive-by or walk-by readers are generally referred to as automated meter 

reading (AMR) technology. However, some AMR meter implementations do use fixed networks. AMI 

and AMR are competing technologies, with the implementation of AMR possibly discouraging the 

installation of the more demand response-friendly AMI. This “competition” is discussed below. 

Through May 2007, AMR meters are still out-shipping AMI meters.118 Notably, however, a number of 

utilities have recently announced plans to deploy AMI meters to replace not only electro-mechanical 

meters, but also replace previously installed AMR meters (e.g., Connecticut Light & Power).119 At least 

one analyst forecasts that AMI meter sales will outpace AMR meter sales within 3 to 5 years.120 Together 

AMR and AMI meter sales have been experiencing approximately 20 percent compounded growth yearly 

over the past several years.121 Such compounded growth is forecasted to continue for the next 5 to 6 

years.122 However, AMI near-term growth potential may be capped by existing and near-term available 

manufacturing capability limitations.123

 117 Id.

118 Personal communication with Howard Scott (Cognyst Advisors), June 6, 2007. Cognyst publishes the Scott 

Report: AMR Deployments in North America, which tracks advanced metering shipment data and trends. 

119 CL&P compliance filing, “Advanced Metering Infrastructure Plan,” in Docket No. 05-10-03 Order No. 7. 

120 Howard Scott. 

121 Id.

122 Id.

123 Id.
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AMI Functions 

The list of functions being required of AMI systems by various utilities is growing. The following list is 

a compilation of typical specifications listed by a number of utilities in their recent AMI RFPs.124 

• ability to provide time-stamped interval data for each customer, at least hourly, but often as 

short an interval as 15 or 30 minutes, 

• option of remote disconnect/connect for some or all meters, 

• ability to remotely upgrade meter firmware,125

• ability to send messages to equipment in or around customer home to support demand 

response, 

• positive notification of outage and restoration (promising both significant cost savings and 

customer service benefits), 

• capability to remotely read meters on-demand, 

• voltage flagging capability if voltage is outside of range configurable by utility, 

• voltage interval reading capability at same interval as meter readings, 

• tamper flagging capability, 

• memory to store specified number of days of readings on meters (anywhere from 7 to 45 

days, depending on the utility), 

• support for some form of prepay metering, 

• daily register reading of meters, often at midnight, 

• inclusion of data warehousing systems -- seen as increasingly necessary to store large 

volumes of data gleaned from AMI and meter data management systems (MDM), 

• tight integration with MDM into overall operations management systems -- with links to 

accounting, billing, reporting, outage management, and other operations systems, and 

• ability to extend AMI and smart grids to multiple in-home appliances connected together as 

part of a home-area network (HAN). 

Two notable AMI requirements added to the list of specifications in RFPs since the last report are remote 

connect/disconnect capability and connectivity between the grid and HANs. 

Remote Connect/Disconnect 

Remote connect/disconnect is a key new feature and has been included as a requirement in “almost every 

request for information or RFP issued by major investor owned utilities or large municipals in the last 

year.”126 Southern California Edison in particular, has been a big proponent of this capability because it 

has over five million customers, and well over one million of those customers on average move per 

year.127 With remote connect/disconnect, Southern California Edison is able to disconnect a residence 

when the prior owner vacates and then reconnect remotely when the new customer needs it.128 This 

feature is important for other reasons as well. In Texas, remote connect/disconnect makes it possible to 

 124 Patti Harper-Slaboszewicz (Utilipoint), May 16, 2007. 

125 “Computer programming instructions that are stored in a read-only memory unit rather than being implemented 

through software.” The American Heritage® Dictionary of the English Language, Fourth Edition, 2007, Houghton Mifflin 

Company. 

126 Patti Harper-Slaboszewicz (Utilipoint), May 30, 2007, IssueAlert, available at 

http://www.utilipoint.com/issuealert/article.asp?id=2863. 127 Id.

128 Id.
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easily switch customers from one competitive retail provider to another as needed.129 Remote 

connect/disconnect may also be valuable for its ability to avoid extended outages and overloading of 

transformers at critical peak by allowing grid operators to disconnect customers where lines are 

stressed.130

Home-Area Networks 

The ability to connect to a HAN is another AMI feature that has gained attention in the last year. A HAN 

“is a network contained within a user's home that connects a person's digital devices, from multiple 

computers and their peripheral devices to telephones, VCRs, televisions, video games, home security 

systems, "smart" appliances, fax machines and other digital devices that are wired into the network.”131 

Including a HAN module into the meter allows multiple in-premise (or in-home) appliances to be 

interconnected, yet individually identifiable, potentially affording the following benefits: 

• remote load control over multiple in-home appliances, 

• enhanced ability, with its two-way communications capability, to measure, verify and 

dispatch demand response, and

• feedback displays to consumers showing them the billing effects associated with usage of 

various appliances.132

An illustration of the interconnectedness of HANs with AMI and various devices inside and outside of a 

home is shown in Figure III-1. As this figure illustrates, a HAN-enabled electric meter can serve as the 

hub of communications. 

Figure III-1. Illustration of AMI and home-area-networks

Source: Southern California Edison 

 129 Id.

130 Id.

131 Webopedia.com (http://www.webopedia.com/TERM/H/HAN.html). 

132 UtilityAMI High-Level Requirements, Revision 2.7, Approved August 4, 2006, available at 

http://www.electricitydeliveryforum.org/pdfs/UtilityAMI_High-Level_Reqv2-7Approved.pdf. 
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A significant issue associated with enabling device interconnection is choosing and configuring a 

particular open-standard HAN connectivity solution. Several competing protocols are available. Due 

largely to its inclusion in the Southern California Edison AMI concept, Zigbee, a HAN wireless mesh 

protocol received particular focus.133 Other non-proprietary HAN wireless networks also are available, 

e.g., Z-Wave, Home-Plug, WiFi, Bluetooth, Insteon, and EIA 709. 

Developments in Advanced Metering 

Since last year’s Commission staff report, AMI gained support from a number of initiatives. For 

example, at its 2007 Winter Meeting, the National Association of Regulatory Utility Commissioners 

(NARUC) issued a resolution that recognized the benefits of advanced metering. The resolution calls for 

elimination of barriers to advanced metering and recommends that state commissions provide investment 

incentives and accelerated depreciation to help utilities quickly recover their advanced metering 

investments.134 

Recent AMI Initiatives by States and Utilities 

This section reviews state AMI initiatives, including the status of the AMI proceedings that were required 

in EPAct 2005, and recent announcements of utility AMI deployment. 

EPAct 2005 PURPA Metering Assessments 

Section 1252(b) of EPAct 2005 added a new section 115(i) to the Public Utility Regulatory Policies Act 

of 1978 (PURPA)135 that requires states to investigate demand response and time-based metering. Section 

115(i) of PURPA states that “each state regulatory authority shall conduct an investigation and issue a 

decision whether or not it is appropriate for electric utilities to provide and install time-based meters and 

communications devices for each of their customers which enable such customers to participate in timebased pricing rate schedules and other demand response programs.” Section 1252(b) also requires states 

to report their findings to Congress by August 8, 2007. 

By July 2007, most states had open proceedings to discuss the EPAct provisions. States, such as Ohio, 

commenced comprehensive proceedings to examine the advanced metering PURPA standard. Other 

states, such as California, did not institute a specific PURPA proceeding, but have been engaged in 

detailed, ongoing proceedings relating to AMI. Twelve states have concluded their proceedings, with two 

deciding that it was appropriate for their utilities to provide and install time-based meters. Another 11 

opted to not require it. Information on the activities of state regulatory agencies in response to EPAct 

2005 is included in Appendix E. 

 133 ZigBee is a low-cost, low-power, industry standard (IEE 802.15.4) control system for appliances and applications 

that is adaptable to many different configurations and situations. It securely allows communications using the 8 AES 128 bit 

encryption standard (the same standard that is used in ATM machines) between devices such as lighting controls, thermostats, 

energy display, and security systems. HAN protocols such as ZigBee can provide a control link to demand-response equipment, 

allowing verifiable participation in demand-response programs. [Project No. 31418 -- Rulemaking Related to Advanced 

Metering, Initial Comments of Coalition of Retail Marketers, December 18, 2006] 

134 NARUC Winter 2007, “Resolution to Remove Regulatory Barriers To the Broad Implementation of Advanced 

Metering Infrastructure”, adopted February 21, 2007, available at

http://www.naruc.org/associations/1773/files/resolutions/winter07/res.to.remove.regulatory.barriers.to.the.broad.implementation.

of.advanced.metering.infrastructure.pdf. 135 Pub. L. No. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. titles 15, 16, 26, 30, 42, and 43). 
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State AMI Activity 

In addition to the proceedings required by EPAct 2005, many states have engaged in additional activity 

on advanced metering. State regulators have taken actions ranging from the approval of smart meter 

projects or AMI deployment to re-establishing collaborative efforts and workshops to issuing 

rulemakings. Table III-1 details activity in certain individual states. 

Table III-1. State AMI initiatives 

State Activity 

California PG&E—received approval of its Smart Meter project application from the CPUC. 

SDG&E—received approval of its smart meter project following a settlement with the 

utility, the PUC’s Division of Ratepayer Advocates, and advocacy group the Utility 

Consumers Action Network.136 

SCE—requested approval for its Phase II AMI Pre-Deployment Activities and Cost 

Recovery Mechanism is pending before the CPUC.137

Connecticut The state of Connecticut passed a new DR-AMI bill requiring utilities in the state to: 

o install new “smart” meters and associated technologies capable of 

measuring real-time prices, in support mandatory TOU pricing. 

o deploy AMI by January 1, 2009.138

Connecticut Light & Power—submitted its AMI plan, which is pending before the 

DPUC.139

District of Columbia The DC PSC approved a pilot program (PowerCentsDC), which allows residential 

customers involved with the pilot to test three different pricing schedules.140 It is said 

to be a first of its kind pilot in the electric industry.141

 136 SDG&E's "smart meter" program receives final state approval, April 12, 2007, available at

http://public.sempra.com/newsreleases/viewpr.cfm?PR_ID=2150&Co_Short_Nm=SDGE. 137 SCE’s Application for Approval of Advanced Metering Infrastructure Pre-Deployment Activities and Cost Recovery 

Mechanism, available at http://www.sce.com/NR/rdonlyres/5F9E844C-9958-431D-B822-

A6B72F544174/0/01_2007_AMI_Phase_II_legal_Insert.pdf. 138 CL&P compliance filing “Advanced Metering Infrastructure Plan,” in Docket No. 05-10-03 Order No. 7. See also 

Sections 13(a) and 13(c) of Connecticut’s Public Act 05-01, An Act Concerning Energy Independence (“EIA”). 

139 Id. 140 Formal Case No. 1002, In The Matter Of The Joint Application Of Pepco And The New RC. Inc. For Authorization 

And Approval Of Merger Transaction. DC PSC Order No. 14166 (January 12, 2007). 

141 Transmission & Distribution World, Pilot Program to Help Washington DC Customers Manage Electricity Bills

(May 9, 2007), available at http://tdworld.com/info_systems/highlights/sensus-smart-metering-contract/index.html. 
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Table III-1. State AMI initiatives (Cont.) 

State Activity 

Maryland BG&E—the MD PSC approved BGE’s demand-response pilot program142 and BGE’s 

request for rate schedule changes and surcharges to cover a Phase I pilot of the 

proposed AMI deployment.143 

Pepco—filed for authority to establish surcharges to support DSM and AMI 

deployment initiatives;144 and received approval to establish a DSM Collaborative and 

AMI Advisory Group.145 The DSM Collaborative would review and discuss Pepco’s 

proposed DSM programs. The AMI Advisory Group would “be kept apprised of the 

progress, status, components and development of Pepco’s AMI installation.”146 Pepco 

proposed that the advisory group be comprised at minimum of Pepco, the Maryland 

PSC, the Office of People’s Counsel (OPC), and the Maryland Energy 

Administration.147

New York New York State Public Service Commission (NYSPSC)—issued an Order requiring 

electric utilities to conduct AMI cost-benefit studies and file comprehensive plans for 

development and deployment of advanced metering systems.148 

Con Edison and Energy East (Rochester Gas & Electric (RG&E) and New York State 

Electric & Gas (NYSEG))—have filed their plans.149 In its plan, Energy East suggested 

that with NYSPSC approval, RG&E and NYSEG could begin meter installation as 

early as 2008.150

Con Edison–filed a proposal for an electric rate increase which included $340 million 

to install AMI and AMR (May 4, 2007).151

 142 BG&E filing with MD PSC, January 23, 2007, available at

http://webapp.psc.state.md.us/Intranet/CaseNum/NewIndex3_VOpenFile.cfm?filepath=C%3A%5CCasenum%5C9100-

9199%5C9111%5CItem_1%5CBourland1-23-07.pdf. 143 Id.

144 Application Of PEPCO For Authorization To Establish A Demand Side Management Surcharge And An Advance 

Metering Infrastructure Surcharge And To Establish A DSM Collaborative And An AMI Advisory Group (March 21, 2007). 

145 Pepco DSM/AMI application (March 21,2007). 

146 Id.

147 Id.

148 Notably, Con Edison in its compliance filing, proposes full AMI deployment except where it already had installed 

automated meter reading in Westchester. There it proposes to upgrade the automated meter reading system with pole top 

collectors that allow more frequent than once per month readings (Con Edison compliance filing, March 28, 2007). 

149 Advanced Metering Infrastructure Overview and Plan, Rochester Gas and Electric Corporation 

New York State Electric and Gas Company, February 1, 2007, available at

http://www.dps.state.ny.us/NYSEG_RGE_AMI_Filing.pdf. 150 Id.

151 Con Edison of New York's Electric Rate Case Filing - May 4, 2007, available at

http://investor.conedison.com/phoenix.zhtml?c=61493&p=irol-newsArticle&ID=995985&highlight=. 
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Table III-1. State AMI initiatives (Cont.) 

State Activity 

Ohio PUC of Ohio—adopted recommendations to require state electric distribution 

companies to file reports that included a list of advanced metering technologies and 

costs.152 In that same decision, the PUC of Ohio “indicated that all electric distribution 

utilities should offer tariffs to all customer classes, which are, at a minimum, 

differentiated according to on- and off-peak wholesale periods. Moreover, it noted that 

time-of-use meters should be made available to customers subscribing to the on- and 

off-peak tariffs.”153 

PUC of Ohio—initiated proceeding 07-646-EL-UNC to establish AMI workshops to 

study the cost/benefits of AMI deployment strategies and cost recovery mechanisms.154 

The first workshop was set for July 26, 2007.155

Pennsylvania PA PUC—tasked the Pennsylvania Demand Side Response Working Group to perform 

cost-benefit assessments for all utilities to further develop their advanced metering 

infrastructure.156 

Commonwealth of Pennsylvania— issued a policy statement stating the public should 

have access to historic billing data and real time metered data to facilitate retail choice, 

demand side response, and energy conservation initiatives.157

 152 Case No. 05-1500-EL-COI. 153 Before the PUC of Ohio, In the Matter of the Commission-Ordered Workshop Regarding Smart Metering 

Deployment, Case No. 07-646-EL-UNC (June 27, 2007), available at

http://dis.puc.state.oh.us/TiffToPDf/A1001001A07F27B23701E87977.pdf. 154 Case No. 07-646-EL-UNC, PUC of Ohio (June 27, 2007). 

155 Case No. 07-646-EL-UNC, PUC of Ohio (June 27, 2007). 

156 NOTICES: Investigation of Conservation, Energy Efficiency Activities and Demand Side Response by Energy 

Utilities and Ratemaking Mechanisms to Promote Those Efforts; Doc. No. M-00061984 [36 Pa.B. 6485] [October 21, 2006], 

Public Meeting held September 28, 2006.

157 Final Policy Statement on “Default Service and Retail Electric Markets,” § 69.1812. Information and data access 

(Docket No. M-00072009). 
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Table III-1. State AMI initiatives (Cont.) 

