Automated Demand Response
Automated Demand Response
We provide Automated Demand Response, Price Response, Demand Response Programs and Demand Side Management design and project development solutions that also include the best software for real time energy management, controls and monitoring.
Our Demand Side Management solutions may provide a return on investment in less than 12 months, depending on location, how energy is used, and the local electric and natural gas rates. We provide Demand Side Management design and project development solutions that may provide a return on investment in less than 12 months. We also offer Demand Side Management technologies that may include; Absorption Chillers, Adsorption Chillers, Automated Demand Response, Cogeneration, Demand Response Programs, Demand Side Management, Energy Master Planning, Engine Driven Chillers, Trigeneration and Energy Conservation Measures.
Our company provides turn-key project solutions that include all or part of the following:
- Engineering and Economic Feasibility Studies
- Project Design, Engineering & Permitting
- Project Construction
- Project Funding & Financing Options
- Shared/Guaranteed Savings program with no capital requirements
- Project Commissioning
- Operations & Maintenance
Demand Side Management & and DSM Solutions Including: Demand Response, Demand Response Programs, and Automated Demand Response
What are Demand Response Programs?
Demand Response Programs are programs usually designed and offered by electric utilities that offer those clients that sign-up for specific DR programs with financial incentives and other benefits that help those participating customers to curtail energy use. These actions by the electric utilities and participating clients provide a reliable, predictable amount of power (megawatts) that the ISO’s and RTO’s can count on during an emergency when energy supplies are low, and there is an inadequate amount of available power generation. The electric utilities typically require that those customers that enroll in their DR program(s) install certain software and hardware, that communicates with these client’s online energy management systems, and can control these client’s electric power requirements as needed.
What is Demand Response?
Demand Response is defined as a set of time dependent activities that reduce or shift electricity use to:
- Improve electric grid reliability
- Manage electricity costs
- And provide systems that encourage load shifting or load shedding during times when the electric grid is near its capacity or electric power prices are high
Electric power generation and distribution systems are strongly affected by supply-side policies (how, when, and where to generate electricity, how to couple generation into the grid, how to transmit and distribute generated electricity) and demand-side policies (pricing schemes, conservation efforts, customer premises automation, and, in extreme circumstances, rolling blackouts). Demand-side programs focus on reducing the peak-to-average demand profiles through automation in the customer premises.
What is Automated Demand Response?
Automated Demand Response is a Demand Side Management solution that is specifically designed for a customer’s specific location, energy/power requirements, and also for the specific electric rates for that customer’s location. Automated Demand Response does not involve human intervention, but is initiated at a facility through receipt of an external communications signal. Automated Demand Response is a rather new area of DSM technologies and may provide a lucrative revenue stream for customers who can curtail electric load in response to demand incentives, ICAP payments, and/or commodity prices. Automated demand response technology seeks to automatically, through software and hardware applications, to respond to variations in the electricity/power market prices.
Demand Response or Demand Side Management can be achieved through demand reduction, by shifting load to a less expensive time period, or by substituting another resource for delivered electricity (such as natural gas or onsite power generation, also known as "distributed generation."
Demand Response (DR) is a set of activities to reduce or shift electricity use to improve electric grid reliability, manage electricity costs, and ensure that customers receive signals that encourage load reduction during times when the electric grid is near its capacity. The two main drivers for widespread demand responsiveness are the prevention of future electricity crises and the reduction of electricity prices. Additional goals for price responsiveness include equity through cost of service pricing, and customer control of electricity usage and bills. The technology developed and evaluated in this report could be used to support numerous forms of DR programs and tariffs.
A recent pilot test to enable an Automatic Demand Response system in California has revealed several lessons that are important to consider for a wider application of a regional or statewide Demand Response Program.
