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Load as a Resource

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Demand Response as a System Reliability Resource
Eto, J., N. Lewis, D. Watson and S. Kiliccote, Lawrence Berkeley National Laboratory; D. Auslander and I. Paprotny, University of California, Berkeley; Y. Makarov, Pacific Northwest National Laboratory. January 2012
1.1 MB PDF, 91 pp

The Demand Response as a System Reliability Resource project consists of six technical tasks:

  • Task 2.1. Test Plan and Conduct Tests: Contingency Reserves Demand Response (DR) Demonstration—a pioneering demonstration of how existing utility load-management assets can provide an important electricity system reliability resource known as contingency reserve.
  • Task 2.2. Participation in Electric Power Research Institute (EPRI) IntelliGrid—technical assistance to the EPRI IntelliGrid team in developing use cases and other high-level requirements for the architecture.
  • Task 2.3. Research, Development, and Demonstration (RD&D) Planning for Demand Response Technology Development—technical support to the Public Interest Energy Research (PIER) Program on five topics: Sub-task 1. PIER Smart Grid RD&D Planning Document; Sub-task 2. System Dynamics of Programmable Controllable Thermostats; Sub-task 3. California Independent System Operator (California ISO) DR Use Cases; Sub-task 4. California ISO Telemetry Requirements; and Sub-task 5. Design of a Building Load Data Storage Platform.
  • Task 2.4. Time Value of Demand Response—research that will enable California ISO to take better account of the speed of the resources that it deploys to ensure compliance with reliability rules for frequency control.
  • Task 2.5. System Integration and Market Research: Southern California Edison (SCE)—research and technical support for efforts led by SCE to conduct demand response pilot demonstrations to provide a contingency reserve service (known as non-spinning reserve) through a targeted sub-population of aggregated residential and small commercial customers enrolled in SCE's traditional air conditioning (AC) load cycling program, the Summer Discount Plan.
  • Task 2.6. Demonstrate Demand Response Technologies: Pacific Gas and Electric (PG&E)—research and technical support for efforts led by PG&E to conduct a demand response pilot demonstration to provide non-spinning reserve through a targeted sub-population of aggregated residential customers enrolled in PG&E's AC load curtailment program, the Smart AC™ Demand Response Program.
Autonomous Demand Response for Primary Frequency Regulation
Donnelly, M., S. Mattix, D. Trudnowski, J.E. Dagle. PNNL-21152. January 2012
947 KB PDF, 69 pp

Demand response has long been an integral part of power system control and operation. Recently, demand response has received more interest as a potentially effective tool to help gain higher levels of asset utilization on the bulk power grid and to avoid or delay the need for new transmission-line construction.

Autonomous demand response is defined as load response to system-based signals rather than to master control signals or price signals from a central dispatch center. The most readily available system- based signal is frequency, which can be a very reliable indicator of grid instability, problems, or abnormal conditions. Speed governing systems at central generating stations, when operating in droop mode, employ frequency as the primary feedback signal. These governors are largely responsible for affecting primary frequency response of the bulk power grid thereby maintaining a continuous balance between supply and demand.

This research examines the use of autonomous demand response to provide primary frequency response in an interconnected grid. Ultimately, it is conceivable that all primary frequency response might be delivered by responsive load leaving dispatchable generation to be base loaded or ramped with very slow ramp rates. If this objective were to be achieved, numerous benefits might be realized, including reduced emissions from fossil plants as a result of higher operating efficiencies and greater flexibility in integrating variable generation sources such as wind and solar. The work builds on previous studies in several key areas: it uses a large realistic model (i.e., the interconnection of the western United States and Canada); it establishes a set of metrics that can be used to assess the effectiveness of autonomous demand response; and it independently adjusts various parameters associated with using autonomous demand response to assess effectiveness and to examine possible threats or vulnerabilities associated with the technology. Where prior research has focused on showing the efficacy of the concept in delivering primary frequency response, this study's primary objective was to identify any potential deleterious effects.

More than 6000 simulations of the power system model were conducted during the course of the study. A key finding is that there are very few conditions associated with autonomous demand response that have the potential to degrade reliability. Substantial improvement in primary frequency response was demonstrated in almost all cases without negative impacts on other aspects of system reliability. Two areas of concern documented in the study are excessive time delay within the control loop and high penetration of autonomous demand response concentrated in one region of an interconnected grid. Both concerns are related to oscillatory stability of the grid, not with frequency response, and both could be corrected by appropriate design of the control law. The authors conclude that frequency-based autonomous demand response should not be used in conjunction with demand-side appliances that respond slowly to frequency excursions unless care is taken to ensure that the control law takes into account the appropriate delay.

Another finding is that the marginal benefit attributable to autonomous demand response is quantifiable, and can be used to determine the value of the technology for providing primary frequency response in an environment of increasing costs for this service as provided by traditional means. Additional work is needed to verify the findings of this preliminary investigation. It is proposed that this work be conducted in collaboration with the electric utility industry.