State Activity 

Texas State of Texas—passed legislation (House Bill 2129) in 2006 allowing utilities to use 

surcharges to fund advanced meters.158 

PUC of Texas—issued a proposed rulemaking that lists minimum functionality criteria 

utilities would be required to meet with their advanced metering deployments. The 

Texas rulemaking added several advanced capabilities to the minimum functionality 

criteria, such as two-way communications, capability to provide timely customer usage 

data to retail electric providers, capability for customers to receive pricing signals from 

their retail electricity providers or a designated customer agent, and the ability to 

upgrade capabilities as technology advances.159 The proposed rulemaking also states 

that an electric utility “shall not deploy an AMS (advanced metering system) that has 

not been successfully installed previously with at least 500 advanced elsewhere in the 

world, except for pilot programs.”160

On September 29, 2006, the PUC of Texas reported to the Texas legislature its finding 

that there are no barriers to AMI in Texas.161

Vermont Vermont Public Service Board—opened a docket requiring both statewide AMI and 

utility-by-utility AMI cost-benefit studies.162

Large Utility AMI Deployment Plans and Activity 

AMI market activity, as measured by the number of meters planned or installed, increased nearly threefold from 2005 to 2006, and is projected to double again by 2008. Utilities are signing contracts, filing 

AMI plans with regulators, operating AMI pilot programs, issuing RFPs for AMI infrastructure or 

consulting assistance, and announcing plans to implement AMI. This section documents these 

deployment announcements.163 

Figure III-2 shows a general trend of increased market activity, based on the number of meters installed or 

planned through 2006, and projections for 2007 and 2008. However, this implementation was heavily 

influenced by PG&E’s 2006 announcement of 5 million meters (PG&E accounted for two-thirds of the 

meters in 2006). If all of the announced deployments since the last report that are indicated in this Figure 

actually occur, over 40 million new advanced meters will be deployed in the next several years.164 But 

given the influence of particularly large, individual utilities, penetration may be focused in certain 

geographic areas. 

 158 PUC of Texas, Project No. 31418 Proposal for Publication of Amendments..., etc., as approved at the October 26, 

2006 Open Meeting. 

159 Id.

160 Id.

161 PUC of Texas, January 2007, Report to the 80th Texas Legislature on “Scope of Competition in Electric Markets in 

Texas, available at http://speakuptexas.com/electric/reports/scope/2007/2007scope_elec.pdf. 162 Vermont Public Service Board, Smart Metering RFP available at http://publicservice.vermont.gov/energyefficiency/SmartMeterRFP.pdf. 163 Of course, the most firm indication of market activity is when a utility has an agreement or has signed a contract 

with an AMI vendor. However, until the AMI enabled meter is actually installed, utilities may make changes or delay their AMI 

purchasing activity. 

164 Commission staff estimates that if these announcements result in deployments, the market penetration of advanced 

metering in the U.S. could be over 20 percent by the end of 2010. 
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Figure III-2. AMI market activity, actual and projected 

Source: UtiliPoint International 

Notes: 

• Contracted: the utility and the AMI vendor announced an agreement and/or signed a contract. 

• Filed AMI plan: the investor owned utility filed a plan to invest in AMI with its regulator. 

• On going pilot: the utility is actively engaged in piloting AMI systems from one or more AMI vendors. 

• Market activity: the utility has issued RFPs for either AMI or an AMI consultant, or has hired an AMI 

consultant to prepare an RFP for AMI. 

• Utility plans: the utility has publicly announced plans for investing in AMI. 

Because one utility can have such a large impact on data, another means to assess trends in utility AMI 

deployments is through counting the number of utility announcements per year. This adjusts for the 

impact that one or two large utilities, such as PG&E, can have on the number of meters deployed. Figure 

III-3 presents the trend in AMI deployment as measured by the number of large utility deployments. 

0

5

10

15

20

25

1996 1997 1999 2001 2002 2004 2005 2006 2007 2008

Year 

Millions of Meters

Utility plans

Market Activity

Ongoing Pilot

Filed AMI plan

Contracted

0

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10

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20

25

1996 1997 1999 2001 2002 2004 2005 2006 2007 2008

Year 

Millions of Meters

Utility plans

Market Activity

Ongoing Pilot

Filed AMI plan

Contracted
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Figure III-3. Number of utilities announcing AMI deployments 

Source: UtiliPoint International

In 2006, five utilities announced large deployments of AMI, and by 2007 an additional 17 large AMI 

deployment announcements are expected, with various degrees of certainty. Five have been announced to 

date. Projections suggest that 2007 and 2008 should continue the trend of increasing activity in the 

market. 

A detailed list of some of the large AMI deployments that have been announced or are expected with 

some level of confidence by the end of 2008 can be found in Table F-1 in Appendix F.165 Of particular 

note in this list are several recent announcements. 

• Pepco Holdings, Inc., filed a Blueprint for the Future with Delaware, District of Columbia, and 

Maryland, which includes plans to deploy AMI for all of its customers to support demand 

response, the environment, improve customer service, and reduce operational costs. 

• The three California investor-owned utilities are all pursuing AMI with strong encouragement 

from the CPUC. PG&E is in the early stages of deploying their 5.1 million meters while SCE 

and SDG&E are expected to begin deployment in 2007 or 2008. Together these three utilities 

represent over 10 million meters. 

• Duke Energy has also announced plans to deploy AMI in its Kentucky operations. In testimony 

filed with the Public Service Commission of Kentucky in 2006, Duke Energy noted that “Duke 

Energy Kentucky expects to deploy AMI infrastructure in the near future.”166 Another large 

utility (close to five million meters), American Electric Power, is evaluating AMI “for 

 165 Table F-1 in Appendix F is based on a forecast of implementation compiled by Patti Harper-Slaboszewicz of 

UtiliPoint International under contract to FERC. 

166 Direct Testimony of Bruce L. Sailers on Behalf of Duke Energy Kentucky, In the Matter of Consideration of the 

Requirements of the Federal Energy Policy Act of 2005 Regarding Time-Based Metering, Demand Response, and 

Interconnection Service, May 19, 2006, 10. 

0

2

4

6

8

10

12

14

16

18

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Year

Number of Utilities

0

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4

6

8

10

12

14

16

18

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Year

Number of Utilities
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deployment initially within our largest urban areas. AEP has performed a detail analysis for 

Columbus, Ohio, and is awaiting regulatory review before proceeding further.”167 

• Large cooperatives and municipal utilities are also implementing advanced metering. The City of 

Tallahassee, Florida (108,000 meters) has announced plans for AMI in 2007,168 as well as plans 

for the deployment of smart thermostats. 

Issues and Challenges 

In its review of issues associated with advanced metering, Commission staff identified three important 

issues and challenges: 

• Technological obsolescence concerns 

• Deployment decisions 

• Interoperability and open standards 

Technological Obsolescence Concerns 

According to its many proponents, AMI technology has arrived. Most of the issues facing AMI that 

remain are associated with deployment strategies. Still, issues of uncertain meter life-expectancy and risk 

of post-installation technological obsolescence remain, which would result in having to replace the meters 

before original costs are recovered. Notably, metering analysts report that a number of recent RFPs have, 

as a result, included requirements for warranties of advanced metering equipment and have required that 

the firmware be remotely upgradeable, in order to mitigate these risks.169 

Deployment Decisions 

AMI implementations come with a significant price tag, even as the cost of the advanced meters 

themselves continues to decrease. This is especially true for large and full-featured AMI deployments. 

Furthermore, utilities and their regulators are faced with evaluating a number of alternative metering 

products, network configurations, and deployment strategies in designing and evaluating AMI systems for 

cost-effectiveness over the life of the meters. Pilots or test-phase deployments continue to be used 

extensively to assess costs and benefits and to allow both utilities and their customers to test and “try out” 

various AMI products, configurations, and features. 

Interoperability and Open Standards 

As discussed in more detail in last year’s Commission staff report, there are technology standards on 

common functionality of AMI systems. In particular, ANSI standard C12.19 (Utility Industry End 

Device Tables) enables metering data and data tables to be transferred from one computer application and 

system to another. The next standard, ANSI standard C12.22 (Protocol Specification for Interfacing to 

Data Communications Networks), which would enable C12.19 metering data structures to be shared over 

any combination of “physical” network media,170 is pending. 

 167 “Utility Considering its Advanced Metering Options”, Energy Pulse, J. Carr and D. Fitchett, February 16, 2007. 

168 At the March 28, 2007 City Commission meeting, the decision to invest in Smart Metering and Smart thermostats 

was approved by the City Commission which oversees the city utility. See 

http://www.talgov.com/commission/meetings/agendas/070328.cfm. 169 Information provided FERC by Patti Harper-Slaboszewicz (Utilipoint), May 16, 2007. 

170 Notably, the state of Texas has included C12.22 compliance among its list of minimum AMS features that a utility 

is required to include with its AMS deployment. 
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Since last year’s Commission staff report, utilities looking to deploy AMI with HAN-connectivity have 

focused attention on how to configure HAN to AMI systems connections.171 HAN connectivity 

represents a new opportunity for advanced metering, but also introduces a new issue. The heart of the 

issue is whether the utility-owned meter should serve as the connection (or “gateway”) to the HAN, or 

whether AMI-based gateways only serve to exclude competitive third-party HAN solutions. In other 

words, deploying advanced meters with grid-to-HAN gateway switches makes those gateways part of the 

utility-provided metering solution. Some AMI consultants as well as HAN solution vendors argue that 

third party HAN connectivity solutions do not need utility-based advanced meter gateway switches.172 

Proponents of utility-based gateways, on the other hand, argue that utilities are best positioned to provide 

meter-to-HAN connectivity services and that use of these gateways allows needed central administration 

and verification for load control and demand-response purposes, e.g., “to provide Critical Peak Pricing 

(CPP) and other emergency event customer notifications.,” “...provide better confirmation that these 

notifications were both sent and received,” and “significantly reduce the need to outsource such 

communication activities to third party providers.”173 

 171 Information provided to FERC staff by Patti Harper-Slaboszewicz (Utilipoint), May 16, 2007. 

172 Personal communications with Roger Levy (Levy and Associates), May 31, 2007. 

173 Supplemental Testimony Supporting Southern California Edison Company’s (U 338-E) Application for Approval 

of Advanced Metering Infrastructure Deployment Strategy and Cost Recovery Mechanism; VOLUME 5 – Advanced Integrated 

Meter(AIM) Directional Cost Benefit Analysis and Future Benefits Allocation; Before the Public Utilities Commission of the 

State of California (August 1, 2005). See http://www.sce.com/NR/rdonlyres/F595B029-0189-4C2B-932AB589BA052B49/0/SCEMarch30_2005_Application_Vol5.pdf 
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Appendix A – Glossary for the Report 

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A-1

Appendix A: Glossary for the Report 

Actual Annual MWh change: The actual sum of MWh changes due to customer participation in a 

sponsored Demand Response (DR) program. 

Actual MWh Change: The total annual change in energy consumption (measured in MWh) that 

resulted from the deployment of demand-response programs during the year. 

Actual Peak Reduction (APR): The coincident reductions to the annual peak load (measured in 

megawatts) achieved by customers that participate in a demand-response program at the time of the 

annual system peak of the utility or ISO. It reflects the changes in the demand for electricity resulting 

from a sponsored demand-response program that is in effect at the same time a utility or ISO 

experiences its annual system peak load, as opposed to the installed peak load reduction capability 

(i.e., Potential Peak Reduction). It should account for the regular cycling of energy efficient units 

during the period of annual system peak load. For curtailment service providers (CSP), the actual 

peak reduction should include the demand-response load provided at the time of the peak for the 

region in which they aggregate customer load. For utilities, it should include the demand-response 

load at the time of the utility annual system peak load. For RTOs/ISOs, it should include the demandresponse load at the time of the RTO/ISO annual system peak load.

Advanced Metering Infrastructure (AMI): AMI or “advanced metering” is defined as a metering 

system that records customer consumption [and possibly other parameters] hourly or more frequently 

and that provides for daily or more frequent transmittal of measurements over a communication 

network to a central collection point. AMI includes the communications hardware and software and 

associated system and data management software that creates a network between advanced meters and 

utility business systems and which allows collection and distribution of information to customers and 

other parties such as competitive retail providers, in addition to providing it to the utility itself. 

Ancillary Services: Those services necessary to support the transmission of electric power from seller 

to purchaser, given the obligations of control areas and transmitting utilities within those control areas, 

to maintain reliable operations of the interconnected transmission system. Ancillary services supplied 

with generation include load following, reactive power-voltage regulation, system protective services, 

loss compensation service, system control, load dispatch services, and energy imbalance services. 

Ancillary Service Market Programs: Demand-response programs in which customers bid load 

curtailments in RTO/ISO markets as operating reserves. If their bids are accepted, they are paid the 

market price for committing to be on standby. If their load curtailments are needed, they are called by 

the RTO/ISO, and may be paid the spot market energy price. 

Asset Management: The ability to leverage the value of metering data and other available 

information to increase the value of utility investments and/or to improve customer service. One 

example is using hourly interval data to measure the load on transformers at the time of the system 

peak. 

Automated Meter Reading: automatic or automated meter reading -- allows meter read to be 

collected without actually viewing or touching the meter with any other equipment. One of the most 

prevalent examples of AMR is mobile radio frequency whereby the meter reader drives by the 

property, and equipment in the car receives a signal sent from a communication device under the glass 

of the meter. 

Balancing Authority: The responsible entity that integrates resource plans ahead of time, maintains 

load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection 
Appendix A – Glossary for the Report 

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A-2 

frequency in real time. 

Bid Limits: The maximum $/MWh bid that can be submitted by a program participant. 

Billing or Revenue Meter: Meters installed at customer locations that meter electric usage and 

possibly other parameters associated with a customer account and provide information necessary for 

generating a bill to the customer for the customer account. 

Capacity Market Programs (CAP): Demand-response programs in which customers offer load 

curtailments as system capacity to replace conventional generation or delivery resources. Customers 

typically receive day-of notice of events and face penalties for failure to curtail when called upon to do 

so. Incentives usually consist of up-front reservation payments. 

Commercial sector: An energy-consuming sector that consists of service-providing facilities and 

equipment belonging to: businesses; federal, state, and local governments; and other private and 

public organizations, such as religious, social, or fraternal groups. The commercial sector includes 

institutional living quarters, sewage treatment facilities, and street lighting. Common uses of energy 

associated with this sector include space heating, water heating, air conditioning, lighting, 

refrigeration, cooking, and running a wide variety of other equipment. Note: This sector includes 

generators that produce electricity and/or useful thermal output primarily to support the activities of 

the above-mentioned commercial establishments. 

Conservation. Conservation includes consumer actions or decisions to use less energy, perhaps by 

reconsidering priorities and eliminating some energy use. Actions could include turning off extra 

lights, raising thermostats in summer or lowering them in winter, and taking pre-vacation steps such as 

turning off power strips or lowering water-heater temperatures. Conservation and energy efficiency 

(see separate definition) are often used as though they are synonymous, because both reduce kilowatt 

hours used by consumers. 

Contingency Reserve: The provision of capacity deployed by the Balancing Authority to meet the 

Disturbance Control Standard (DCS) and other NERC and Regional Reliability Organization 

contingency requirements.

Cooperative Electric Utility: An electric utility legally established to be owned by and operated for 

the benefit of those using its service. The utility company will generate, transmit, and/or distribute 

supplies of electric energy to a specified area not being serviced by another utility. Such ventures are 

generally exempt from federal income tax laws. Most electric cooperatives were initially financed by 

the Rural Utilities Service (formerly the Rural Electrification Administration), U.S. Department of 

Agriculture. 

Critical Peak Pricing (CPP): CPP rates are a hybrid of the TOU and RTP design. The basic rate 

structure is TOU. However, provision is made for replacing the normal peak price with a much higher 

CPP event price under specified trigger conditions (e.g., when system reliability is compromised or 

supply prices are very high). 

Curtailment Service Provider (CSP): Demand-response load providers that are not necessarily load 

serving entities. CSPs may sponsor demand-response programs and sell the demand-response load to 

utilities, RTOs and/or ISOs. 