The six facilities involved in the site testing were from diverse areas of our economy. The test subjects included a major retail food marketer and one of their retail grocery stores, financial services buildings for a major bank, a postal services facility, a federal government office building, a state university site, and ancillary buildings to a pharmaceutical research company. Although these organizations are all serving diverse purposes and customers, they share some underlying common characteristics that make their simultaneous study worthwhile from a market transformation perspective. These are large organizations. Energy efficiency is neither their core business nor are the decision-makers who will enable this technology powerful players in their organizations. The management of buildings is perceived to be a small issue for top management and unless something goes wrong, little attention is paid to the building manager’s problems. All of these organizations contract out a major part of their technical building operating systems. Control systems and energy management systems are proprietary. Their systems do not easily interact with one another. Management is, with the exception of one site, not electronically or computer literate enough to understand the full dimensions of the technology they have purchased. Despite the research teams development of a simple, straightforward method of informing them about the features of the demand response program, they had significant difficulty enabling their systems to meet the needs of the research. The research team had to step in and work directly with their vendors and contractors at all but one location. All of the participants have volunteered to participate in the study for altruistic reasons, that is, to help find solutions to California’s energy problems. They have provided support in workmen, access to sites and vendors, and money to participate. Their efforts have revealed organizational and technical system barriers to the implementation of a wide scale program.
What is load response?
Load response is a form of demand side management solution that commercial and industrial customers may choose to employ in response to wholesale electricity prices or other market incentives which can serve several important system-wide functions.
For example, retail customers can ease tight capacity situations and mitigate reliability concerns by reducing their electric power usage or consumption. By reducing consumption in response to price signals or other financial incentives, retail customers also can reduce peak wholesale electricity prices, mitigate price volatility, and reduce opportunities for market manipulation.
It is not necessary for all customers to participate in these emergency or economic load response programs; even the response of a small percentage of customers can produce significant benefits for the electric grid and its customers.
In order to participate in load response programs, customers need load response “tools” or solutions that can assist them in reducing their electric power usage at the appropriate times.
The two main categories of load response tools are communications devices and mechanisms for modifying a customer’s usage of electricity supplied by the grid during peak hours and conditions. Customers have two basic mechanisms for reducing their demand on the local electricity grid. They can simply reduce their electricity at key times through load response management, energy efficiency or energy conservation measures and improvements, or the customer can shift their source of electricity from the grid to on-site cogeneration or trigeneration power and energy systems thereby reducing their use of grid electricity but not their overall use of electricity.
Emergency load response can be implemented with readily available technology. For example, load response software can be installed in a building (e.g., an industrial facility, an office building, or commercial establishment, or even a home) that would connect to the outside world (signals sent by the Independent System Operator) with building control systems (e.g., thermostats, light dimmers). The building owner or operator could choose to respond to the signal or not. With currently available software, building operators could be notified through e-mail, cellular phone, and alpha-numeric paging of an expected reliability threat and could respond as simply as pressing a “yes” or “no” button included with the system. An affirmative answer would trigger predetermined changes to building systems (e.g., the lights could dim twenty percent, the AC thermostat could rise two degrees) for a set time.
Emergency load response to serve a reliability function is not new technology. For years, electric utilities and system operators have offered special rates to customers who were willing to curtail their load upon request from the utility or system operator to avert short-term reliability problems. On hot days when demand threatens to overwhelm the available capacity on the system, customers willing and able to lower the amount of electricity they draw from the grid offer a resource that can be tapped to delay or avoid the need for more drastic measures, including rolling brown-outs or rolling black-outs. Customers participating in load response programs don’t just avoid costs associated with consuming at high prices at peak periods; they can receive payments from “selling” the power they don’t use at market prices.
Simply put the electricity that the customer decides not to use at peak times can be sold back into the energy market at peak prices.
Demand Side Management or "DSM," is the process of managing the consumption of energy, generally to optimize available and planned generation resources.
Not all businesses are candidates for cogeneration or trigeneration, however, your company may be a great candidate for other energy-saving solutions. One of these is Demand Side Management, or "DSM". We also provide cost-effective DSM solutions.
According to the Department of Energy, Demand Side Management refers to "actions taken on the customer’s side of the meter to change the amount or timing of energy consumption. Utility DSM programs offer a variety of measures that can reduce energy consumption and consumer energy expenses. Electricity DSM strategies have the goal of maximizing end-use efficiency to avoid or postpone the construction of new generating plants.”
Background on Demand Side Management
Demand-side management (DSM) programs consist of the planning, implementing, and monitoring activities of electric utilities that are designed to encourage consumers to modify their level and pattern of electricity usage.
In the past, the primary objective of most DSM programs was to provide cost-effective energy and capacity resources to help defer the need for new sources of power, including generating facilities, power purchases, and transmission and distribution capacity additions. However, due to changes occurring within the industry, electric utilities are also using DSM to enhance customer service. DSM refers only to energy and load-shape modifying activities undertaken in response to utility-administered programs. It does not refer to energy and load-shape changes arising from the normal operation of the marketplace or from government-mandated energy-efficiency standards.