Measuring Short-term Air Conditioner Demand Reductions for Operations and Settlement
Bode, J., M. Sullivan, J. Eto. LBNL-5330E. January 2012
1.0 MB PDF, 120 pp

Several recent demonstrations and pilots have shown that air conditioner (AC) electric loads can be controlled during the summer cooling season to provide ancillary services and improve the stability and reliability of the electricity grid. A key issue for integration of air conditioner load control into grid operations is how to accurately measure shorter-term (e.g., ten's of minutes to a couple of hours) demand reductions from AC load curtailments for operations and settlement. This report presents a framework for assessing the accuracy of shorter-term AC load control demand reduction measurements. It also compares the accuracy of various alternatives for measuring AC reductions — including methods that rely on regression analysis, load matching and control groups — using feeder data, household data and AC end-use data. A practical approach is recommended for settlement that relies on set of tables, updated annually, with pre- calculated load reduction estimates. The tables allow users to look up the demand reduction per device based on the daily maximum temperature, geographic region and hour of day and simplify the settlement process.

Customer Impact Evaluation for the 2009 Southern California Edison Participating Load Pilot
Gifford, W., S. Bodmann and P. Young, KEMA; J. Eto, Lawrence Berkeley National Laboratory; J. Laundergan, Southern California Edison. LBNL-3550E. June 2010
310 KB PDF, 35 pp

The 2009 Participating Load Pilot Customer Impact Evaluation provides evidence that short duration demand response events which cycle off air conditioners for less than thirty minutes in a hot, dry environment do not lead to a significant degradation in the comfort level of residents participating in the program.

This was investigated using

  1. Analysis of interval temperature data collected from inside residences of select program participants; and
  2. Direct and indirect customer feedback from surveys designed and implemented by Southern California Edison at the conclusion of the program season.

There were 100 indoor temperature monitors that were acquired by LBNL for this study that transmitted temperature readings at least once per hour with corresponding timestamps during the program season, June - October, 2009. Recorded temperatures were transferred from the onsite telemetry devices to a mesh network, stored, and then delivered to KEMA for analysis. Following an extensive data quality review, temperature increases during each of the thirty demand response test events were calculated for each device. The results are as follows:

  1. Even for tests taking place during outside temperatures in excess of 100 degrees Fahrenheit, over 85 percent of the devices measured less than a 0.5 degree Fahrenheit temperature increase indoors during the duration of the event.
  2. For the increases that were observed, none was more than 5 degrees and it was extremely rare for increases to be more than 2 degrees.

At the end of the testing season SCE and KEMA designed and conducted a survey of the a facilities and public works managers and approximately 100 customers feedback survey to assess the extent the PLP events were noticed or disrupted the comfort level of participants. While only a small sampling of 3 managers and 16 customer surveys were completed, their responses indicate:

  1. No customer reported even a moderate level of discomfort from the cycling-off of their air conditioners during test events.
  2. Very few customers noticed any of the thirty events at all.

The results of this study suggest that the impacts on comfort from short-duration interruptions of air-conditioners, even in very hot climates, are for the most part very modest, if they are even noticed at all. Still, we should expect that these impacts will increase with longer interruptions of air-conditioning. By the same token, we should also expect that they will be less significant in cooler climates.

NYISO Industrial Load Response Opportunities: Resource and Market Assessment—Task 2 Final Report
Kirby, B., M. Starke and S. Adhikari, Oak Ridge National Laboratory. ORNL/TM-2009/147. October 2009
834 KB PDF, 71 pp

This report examines the ability of responsive loads to reduce energy costs and increase power system reliability by selling ancillary services (regulation, contingency reserves, and dynamic reactive support) to the power system while purchasing power to perform the basic functions the loads were designed to do. A basic understanding of power system ancillary services is provided including definitions and characteristics of each service. Preliminary examination of ancillary service prices in NY, Texas, California, and New England indicate that regulation prices are particularly attractive, and have been for years. Studying the hourly energy and ancillary service market prices provides a sound basis for determining the genuine value of response to the power system and the revenue responsive loads can likely capture. Load response is examined as it relates to power system needs in general and as it relates to the specific requirements of the power system operated by the New York Independent System Operator. The various current opportunities for load response within the New York Independent System Operator market structure are discussed. A modeling effort to determine the optimal mix of energy and ancillary service response capabilities for individual loads is outlined.

Demand Response Spinning Reserve Demonstration — Phase 2 Findings from the Summer of 2008
Eto, J., Lawrence Berkeley National Laboratory; J. Nelson-Hoffman and E. Parker, Southern California Edison; C. Bernier and P. Young, KEMA; D. Sheehan, BPL Global; and J. Kueck and B. Kirby, Oak Ridge National Laboratory. LBNL-2490E. April 2009
5.4 MB PDF, 151 pp

The Demand Response Spinning Reserve project is a pioneering demonstration showing that existing utility load-management assets can provide an important electricity system reliability resource known as spinning reserve. Using aggregated demand-side resources to provide spinning reserve as demonstrated in this project will give grid operators at the California Independent System Operator (CA ISO) and Southern California Edison (SCE) a powerful new tool to improve reliability, prevent rolling blackouts, and lower grid operating costs.