Customer Account: A record at the energy provider that identifies an entity receiving electric service 

at one or more locations within the utility service footprint. The identified entity is responsible for 

paying the cost of energy consumed and metered at the location(s) on the account. There may be no 

meter associated with the customer account (such as with street lights), or one or more meters 

associated with a particular customer account. 
Appendix A – Glossary for the Report 

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A-3

Demand: Represents the requirements of a customer or area at a particular moment in time. Typically 

calculated as the average requirement over a period of several minutes to an hour, and thus usually 

expressed in kilowatts or megawatts rather than kilowatt-hours or megawatt-hours. Demand and load 

are used interchangeably when referring to energy requirements for a given customer or area. 

Demand Bidding: A demand-response program where customers or curtailment service providers 

offer bids to curtail based on wholesale electricity market prices or an equivalent. Mainly offered to 

large customers (e.g., one MW and over), but small customer demand-response load can be aggregated 

by curtailment service providers and bid into the demand bidding program sponsor. 

Demand Response (DR): Changes in electric usage by end-use customers from their normal 

consumption patterns in response to changes in the price of electricity over time, or to incentive 

payments designed to induce lower electricity use at times of high wholesale market prices or when 

system reliability is jeopardized. 

Demand Response Aggregator: A company who bids demand reductions or acts an agent on behalf 

of retail customers directly into the RTO’s or ISO’s organized markets. Demand-response aggregators 

act as an intermediary for many small retail loads that cannot individually participate in the organized 

market because they lack standing as an LSE or because they individually cannot meet a requirement 

that a demand-response bid be of minimum size. 

Demand Response Event: A period of time identified by the demand-response program sponsor 

when it is seeking reduced energy consumption and/or load from customers participating in the 

program. Depending on the type of program and event (economic or emergency), customers are 

expected to respond or decide whether to respond to the call for reduced load and energy usage. The 

program sponsor generally will notify the customer of the demand-response event before the event 

begins, and when the event ends. Generally each event is a certain number of hours, and the program 

sponsors are limited to a maximum number of events per year. 

Demand Response Load: The load reduction that results from demand-response activities. 

Demand Resources: The set of demand response and energy efficiency resources and programs that 

can be used to reduce demand or reduce electricity demand growth. 

Demand-Side Management (DSM): The planning, implementation, and monitoring of activities 

designed to encourage consumers to modify patterns of electricity usage, including the timing and 

level of electricity demand. It does not refer to energy and load-shaped changes arising from the 

normal operation of the marketplace or from government-mandated energy-efficiency standards. 

Demand-Side Management covers the complete range of load-shape objectives, including strategic 

conservation and load management, as well as strategic load growth. 

Direct Load Control (DLC): A demand-response activity by which the program operator remotely 

shuts down or cycles a customer’s electrical equipment (e.g. air conditioner, water heater) on short 

notice. Direct load control programs are primarily offered to residential or small commercial 

customers. 

Duration of Event: The length of an Emergency or Economic Demand Response Event in hours. 

EIA ID Number: Unique identification number assigned by EIA to companies and entities operating 

in the electric power industry. 

Economic Demand Response Event: A demand-response event in which the demand-response 

program sponsor directs response to an economic market opportunity rather than for reliability or 

because of an emergency in the energy delivery system of the program sponsor or the RTO/ISO. 
Appendix A – Glossary for the Report 

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A-4 

Elasticity of Demand: The degree to which consumer demand for a product responds to changes in 

price, availability or other factors. 

Electric Reliability Council of Texas (ERCOT): The electric reliability organization which ensures 

reliable and cost-effective operation of the grid in the Texas area. 

Electric Utility: A corporation, person, agency, authority, or other legal entity or instrumentality 

aligned with distribution facilities for delivery of electric energy for use primarily by the public. 

Included are investor-owned electric utilities, municipal and state utilities, federal electric utilities, and 

rural electric cooperatives. A few entities that are tariff based and affiliated with companies that own 

distribution facilities are also included. 

Emergency Demand Response Event: A demand-response event called by the program sponsor in 

response to an emergency of the delivery system of the demand-response sponsor or of another entity 

such as a utility or ISO. 

Emergency Demand Response Program (EDRP): A demand-response program that provides 

incentive payments to customers for load reductions during periods when reserve shortfalls arise. 

Energy: The capacity for doing work as measured by the capability of doing work (potential energy) 

or the conversion of this capability to motion (kinetic energy). Energy has several forms, some of 

which are easily convertible and can be changed to another form useful for work. Most of the world's 

convertible energy comes from fossil fuels that are burned to produce heat that is then used as a 

transfer medium to mechanical or other means in order to accomplish tasks. Electrical energy is 

usually measured in kilowatt-hours.

Energy Efficiency: Refers to using less energy to provide the same or improved level of service to 

energy consumers in an economically efficient way. Energy efficiency uses less energy by employing 

products, technologies, and systems to use less energy to do the same or better job than by 

conventional means. Energy efficiency saves kilowatt-hours on a persistent basis, rather than being 

dispatchable for peak hours, as are some demand-response programs. Energy efficiency can include 

switching to energy-saving appliances (such as Energy Star® certified products) and advanced 

lighting (compact fluorescent or LED lighting); improving building design and construction (better 

insulation and windows, tighter ductwork, use of high-efficiency heating, ventilation, and air 

conditioning); and redesigning manufacturing processes (advanced electric motor drives, heat recovery 

systems) to use less energy, thus reducing use of electricity and natural gas. 

Enhanced Customer Service: The ability to offer ultimate customers the choice of bill data, 

additional rate options such as real time pricing or critical peak pricing, verify an outage or restoration 

of service following an outage, more information to understand a customer concern over an electric 

bill, reduce bill estimates when a meter read is not available, opening or closing of an account due to 

customer relocation without requiring a site visit to the meter(s), and/or more accurate bills. 

Enrollment: The amount of customer participation in a demand-response program. Participation 

refers to either the number of customers or the amount of MW who have registered for a program and 

have met eligibility criteria. Customer participation in a program does not necessarily imply that the 

customer will actively adjust their consumption due to direction from a grid operator or price signals. 

Consequently, enrollment typically measures potential demand reduction that could be achieved. 

Fixed Network: A fixed network refers to either a private or public communication infrastructure 

which allows the utility to communicate with meters without visiting or driving by the meter location. 

Florida Reliability Coordinating Council (FRCC): The FRCC is one of eight Regional Reliability 

Councils in the lower 48 states that comprise the North American Electric Reliability Corporation 

(NERC). It covers Peninsular Florida, east of the Apalachicola River. 
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Gas Meter: A meter that measures natural gas usage for ultimate customers. 

Home-Area Network (HAN): Network contained within a user's home that connects a person's 

digital devices, from multiple computers and their peripheral devices to telephones, VCRs, televisions, 

video games, home security systems, "smart" appliances, fax machines and other digital devices that 

are wired into the network. 

ICAP Credit: An RTO or ISO capacity credit to satisfy a resource requirement. 

Independent System Operator (ISO): An organization that has been granted the authority to operate, 

in a nondiscriminatory manner, the transmission assets of the participating transmission owners in a 

fixed geographic area. ISOs often run organized markets for spot electricity. 

Industrial: The energy-consuming sector that consists of all manufacturing facilities and equipment 

used for producing, processing, or assembling goods. The industrial sector encompasses the following 

types of activity: manufacturing; agriculture, forestry, and fisheries; mining; and construction. 

Overall energy use in this sector is largely for process heat and cooling and powering machinery, with 

lesser amounts used for facility heating, air conditioning, and lighting. Fossil fuels are also used as 

raw material inputs to manufactured products. This sector may include energy deliveries to large 

commercial customers, and may exclude deliveries to small industrial customers which may be 

included in the commercial sector. It also may classify by using the North American Industry 

Classification System or on the basis of energy demand or annual usage exceeding some specified 

limit set by the energy provider.

Industrial Customer: Electric power consumers which usually consume large amounts of electricity 

and are usually in the manufacturing, construction, mining, agriculture, fishing or forestry industries. 

Utilities usually classify service to these consumers based on their power demand or an annual usage 

amount which exceeds some specified limit. 

Interface with Water or Gas Meters: The ability of the AMI network to collect water or gas meter 

readings and to transmit the gas or water meter readings over the AMI network to an entity that can 

provide the gas or water meter readings to the gas or water utility providing the service. 

Interruptible/Curtailable Service (I/C): Curtailment options integrated into retail tariffs that 

provide a rate discount or bill credit for agreeing to reduce load during system contingencies. 

Penalties may be assessed for failure to curtail. In some instances, the demand reduction may be 

affected by direct action of the System Operator (remote tripping) after notice to the customer in 

accordance with contractual provisions. For example, demands that can be interrupted to fulfill 

planning or operating reserve requirements normally should be reported as Interruptible Demand. 

Interruptible programs have traditionally been offered only to the largest industrial (or commercial) 

customers. Interruptible Demand as reported here does not include Direct Control Load or price 

responsive demand response. 

Interval Data: Interval data is a fine-grained record of energy consumption, with readings made at 

regular intervals throughout the day, every day. Interval data is collected by an interval meter, which, 

at the end of every interval period, records how much energy was used in the previous interval period. 

Common forms of interval data include 15-minute data and hourly data. 

Investor-Owned Utility (IOU): A utility organized under state law as a publicly traded corporation 

for the purposes of providing electric power service and earning profits for its stockholders. 

Kilowatt (kW): One thousand watts.

Kilowatt-hour (kWh): One thousand watt-hours. 
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Line Loss: Electric energy lost because of the transmission of electricity. Much of the loss is thermal 

in nature.

Load (Electric): The amount of electric power delivered or required at any specific point or points on 

a system. The requirement originates at the energy-consuming equipment of the consumers.

Load Acting as a Resource (LaaR): An interruptible program operated by ERCOT in which 

customers may qualify to provide operating reserves. 

Load Forecasting: The estimation of future load requirements for specified intervals for a period of 

time. The load forecast may provide an estimate of hourly loads for a group of ultimate customers for 

the next five years, for example. 

Load Management: Demand management practices directed at reducing the maximum kilowatt 

demand on an electric system and/or modifying the coincident peak demand of one or more classes of 

service to better meet the utility system capability for a given hour, day, week, season, or year. 

Load-serving entity (LSE): Any entity, including a load aggregator or power marketer, that serves 

end-users within a control area and has been granted the authority or has an obligation pursuant to 

state or local law, regulation, or franchise to sell electric energy to end-users located within the control 

area. 

Maximum Demand: This is determined by the interval in which the 60-minute integrated demand is 

the greatest. 

Maximum Hourly Load: The highest amount of demand that is measured or expected to be curtailed 

at a certain point in time. 

Megawatt (MW): One million watts of electricity. 

Megawatt-hour (MWh): One thousand kilowatt-hours or 1 million watt-hours. 

Meter Data Management: Meter data management provides utilities a place to store meter data 

collected from advanced meters. Utilities that install AMI usually invest in meter data management to 

provide storage for the large number of meter readings that will be collected each year per meter. 

Meter data management can also translates raw meter data into systems, such as billing, customer 

service, etc., that require meter data transformed in a particular way. 

Midwest Reliability Organization (MRO): The Midwest Reliability Organization (MRO) is one of 

eight Regional Reliability Councils in the lower 48 that comprise NERC. Its members include the 

following states: Minnesota, Wisconsin, Iowa, North Dakota, South Dakota, Nebraska, Montana, 

Illinois and Upper Peninsula of Michigan. 

Minimum Term: The minimum length in years that customers are obligated to participate in a 

demand-response program. 

Municipality: A village, town, city, county, or other political subdivision of a state.

National Association of Regulatory Utility Commissioners (NARUC): A non-profit organization 

whose members include the governmental agencies that are engaged in the regulation of utilities and 

carriers in the fifty states, the District of Columbia, Puerto Rico. 

North American Electric Reliability Corporation (NERC): The organization certified by the 

Commission as the reliability organization for the nation’s bulk power grid. NERC consists of eight 

Regional Reliability Councils in the lower 48 states. The members of these Councils are from all 

segments of the electricity supply industry - investor-owned, federal, rural electric cooperative, 

state/municipal, and provincial utilities, independent power producers, and power marketers. 
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Operating Company: The name a utility uses in doing business within a particular state associated 

with a particular service territory. 

Outage Management: The response of an electric utility to an outage affecting the ultimate 

customers of the electric service. The utility may use the AMI network to detect outages, verify 

outages, map the extent of an outage, or verify the service has been restored after repairs have been 

made. 

Peak Demand: The maximum load during a specified period of time. 

Potential MWh Change: The potential total annual change in energy consumption (measured in 

MWh) that would result from the deployment of demand-response programs. It reflects the total 

change in consumption if the full demand reduction capability of the program were deployed, as 

opposed to actual MWh change during the year.

Potential Peak Reduction: The potential annual coincident peak load reduction (measured in 

megawatts) that can be deployed from demand-response programs. It represents the load that can be 

reduced either by the direct control of the utility system operator or by the consumer in response to a 

utility request to curtail load. It reflects the installed load reduction capability, as opposed to the 

Actual Peak Reduction achieved by participants, during the time of annual system peak load. It should 

account for the regular cycling of energy efficient units during the period of system peak load. For 

utilities, it should be the potential sum of demand reduction capability to their annual peak load 

(measured in megawatts) achieved by the program participants. For an RTO or ISO, it should be the 

sum of coincident reduction capability to the RTO or ISO achieved by participants at the time of 

system peak of the RTO or ISO. Similarly, for CSPs, it should be the sum of coincident reduction 

capability sponsored by the CSP and achieved by demand-response program participants at the time of 

the peak for the region in which the CSP is aggregating customer load. 

Power Marketers: Business entities, including energy service providers, that are engaged in buying 

and selling electricity, but do not own generating or transmission facilities. Power marketers and 

energy service providers, as opposed to brokers, take ownership of the electricity and are involved in 

interstate trade. Power marketers file with the Federal Energy Regulatory Commission (FERC) for 

status as a power marketer. Energy service providers may not register with FERC but may register 

with the states if they undertake only retail transactions.

Power Quality Monitoring: The ability of the AMI network to discern, record, and transmit to the 

utility instances where the voltage and/or frequency were not in ranges acceptable for reliability. 

Premise Device/Load Control Interface or Capability: The ability of the AMI network to 

communicate directly with a device located on the premises of the ultimate customer, which may or 

may not be owned by the utility. These might include a programmable communicating thermostat or a 

load control switch. 

Pre-Pay Metering: A metering and/or software and payment system that allows the ultimate 

customer to pay for electric service in advance. 

Price Responsive Demand Response: All demand-response programs that include the use of timebased rates to encourage retail customers to reduce demands when prices are relatively high. These 

demand-response programs may also include the use of automated responses. Customers may or may 

not have the option of overriding the automatic response to the high prices. 

Pricing Event Notification Capability: The ability of the AMI network to convey to utility 

customers participating in a price responsive demand-response program that a demand-response event 

is planned, beginning, ongoing, and/or ending. 
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Provision of Usage Information to Customers: The ability of the AMI network to convey to 

ultimate customers information on their usage in a timely fashion. Timely in this context would be 

dependent on the customer class, with larger customers generally receiving the information with less 

lag time than residential customers. 

Public Utility: An enterprise providing essential public services, such as electric, gas, telephone, 

water, and sewer under legally established monopoly conditions.

Public Utility District: Municipal corporations organized to provide electric service to both 

incorporated cities and towns and unincorporated rural areas. 

Publicly Owned Electric Utility: A class of ownership found in the electric power industry. This 

group includes those utilities operated by municipalities, political subdivisions, and state and federal 

power agencies (such as BPA or TVA). 

Railroad and Railway Electric Service: Electricity supplied to railroads and interurban and street 

railways, for general railroad use, including the propulsion of cars or locomotives. Such electricity is 

supplied under separate and distinct rate schedules.

Real Time Pricing (RTP): A retail rate in which the price for electricity typically fluctuates hourly 

reflecting changes in the wholesale price of electricity. RTP prices are typically known to customers 

on a day-ahead or hour-ahead basis. 

Reduce Line Losses: The ability to use the AMI network to lower the line losses on the transmission 

system. 

Regional Transmission Organization (RTO): An organization with a role similar to that of an 

independent system operator but covering a larger geographical scale and involving both the operation 

and planning of a transmission system. RTOs often run organized markets for spot electricity. 