Historical Information of DSM (1999)
In 1999, 848 electric utilities report having demand-side management (DSM) programs. Of these, 459 are classified as large, and 389 are classified as small utilities. This is a decrease of 124 utilities from 1998.(1) DSM costs were almost unchanged at 1.4 billion dollars in both 1998 and 1999.
Energy Savings for the 459 large electric utilities increased to 50.6 billion kilowatthours, 1.4 billion kilowatthours more than in 1998. These energy savings represent 1.5 percent of annual electric sales of 3,312 billion kilowatthours(2) to ultimate consumers in 1999.
Actual peak load reductions for large utilities decreased in 1999 to 26,455 megawatts. Potential peak load reductions of 43,570 megawatts were an increase of 2,140 over 1998.
In 1999, incremental energy savings for large utilities were 3.1 billion kilowatthours, incremental actual peak load reductions were 2,263 megawatts.
Technologies Used in Demand Side Management:
These energy conservation technologies are implemented to reduce total energy use. Specific technologies include energy-efficient lighting, appliances, and building equipment, all of which can be found on the EREN Buildings Energy Efficiency page. For energy efficiency at industrial sites, see the EREN Industrial Energy Efficiency page.
These technologies are used to smooth out the peaks and dips in energy demand — by reducing consumption at peak times ("peak shaving"), increasing it during off-peak times ("valley filling"), or shifting the load from peak to off-peak periods — to maximize use of efficient baseload generation and reduce the need for spinning reserves.
Energy management control systems (EMCSs) can be used to switch electrical equipment on or off for load leveling purposes. Some EMCSs enable direct off-site control (by the utility) of user equipment. Typically applied to heating, cooling, ventilation, and lighting loads, EMCSs can also be used to invoke on-site generators, thereby reducing peak demand for grid electricity. Energy storage devices located on the customer’s side of the meter can be used to shift the timing of energy consumption.
Issues Involving the Implementation Demand Side Management Solutions Include: Public Benefits Programs, Rate Schedules, Time-of-Use Rates, Power Factor Charges, and Real-Time-Pricing
Public Benefits Programs
Prior to electricity industry restructuring, utilities were responsible for a variety of programs (including DSM) that meet social objectives. Under restructuring, funding for these programs is typically through a small surcharge ("wires charge" or "system benefits charge") on utility bills.
Utilities can structure their rates to encourage customers to modify their pattern of energy use.
Time-of-use rates involve charging higher prices for peak electricity as a way to shift demand to off-peak periods. Interruptible rates offer discounts in exchange for a user commitment to reduce demand when requested by the utility.
Power Factor Charges
Power factor charges can be implemented to discourage commercial and industrial utility customers from partially loading their electrical equipment, as this requires the utility to generate extra current to cover the resulting system losses.
Real-time pricing is where the electricity price varies continuously (or hour by hour) based on the utility’s load and the different types of power plants that have to be operated to satisfy that demand.
The Growing Need of Demand Side Management (reprinted with permission by the Author, Satish Saini)
Analysis of the Ontario electricity market since it opened for competition in May 2002 shows it on the verge of facing supply shortages leading to reliability problems and dependent on importing expensive electricity leading to high rising prices.
Ontario’s Deregulated Electricity Market:
The Ontario electricity market was deregulated apparently based on optimistic reports of successes in other jurisdictions and Ontario’s sufficient generation resources. But supply shortages and high rising prices in the initial phase of the deregulated market made the consumers cry and the Ontario Government put a four-year cap on the retail price for residential, commercial and other designated customers just after six months of market deregulation.
Power Position in Ontario
After deregulating the market in May 2002, Ontario has experienced record peak electricity demands while its generation resources availability was below the expected levels. A number of times Independent Market Operator (IMO) was forced to issue power alerts in the face of insufficient reserve margins and to make emergency purchases of energy at high prices. A peak of 25,414 MW in summer in the month of August, 2002 and a new winter peak of 24,158 MW were faced, breaking the previous record set nine years ago.
The hourly import levels since market opening in May 2002 up to August 31, 2003 indicate an average import level of 1,120 MW for all hours. During the 2,171 hours when Ontario demand exceeded 20,000 MW the average import level was 1,579 MW. During the 265 hours when Ontario demand exceeded 23,000 MW the average import level was 2,436 MW, which occasionally reached the Ontario’s coincident import capability of around 4,000 MW.