In the first phase of this demonstration project, we target marketed SCE's air-conditioning (AC) load-cycling program, called the Summer Discount Plan (SDP), to customers on a single SCE distribution feeder and developed an external website with real-time telemetry for the aggregated loads on this feeder and conducted a large number of short-duration curtailments of participating customers' air-conditioning units to simulate provision of spinning reserve. In this second phase of the demonstration project, we explored four major elements that would be critical for this demonstration to make the transition to a commercial activity:

  1. We conducted load curtailments within four geographically distinct feeders to determine the transferability of target marketing approaches and better understand the performance of SCE's load management dispatch system as well as variations in the AC use of SCE's participating customers;
  2. We deployed specialized, near-real-time AC monitoring devices to improve our understanding of the aggregated load curtailments we observe on the feeders;
  3. We integrated information provided by the AC monitoring devices with information from SCE's load management dispatch system to measure the time required for each step in the curtailment process; and
  4. We established connectivity with the CA ISO to explore the steps involved in responding to CA ISO-initiated requests for dispatch of spinning reserve.

The major findings from the second phase of this demonstration are:

  1. Demand-response resources can provide full response significantly faster than required by NERC and WECC reliability rules.
  2. The aggregate impact of demand response from many small, individual sources can be estimated with varying degrees of reliability through analysis of distribution feeder loads.
  3. Monitoring individual AC units helps to evaluate the efficacy of the SCE load management dispatch system and better understand AC energy use by participating customers.
  4. Monitoring individual AC units provides an independent data source to corroborate the estimates of the magnitude of aggregate load curtailments and gives insight into results from estimation methods that rely solely on distribution feeder data.
Using Air Conditioning Load Response for Spinning Reserve
Kueck, J., B. Kirby, M. Ally, and C. Rice, ORNL. ORNL/TM-2008/227. February 2009
280 KB PDF, 33 pp

This report assesses the use of air conditioning load for providing spinning reserve and discusses load forecasting challenges, temperature effect, and the effect of the load drop on customer homes. Air conditioning load is well suited for the spinning reserve service because it often increases during heavy load periods and can be curtailed for short periods with little impact to the customer. The report also provides an appendix describing the ambient temperature effect on air conditioning load.

Providing Reliability Services through Demand Response: A Preliminary Evaluation of the Demand Response Capabilities of Alcoa Inc.
Todd, D., M. Caufield, B. Helms, Alcoa Power Generating, Inc.; M. Starke, B. Kirby, J. Kueck, Oak Ridge National Laboratory. January 2009
952 KB PDF, 60 pp

Demand response is the largest underutilized reliability resource in North America. Historic demand response programs have focused on reducing overall electricity consumption (increasing efficiency) and shaving peaks but have not typically been used for immediate reliability response. Many of these programs have been successful but demand response remains a limited resource. The Federal Energy Regulatory Commission (FERC) report, "Assessment of Demand Response and Advanced Metering" (FERC 2006) found that only five percent of customers are on some form of demand response program. Collectively they represent an estimated 37,000 MW of response potential. These programs reduce overall energy consumption, lower green house gas emissions by allowing fossil fuel generators to operate at increased efficiency and reduce stress on the power system during periods of peak loading.

This report is organized into seven chapters. The first chapter is the introduction and discusses the intention of this report. The second chapter contains the background. In this chapter, topics include: the motivation for Alcoa to provide demand response; ancillary service definitions; the basics behind aluminum smelting; and a discussion of suggested ancillary services that would be particularly useful for Alcoa to supply. Chapter 3 is concerned with the independent system operator, the Midwest ISO. Here the discussion examines the evolving Midwest ISO market structure including specific definitions, requirements, and necessary components to provide ancillary services. This section is followed by information concerning the Midwest ISO's classifications of demand response parties. Chapter 4 investigates the available opportunities at Alcoa's Warrick facility. Chapter 5 involves an in-depth discussion of the regulation service that Alcoa's Warrick facility can provide and the current interactions with Midwest ISO. Chapter 6 reviews future plans and expectations for Alcoa providing ancillary services into the market. Last, chapter 7, details the conclusion and recommendations of this paper.

Spinning Reserve from Hotel Load Response: Initial Progress
Kirby, B., J. Kueck, Oak Ridge National Laboratory; T. Laughner, K. Morris, Tennessee Valley Authority. October 2008
465 KB PDF, 35 pp

This project was motivated by the fundamental match between hotel space conditioning load response capability and power system contingency response needs. As power system costs rise and capacity is strained, demand response can provide a significant system reliability benefit at a potentially attractive cost.