Reliability-Based Program: Programs that are activated during system emergencies or to maintain 

local or system reliability. Reliability-based demand-response programs typically include emergency 

demand-response programs, capacity market programs, direct load control (DLC), 

interruptible/curtailable rates, and ancillary-services market programs. 

Remotely Change Metering Parameters: The ability to change parameters associated with a 

particular revenue or billing meter, such as the length of the data interval measured, without a site visit 

to the meter location. 

Remote Connect/Disconnect: The ability to physically turn on or turn off power to a particular 

billing or revenue meter without a site visit to the meter location. 

Residential: The energy-consuming sector that consists of living quarters for private households. 

Common uses of energy associated with this sector include space heating, water heating, air 

conditioning, lighting, refrigeration, cooking, and running a variety of other appliances. The 

residential sector excludes institutional living quarters. This sector may exclude deliveries or sales to 

apartment buildings or homes on military bases (these buildings or homes may be included in the 

commercial sector). 

Response Time: The maximum notice and lead time that a demand-response program sponsor 

provides to demand-response program participants prior to an economic or emergency demandresponse event. 

Responsive Reserve: The daily operating reserves in ERCOT that are intended to help restore the 

frequency of the interconnected transmission system within the first few minutes of an event that 

causes a significant deviation from the standard frequency.
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Retail: Sales covering electrical energy supplied for residential, commercial, and industrial end-use 

purposes. Other small classes, such as agriculture and street lighting, also are included in this 

category.

Revenue Assurance: A set of activities designed to increase the revenue from providing electric 

service to ultimate customers, including locating meters without associated customer accounts, 

relatively high line losses compared with other similar locations, energy theft, and/or improper 

metering installations. 

Service Territory: The area within a particular state where an electric utility is allowed to provide 

ultimate customers for distribution, transmission, or energy services. 

Smart Grid: Real-time visualization technologies on the transmission level and smart meter and 

communications technologies on the distribution level that enable demand response, distributed energy 

systems (generation, storage, thermal), consumer energy management systems, distributed automation 

systems and smart appliances. 

Smart Metering: See definition for Advanced Metering 

Smart Thermostat: Thermostats that adjust room temperatures automatically in response to price 

changes or remote signals from system operators. Also known as programmable communicating 

thermostats. 

Specific Event Limits: The maximum number of events that can be called during a year. 

Southwest Power Pool (SPP): The Southwest Power Pool is both the RTO and NERC reliability 

organization for Kansas, Missouri, Oklahoma, and part of New Mexico. 

System (Electric): Physically connected generation, transmission, and distribution facilities operated 

as an integrated unit under one centralized manager or operations supervisor.

Theft Detection: The ability to detect when a revenue or billing meter has been potentially tampered 

with and to indicate a potential energy theft in progress that should be further investigated by the 

utility. 

Time-Based Rate (TBR): A retail rate in which customers are charged different prices for different 

times during the day. Examples are time-of-use (TOU) rates, real time pricing (RTP), hourly pricing, 

and critical peak pricing (CPP). 

Time-of-use (TOU) Rate: A rate with different unit prices for usage during different blocks of time, 

usually defined for a 24 hour day. TOU rates reflect the average cost of generating and delivering 

power during those time periods. Daily pricing blocks might include an on-peak, partial-peak, and 

off-peak price for non-holiday weekdays, with the on-peak price as the highest price, and the off-peak 

price as the lowest price.

Transformer: A device that operates on magnetic principles to increase (step up) or decrease (step 

down) voltage.

Transmission: The movement or transfer of electric energy over an interconnected group of lines and 

associated equipment between points of supply and points at which it is transformed for delivery to 

consumers or is delivered to other electric systems. Transmission is considered to end when the 

energy is transformed for distribution to the consumer.

Transmission System (Electric): An interconnected group of electric transmission lines and 

associated equipment for moving or transferring electric energy in bulk between points of supply and 

points at which it is transformed for delivery over the distribution system lines to consumers.
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Transportation: An energy consuming sector that consists of electricity supplied and services 

rendered to railroads and interurban and street railways, for general railroad use including the 

propulsion of cars or locomotives, where the electricity is supplied under separate and distinct rate 

schedules. 

Type of Organization: in fielding the FERC Survey, this allowed Commission staff to identify the 

type of organization that best represents the energy market participant. The possible categories were : 

Investor-owned utilities (IOU), Municipal Utility (M), Cooperative Utility (C), State-owned Utility 

(S), Federally-owned Utility (F), Independent System Operator (ISO), Regional Transmission 

Operator (RTO), Curtailment Service Provider (CSP), or other (O).

Ultimate Consumer: A consumer that purchases electricity for its own use and not for resale.

Uncommitted Capacity: Generating resources that are physically located in the region, but are not 

dedicated or contractually committed to serve load in the region.

Watt (W): The unit of electrical power equal to one ampere under a pressure of one volt. A watt is 

equal to 1/746 horsepower.

Watt-hour (Wh): The electrical energy unit of measure equal to one watt of power supplied to, or 

taken from, an electric circuit steadily for one hour.

Year of Study: Identification of the projected years covered by a specified study.
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-1

Appendix B: Documentation of 2006 Demand Response 

Estimates 

Table B-1 provides additional support for Figure II-1 on the level of demand response achieved during 

summer 2006. Following Table B-1 are the source notes for Figure II-1 and Table B-1. 
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-2 

OP4- Action 12 6.1% 227.1 4,070 3,701 2 Aug * SW Conn.

OP4- Action 12 2.1% 597 28,490 28,130 2 Aug * ISO-New England

Emergency DR activated 2.8% 948 35,018 33,939 2 Aug * NYISO

Full Emergency Load 

Response 3.3% 2,050 64,067 62,017 2 Aug * Mid Atlantic

Not called outside 

Mid-Atlantic 1.4% 2,050 148,001 144,644 2 Aug * PJM

Max Gen Warning; 

NERC EEA2 2.3% 2,651 117,000 113,750 1 Aug Midwest ISO

None called Unknown Not called Not applicable 42,227 19 Jul * SPP

Yellow: 

Conservation Needed Not applicable Not called 64,567 62,339 17 Aug * ERCOT

Emergency Stages 1 & 2 4.1% 2,066 52,336 50,270 24 Jul * CAISO

Emergency Procedures and 

Levels called by 

System Operators

Demand 

Response as 

Percent

of System 

Peak

Demand 

Response 

(MW)

Projected 

System Peak 

(MW)

Actual 

System 

Peak 

(MW)

Date of 

Summer 

2006 Peak 

Load

Transmission 

System Operator

Table B-1. Summary of RTO and ISO area demand response in summer 2006

Sources: Numbers in this table are based on data available to Commission staff, including RTO and ISO publications, and interviews with RTOs and ISOs and with other market participants. The column “demand response as percent of peak” includes conservation estimates. Demand response for CAISO is based on staff estimates, due to lack of comprehensive, ISO-collected data. Data for MISO is for August 1, when demand response was called and measured. MISO’s peak day was July 31.* New record peak in peak demand

OP4- Action 12 6.1% 227.1 4,070 3,701 2 Aug * SW Conn.

OP4- Action 12 2.1% 597 28,490 28,130 2 Aug * ISO-New England

Emergency DR activated 2.8% 948 35,018 33,939 2 Aug * NYISO

Full Emergency Load 

Response 3.3% 2,050 64,067 62,017 2 Aug * Mid Atlantic

Not called outside 

Mid-Atlantic 1.4% 2,050 148,001 144,644 2 Aug * PJM

Max Gen Warning; 

NERC EEA2 2.3% 2,651 117,000 113,750 1 Aug Midwest ISO

None called Unknown Not called Not applicable 42,227 19 Jul * SPP

Yellow: 

Conservation Needed Not applicable Not called 64,567 62,339 17 Aug * ERCOT

Emergency Stages 1 & 2 4.1% 2,066 52,336 50,270 24 Jul * CAISO

Emergency Procedures and 

Levels called by 

System Operators

Demand 

Response as 

Percent

of System 

Peak

Demand 

Response 

(MW)

Projected 

System Peak 

(MW)

Actual 

System 

Peak 

(MW)

Date of 

Summer 

2006 Peak 

Load

Transmission 

System Operator

Table B-1. Summary of RTO and ISO area demand response in summer 2006

Sources: Numbers in this table are based on data available to Commission staff, including RTO and ISO publications, and interviews with RTOs and ISOs and with other market participants. The column “demand response as percent of peak” includes conservation estimates. Demand response for CAISO is based on staff estimates, due to lack of comprehensive, ISO-collected data. Data for MISO is for August 1, when demand response was called and measured. MISO’s peak day was July 31.* New record peak in peak demand
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-3

Source Notes for Figure II-1 and Table B-1 

Figure Table 

RTO or ISO and Data Item II-1 B-1 Data Unit(s) Data Source, Source note, or Derivation Method New England Independent System Operator (ISO-NE) Source is ISO New England (ISO-NE), unless otherwise noted 

ISO-NE summer 2006 data:

See also, H. Yoshimura (ISO-NE), FERC Wholesale Demand  Response Technical Conference, transcript, 14-19; and Yoshimura & Whitley,  submitted "Responses to FERC". 

Forecast peak load √ 28,490 MW ISO-NE, systems operations page of website. 

Actual peak load √ 28,130 MW ISO-NE, 2006 Annual Markets Report, June 11, 2007, 1. Maximum Hourly Reduction 625 MW ISO-NE, 2006 Annual Markets Report, June 11, 2007, 116. Peak day, hour √ 2-Aug-06 3-4 p.m. ISO-NE, 2006 Annual Markets Report, June 11, 2007, 116. Peak hour reduction √ √ 597 MW ISO-NE, 2006 Annual Markets Report, June 11, 2007, 116. Peak hour reduction √ √ 2.1% FERC analysis: total reduction divided by peak load (both MW) 

Peak hour reliability reduction: 513 MW Hopper, et al., Electricity Journal, June 2007, 66. ISO-NE 2006 Emergency Levels and Procedures Details of Operating Procedure 4, steps 9 and 12, are described below. ISO-NE summer 2007 demand-response resources: Total ISO-NE enrollment √ 1,036.6 MW Enrolled MW as of June 2007 

 of which economic √ 97.1 MW NEPOOL Participants Committee Meeting, June 8, 2007, 20.  of which reliability √ 939.5 MW NEPOOL Participants Committee Meeting, June 8, 2007, 20. 

New York Independent System Operator (NYISO) Source is New York ISO (NYISO), unless otherwise noted 

NYISO summer 2006 data: Forecast peak load √ 35,018 MW NYISO website: http://www.nyiso.com/public/market_data. 

Actual peak load √ 33,939 MW "Operations & Market Performance: Summer 2006," September 13, 2006. Peak day, hour √ 2-Aug-06 3-4 p.m. "Operations & Market Performance: Summer 2006," September 13, 2006. Peak hour reduction √ √ 948 MW 

“Responses to FERC," FERC Wholesale Demand Response Technical  Conference, transcript, 3. 

Peak hour reduction √ √ 2.8% FERC analysis: total reduction divided by peak load (both MW). 

NYISO 2006 Emergency Levels and Procedures Details of Emergency Demand Response are described below. NYISO summer 2007 demand-response resources: "NYISO's Demand Response Programs 2007," PowerPoint presentation. Total NYISO enrollment √ 2,199 MW Enrolled MW, as of May 2007. 

 of which economic √ 389 MW email from NYISO to FERC staff. 

 of which reliability (EDRP & ICAP/SCR) √ 1,810 MW email from NYISO to FERC staff. 
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-4 Source Notes for Figure II-1 and Table B-1 (Cont.)

Figure Table 

RTO or ISO and Data Item II-1 B-1 Data Unit(s) Data Source, Source note, or Derivation Method PJM Interconnection, Inc. (PJM)

PJM summer 2006 data: 

PJM, "State of the Market Report, Briefing: 2006 (SOMB)," March 21, 2007; 

available at: www.pjm.com/markets/market-monitor/downloads/mmupresentations/20070321-item-12-som-mrc-briefing-2007.pdf; 

 PJM, 2006 State of the Market Report, (SOM), March 8, 2007. 

Forecast peak load √ 148,001 MW PJM: www.pjm.com/services/system-performance/historical.html

Actual peak load, total market √ 144,644 MW PJM, "SOMB", 10. 

Peak day, hour √ 2-Aug-06 4-5 p.m. PJM, email to FERC Staff. Peak hour reduction, total market √ √ 2,050 MW SOM, Vol. I, 12-13; available at: www.pjm.com/markets/market-monitor/som.html

Peak hour reduction, total market √ √ 1.4% FERC analysis: total reduction divided by peak load (both MW) 

 of which Full Emergency Load Response 799 MW Hopper, et. al., Electricity Journal, June 2007, 67. 

Actual peak load, Mid-Atlantic zone √ 62,016 MW PJM: www.pjm.com/services/system-performance/historical.html

 Peak reduction, Mid-Atlantic zone √ 2,050 MW PJM, www.pjm.com/services/system-performance/historical.html Peak reduction, Mid-Atlantic zone √ 3.3% 

PJM, "SOMB", p. 10; FERC divided total reduction by Mid-Atlantic peak, where  emergency conditions were called. 

PJM 2006 Emergency Levels and Procedures Details of Full Emergency Load Response are described below PJM summer 2007 demand-response resources: PJM, enrolled MW as of July 2007 Summer 2007 Demand Resources √ 3,733 MW  including economic √ 1,578 MW  including reliability √ 2,155 MW 

2006 SOM, 101; 2005 SOM, 82; "Load Response Activity Report, Jan-June 

 2007", available at:: www.pjm.com/committees/workinggroups/dsrwg/downloads/20070724-item-02-dsr-activity.pdf

Midwest Independent System Operator, Inc. (MISO) Source is Midwest ISO (MISO), unless otherwise noted 

MISO summer 2006 data: Forecast peak load √ 117,000 MW “Summer 2006 Review & Discussion,” presentation, 9/6/06, 11. Actual peak load √ 113,750 MW 

Real-Time Market Reports, August 2006: http://www.midwestmarket.org/mkt_reports/rt_ex/20060802_rt_ex.pdf

Day and hour of measured reduction √ 1-Aug-06 3-4 p.m. "2006 Load Management Response Survey," summary, January 5, 2007. 

Peak hour reduction, August 1 √ √ 2,651 MW Actual reductions, based on MISO survey to Balancing Authorities  including interruptible resources 1,387 MW "2006 Load Management Response Survey," summary, January 5, 2007. Peak hour reduction, August 1 √ 2.3% FERC analysis: total reduction divided by peak load (both MW) MISO 2006 Emergency Levels and Procedures 

Details of MISO, Maximum Generation Warning & NERC EEA2 are described  below. 

MISO summer 2007 demand-response resources: Enrolled MW as of April 2007.Summer 2007 Demand Resources: √ 4,099 MW 

“2007 MISO Summer Readiness Workshop: Resource Assessment,” April 6, 2007, 6. 

 including interruptible resources √ 2,534 MW 

 including direct load control √ 1,565 MW 
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-5

Source Notes for Figure II-1 and Table B-1 (Cont.)

Figure Table 

RTO or ISO and Data Item II-1 B-1 Data Unit(s) Data Source, Source note, or Derivation Method Electric Reliability Council of Texas (ERCOT)

ERCOT summer 2006 data: Forecast peak load √ 64,567 MW Public Utility Commission of Texas, Wholesale Market Oversight web site. Actual peak load √ 62,339 MW ERCOT, 2006 Annual Report, May 2007, 6. Peak hour reduction √

 Demand 

Response 

not called MW LaaRs were not called on for system reliability purposes on peak day. 

Peak day, hour √ 17-Aug-06 4-5 p.m. Public Utility Commission of Texas, Wholesale Market Oversight. LaaRs use on peak day 1,150 MW Email, call with ERCOT IMM: LaaRs served as operating reserves on peak day. 

ERCOT 2006 Emergency Levels and Procedures ERCOT called no emergencies called on peak day. 

ERCOT summer 2007 demand-response resources: Summer 2007 Demand Resources: √ 1,985 MW 

Load Acting as a Resource (LaaRs) √ 1,150 MW Registered, as of end, 2006; Source, Potomac Economics, External Market Monitor for ERCOT (but limited to 1,150 MW for responsive reserves at a time). 

