Scott Neumann is Chief Technology Officer of Utility Integration Solutions, Inc. (UISOL), a consulting firm based in Lafayette, California. His professional background includes working with Empros, CES International, MessageTek, and UISOL. Scott leads the U.S. efforts within IEC TC57 for the development of standards related to power system operations and associated information exchanges. Fereidoon (Perry) Sioshansi is President of Menlo Energy Economics, a consulting firm with experience in demand-side management, How to Get More Response real-time pricing, enabling technologies, and demand response. His professional background from Demand Response includes working at Southern California Edison Company, the Electric Power Research Institute, and Global Energy Decisions. He has a Ph.D. in Economics from Purdue University. Despite all the rhetoric, demand response’s contribution Ali Vojdani is CEO of Utility Integration to meet peak load will remain elusive in the absence Solutions. His professional background of enabling technology and standardized business includes working with Pacific Gas and Electric, EPRI, Perot Systems, Vitria protocols. Technology, and UISOL. He has a Ph.D. in Electrical Engineering. Scott Neumann, Fereidoon Sioshansi, Ali Vojdani and Gaymond Yee is a Research Coordinator at the California Institute for Energy and the Gaymond Yee Environment (CIEE). His professional background includes working at Silicon Energy, Diablo Research, EnergyLine Systems, and Science Applications International Corporation. He has a Master of Engineering Degree in Mechanical Engineering from the I. Summer’s Heat Wave When operators run out University of California at Berkeley. shows DR’s Potential of generation capacity, the alternatives are either to resort to This article is based on a research project managed by the California Institute for Energy This past summer’s heat wave rolling blackouts – which nobody and the Environment on behalf of the California engulfed most of the U.S. and likes – or to plead to customers to Energy Commission (CEC), with funding from the Public Interest Energy Research (PIER) stretched many utilities and sys- drop discretionary loads. This program. This Demand Response Enabling tem operators close to the limit. In practice, where customers are Technology Development (DR ETD) project California, the Independent Sys- provided financial incentives to was conducted by a team of consultants led by Utility Integration Solutions, Inc., with tem Operator (CAISO) had to drop load during emergencies is contributions from Dynamic Networks, Menlo declare several Stage 1 and Stage 2 known as demand response or Energy Economics, Michigan Group, Nexant, alerts in July,1 signaling that its DR.2 Infotility, Savvion, and TIBCO. Participating stakeholders included the California reserve margin was precariously urrently, system operators Independent System Operator (CAISO), low. Similar episodes were C have limited capabilities to Pacific Gas & Electric Company, Southern California Edison Company, San Diego Gas & repeated across the country in engage in DR for a number of Electric Company, DR service provider July and August as new peak load reasons. Most importantly, the Infotility, and a few representative commercial records were repeatedly set and protocols for sending the signal and residential customers. broken (Figure 1). System opera- that capacity is tight and voluntary tors, once again, were reminded load shedding is needed is time- of the real value of demand consuming, error-prone, and response programs. mostly manual. Since system 24 1040-6190/$–see front matter # 2006 Elsevier Inc. All rights reserved., doi:/10.1016/j.tej.2006.09.001 The Electricity Journal Figure 1: Killer Heat Wave, Record Peaks. Source: Various ISOs/RTOs operators must balance load in recent report by the Federal III. How Much DR is real-time, any delays to get a signal A Energy Regulatory Really There? out, get confirmation, and get Commission (FERC), for example, tangible results must be fast, provides some evidence.4 One Following the passage of the error-free and automatic – study claims annual savings of Energy Policy Act (EPAct) in characteristics that are lacking $15 billion per year in the U.S. for August 2005, there has been in most current systems. shifting 5 to 8 percent of con- renewed interest in smart meters, This means that in many cases, sumption from peak to off-peak time-variable pricing, and the operator may resort to hours and for depressing peak demand response – the legs of a involuntary load shedding simply demand by 4 to 7 percent.5 stool. EPAct’s main contribution because of inherent delays and Another study looking at the New was two-fold: First, it codifies the inefficiencies in implementing England ISO’s service area claims significance of enabling technol- DR programs. annual savings of $580 million per ogies, which are prerequisites to year for reducing peak demand wider implementation of DR. by as little as 5 percent.6 