Assessing the Value of Regulation Resources Based on Their Time Response Characteristics
Makarov, Y.V., J. Ma, S. Lu, T.B. Nguyen. PNNL-17632. June 2008
631 KB PDF, 83 pp

Fast responsive generation, demand control and energy storage are valuable power sys-tem regulation resources because they allow controls to be applied at the exact moment and in the exact amount needed. Faster control could potentially provide more reliable compliance with the North American Electric Reliability Corporation (NERC) Control Performance Standards (CPS) [1] at relatively lesser regulation capacity procurements. The current California Independent System Operator (ISO) practices and markets do not provide a differentiation among the regulation resources based on their speed of response (with the exception of some capacity bid limitations applied to generators with minimum ramping capability). California ISO practices and markets could be updated to enable more fast regulation resources into the California ISO service area.

Demand Response Spinning Reserve Demonstration
Eto, J., Principal Investigator (Lawrence Berkeley National Laboratory), Project Team: J. Nelson-Hoffman, C. Torres, S. Hirth, B. Yinger (Southern California Edison), J. Kueck, B. Kirby (Oak Ridge National Laboratory), C. Bernier, R. Wright (RLW Analytics), A. Barat (Connected Energy), D. Watson (Lawrence Berkeley National Laboratory). LBNL-62761. May 2007
799 KB PDF, 78 pp

The Demand Response Spinning Reserve project is a pioneering demonstration of how using existing utility load-management assets can provide an important electricity system reliability resource known as spinning reserve. Providing spinning reserve with aggregated demand-side resources such as those illustrated in this report will give grid operators at California Independent System Operator (CAISO) and Southern California Edison (SCE) a powerful, new tool to improve system reliability, prevent rolling blackouts, and lower system operating costs.

The work completed to date to demonstrate the use of demand-response as spinning reserve has produced important programmatic and technical insights, including:

  • Target-marketing a utility's air-conditioning load-cycling program to customers served by a single distribution feeder can be a successful strategy. SCE successfully recruited a high proportion (nearly one-third) of eligible customers to participate in the demonstration.
  • Repeated curtailment of these customers' air-conditioning in a manner similar to the deployment of spinning reserve can be accomplished without a single customer complaint. SCE curtailed these customers' air-conditioning units 37 times during the final portion of Southern California's cooling season for durations lasting from five to nearly 20 minutes, and did not receive any customer complaints regarding the curtailments.
  • Real-time visibility of load curtailments can be achieved through an open data platform and secure website. The project team demonstrated a highly flexible, open yet secure data-integration, archival, and presentation platform that allowed external audiences (e.g., electricity grid operators) to see curtailments in real time. Using such a platform and website could significantly lower the costs of this service relative to current practices.
  • Analysis methods developed for this project could one day be used to predict magnitude of load curtailments as a function of weather and time of day. The project team developed statistical methods to estimate the load that would have been observed without a curtailment and means for comparing this estimated load to actual loads observed during curtailments. The team also conducted exploratory analyses that confirmed the existence of a relationship between the magnitude of the load curtailment, and ambient weather conditions and to a lesser, but still suggestive extent, time of day.
  • Load curtailments can be fully implemented much faster than ramping up of spinning reserve from thermal generation. The project team measured full load response in less than 20 seconds and identified technical opportunities to further increase the response speed.
Loads Providing Ancillary Services: Review of International Experience
Heffner, G. and C. Goldman, LBNL; B. Kirby, ORNL; and M. Kintner-Meyer, PNNL. LBNL-62701, ORNL/TM-2007/060, PNNL-16618. May 2007
Report, 327 KB PDF, 64 pp
Appendix, 829 KB PDF, 71 pp
In this study, we examine the arrangements for and experiences of end-use loads providing ancillary services (AS) in five electricity markets: Australia, the United Kingdom (UK), the Nordic market, and the ERCOT and PJM markets in the United States. Our objective in undertaking this review of international experience was to identify specific approaches or market designs that have enabled customer loads to effectively deliver various ancillary services (AS) products. We hope that this report will contribute to the ongoing discussion in the U.S. and elsewhere regarding what institutional and technical developments are needed to ensure that customer loads can meaningfully participate in all wholesale electricity markets.
Demand Response For Power System Reliability: FAQ
Kirby, B.J. Oak Ridge National Laboratory. ORNL/TM-2006/565. December 2006
518 KB PDF, 43 pp

Demand response is the largest underutilized reliability resource in North America. Historic demand response programs have focused on reducing overall electricity consumption (increasing efficiency) and shaving peaks but have not typically been used for immediate reliability response. Many of these programs have been successful but demand response remains a limited resource. The Federal Energy Regulatory Commission (FERC) report, Assessment of Demand Response and Advanced Metering (FERC 2006) found that only five percent of customers are on some form of demand response program. Collectively they represent an estimated 37,000 MW of response potential. These programs reduce overall energy consumption and they also reduce stress on the power system at times of peak loading.

More recently demand response has begun to be considered, and in some cases actually used, to directly supply reliability services to the power system. Rather than reducing overall power system stress by reducing peak loading over multiple hours these programs are targeted to immediately respond to specific reliability events. This is made possible by advances in communications and controls and has benefits for the power system and the load.