Emergency Interruptible Load Service 

not yet 

known MW 

Texas issued RFP for at least 500 MW .emergency interruptible resources;  minimum level not met at press time. 

Southwest Power Pool, Inc. (SPP RTO) Source is the Southwest Power Pool (SPP), unless otherwise noted. 

SPP summer 2006 data: Actual peak load √ 42,284 MW 2006 State of the Market Report, SPP, Inc., May 16, 2007 draft, 11.

Peak hour reduction 

Demand 

Response 

not called MW 

SPP had no ISO-level programs in place; SPP IMM conversation with FERC staff. 

Peak hour reduction √ √ 70 MW 

SPP knew anecdotally of a utility program, which called its interruptible  resources. 

Peak day, hour √ 19-Jul-06 4-5 p.m. SPP, email with market monitor. 

SPP 2006 Emergency Levels and Procedures SPP called no emergencies called on peak day. SPP summer 2007 demand-response resources: Summer 2007 Demand Resources √ unknown MW SPP, conversation with market monitor. 
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-6 Source Notes for Figure II-1 and Table B-1 (Cont.)

Figure Table 

RTO or ISO and Data Item II-1 B-1 Data Unit(s) Data Source, Source note, or Derivation Method California Independent System Operator (CAISO) Source is California ISO (CAISO), unless otherwise noted. 

CAISO summer 2006 data: Forecast peak load √ 52,336 MW "Alert, Warning, Emergency and Power Watches," Actual peak load √ 50,270 MW 2006 Annual Report: Market Issues & Performance, April 5, 2007, 6. 

Peak day, hour √ 24-Jul-06 1-2 p.m. CAISO Peak hour reduction √ √ 2,066 MW FERC estimate: difference between forecast & actual peak load; Peak hour reduction √ √ 4.1% reduction divided by actual peak; includes conservation estimates. Peak hour reduction 1,191 MW CAISO 2006 Emergency Levels and Procedures Details of Emergency Stages and “Conservation critical” are described below. CAISO summer 2007 demand-response resources: Total Enrollment (& program type); of which: √ 2,789 MW 

 IOU price-responsive (economic) √ 1,056 MW 

 IOU interruptible programs (reliability) √ 1,613 MW 

Ahmad Faruqui & Ryan Hledik, The Brattle Group, for the California Energy 

Commission (CEC), The State of Demand Response in California. 

 CEC-200-2007-003-D, April 2007, 17. 

 ISO: Voluntary Load Response Program √ 15 - 50 MW CAISO, conference call with FERC staff, January 2007. 

 ISO: Participating Load Program √ ~ 85 MW Conference call with FERC staff, January 2007. 
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B-7

Definitions for Table B-1: 

Transmission System Operator: RTOs (regional transmission organizations) and ISOs (independent 

system operators) are responsible for dispatch of system resources, including generation and demand 

response. Most of the demand-response programs are invoked by the RTOs or ISOs for system 

reliability needs on peak days. 

Date: This column indicates the date of the system peak in the summer of 2006. The exception is the 

Midwest Independent System Operator (MISO), which called on demand-response resources on 

August 1 and 2, but not on July 31, the date of its system peak. Except for MISO, all of the peak load 

data in this table were record peaks. 

Actual System Peak (MW): This column indicates the system peak in megawatts, as reported by the 

RTO or ISO. The number in the table is the “integrated hourly load” measured by the system 

operator, rather than the “five minute interval” data, which sometimes produces a different peak 

number. The difference between those two measures, and the fact that initial data is usually revised 

based on final metering data a few months after the original report, can lead to multiple numbers being 

reported even by the same entity. 

Projected System Peak (MW): These demand numbers, in megawatts of expected load, are those the 

RTOs and ISOs projected earlier on the peak day as the market area’s expected load peak for the day. 

The expected peak demand forecast is often revised throughout the day on days with extreme 

conditions. In some cases, particularly for California, Commission staff estimated total conservation 

and demand response based on the difference between these two numbers. 

Demand Response as Percent of System Peak in Load pockets (MW, percent): These numbers 

were broken out for two RTOs and ISOs, when reported, because much of the relief came from the 

most congested load pockets. RTOs and ISOs may have had programs that targeted enrollment in 

their most congested areas. This detail is illustrated beneath the RTO/ISO in Table B-1. 

 

Emergency Procedures and Levels Called by System Operators: 

Different emergency procedures are embodied in the operating procedures of each market. Not every 

market declared an emergency on their peak day. Some only called for conservation. The following 

explains what levels were called for during emergencies, and their meaning. 

CAISO: California used both voluntary conservation and demand-response programs. Some were 

invoked by the ISO; others are called by utilities. These are the highlights of the conservation 

alert and maintenance restrictions, as well as Stage 1 and 2 Emergencies called by the ISO. 

• CAISO announced a “Power Watch” the prior day, and displayed a “Conserve-O-Meter” 

on www.CAISO.com with an arrow pointing to “Red: Conservation Critical.” CAISO 

called on its Voluntary Load Reduction Program, and issued a “restricted maintenance 

order” (RMO) from 6 a.m. to 8 p.m. Under an RMO, no one can do any maintenance 

without permission from the ISO.174 

• The CAISO called Stage 1 and 2 Emergencies. Normal operations are when the forecast 

reserve level is greater than 7%. A Stage 1 Emergency is called when the forecast reserve 

level is less than 7%; it was in effect from 10 a.m. to 9 p.m. During Stage 1, the ISO 

called on its Voluntary Load Reduction Program. The ISO declares a Stage 2 Emergency 

when it expects operating reserves to fall below 5%; this was in effect from 1 p.m. to 9 

 174 CAISO, "Alert, Warning, Emergency and Power Watches," (AWE); excel spreadsheet tab “2006 AWE record”. 
Appendix B – Documentation of 2006 Demand Response Estimates 

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B-8 

p.m. During Stage 2, the ISO calls for load in interruptible programs to curtail; most of 

these are under the IOU’s control.175

ERCOT: The Public Utility Commission of Texas (PUCT) website displays a daily 

conservation alert. On ERCOT’s peak day, the alert was at: “Yellow: Conservation Needed.” 

This indicates that the PUCT expects a peak demand day, but that, given available capacity, 

there should be sufficient resources if people conserve. No emergency levels were declared 

on ERCOT’s peak day.176

SPP: The Southwest Power Pool did not declare an emergency condition on its peak 2006 

day.177

MISO: The Midwest Independent System Operator (MISO) did not call for demand response 

on its peak day, July 31, 2006. August 1 was included in Table B-1 and Figure II-1 because 

MISO measured the effects of demand response on the second peak day. On July 31 - August 

2, MISO used a combination of its Generation Emergency Procedures, and NERC Energy 

Emergency Alerts (EEA). The ISO procedures were revised prior to the summer of 2007, so 

these definitions are not current.178

• A “Maximum Generation Warning” was declared from 10:42 a.m. to 6:27 p.m. (EST) 

on August 1. A “Max Gen Warning” meant that operating reserves would probably 

be needed to meet load. 

• A NERC EEA1 was in effect from 12 noon to 7:00 p.m. for the entire market 

footprint. An EEA1 denotes that all available resources are committed to meet 

demand. 

• A NERC EEA2 was in effect for the Central and East regions from 10:42 a.m. to 5:49 

p.m. An EEA2 invokes public appeals for conservation, the interruption of non-firm 

load (according to contracts), and “demand-side management” (DSM) measures. All 

interruptible and DSM programs were run by utilities in the MISO footprint, rather 

than by the MISO. 

PJM: PJM implemented Full Emergency Load Response in the Mid-Atlantic control zone on 

August 2, between 2 p.m. and 7 p.m. “Full Emergency Load Response combines in one 

construct the energy payment provided for previously by the Emergency Load Response 

Program and the capacity credit earned as an Active Load Management resource. 

Performance of Full Emergency resources is mandatory.”179 PJM’s other emergency option, 

Energy only, was not called in August 2006. 

NYISO: Emergency demand response activated. The NYISO activated its Emergency 

Demand Response Program (EDRP) and its Installed Capacity / Special Case Resources 

(SCR) in two regions on August 2.180 These resources were called in Zones J (New York 

City) and K (Long Island) from 1 p.m. to 8 p.m. to meet local reliability rules. EDRP and 

 175 CAISO, "AWE”; excel spreadsheet tab 2006 AWE record, and CAISO, "Demand Response, Where We Are 

Now," January 25, 2007 PowerPoint presentation. 

176 The Public Utility Commission of Texas (PUCT) has conservation alert levels posted on its main page: 

http://www.puc.state.tx.us/. Conversations and emails with Danielle Jaussaud, Market Oversight, PUCT. 

177 Conversations with SPP market monitoring staff. 

178 MISO, “Summer 2006 Review & Discussion,” PowerPoint presentation, September 6, 2006. 

179 Email from PJM, VP of Federal Government Policy, about peak period demand response for summer 2006. 

180 NYISO, monthly call with FERC staff and Market Monitors, August 8, 2006, and NYISO, “Operations and 

Market Performance: Summer 2006,” discussion draft for September 13, 2006 call. 
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B-9

SCR resources were activated in Zones A, B, and C (West, Genesee, and Central zones in 

Western New York area) to support voltages, and to allow NYISO to export 2,500 MW of 

scheduled power to PJM. ICAP/SCR resources are sometimes activated prior to EDRP 

resources. SCR is activated in response to a forecast or actual operating reserve deficiency.181

ISO-NE: OP4 is one of the ISO’s operating procedures; it refers to a series of actions the ISO 

can take when it is in a capacity sufficiency situation. They are documented in its “Operating 

Procedures: OP 4 – Action During a Capacity Deficiency (2005).182 The actions taken on its 

peak 2006 day included: 

• OP4-Action 9 was called from 12:15 p.m. to 6:00 p.m. (EDT). In Action 9, the ISO 

requests voluntary load curtailment from market participants’ facilities, and calls for 

interruptions in its “Real-Time Demand Response – 30 Minutes or Less Notification” 

program. 

• OP4-Action 12 was called from 1:00 p.m. to 4:45 p.m. Under Action 12, the ISO 

implements a five percent voltage reduction. It calls on interruptible resources 

enrolled in its “Real-Time Demand Response – 30 Minutes or Less Notification” 

program. At OP4 – 12, ISO-NE announces a NERC EEA Level 2 alert (see MISO for 

EEA2 details). 

 181 NYISO, “Demand Response Programs,” March 15, 2006. 

182 ISO-NE Operating Procedures, “OP 4 – Action During a Capacity Deficiency,” revision 6, effective Aug 5, 

2005, 5-6. 
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Appendix C – NERC Estimates of Demand Response 

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C-1

Appendix C: North American Electric Reliability 

Corporation Estimates of Demand Response Availability 

This appendix summarizes NERC’s estimates of the level of demand response by NERC region in 

2006 and 2007. NERC bases its numbers on an estimate of the availability of demand response on a 

firm basis, and reflects demand reductions from only traditional interruptible/curtailable load or direct 

load control. NERC does not include demand bidding programs or time-based rate programs.183 To 

support future estimates of demand response, NERC’s planning and operations committee has 

authorized a task force to examine how the response from other demand-response programs can 

reliably be counted.184

Figure C-1. Demand response by NERC region 

Source: NERC, 2007 Summer Assessment

 183 NERC has directed that reductions from economic or price-based program should be added back into load, but 

it is not known whether it is universally done. 

184 Staff conversation with NERC, June 8, 2007. 

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007

ERCOT FRCC MRO NPCC RFC SERC SPP WECC NERC

Percentage of Total Internal Demand

Direct Control Load Management

Interruptible Demand

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007 2006 2007

ERCOT FRCC MRO NPCC RFC SERC SPP WECC NERC

Percentage of Total Internal Demand

Direct Control Load Management

Interruptible Demand
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Appendix D - Overview of Demand Response in RTO and ISO Markets 

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D-1

Appendix D: Overview of Demand Response in RTO and 

ISO Markets 

In order to gain a better understanding of the Commission’s actions related to demand response, it is 

helpful to see an overview of demand-response participation in each of the seven RTOs and ISOs.185 

The following table includes this information, indicating the status of RTO and ISO market rules for 

demand response: already in place, subject to ongoing proceedings, or subject to regional initiatives to 

explore greater demand response. Additional detail on RTO/ISO demand response, and commission 

actions in each RTO and ISO follows. As of 2007, demand-response resources are increasingly being 

integrated into various organized electricity markets, including ancillary services, energy, and capacity 

markets. The level to which these resources can now participate in these markets varies depending on 

the individual RTO or ISO. Additional proposals and initiatives are underway within RTO/ISO 

regions to further integrate demand resources. 

 185 Table D-1 includes information related to demand-response participation in ERCOT. Note that the report 

incorporates this information in order to be comprehensive, but the Commission does not have jurisdiction over this RTO. 
Appendix D - Overview of Demand Response in RTO and ISO Markets

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D-2 Table D-1. Demand response status in RTOs and ISOs

Notes:

H: History and in placeO: Open dockets and actionsI: Initiatives that are being discussed* For retail and state initiatives "H" and "O" represent activities before a state(s).

Market Element

HO I HO I HO I HO I HO I HO I HO I

Demand Response Program 999999999999999 999

Emergency Situation DR Program 999 9 9Real Time DR Bids 99 9 9 99 99 9 9Day Ahead DR Bidding into Market 9 9 99 9 9 9Capacity Market DR Participation 99 99 9 9 9

DR in Long-Term Tx Planning 9 9 99 9Bid Price Floor or Cap for DR 9 9Ancillary Services DR Participation 99 99 9 99 9 9

Reactive Supply & Voltage Control

9

Regulation 99 9Spinning 99 9 9 9 9Non-spinning (10 Min.) 99 9 9 9 9Long Term Supplemental (30 Min.) 99 9 9Generator Imbalances

ERCOT MISO SPP NYISO ISO-NE PJM CAISO

Table D-1. Demand response status in RTOs and ISOs

Notes:

H: History and in placeO: Open dockets and actionsI: Initiatives that are being discussed* For retail and state initiatives "H" and "O" represent activities before a state(s).

Market Element

HO I HO I HO I HO I HO I HO I HO I

Demand Response Program 999999999999999 999

Emergency Situation DR Program 999 9 9Real Time DR Bids 99 9 9 99 99 9 9Day Ahead DR Bidding into Market 9 9 99 9 9 9Capacity Market DR Participation 99 99 9 9 9

DR in Long-Term Tx Planning 9 9 99 9Bid Price Floor or Cap for DR 9 9Ancillary Services DR Participation 99 99 9 99 9 9

Reactive Supply & Voltage Control

9

Regulation 99 9Spinning 99 9 9 9 9Non-spinning (10 Min.) 99 9 9 9 9Long Term Supplemental (30 Min.) 99 9 9Generator Imbalances

ERCOT MISO SPP NYISO ISO-NE PJM CAISO Market Element

HO I HO I HO I HO I HO I HO I HO I HO I HO I HO I

Demand Response Program 999999999999999 999

Emergency Situation DR Program 999 9 9Real Time DR Bids 99 9 9 99 99 9 9Day Ahead DR Bidding into Market 9 9 99 9 9 9Capacity Market DR Participation 99 99 9 9 9

DR in Long-Term Tx Planning 9 9 99 9Bid Price Floor or Cap for DR 9 9Ancillary Services DR Participation 99 99 9 99 9 9

Reactive Supply & Voltage Control

9

Regulation 99 9Spinning 99 9 9 9 9Non-spinning (10 Min.) 99 9 9 9 9Long Term Supplemental (30 Min.) 99 9 9Generator Imbalances

ERCOT MISO SPP NYISO ISO-NE PJM CAISO

HO I HO I HO I HO I

Demand Response Program 999999999999999 999

Emergency Situation DR Program 999 9 9Real Time DR Bids 99 9 9 99 99 9 9Day Ahead DR Bidding into Market 9 9 99 9 9 9Capacity Market DR Participation 99 99 9 9 9

DR in Long-Term Tx Planning 9 9 99 9Bid Price Floor or Cap for DR 9 9Ancillary Services DR Participation 99 99 9 99 9 9

Reactive Supply & Voltage Control

9

Regulation 99 9Spinning 99 9 9 9 9Non-spinning (10 Min.) 99 9 9 9 9Long Term Supplemental (30 Min.) 99 9 9Generator Imbalances

ERCOT MISO SPP NYISO ISO-NE PJM CAISO
Appendix D - Overview of Demand Response in RTO and ISO Markets

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D-3

New York ISO 

NYISO has a working real-time market and has been directed by the Commission to integrate demand 

side resources into this market as well as its ancillary services market. The New York Public Service 

Commission placed all medium and large customers on real-time pricing based on locational marginal 

pricing (LMP) as their default rate. 