Second, it instructs both the II. Is DR Cost-Effective? During the August heat wave, Department of Energy (DOE) and PJM Interconnection reported FERC to establish baselines and A number of studies have cost savings totaling $650 million goals for increased reliance on confirmed the cost-effectiveness attributed to DR programs.7 On DR. of DR relative to the alternatives, Aug. 2, 2006, alone, when PJM set s a consequence, DOE namely reliance on peaking units a new peak load record of A published a report in or rolling blackout. The former 144,796 MW, it reported DR sav- February estimating DR’s poten- are expensive – as everyone ings of $230 million.8 Similar tes- tial benefits, offering recommen- recognizes – and the latter even timonials are available from other dations on how these benefits more so.3 ISOs and RTOs. may be captured.9 As a starting October 2006, Vol. 19, Issue 8 1040-6190/$–see front matter # 2006 Elsevier Inc. All rights reserved., doi:/10.1016/j.tej.2006.09.001 25 Table 1: What is DR? Price-Based Options Incentive-Based Programs Time-of-use (TOU): a rate with different unit prices for usage Direct load control: a program by which the program during different blocks of time, usually defined for a 24-hour day. operator remotely shuts down or cycles a customer’s electrical TOU rates reflect the average cost of generating and delivering equipment (e.g., air conditioner, water heater) on short power during those time periods. notice. Direct load control programs are primarily offered to residential or small commercial customers. Real-time pricing (RTP): a rate in which the price for electricity Interruptible/curtailable (I/C) service: curtailment options typically fluctuates hourly reflecting changes in the wholesale price integrated into retail tariffs that provide a rate discount or of electricity. Customers are typically notified of RTP prices on a bill credit for agreeing to reduce load during system day-ahead or hour-ahead basis. contingencies. Penalties may be assessed for failure to curtail. Interruptible programs have traditionally been offered only to the largest industrial (or commercial) customers. Critical peak pricing (CPP): CPP rates are a hybrid of the TOU and Demand bidding/buyback programs: customer offers bids RTP design. The basic rate structure is TOU. However, provision is to curtail based on wholesale electricity market prices or made for replacing the normal peak price with a much higher an equivalent. Mainly offered to large customers CPP event price under specified trigger conditions (e.g., 1 MW or over). (e.g., when system reliability is compromised or supply Emergency demand response programs: programs that prices are very high). provide incentive payments to customers for load reductions during periods when reserve shortfalls arise. Capacity market programs: customers offer load curtailments as system capacity to replace conventional generation or delivery resources. Customers typically receive day-of notice of events. Incentives usually consist of up-front reservation payments, with penalties levied for failure to curtail when called upon to do so. Ancillary services market programs: customer bid load curtailments in ISO/RTO 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 ISO/RTO, and may be paid the spot market energy price. Source: Benefits of DR in Electricity Markets and Recommendations for Achieving Them, US DOE, Feb. 06. point, DOE divided DR programs signal that there is an impending potential to be around into two basic categories, price- emergency and ask for customers 20,500 MW, or 3 percent of the and incentive-based (Table 1), to shed load in exchange for peak load. Surprisingly, DOE and identified various sub- predetermined (the former case) found that DR capacity has actu- categories under each. Following or negotiated (the latter case) ally declined from its peak in these definitions, the focus of the prices/incentives. 1996, when more utilities engaged present article is on demand he DOE study estimated in such programs and had more bidding/buyback and emergency T current (2004) U.S. DR load under control. demand response programs. capacity around 9,000 MW, DOE offered a long list of These programs, broadly speak- roughly 1.3 percent of the U.S. recommendations under six ing, require the system operator to peak load. It estimated DR’s major categories: 26 1040-6190/$–see front matter # 2006 Elsevier Inc. All rights reserved., doi:/10.1016/j.tej.2006.09.001 The Electricity Journal reports by DOE and FERC, blame the problem on lack of enabling technology – which certainly is a major obstacle. Without afford- able smart meters, reliable and inexpensive two-way communi- cation and widespread use of time-variable tariffs, the true potential of DR will never be realized. But there are two other highly critical aspects of enabling tech- Figure 2: How Much Demand Response Is There? Source: Assessment of Demand nology, which remain as serious Response and Advanced Metering, FERC, Aug.