Unfortunately, preconceptions concerning load response capabilities, coupled with misunderstandings of power system reliability needs, are limiting the use of responsive loads. In many places loads are prohibited from providing the most valuable reliability services in spite of their being evidence that their response can be superior to that of generators. This is denying the power system of a valuable reliability resource. It is also denying loads the ability to sell valuable services.

This report addresses a number of common misconceptions concerning responsive load and power system reliability interactions. It is structured as a set of short questions and answers and is intended for power system operators, planners, regulators, load owners, and other interested parties.

The report is organized into three chapters. Chapter 1 is this introduction. Chapter 2 contains questions and answers on demand response and power system reliability. Chapter 3 provides conclusions and recommendations.

A Survey of Utility Experience with Real Time Pricing
Barbose, G., and C. Goldman, Lawrence Berkeley National Laboratory; and B. Neenan, Neenan Associates. LBNL-54238. December 2004
583 KB PDF, 127 pp

Under real time pricing (RTP) tariffs, electricity consumers are charged prices that vary over short time intervals, typically hourly, and are quoted one day or less in advance to reflect contemporaneous marginal supply costs. RTP differs from conventional retail tariffs, which are based on prices that are fixed for months or years at a time to reflect average, embedded supply costs. In recent years, a resurgence of interest in RTP has occurred. Economists recognize that providing electricity consumers with price incentives to reduce their usage when wholesale prices rise would improve the performance of wholesale electricity markets in two important ways: mitigating suppliers' ability to exercise market power and dampening price volatility. Policymakers engaged in electric utility resource planning have also recognized that, by reducing peak demand, RTP could play an important role in a portfolio of strategies for cost-effectively meeting utility load obligations. While other mechanisms can be used to induce price responsive demand and/or reduce peak demand, many economists argue that RTP represents the most direct and efficient approach, and therefore it should be the primary focus of policymakers' efforts to improve the performance of wholesale and retail electricity markets (Borenstein et al. 2002).

While clearly appealing from a theoretical perspective, questions remain about the extent to which RTP can ultimately affect wholesale market performance and utility resource planning. First, assuming that RTP is offered on a voluntary basis, how many customers would choose to enroll in RTP, given the additional risks and transaction costs compared to traditional, fixed price retail supply service? Second, even if a sizable number of customers did choose to enroll, to what extent, and how consistently, would a diverse population of participants respond to the prices they face? Some insight into these issues can be gleaned from experiences with several prominent RTP programs frequently featured in the literature. However, to understand the potential role of RTP in settings with substantially different types of customers and/or different market and regulatory conditions, policymakers require a wider base of experience.

Customer Response to Day-ahead Wholesale Market Electricity Prices: Case Study of RTP Program Experience in New York
Goldman, C., N. Hopper, O. Sezgen, M. Moezzi and R. Bharvirkar, Lawrence Berkeley National Laboratory; and B. Neenan, R. Boisvert, P. Cappers, and D. Pratt, Neenan Associates. June 2004
Report, 2.3 MB PDF, 208 pp
Appendix, 744 KB PDF, 63 pp
Fact Sheet, 336 KB PDF, 2 pp

This study attempts to address some of these information gaps through an in-depth case study of 149 large commercial and industrial customer accounts served by Niagara Mohawk Power Corporation (NMPC). In October 1998, with the commencement of retail access in New York, NMPC replaced the existing time-of-use (TOU) tariff for large customers with peak demand in excess of two megawatts with a day-ahead, market-based RTP rate design. This new default SC-3A service, called "Option 1", recovers fixed costs (e.g., transmission and distribution) largely through demand charges and prices electric commodity at hourly-varying prices indexed to the NYISO day-ahead market. Hourly prices for the next day are transmitted to customers by 4pm.

Demand Response Research Plan to Reflect the Needs of the California Independent System Operator
Kirby, B., and J. Kueck. February 2004
530 KB PDF, 78 pp

This document presents a research plan to increase the use of demand response and enhance power system reliability. This research plan is based only upon interviews and discussions with California Independent System Operator (CAISO) staff.

Demand Response Research Plan to Reflect the Needs of the California Independent System Operator
Kueck, J., and B. Kirby, Oak Ridge National Laboratory. January 2004
316 KB PDF, 76 pp

This document presents a research plan to increase the use of demand response and enhance power system reliability. This research plan is based only upon interviews and discussions with California Independent System Operator (CAISO) staff.

Spinning Reserve from Pump Load: A Technical Findings Report to the California Department of Water Resources
Kirby, B., and J. Kueck, Oak Ridge National Laboratory. November 2003
443 KB PDF, 58 pp

The Oak Ridge National Laboratory (ORNL), at the request of the California Energy Commission and the U.S. Department of Energy, investigating opportunities for electrical load to provide the ancillary service of spinning reserve to the electric grid. The load would provide this service by stopping for a short time when there is a contingency on the grid such as a transmission line or generator outage. There is a possibility that a significant portion of the California Independent System Operator's (CAISO's) spinning reserve requirement could be supplied from the California Department of Water Resources (CDWR) pumping load.