Demand Response Program 

NYISO markets include demand response, under the Emergency Demand Response Program 

(EDRP)186 and the Incentivized Day-Ahead Economic Load Curtailment Program,187 since 2001. The 

NYISO also recently filed proposed tariff revisions to clarify, modify, and make consistent the 

activation of its demand-response Special Case Resources (SCR) program and EDRP.188 Further, 

NYISO prepares a semi-annual report on demand side management programs and new generation 

additions, as required by the Commission.189 

Emergency Situation Demand Response Programs 

NYISO updated and made permanent the EDRP and the installed capacity (ICAP) Special Case 

Resources Program and DADRP to back demand off the power grid in emergencies.190 

Real-Time Demand Response Bids – Higher of Bid or LMP 

The Commission ordered NYISO to integrate demand side resources into the real-time energy market 

by the third quarter of 2007.191 

Day-Ahead Demand Response Bidding into Market 

Demand response participates in NYISO day-ahead markets through the DADRP.192 

Capacity Market Demand Response Participation 

Resources in the ICAP Special Case Resources Program can participate in the NYISO’s capacity 

markets.193 

Demand Response in Long-Term Transmission Planning 

NYISO includes demand-response modeling as part of the assessment undertaken to meet its installed 

capacity requirement as well as in its comprehensive reliability planning process.194

Bid Price Floor or Cap for Demand Response 

Demand response in NYISO has a bid price floor.195 

Ancillary Services Demand Response Participation 

 186 N.Y. Indep. Sys. Operator, Inc., 95 FERC ¶ 61,136 (2001). 

187 This program is also known as the Day-Ahead Demand Response Program (DADRP). See N.Y. Indep. Sys. 

Operator, Inc., 95 FERC ¶ 61,223 (2001). 

188 See Docket No. ER-07-862. 

189 N.Y. Indep. Sys. Operator, Inc., 97 FERC ¶ 61,095 (2001). 

190 N.Y. Indep. Sys. Operator, Inc., 113 FERC ¶ 61,089 (2005). 

191 N.Y. Indep. Sys. Operator, Inc., 116 FERC ¶61,043(2006). 

192 N.Y. Indep. Sys. Operator, Inc., 103 FERC ¶ 61,374(2003. 

193 N.Y. Indep. Sys. Operator, Inc., 95 FERC ¶ 61,136(2001); N.Y. Indep. Sys. Operator, Inc., 113 FERC ¶61,089. 

194 See Docket No. ER07-862; N.Y. Indep. Sys. Operator, Inc., 116 FERC ¶ 61,043(2006). 

195 N.Y. Indep. Sys. Operator, Inc., 109 FERC ¶61,101 (2004). 
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D-4 

After Commission guidance in 2004, NYISO market rules allow for greater market participation by 

demand side resources. Demand side resources now provide ancillary services for demand-response 

participation as a regulation, spinning, non-spinning and long-term supplemental resource and are 

included in synchronous reserve markets. NYISO will fully integrate them into the ancillary services 

market by September 2007.196 

ISO New England 

New England has been facing the prospect of an electricity supply shortage. Activating demand 

response through a forward capacity market could help lessen the potential problem. In addition, 

Connecticut, Massachusetts, and Vermont have each been examining their policies with regard to 

demand response and time-based rates. 

Demand Response Programs 

As a member of the New England Power Pool (NEPOOL), ISO-NE markets have helped NEPOOL 

reduce consumption in peak periods since 2002 through a demand-side management plan known as 

the NEPOOL Load Response Program.197 NEPOOL’s Load Response Program includes the 

following: (1) Day-Ahead Demand Response Program; (2) Real-Time 30 Minute Demand Response 

Program; (3) Real-Time Two Hour Demand Response Program; (4) Real-Time Price Response 

Program; and (5) Real-Time Profiled Response Program. Participants in these programs provide 

measurement results demonstrating the extent of curtailment.198

Emergency Situation Demand Response Programs 

ISO-NE has used the Real-Time Demand Response Program to ease load demands in emergency 

situations and encourage an increase in the amount of interruptible load available during capacity 

shortages in NEPOOL since 1999.199

Real-Time Demand Response Bids – Higher of Bid or LMP 

Demand response submits real-time bids when it participates in the ISO-NE Real-Time 30 Minute 

Demand Response Program; Real-Time Two Hour Demand Response Program; Real-Time Price 

Response Program; and Real-Time Profiled Response Program. 

Day-Ahead Demand Response Bidding into Market 

Demand submits day-ahead bids when it is a part of the ISO-NE Day-Ahead Demand Response 

Program. 

In 2005, the Commission directed ISO-NE to implement an integrated clearing approach Day-Ahead 

Load Response Program (DALRP). In response, the ISO-NE submitted a compliance filing requesting 

the approval of a sequential clearing methodology for the DALRP which would be replaced with an 

integrated clearing methodology after the infrastructure for direct demand participation was in place as 

part of the ancillary services market. The Commission granted this request but directed ISO-NE to 

implement an integrated clearing methodology.200

 196 N.Y. Indep. Sys. Operator, Inc., 106 FERC ¶ 61,111 (2004); N.Y. Indep. Sys. Operator, Inc., 116 FERC ¶ 

61,043. 

197 N.Y. Indep. Sys. Operator, Inc., 100 FERC ¶ 61,287 (2002). 

198 Id.

199 ISO New England, Inc., 88 FERC ¶ 61,304 (1999). 

200 New England Power Pool, Inc., 111 FERC ¶ 61,064 (2005); New England Power Pool, Inc., 117 FERC ¶ 

61,165 (2006). 
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D-5

Capacity Market Demand Response Participation 

In June 2006, FERC approved a settlement providing for a Forward Capacity Market (FCM) in ISONE. The FCM employs: (1) a forward resource adequacy auction in which ISO-NE would procure 

100 percent of the forecasted installed capacity requirements for each commitment period; (2) a 

descending clock auction held far enough in advance of the commitment period to allow participation 

by new market entrants; (3) penalties for non-performance; and (4) a transition period.201 Pending 

approval of auction market rules before FERC, ISO-NE plans to hold the first auction in February 

2008 for resources that can provide capacity beginning in June 2010.202 ISO-NE’s next step in the 

FCM process will be to evaluate “show of interest” proposals it received and notify applicants in 

October 2007 if they are eligible to participate.203 

Demand-response resources in Real-Time Demand Response Programs can qualify as an ICAP 

resource in ISO-NE. There is a pilot underway which will run at least through summer 2007 that 

should help ISO-NE find better ways to measure the reductions demand-response resources are 

providing in close to real time.204 

Ancillary Services Demand Response Participation 

The ancillary services ISO-NE demand-response resources provide are: reactive supply and voltage 

control; regulation; spinning; non-spinning; long term supplemental; and generator imbalances. 

Demand Response in Long-Term Transmission Planning

ISO-NE considers the contribution of demand-response resources in meeting projected demand and 

evaluating the adequacy of installed capacity. Its modeling to support the development of installed 

capacity requirement values is based on assumptions regarding generating and demand-response 

resources, system load forecasts, and the reliability benefits from direct connections to neighboring 

power systems.205 

Bid Price Floor or Cap for Demand Response 

ISO-NE’s Day-Ahead Demand Response Program subjects demand-response resources to a bid floor 

and a bid ceiling.206

 201 Devon Power LLC, 115 FERC ¶ 61,340 (2006). 

202 Platt’s Inside FERC, page 14, March 26, 2007. 

203 Megawatt Daily, page 1, Vol. 12 No. 53, March 19, 2007. 

204 Technical Conference Transcript, Docket No. AD07-11, April 23, 2007, page 31, line 22 – page 32, line 17, 

http://www.ferc.gov/EventCalendar/Files/20070504072920-AD07-11-04-23-07.pdf. 205 ISO New England, Inc., 118 FERC ¶ 61,157 (2007). 

206 New England Power Pool, 101 FERC ¶ 61,344 (2002). 
Appendix D - Overview of Demand Response in RTO and ISO Markets

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D-6 

PJM Interconnection, LLC 

PJM allows demand response to participate in energy and ancillary services markets, and gives 

installed capacity credits for demand resources that commit to curtail when directed. PJM continues to 

work on full integration of demand response as a capacity resource in the Commission-approved 

Reliability Pricing Model (RPM). A regional initiative composed of the five original PJM states, the 

Mid-Atlantic Distributed Resources Initiative (MADRI), has been operating since 2004, and continues 

to meet to examine and support policy on demand response and distributed generation. 

Demand Response Programs 

Since 2002, PJM has offered a financial incentive to its customers to reduce consumption as its LMP 

rises. This Economic Load Response Program provides for reductions on both a real-time and dayahead basis, as well as an additional incentive to participants who reduce load relative to a LMP. 207 

The Commission authorized a non-hourly metered pilot program which will allow PJM to determine 

whether an alternative demand reduction measurement mechanism can become permanent. 208 

In December 2006, the Commission directed PJM to conduct a forum for discussions to identify and 

rectify barriers to entry of demand response by February 20, 2007 and to file a report on the status of 

the additional process for pursuing demand response and incorporating energy efficiency applications 

by August 20, 2007. In addition, the Commission directed PJM to incorporate into its tariff by 

February 2007, the eight criteria in Schedule 6 of the Reliability Assurance Agreement and the rules in 

the PJM manuals associated with standards and procedures for demonstration that a resource has the 

capability to provide a reduction in demand, the calculation of the Demand Response Factor and 

Unforced Capacity Value of a demand resource, and rules and procedures for verifying the 

performance of demand resources.209

PJM utility members are implementing or have proposed to implement greater demand response and 

energy efficiency into the market. For example, Com Ed has supported a residential real-time pricing 

(RTP) collaborative within Chicago. The Illinois Commerce Commission has recently adopted a 

policy and Illinois has a new law with provisions that will provide all residential customers with the 

ability to select RTP. Legislation enacted by the Illinois General Assembly in June 2006 required 

each electric utility serving more than 100,000 customers to submit real-time pricing tariffs to the 

Illinois Commerce Commission for approval. BG&E (in Maryland) and Pepco Holdings have 

announced new initiatives to promote energy efficiency and demand response. Pepco DC is 

implementing an advanced metering/rates/smart thermostat pilot under DC PSC jurisdiction. 

The penetration rates of advanced metering in PJM are notable because they are increasing. The 

Reliability First Corporation footprint has the highest penetration rate of advanced metering in PJM. 

Pennsylvania has the highest penetration in the U.S. 

Emergency Situation Demand Response Programs 

PJM manages critical power situations under its Emergency Load Response Program.210

 207 PJM Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002). 

208 PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006). 

209 PJM Interconnection, L.L.C., 117 FERC ¶61,331 (2006). 

210PJM Interconnection, L.L.C., 92 FERC ¶ 61,059 (2000); PJM Interconnection, L.L.C., 95 FERC ¶ 61,306; 

PJM Interconnection, L.L.C., 99 FERC ¶ 61,139 (2002); PJM Interconnection, L.L.C., Docket No. ER04-1193 (2004) 
Appendix D - Overview of Demand Response in RTO and ISO Markets

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D-7

Real-Time Demand Response Bids – Higher of Bid or LMP211

Real-time demand-response bids reflect LMP in PJM. 

Day-Ahead Demand Response Bidding into Market212

Demand response can bid into the PJM day-ahead market. 

Capacity Market Demand Response Participation 

Participants in PJM’s Full Emergency Load Response Program Forum can receive ICAP credit.213 

The Commission has specifically considered and responded to concerns that PJM did not allow 

demand response to compete on a level playing field with generation to solve reliability problems in 

the PJM Reliability Pricing Model proceeding.214 As a result, demand-response resources participate 

in RPM auctions, are eligible to set the market clearing price, and may receive revenues for load 

reductions as Interruptible Load Resources in a manner similar to that provided under PJM’s Active 

Load Management rules. LSEs rely on demand response when acting to meet PJM’s Fixed Resource 

Requirement. 

Ancillary Services Demand Response Participation215

Demand-response resources can directly participate in synchronized reserve and regulation service 

markets. The PJM OATT has a one-minute snapshot verification method to determine whether a 

demand-response participant actually reduced load during a Synchronized Reserve Event. 

Synchronized reserves replaced PJM’s former spinning reserve market and are provided by both 

generation and demand resources. 

Demand Response in Long-Term Transmission Planning 

In November 2006, the Commission conditionally accepted PJM’s Regional Transmission Expansion 

Planning Protocol (RTEP) and directed PJM to evaluate the extent to which demand response or new 

generation could eliminate the need for an economic-based upgrade. In addition, the Commission 

directed PJM to delineate ways in which generators and demand-response providers will be included 

in the economic planning process. The Commission also required PJM to clarify the timeline for 

including demand response, generation, or merchant transmission proposals into each annual RTEP.216

Bid Price Floor or Cap for Demand Response 

PJM has no bid price floor or cap for demand response. 

 (unpublished letter order); PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 (2006). 

211 See information about real-time demand-response bids in previous sections and PJM Interconnection, L.L.C., 

92 FERC ¶ 61,059; PJM Interconnection, L.L.C., 95 FERC ¶ 61,306; PJM Interconnection, L.L.C., 99 FERC ¶ 61,139; PJM 

Interconnection, L.L.C., 99 FERC ¶ 61,227 (2002); PJM Interconnection, L.L.C., Docket No. ER04-1193 (2004) 

(unpublished letter order); and PJM Interconnection, L.L.C., 114 FERC ¶ 61,201. 

212 See information about demand-response day-ahead bidding in previous sections and PJM Interconnection, 

L.L.C., 99 FERC ¶ 61,227 and PJM Interconnection, L.L.C., 114 FERC ¶ 61,201 . 

213 PJM Interconnection, L.L.C., 114 FERC ¶ 61,201. 

214 PJM Interconnection, L.L.C., 117 FERC ¶ 61,331. 

215 PJM Interconnection, L.L.C., 114 FERC ¶ 61,201. 

216 PJM Interconnection, L.L.C., 117 FERC ¶ 61,218 (2006). 
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California ISO (CAISO) 

The development and current status of CAISO demand response is related to and influenced by the 

2000-2001 California electricity crisis. The CAISO demand-response policies and procedures will be 

operational when the Commission-approved market redesign and technology upgrade (MRTU) 

becomes effective in January 2008. 

Demand Response Programs 

In July 2002, the Commission accepted, rejected, and modified in part the California Comprehensive 

Market Redesign Proposal (MD02 Proposal).217 In its analysis, the Commission stated that it would 

“implement a West-wide market power mitigation program” that approves a competitive market 

design. The Commission stated demand response, at the retail level, was not within its authority to 

implement. However, the Commission did require the CAISO to change the rules of its spinning 

reserve markets to enable the full participation of demand response as a resource. 

In September 2006, the Commission approved the CAISO MRTU. MRTU will provide loads with 

demand-response capability (1) the opportunity to participate in the CAISO day-ahead, real-time, and 

ancillary services markets under comparable requirements as supply, and (2) corresponding market 

value. In that order, the Commission also (1) directed CAISO to work with all interested parties in 

developing demand-response proposals and that those proposals be filed with the Commission and (2) 

encouraged Local Regulatory Authorities to ensure that demand-response resources included in their 

individual resource adequacy plans are made available to the CAISO. The CAISO has stated it will 

continue its Participating Load Program year-round under the MRTU.218 

In January 2007, the CAISO presented a workplan for the integration of retail/wholesale policies, 

programs, and market designs at a Board of Governors meeting. 