Spinning Reserve From Responsive Loads
Kirby, B., P.E., Oak Ridge National Laboratory. March 2003
292 KB PDF, 41 pp

Responsive load is the most underutilized reliability resource available to the power system today. It is currently not used at all to provide spinning reserve. Historically there were good reasons for this, but recent technological advances in communications and controls have provided new capabilities and eliminated many of the old obstacles. North American Electric Reliability Council (NERC), Federal Energy Regulatory Commission (FERC), Northeast Power Coordinating Council (NPCC), New York State Reliability Council (NYSRC), and New York Independent System Operator (NYISO) rules are beginning to recognize these changes and are starting to encourage responsive load provision of reliability services. This report provides detailed results from one example technology, the Carrier Comfort Choice responsive thermostats deployed in the Long Island Power Authority (LIPA) LIPA edge program to provide peak demand reduction through central control of residential and small commercial air-conditioners.

EnergyWeb Screening Criteria Report
Widergren, S.E., R.T. Guttromson, and M.C. Baechler, Pacific Northwest National Laboratory. January 2003
188 KB PDF, 52 pp

This report describes a framework for evaluating candidate participants in a distributed resource aggregation program, as envisioned in the Bonneville Power Administration's (BPA) EnergyWeb initiative. The framework includes definition of system goals, relevant material that characterizes a distributed energy resource (DER) participant, rules for evaluating candidate participants, and a process that utilizes this information to produce a list of the most attractive candidates.

How and Why Customers Respond to Electricity Price Variability: A Study of NYISO and NYSERDA 2002 PRL Program Performance
Neenan, B., D. Pratt, P. Cappers, J. Doane, J. Anderson and R. Boisvert, Neenan Associates; C. Goldman, O. Sezgen, G. Barbose and R. Bharvirkar, Lawrence Berkeley National Laboratory. January 2003
2.4 MB PDF, 376 pp

Summer 2002 was the second year of operation for the New York Independent System Operator's (NYISO) suite of Price Responsive Load (PRL) Programs: the Day-Ahead Demand Response Program, the Emergency Demand Response Program, and the third year of operation for the Installed Capacity Program/Special Case Resources program. It also marked the second year that the New York State Energy Research Authority (NYSERDA) provided funding to support participation in these programs. NYISO and NYSERDA commissioned Neenan Associates, augmented by significant professional staff resources provided by the Consortium for Electric Reliability Technology Solutions with U.S. Department of Energy funding, to conduct a comprehensive evaluation of the performance of the 2002 PRL programs.

Spinning Reserves from Controllable Packaged Through the Wall Air Conditioner (PTAC) Units
Kirby, B.J., and M.R. Ally. November 2002
462 KB PDF, 62 pp

This report summarizes the feasibility of providing spinning reserves from packaged through the wall air conditioning (PTAC) units. Spinning reserves, together with non-spinning reserves, compose the contingency reserves; the essential resources that the power system operator uses to restore the generation and load balance and maintain bulk power system reliability in the event of a major generation or transmission outage. Spinning reserves are the fastest responding and most expensive reserves. Many responsive load technologies could (and we hope will) be used to provide spinning reserve. It is also easier for many loads (including air conditioning loads) to provide the relatively shorter and less frequent interruptions required to respond to contingencies than it is for them to reduce consumption for an entire peak period. Oak Ridge National Laboratory (ORNL) is conducting research on obtaining spinning reserve from large pumping loads and from residential and small commercial thermostat controlled heating, ventilation and air conditioning (HVAC) units. The technology selected for this project, Digi-Log's retrofit PTAC controller, offers significant advantages.

To evaluate the availability of spinning reserve capacity from responsive heating and air conditioning loads, ORNL obtained data from a number of units operating over a year at a motel in the TVA service territory. A total of 24 PTAC units in as many rooms were fitted with Digi- Log's supervisory control unit that could be controlled from the motel front desk. Twelve of the rooms formed the group in which the controller was controlled from the hotel front desk only. The remaining twelve rooms were controlled by the occupant and formed the uncontrolled group. This enables us to evaluate the spinning reserve capacity from PTACS that were operating normally and from those under active energy management.

Do "Enabling Technologies" Affect Customer Performance in Price-Responsive Load Programs?
Goldman, C., M. Kintner-Meyer, and G. Heffner. 2002 ACEEE's Summer Study on Energy Efficiency in Buildings, Asilomar, CA. August 2002
72 KB PDF, 16 pp

Price-responsive load (PRL) programs vary significantly in overall design, the complexity of relationships between program administrators, load aggregators, and customers, and the availability of "enabling technologies." Enabling technologies include such features as web-based power system and price monitoring, control and dispatch of curtailable loads, communications and information systems links to program participants, availability of interval metering data to customers in near real time, and building/facility/end-use automation and management capabilities. Two state agencies—NYSERDA in New York and the CEC in California—have been conspicuous leaders in the demonstration of demand response (DR) programs utilizing enabling technologies. In partnership with key stakeholders in these two states (e.g., grid operator, state energy agencies, and program administrators), Lawrence Berkeley National Laboratory (LBNL) and Pacific Northwest National Laboratory (PNNL) surveyed 56 customers who worked with five contractors participating in CEC or NYSERDA-sponsored DR programs. We combined market research and actual load curtailment data when available (i.e., New York) or customer load reduction targets in order to explore the relative importance of contractor's program design features, sophistication of control strategies, and reliance on enabling technologies in predicting customer's ability to deliver load reductions in DR programs targeted to large commercial/industrial customers.