In June 2007, the Commission issued an order on some of the compliance filings CAISO has made in 

response to the Commission’s September 2006 order.219 The Commission directed the CAISO to file a 

status report by August 2007 which (1) details the progress made toward these efforts; (2) includes a 

future action plan for increased demand-response participation in MRTU; and (3) documents the 

results of at least one additional CAISO-sponsored stakeholder forum. In the June 2007 order, the 

Commission instituted the requirement that the CAISO file annual reports evaluating its demandresponse programs, including the amount of demand response it has elicited. The first report is due 

January 15, 2008. At a minimum, the CAISO’s report must include: (a) information on customer 

enrollment for each demand-response program in terms of the number of customers and total potential 

in load reduction in MWs; and (b) information on total load reductions achieved per program per event 

during the prior year, including the CAISO’s system load at time of curtailments, total MWs reduced, 

total payments for reductions and effects of the demand-response programs on wholesale prices. 

Advanced metering is being implemented in CAISO markets per a California Public Utilities 

Commission (CPUC) directive by investor-owned utilities. PG&E has begun implementation. 

SDG&E will recover metering costs through rates and increase the functionality of its meters to 

support demand response. Southern California Edison has developed a proposal to implement an 

advanced metering prototype. 

 217 Cal. Indep. Sys. Operator Corp., 100 FERC ¶ 61,060(2002). 

218 Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274 (2006). 

219 Cal. Indep. Sys. Operator Corp., 119 FERC ¶ 61,313 (2007). 
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Emergency Situation Demand Response Programs 

The CAISO has no emergency situation demand-response programs. 

Real-Time Demand Response Bids – Higher of Bid or LMP 

The CAISO MD02 created a Participating Load Program for demand-response resources.220 Since 

2003, CAISO has called on participating demand-response resources in this program based on bids 

they submit in response to real-time dispatch instructions from CAISO and uses LMP and an 

Integrated Forward Market as part of its congestion management system.221 Demand resources are 

treated the same as generation and settled at the applicable nodal price. Single load or aggregate load 

greater than 1 MW can participate as a demand-response resource in this market and must meet the 

CAISO’s telemetry and metering requirements to participate. 

Day-Ahead Demand Response Bidding into Market 

Participating load will be able to bid/self-schedule in day-ahead markets under MRTU. 

Capacity Market Demand Response Participation 

The CAISO has no central capacity market. However, Local Regulatory Authorities establish the 

extent to which demand response counts toward the LSEs' resource adequacy requirements. The 

September 2006 order encouraged Local Regulatory Authorities to ensure that demand-response 

resources included in their resource adequacy programs can be made available to the CAISO in a way 

that is compatible with the CAISO's reliability needs and reduces CAISO's backstop procurement.222

Ancillary Services Demand Response Participation 

Demand-response resources in the CAISO’s Participating Load Program can participate in the 

CAISO’s markets and provide ancillary services. 

Demand Response in Long-Term Transmission Planning 

The CAISO accounts for demand response and energy efficiency in transmission planning studies by 

reducing by the appropriate amount the peak load assumed in the studies. Demand response and 

energy efficiency are at the top of the "loading order" in the procurement plans of utilities within the 

CAISO. 

Bid Price Floor or Cap for Demand Response 

The CAISO has no bid price floor or cap for demand response. 

 220 Cal. Indep. Sys. Operator Corp., 100 FERC ¶ 61,060. 

221 Cal. Indep. Sys. Operator Corp., 105 FERC ¶ 61,140 (2003). 

222 Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274 . 
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Midwest ISO 

The Midwest ISO currently uses an energy-only market approach and relies on price responsive 

demand to maintain power system reliability.223 In February 2007, Midwest ISO made a filing at the 

Commission to institute an ancillary services market. Among other things, the Midwest ISO filing 

proposed to expand the integration of demand resources into ancillary services and energy markets. 

Midwest ISO has a demand response task force that is working on recommendations. The Midwest 

ISO has administered a survey to find out how much demand response is available and was provided 

during summer 2006 peak demand periods.224 A heightened level of state involvement on demand 

response has been occurring through the Organization of Midwest ISO States and with the Midwest 

Demand Response Initiative. 

Demand Response Programs 

Demand-response resources have been participating in Midwest ISO markets in a manner comparable 

to generation resources since 2004.225 In February 2007, Midwest ISO submitted various OATT 

revisions in compliance with Commission orders to implement a day-ahead and real-time ancillary 

services market, which was to be simultaneously co-optimized with its existing day-ahead and realtime energy market.226 Although the Commission rejected the proposal in June 2007 because it was 

lacking a market power analysis and a readiness plan, the Commission provided detailed guidance so 

Midwest ISO could re-file a complete proposal quickly and the Midwest ISO could meet its market 

start date of spring 2008. 

Emergency Situation Demand Response Programs 

Midwest ISO has considered demand-response resources in emergency situations since 2004. 

Midwest ISO identifies Demand Response Resources (DRRs) available only in Maximum Generation 

Emergencies. The ability of DRRs to respond as intended is verified as part of the registration process 

for DRR certification. Midwest ISO measures the responses of DRRs through metering or statistical 

estimation and exempts these resources from certain penalties that apply to generation resources. 

 

A September 2006 technical conference found that: (1) Midwest ISO's proposed Adequate Ramp 

Capability (ARC) procedure for shortage and emergency conditions in its real-time market would not 

have a direct effect on the deployment of demand-response capability; (2) in most cases, available 

demand response is controlled by Midwest ISO’s balancing authorities and is not under Midwest ISO's 

direct operational control; (3) to the extent ARC procedures improve the accuracy of market prices, 

market participants will have a clear incentive to take advantage of potential demand reduction 

response capability; (4) most Midwest ISO demand response is not designed for ARC's short-term, 

 223 See Constellation Energy Presentation at 

http://www.ingaa.org/Documents/Foundation%20Meetings/Foundation%202005%20Annual%20Meeting%20Presentations/S

aturday11-5/2.%20Simon%20Julie%2011-5-05.pdf , (Constellation Energy Presentation). 

Also, Ronald McNamara discussion of Incorporating Demand Response into Regional Transmission Planning in 

the Midwest, http://www.ferc.gov/EventCalendar/Files/20060125092052-McNamara,%20MISO.pdf (McNamara 

Discussion). 

224 The Summer of 2006: A Milestone in the Ongoing Maturation of Demand Response, by Nicole Hopper, Charles 

Goldman, Ranjit Bharvirkar, and Dan Engel: http://eetd.lbl.gov/ea/EMS/reports/62754.pdf. Also, presentation by Charles 

Goldman for MWDRI, http://misostates.org/MWDRI_DR_Resources_v6042507.pdf. 225 Midwest Indep. Transmission Sys. Operator, Inc., 108 FERC ¶ 61,163 (2004). 

226 See Docket No. ER07-550-000. 
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quick response procedures; and, (5) Midwest ISO stakeholders have started a demand response 

taskforce in Midwest ISO which could address how demand-response programs might be designed or 

re-designed to help account for the short-term, quick response times ARC contemplates. 

Revised ARC procedures became effective in January 2007. In May 2007, Midwest ISO made a filing 

to exempt from Real-Time Revenue Sufficiency Guarantee Charges (RSG Charges) entities either 

decreasing load, increasing behind-the meter generation, increasing their level of imports, or 

decreasing their level of exports, in compliance with the Midwest ISO's directives during a declared 

emergency.227 

Real-Time Demand Response Bids – Higher of Bid or LMP 

The Midwest ISO tariff provides for demand-response resource offers into its real-time market. Some 

of the policies for real-time demand-response bids may be affected by the anticipated re-filing of the 

Midwest ISO ancillary services market proposal.228 

The price volatility make-whole payment (PV MWP) program that has been in place since December 

2006 pays generators when real-time prices are insufficient. The PV MWP applies to demandresponse resources because in Midwest ISO they are treated like generators.229

Day-Ahead Demand Response Bidding into Market 

Midwest ISO allows demand-response resource offers into its day-ahead market. The day-ahead offer 

cap does not apply to demand-response resources, and the offers are submitted at actual verifiable 

prices.230 

Capacity Market Demand Response Participation 

The Midwest ISO has no central capacity market. However, in 2004 the Midwest ISO Resource 

Adequacy and Capacity Market Working Group recommended dispatchable demand response, 

verifiable load reduction and renewable resources participate in capacity market. Demand response 

has participated accordingly.231 

Ancillary Services Demand Response Participation 

Midwest ISO is currently engaged in an active ancillary service market design and is expected to refile a proposal soon so its ancillary market can begin in spring 2008.232 

 

Demand Response in Long-Term Transmission Planning233

Midwest ISO has produced two expansion plans – one in 2003 and another in 2005. As required by 

Commission policy, Midwest ISO develops transmission expansion plans to address the reliability of 

the transmission system it operates and controls and to support competitive electric power supply for 

its markets. The process considers all market perspectives, including demand-side options, and results 

in an “energy-only market” approach. 

 227 See Docket No. ER07-885-000. 

228 Midwest Indep. Transmission Sys. Operator, Inc., 119 FERC ¶ 61,311. 

229 Midwest Indep. Transmission Sys. Operator, Inc., 117 FERC ¶ 61,325 (2006). 

230 Midwest Indep. Transmission Sys. Operator, Inc., 111 FERC ¶ 61,335 (2005). 

231 OMS Fact Sheet No. 2 at http://www.misostates.org/OMS_Fact_Sheet_No2RAWG.pdf. 232 Midwest Indep. Transmission Sys. Operator, Inc., 119 FERC ¶ 61,311. 

233 See Constellation Energy Presentation and McNamara Discussion. 
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Bid Price Floor or Cap for Demand Response 

Midwest ISO markets have no bid price for or cap for demand response. 

Southwest Power Pool (SPP) 

SPP’s market structure is significantly different from other RTO market structures. SPP’s imbalance 

market is a simple real-time energy market without: (1) a day-ahead market; (2) market-based 

resource adequacy mechanisms such as a capacity market; or, (3) a multi-part bidding mechanism to 

ensure recovery of start-up and minimum-load costs. SPP’s market is based on a physical rights 

model, as opposed to the use of financial transmission rights. 

Demand Response Programs 

SPP will file a demand-response program proposal with the Commission by August 1, 2007.234 The 

Commission has already accepted important elements of a SPP mitigation plan that protect customers 

by addressing well-defined structural barriers to competition, market concentration issues, a current 

lack of demand response in SPP, and potential market transition difficulties. The Commission 

directed SPP to include a bid cap in its tariff that will start three months after market implementation 

and continue until SPP makes a showing that sufficient demand response exists in the market to allow 

removal or increase of the bid cap. In addition, the Commission directed SPP to file by the summer of 

2007 modifications to its tariff to incorporate procedures for the commitment in the day-ahead process 

and dispatch in the imbalance market of interruptible demand, behind the meter generation, and other 

demand resources that are capable of providing imbalance service, or provide an explanation and 

rationale for not including such provisions in its tariff. 

Emergency Situation Demand Response Programs 

A bid cap protects customers from the current lack of emergency situation demand-response programs. 

Real-Time Demand Response Bids - Higher of Bid or LMP 

SPP implemented an energy imbalance market and will provide the Commission with a report a year 

from implementation on ways it can incorporate demand response into its imbalance market.235 

Day-Ahead Demand Response Bidding into Market 

SPP will be filing modifications to its tariff related to demand-response bidding into the day-ahead 

market by summer 2007236 

Capacity Market Demand Response Participation 

SPP has no capacity market. 

Ancillary Services Demand Response Participation 

The SPP market has no ancillary services: buyers ensure their own resource adequacy outside of 

market mechanisms; sellers do not have to bid into the imbalance market. 

 

Demand Response in Long-Term Transmission Planning 

The Commission expects SPP to meet Commission requirements for consideration of demand 

response during its conduct of long-term transmission planning processes. 

 234 Southwest Power Pool, Inc., 116 FERC ¶ 61,289 (2006). 

235 Southwest Power Pool, Inc., 114 FERC ¶ 61,289 (2006). 

236 Id.
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Bid Price Floor or Cap for Demand Response 

The SPP has no bid price floor or cap for demand response. 

Electric Reliability Council of Texas (ERCOT) 

ERCOT is a state-chartered (state mandated), nonprofit corporation that controls and operates the 

transmission facilities in Texas. The ERCOT electricity market is a “bilateral” market, with market 

participants meeting their electricity needs primarily through bilateral contracts. Retail Electric 

Providers (REP) must contract with a qualified scheduling entity (QSE) to provide scheduling services 

for their load customers. Resource Entities have (1) generation facilities that can provide energy; 

and/or (2) loads that are capable of reducing demand; and/or (3) reserve capacity. Resource Entities 

must also be represented by a QSE. Only QSEs can submit schedules and bids to ERCOT and settle 

financially with ERCOT. In many cases REPs may be part of the same company as the QSE, and so 

may contract for energy supply through direct agreements with generators. 

ERCOT assists market participants in meeting their balanced-schedule requirements by providing for 

ancillary services and a balancing energy market in which QSEs can buy additional resources to 

correct generation-load imbalances. 

Demand Response Programs 

ERCOT has had a Demand Side Working Group (DSWG), which was created at the direction of the 

Texas PUC, since 2001. Its mission is “to identify and promote opportunities for demand-side 

resources to participate in ERCOT markets, and to recommend adoption of Protocols that foster 

optimum load participation in all markets.” 

ERCOT has relied on over 4,000 megawatts of demand response, primarily interruptible load and 

direct load control programs, to maintain system reliability. One of the goals established by the Texas 

PUC as part of the 2003 wholesale market redesign was that load resources were to have reasonable 

opportunities for greater participation in energy and ancillary services markets in the future.237 

There are three types of load resources, or demand-side resources, in ERCOT: 

• Load Acting as a Resource (LaaR); 

• Qualified Balancing Up Load (BUL); and, 

• Voluntary Load Response. 

Voluntary Load Response provides for customers to “self-direct”, a decision to reduce consumption 

from scheduled or anticipated level in response to price signals. Only customers who have not already 

offered a demand response to the market through the LaaR or BUL offerings can bid in loads under 

the voluntary response offering. Voluntary loads may financially benefit whenever Market Clearing 

Prices of Energy (MCPEs) are high or if a QSE faces a schedule that creates congestion in the 

transmission system only if it has negotiated a favorable REP and/or QSE contract. 

 

237 A Critical Examination of ISO-Sponsored Demand Response Programs A White Paper Prepared for the MultiClient Study: A Critical Examination of Demand Response Programs at the ISO Level: End Goals, Implementation and 

Equity Organized by the Center for the Advancement of Energy Markets and Distributed Energy Financial Group, LLC 

Prepared by Grayson Heffner and Freeman Sullivan. August 2005 (Heffner & Sullivan) and presentation materials at 

http://www.ercot.com/services/training/wholesale_presentations 
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D-14 

Loads contracting through a QSE to provide balancing energy are referred to as Balancing Up Loads. 

BULs are paid only if ERCOT directs them to reduce demand and they respond. Dispatched BULs 

receive both an energy payment—based on the Market Clearing Price for Energy—and a capacity 

payment—based on the Market Clearing Price for Capacity (MCPC). 

ERCOT pays QSEs and the QSEs may flow the payment to the REP, who may, in turn share it with 

the customer who reduced the load. REP products for interruptible customers vary and a retail 

customer can choose how it is compensated for its interruptible load. 

Qualified customers with interruptible loads can provide operating reserves under the LaaR program. 

LaaRs are paid the same as generators in ERCOT. Selected operating reserves providers are also 

eligible for a capacity payment, regardless of whether the interruptible load is actually dispatched. 

This program may be the most demand-friendly ancillary services program in the U.S. 

Emergency Situation Demand Response Programs 

ERCOT requires Retail Electric Providers to provide operating reserves to it on short notice. 

Operating reserves can be either power from generation resources the REPs control or reductions in 

the load the REPs are serving. If an REP fails to provide its required minimum operating reserves, 

ERCOT purchases the difference through day-ahead ancillary services markets. 

Real-Time Demand Response Bids - Higher of Bid or LMP 

QSEs representing Resource Entities bid into a real time market in ERCOT. 

Day-Ahead Demand Response Bidding into Market 

QSEs representing Resource Entities bid into a day-ahead ancillary services market in ERCOT. 