We found preliminary evidence that DR enabling technology has a positive effect on load curtailment potential. Many customers indicated that web-based energy information tools were useful for facilitating demand response (e.g., assessing actual performance compared to load reduction contract commitments), that multiple notification channels facilitated timely response, and that support for and use of backup generation allowed customers to achieve significant and predictable load curtailments. We also found that 60-70% of the customers relied on manual approaches to implementing load reductions/curtailments, rather than automated load control response. The long-term sustainability of customer load curtailments would be significantly enhanced by automated load response capabilities, such as optimizing EMCS systems to respond to day-ahead energy market prices or load curtailments in response to system emergencies.

Impact of Enabling Technologies on Customer Load Curtailment Performance: Summer 2001 Results from NYSERDA's PON 585 and 577 Programs and NYISO's Emergency Demand Response Program
Goldman, C., and G. Heffner, Lawrence Berkeley National Laboratory; and M. Kintner-Meyer, Pacific Northwest National Laboratory. January 27-30, 2002
92 KB PDF, 27 pp

This report describes a market and load research study on a small group of participants in the NYISO Emergency Demand Response Program (EDRP) and the NYSERDA Peak Load Reduction and Enabling Technology Programs. In-depth interviews were conducted with 14 individual customers that participated in the NYISO EDRP program through New York State Electric and Gas (NYSEG), AES NewEnergy, and through eBidenergy/ConsumerPowerLine. These contractors used funding from NYSERDA to apply enabling technologies that were hypothesized to improve customers' ability to curtail load. Both NYSEG and eBidenergy/ConsumerPowerLine offered their customers access to their hourly load data on a day-after basis and, during curtailment events, on a near-real-time basis. Phone interviews were conducted with most customers, however 25% of customers provided initial responses to the survey protocol via email. We then combined the market research information with load data during the curtailment events of August 7-10, 2001 to evaluate the impact of technology on curtailment responses.

Innovative Developments in Load as a Resource
Eto, J., C. Goldman, G. Heffner, B. Kirby, J. Kueck, M. Kintner-Meyer, J. Dagle, T. Mount, W. Schultze, R. Thomas, and R. Zimmerman. IEEE Power Engineering Society Winter Meeting. January 27-30, 2002
116 KB PDF, 3 pp

This paper reports on work the Consortium for Electric Reliability Technology Solutions (CERTS) has been pursuing to hasten the arrival of meaningful load participation in competitive electricity markets. The activities include: experimental economic analysis of the effect of price responsive load in reducing market prices and price volatility; assessments of emerging demand response programs and technologies for enabling customer participation in electricity markets, and demonstrations of load in providing ancillary services (notably, spinning reserve).

Review of Current Southern California Edison Load Management Programs and Proposal for a New Market-Driven, Mass-Market, Demand-Response Program
Weller, G., Weller Associates. January 2002
456 KB PDF, 67 pp

Utility load management programs, including direct load control and interruptible load programs, constitute a large installed base of controllable loads that are employed by utilities as system reliability resources. In response to energy supply shortfalls expected during the summer of 2001, the California Public Utilities Commission in spring 2001 authorized new utility load management programs as well as revisions to existing programs. This report provides an independent review of the designs of these new programs for a large utility (Southern California Edison) and suggests possible improvements to enhance the "price responsiveness" of the customer actions influenced by these programs. The report also proposes a new program to elicit a mass-market demand response to utility price signals.

A Case Study Review of Technical and Technology Issues for Transition of a Utility Load Management Program to Provide System Reliability Resources in Restructured Electricity Markets
Weller, G., July 2001
821 KB PDF, 66 pp

Utility load management programs—including direct load control and interruptible load programs - were employed by utilities in the past as system reliability resources. With electricity industry restructuring, the context for these programs has changed; the market that was once controlled by vertically integrated utilities has become competitive, raising the question: can existing load management programs be modified so that they can effectively participate in competitive energy markets? In the short run, modified and/or improved operation of load management programs may be the most effective form of demand-side response available to the electricity system today. However, in light of recent technological advances in metering, communication, and load control, utility load management programs must be carefully reviewed in order to determine appropriate investments to support this transition.

This report investigates the feasibility of and options for modifying an existing utility load management system so that it might provide reliability services (i.e. ancillary services) in the competitive markets that have resulted from electricity industry restructuring. The report is a case study of Southern California Edison's (SCE) load management programs. SCE was chosen because it operates one of the largest load management programs in the country and it operates them within a competitive wholesale electricity market. The report describes a wide range of existing and soon-to-be-available communication, control, and metering technologies that could be used to facilitate the evolution of SCE's load management programs and systems to provision of reliability services. The fundamental finding of this report is that, with modifications, SCE's load management infrastructure could be transitioned to provide critical ancillary services in competitive electricity markets, employing currently or soon-to-be available load control technologies.

Direct Participation of Electrical Loads in the California Independent System Operator Markets During the Summer of 2000
Marnay, C., K. Hamachi, M. Khavkin, and A. Siddiqui. July 1, 2001
331 KB PDF, 23 pp

California's restructured electricity markets opened on 1 April 1998. The former investor owned utilities were functionally divided into generation, transmission, and distribution activities, all of their gas-fired generating capacity was divested, and the retail market was opened to competition. To ensure that small customers shared in the expected benefit of lower prices, the enabling legislation mandated a 10% rate cut for all customers, which was implemented in a simplistic way that fossilised 1996 tariff structures. Rising fuel and environmental compliance costs, together with a reduced ability to import electricity, numerous plant outages, and exercise of market power by generators drove up wholesale electricity prices steeply in 2000, while retail tariffs remained unchanged. One of the distribution/supply companies entered bankruptcy in April 2001, and another was insolvent. During this period, two sets of interruptible load programs were in place, longstanding ones organized as special tariffs by the distribution/supply companies and hastily established ones run directly by the California Independent System Operator (CAISO). The distribution/supply company programs were effective at reducing load during the summer of 2000, but because of the high frequency of outages required by a system on the brink of failure, customer response declined and many left the tariff. The CAISO programmes failed to attract enough participation to make a significant difference to the California supply demand imbalance. The poor performance of direct load participation in California's markets reinforces the argument for accurate pricing of electricity as a stimulus to energy efficiency investment and as a constraint on market volatility.

Load As a Reliability Resource in Restructured Electricity Markets
Kueck, J., B. Kirby, R. Staunton, Oak Ridge National Laboratory; J. Eto, C. Marnay, C. Goldman, Lawrence Berkeley National Laboratory; and C.A. Martinez, Southern California Edison. June 1, 2001
329 KB PDF, 77 pp

Recent electricity price spikes are painful reminders of the value that meaningful demand-side responses could bring to the restructuring US electricity system. Review of the aggregate offers made by suppliers confirms that even a modest increase in demand elasticity could dramatically reduce these extremes in price volatility. There is a strong need for increased customer participation in markets to enhance system reliability and reduce price volatility. Indeed, allowing customers to manage their loads in response to system conditions might be thought of as the ultimate reliability resource.

This scoping report provides a three-part assessment of the current status of efforts to enhance the ability of customer's load to participate in competitive markets with a specific focus on the role of customer loads in enhancing electricity system reliability. First, this report considers the definitions of electricity-reliability-enhancing ancillary services and a preliminary assessment of the ability of customer's loads to provide these services. Second, is a review a variety of programs in which load has been called on as a system reliability resource. These experiences, drawn from both past and current utility and ISO programs, focus on programs triggered by system condition (e.g., forecast reserves fall below a threshold), rather than those triggered by price (e.g., real-time prices). Third, the report examines the status of the underlying metering, communication, and control technologies required to enable customer loads to participate in competitive electricity markets. Following the three-part assessment, we offer preliminary thoughts on directions for future research.

An R&D Agenda to Enhance Electricity System Reliability by Increasing Customer Participation in Emerging Competitive Markets
Eto, J., C. Marnay, and C. Goldman, Lawrence Berkeley National Laboratory; J. Kueck and B. Kirby; Oak Ridge National Laboratory; J. Dagle, Pacific Northwest National Laboratory; F. Alvarado, T. Mount, and S. Oren, PSERC; and C. Martinez, Southern California Edison. IEEE Power Engineering Society Winter Meeting, January 28-31, 2001
32 KB PDF, 5 pp

Recent electricity price spikes are painful reminders of the value that meaningful demand-side responses could bring to the restructuring US electricity system. Review of the aggregate offers made by suppliers confirms that even a modest increase demand elasticity could dramatically reduce these extremes in price volatility. We submit that dramatically increased customer participation in these markets to enhance system reliability and reduce price volatility is sorely needed. Indeed, allowing customers to manage their loads in response to system conditions might be thought of as the ultimate reliability resource. Toward this end, this paper outlines an agenda for public-interest R&D in support of this objective that includes the following key elements:

  1. Addressing the information needs and control requirements of system operators;
  2. Repositioning existing utility load management assets;
  3. Accelerating the transfer emerging program experiences;
  4. Pioneering promising new program design concepts;
  5. Incorporating grid reliability considerations into the design and operation of end-use technologies; and
  6. Disseminating technology and programmatic solutions through demonstrations