Capacity Market Demand Response Participation 

Balancing Up Loads contracting through a QSE who provide balancing energy are paid only if they 

are selected by ERCOT and reduce load in response. If dispatched, BULs receive both an energy 

payment—based on the Market Clearing Price for Energy—and a capacity payment—based on the 

Market Clearing Price for Capacity. 

Ancillary Services Demand Response Participation 

There are 11 ancillary service programs, eight of which accommodate participation by loads.238

Demand Response in Long-Term Transmission Planning 

ERCOT works directly with the Transmission/Distribution Service Providers, stakeholders/market 

participants through three Regional Planning Groups (North, South, and West).239 ERCOT requires 

that studies on proposed expansion projects consider both transmission and non-transmission solutions 

to performance deficiencies where possible.240 Stakeholders have an opportunity to comment on 

proposals and offer alternative solutions. ERCOT staff performs independent review and provides 

recommendations. 

 238 Heffner & Sullivan. 

239 ISO/RTO Electric System Planning Current Practices, Expansion Plans, and Planning Issues 

A Report Prepared by the ISO/RTO Planning Committee March 2006, 

http://www.ercot.com/news/presentations/2006/IRC_PC_Planning_Report_Final_02_06_06.pdf (Electric Planning Report). 

240 Id. (Electric Planning Report) and Transmission Expansion: Transmission Expansion: Impact of Projects on 

Marginal Costs in ERCOT Impact of Projects on Marginal Costs in ERCOT, Presentation to ERCOT Board of Directors on 

August 16, 2005 by Bill Bojorquez, Director of Transmission Services, ERCOT 

http://www.ercot.com/news/presentations/2005/ce-legislativeday2005.pdf 
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Bid Price Floor or Cap for Demand Response 

QSEs representing Resource Entities have no bid price floor or cap. 
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Appendix E – EPAct 1252 AMI Proceeding Update 

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E-1 

Appendix E: EPAct 1252 AMI Proceedings Update 

The U.S. Demand Response Coordinating Committee (DRCC) has monitored and tracked the 

implementation by state regulatory commissions of Section 1252 of the Energy Policy Act of 2005. 

The following is a state-by-state status report prepared by DRCC on such state activity as of July 1, 

2007. The status of state proceedings in several additional states could not be ascertained, and they are 

not listed in this status update. This does not imply that these states have not taken action on AMI. 

For example, The California Public Utility Commission has been proactive in deploying AMI 

throughout its utilities. 

The DRCC believes it has captured all of the pertinent activity and actions and interpreted them 

appropriately. Due to the scope and nature of state regulatory activities, however, parties interested in 

a particular state are encouraged to review the activities in that state in more detail. Also, in some 

states there has been considerable activity in the area of demand response and advanced metering 

outside of a formal proceeding on EPACT 1252. The DRCC has attempted to highlight some of these 

other activities, and the following listing of them is not meant to be inclusive of all such activity. 

EPACT 1252 Proceedings Status Summary 

States with Open EPACT 1252 Proceedings 27 

States with Closed EPACT 1252 Proceedings 12 

States Deciding to Adopt EPACT 1252 2 

States Deciding not to Adopt EPACT 1252 11 

States Deferring Decision to Adopt EPACT 1252 4 

EPACT 1252 State-by-State Status 

Alabama 

– Proceeding Opened: August 2006 

– Current Status: Open. 

Alaska 

– Proceeding Opened: August 2006 

– Current Status: Open. A Commission Order in June 2007 noted that it is “inclined to 

deny” adoption of Section 1252, but wishes to further develop the record before making a 

final determination. 

Arizona 

– Proceeding Opened: January 2006 

– Current Status: Open. A workshop was scheduled to be held in June 2007. 
Appendix E – EPAct 1252 AMI Proceeding Update 

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E-2 

Arkansas 

– Proceeding Opened: January 2006 

– Current Status: Open. In July 2007, utilities filed proposed “quick start” efficiency 

programs, some of which include demand response. A workshop and public hearing were 

held in May 2007. 

Colorado 

– Proceeding Opened: March 2006 

– Deferred Decision to Adopt EPACT 1252 until March 2008 

– Current Status: Open. Via a December 2006 Order, the Commission deferred 

consideration of EPACT 1252 until March of 2008, pending a review of the results from 

the state’s demand-response pilot program. 

Delaware 

– Proceeding Opened: May 2006 

– Decision: Declined Adoption of EPACT 1252 

– Current Status: Open. Via a January 2007 Order, the Commission decided not to adopt 

EPACT 1252. The proceeding, however, remains open. 

District of Columbia 

– Proceeding Opened: July 2006 

– Current Status: Open. Via a May 2007 Order, the Commission formed a Working Group, 

which is to file a report with the Commission by July 2007. 

Florida 

– Proceeding Opened: January 2007 

– Proceeding Closed: March 2007 

– Decision: Declined Adoption of EPACT 1252 

Georgia 

– Proceeding Opened: August 2006 

– Current Status: Open. 

Idaho 

– Proceeding Opened: July 2006 

– Proceeding Closed: January 2007 

– Decision: Declined Adoption of EPACT 1252 but indicated intent to revisit it in 

utility rate cases 

– The Commission found that the “ubiquitous scope” and “implementation timeline” of 

EPACT 1252 are unrealistic and, therefore, declined to adopt it. The Commission, though, 

agrees with the spirit of the standard and has started smart metering programs with three 

utilities. 

Illinois 

– Proceeding Opened: July 2006 

– Current Status: Open. Via a June 2007 Order the Commission found that Illinois utilities 

have complied with state standards that satisfy the “federal comparable standard test.” The 

proceeding is still open, however, as the Commission needs to determine “whether it is 

appropriate to require utilities to provide time-based meters to all customers.” 
Appendix E – EPAct 1252 AMI Proceeding Update 

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 E-3

Indiana 

– Proceeding Opened: July 2006 

– Current Status: Open. In May 2007 the Commission received Proposed Orders submitted 

by parties to the proceeding. 

Iowa 

– Proceeding Opened: June 2006 

– Proceeding Closed: March 2007 

– Decision: Declined Adoption of EPACT 1252 

Kansas 

– Proceeding Opened: August 2006 

– Current Status: Open. 

Kentucky 

– Proceeding Opened: February 2006 

– Proceeding Closed: December 2006 

– Decision: Declined Adoption of EPACT 1252 

Louisiana 

– Proceeding Opened: December 2005 

– Current Status: Open. The Commission will vote on a Final Proposed Rule at its August 

2007 meeting. The Final Proposed Rule was issued in April 2007 and does not specifically 

approve, reject, or otherwise take action on the PURPA standard. Instead, it provides the 

framework for how advanced metering and demand-response programs should be 

deployed. Meetings and workshops have been held. 

Maryland 

– Proceeding Opened: April 2006 

– Deferred Decision to Adopt EPACT 1252 

– Current Status: Open. Via a February 2007 ruling, the Commission deferred its decision 

on EPACT 1252. 

Michigan 

– Proceeding Opened: January 2007 

– Decision: Most utilities meet the PURPA Standard 

– Current Status: Open. Via a January 2007 Order, the Commission initiated this proceeding 

and announced that all Michigan utilities subject to EPACT 1252 already satisfy the 

PURPA standard, save two: Edison Sault and Midwest Energy Cooperative. The 

Commission created a separate proceeding for each utility, though it did not close this 

proceeding. 

Minnesota 

– Proceeding Opened: August 2006 

– Current Status: Open. 

Missouri 

– Proceeding Opened: June 2006 

– Current Status: Open. 
Appendix E – EPAct 1252 AMI Proceeding Update 

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E-4 

Montana 

– Proceeding Opened: May 2006 

– Proceeding Closed: December 2006 

– Deferred Decision to Adopt EPACT 1252 

– Commission deferred determination of whether to adopt the smart metering provision of 

EPACT 2005 until next general electric case for each utility. 

Nevada

– Proceeding Opened: June 2006 

– Proceeding Closed: January 2007 

– Deferred Decision to Adopt EPACT 1252 

– The Commission deferred decision about EPACT 1252 pending its evaluation of research 

submitted by parties to the proceeding. 

New Hampshire 

– Proceeding Opened: April 2006 

– Current Status: Open. 

– Decision: Adopted EPACT 1252 

– In a June 2007 Order, the Commission adopted EPACT 1252. While the Commission did 

not mandate real-time pricing for all default service customers, it did issue several 

directives to facilitate the development of dynamic rates and smart metering systems. The 

proceeding remains open. 

New Mexico 

– Proceeding Opened: September 2006 

– Current Status: Open. Workshop was held in January 2007. 

New York 

– Proceeding Opened: August 2006 

– Proceeding Closed: July 2007 

– Decision: Declined Adoption of EPACT 1252 

– The Commission determined that it already provides a “time-based metering and 

communications standard comparable to PURPA.” 

North Carolina 

– Proceeding Opened: August 2006 

– Current Status: Open. Via a February 2007 Proposed Order, the Commission’s Staff 

recommended declining adoption of EPACT 1252. 

North Dakota 

– Proceeding Opened: July 2006 

– Current Status: Open. 

Ohio 

– Proceeding Opened: December 2005 

– Current Status: Open. 

– Decision: Adopted EPACT 1252 

– Via a March 2007 Finding and Order, the Commission adopted EPACT 1252 and directed 

electric distribution companies to offer dynamic pricing to all customer classes and to 

make available smart meters to all customers. This proceeding is still open, however, and 
Appendix E – EPAct 1252 AMI Proceeding Update 

1⁄2 2007 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4

 E-5

further activity is planned. In May 2007, the Commission opened a new proceeding to 

facilitate a series of technical workshops on EPACT 1252. 

Rhode Island 

– Proceeding Opened: July 2006 

– Current Status: Open. 

South Carolina 

– Proceeding Opened: December 2005 

– Current Status: Open. 

South Dakota 

– Proceeding Opened: June 2006 

– Current Status: Open. Both a hearing and a workshop were held during May 2007. 

Tennessee 

– Proceeding Opened: July 2006 

– Proceeding Closed: January 2007 

– Decision: Declined Adoption of EPACT 1252 

– Note: This proceeding was specifically for Entergy Arkansas. 

– Proceeding Opened: July 2006 

– Proceeding Closed: January 2007 

– Decision: Declined Adoption of EPACT 1252 

– Note: This proceeding was specifically for Kentucky Utilities Company. 

– Proceeding Opened: February 2006 

– Proceeding Closed: August 2006 

– Decision: Declined Adoption of EPACT 1252 

– Note: This proceeding was specifically for Appalachian Power. 

Texas 

– Proceeding Opened: August 2006 

– Current Status: Open. 

Utah 

– Proceeding Opened: June 2006 

– Proceeding Closed: February 2007 

– Decision: Declined Adoption of EPACT 1252 

Vermont 

– Proceeding Opened: December 2005 

– Proceeding Closed: February 2007 

– Decision: Declined Adoption of EPACT 1252 

Virginia 

– Proceeding Opened: February 2006 

– Proceeding Closed: July 2006 

– Decision: Declined Adoption of EPACT 1252 

Washington 

– Proceeding Opened: April 2006 
Appendix E – EPAct 1252 AMI Proceeding Update 

1⁄2 2007 Assessment of Demand Response and Advanced Metering 3⁄4 

1⁄2 Federal Energy Regulatory Commission 3⁄4 

E-6 

– Current Status: Open. In July 2007, the Commission issued a draft Interpretive and Policy 

Statement that declines adoption of EPACT 1252 because the Commission already 

established a policy relative to the 1980 PURPA standards that is comparable to EPACT 

1252.

West Virginia 

– Proceeding Opened: May 2006 

– Proceeding Closed: December 2006 

– Decision: Declined Adoption of EPACT 1252 

Wyoming 

– Proceeding Opened: August 2006 

– Current Status: Open. 
Appendix F: Utility AMI Implementation Projection 

1⁄2 2007 Assessment of Demand Response and Advanced Metering 3⁄4

1⁄2 Federal Energy Regulatory Commission 3⁄4

F-1

Appendix F: Utility AMI Implementation Projection 

Table F-1 contains a detailed list of some of the large AMI deployments that have been announced or are 

expected with some level of confidence by the end of 2008. This forecast of implementation was 

compiled by Patti Harper-Slaboszewicz of UtiliPoint International under contract to FERC. 
Appendix F: Utility AMI Implementation Projection 

1⁄2 2007 Assessment of Demand Response and Advanced Metering 3⁄4

1⁄2 Federal Energy Regulatory Commission 3⁄4

F-2

Table F-1. Utility AMI Implementation Projection 

Utility AMI type Meters Year Status 

Kansas City Power and Light Fixed RF 473,863 1996 Contracted 

Puget Sound Energy Fixed RF 1,325,000 1997 Contracted 

Exelon (PECO) Fixed RF 2,100,000 1999 Contracted 

United Illuminating (CT) Fixed RF 320,000 1999 Contracted 

Lee County Electric Cooperative PLC 185,280 2001 Contracted 

Pedernales Electric Cooperative PLC 200,698 2001 Contracted 

Austin Energy Fixed RF 125,864 2002 Contracted 

PPL (PA) PLC 1,353,024 2002 Contracted 

WE Energies (WI) Fixed RF 1,000,000 2002 Contracted 

Wisconsin Public Service PLC 425,000 2002 Contracted 

Bangor Hydro PLC 125,000 2004 Contracted 

Colorado Springs Fixed RF 400,000 2005 Contracted 

TXU PLC 265,000 2005 Contracted 

TXU BPL 2,000,000 2005 Contracted 

CenterPoint Fixed RF and BPL 1,900,000 2006 Contracted 

Chathum Kent Fixed RF 100,000 2006 Contracted 

City of Seattle Fixed RF 400,000 2006 Contracted 

PG&E (CA) PLC 5,100,000 2006 Contracted 

Southern Company Fixed RF 35,000 2006 Contracted 

Arizona Public Service Fixed RF 800,000 2007 Utility plans 

Austin Energy Fixed RF 230,000 2007 Contracted 

BGE TBD 1,000,000 2007 Filed AMI plan 

Consolidated Edison BPL 500,000 2007 Utility plans 

Consumers Energy Fixed RF 1,700,000 2007 Utility plans 

DTE Energy TBD 1,300,000 2007 Utility plans 

Duke Energy in Kentucky Fixed RF 250,000 2007 Utility plans 

Florida Power and Light Fixed RF 100,000 2007 Contracted 

Hawaiian Electric Company Fixed RF 3,000 2007 Contracted 

Northeast Utilities Fixed RF 1,181,880 2007 Filed AMI plan 

Southern California Edison Fixed RF 4,475,000 2007 Filed AMI plan 

Tallahassee, city of TBD 107,780 2007 Utility plans 

WE Energies (WI) Fixed RF 100,000 2007 Contracted 

Xcel Energy Fixed RF 710,000 2007 Contracted 

Utilities active in market TBD 3,960,000 2007 Market Activity 

American Electric Power TBD 4,730,000 2008 Utility plans 

Anaheim Utilities Fixed RF 110,635 2008 Utility plans 

Consolidated Edison TBD 1,900,000 2008 Utility plans 

CPS Energy TBD 627,210 2008 Utility plans 

Duke Energy in NC TBD 2,200,000 2008 Filed AMI plan 

Energy East TBD 1,229,788 2008 Filed AMI plan 

Florida Power and Light TBD 3,900,000 2008 Pilot Ongoing 

Hawaiian Electric Company TBD 291,580 2008 Pilot Ongoing 

Pepco Holdings Fixed RF 1,830,000 2008 Filed AMI plan 

Portland General TBD 775,000 2008 Filed AMI plan 

San Diego Gas and Electric TBD 1,300,000 2008 Filed AMI plan 

Central Vermont Public Service TBD 175,000 2010 Utility plans 

Source: Utilipoint International 

Notes: PLC: Powerline carrier 

BPL: Broadband-over-powerlines 

Fixed RF: Refers to AMI that includes a network infrastructure based radio frequency (RF) communications 

independent of the distribution network. Usually the meters send data to and receive data from other meters, data 

collectors, and/or communication towers. 

TBD: To be decided. The utility has not yet announced and/or selected AMI technology