The cause of these heavy imports and supply shortage is stated to be the forced shut down of some generating plants and the delays in returning other generating stations to service as planned that had been taken out of service for routine maintenance.
Even in the future forecast, Ontario’s power generation capacity is said to be insufficient to meet the expected loads. The main reason to worry is that over the next 10 to 15 years, approximately 40 per cent of the current installed capacity will reach the end of its nominal life while the demand is going to increase.
Electricity Prices in Ontario
In Ontario’s electricity market the prices are set by the Independent Electricity Market Operator (IMO) through its real-time auction process for the supply of electricity.
The IMO sets the wholesale electricity prices by collecting offers from suppliers and bids from purchasers to determine on-the-spot market price for electricity. It uses these offers and bids to match electricity supply with demand, and establishes the Hourly Ontario Energy Price called HOEP. So energy prices change from time to time depending upon the demand and available supply.
After deregulating the market in May 2002, the Ontario government freezed the retail price to be paid by residential, commercial and other low volume designated consumers at 4.3 cents per Kwh ($ 43.00 per Mwh) in December, 2002.
Having a look at the following Table-1 showing the maximum HOEP of each month since May 2002, we find it to be as high as $ 1028.42 per Mwh, i.e. to be 24 times higher than the fixed price of $ 43.00 per Mwh
|Table 1. Maximum HOEP ($/Mwh):|
Even if we leave aside this maximum HOEP during the month and take the monthly weighted average of this price, we find from the following Table-2 that even the monthly weighted average price has been more than 1.5 times the fixed price in many months.
|Table 2. Monthly Weighted Average Price ($/Mwh):|
After analyzing the maximum HOEP and Monthly Weighted Average Price of each month as compared to the fixed price, we see from the following Table-3 that it was on an average 350 times during a single month (i.e. on an average 12 times during a day) that the HOEP has been higher than the fixed price
|Table 3. Number of Times HOEP greater than the Fixed Price During the Month (No.):|
What makes the price volatile:
It is the electricity technology and the economics of the electricity industry which contribute to the volatility of price in a deregulated market. Technically, electricity produced cannot be stored in economic ways, and its economics says that supply and demand must be kept in instantaneous balance to avoid high rising prices. So we should have a sufficient supply to meet with the rising demand or reduce demand as per the available supply. So both these factors of supply shortage and rising demand create price volatility.
How to control Price Volatility and Supply Shortages
These can be controlled either by Supply-Side Management by having sufficient supply availability to meet with rising demand or by Demand-Side Management (DSM) by curtailing electricity demand during supply shortages.
For short term measures the supply-side management is not effective as it takes long time for units to start up (if these are available) and meet the rising demand immediately, rather it is demand side management which can be implemented immediately and in more economic ways to keep the balance.
Why DSM is so significant in Ontario
Having studied the excessive and costly monthly imports by Ontario, high rising prices and future generation shortages, we have to think whether to rely solely on our neighbours for help or to take serious initiatives for solutions.
The provincial policies by this time are not attracting any good investments in new power generation plants and our old plants already aging, we stand on the verge of facing severe power crises in the future. And by this time we are familiar with the huge economical losses faced due to blackouts.
Moreover, seeing the electricity price almost always above the fixed set price and growing burden on the tax payers in the shape debt due to subsidies by freezing price, Ontario needs strong DSM strategies.
Potential of DSM in Ontario
As we have seen above that the hourly import levels in Ontario since its deregulation has been on an average 1,120 MW for all hours and around 2500 MW at many times of higher demand. So with a monthly maximum demand of around 25000 MW, it is not a very difficult task to compensate for 10% of it (2,500 MW) with effective Demand Side Management for a province like Ontario.
In one of the statement by a representative of IMO, it was mentioned that Ontario has been able to reduce demand by as much as 4,500 megawatts. This reduction was an important contributor to avoid the need for rotational power outages in Ontario after blackout.
This proves the potential of DSM in Ontario and what we need is a dedicated and sincere approach by various segments of the Power Sector in the province.
We can achieve this by using various Tools and Techniques of DSM as follows:
- Tools for DSM and Dynamic/Real Time Pricing and Time-of-Use Rates
- By exposing customers to dynamic i.e. time-varying prices, Time-of-Use rates, they would have the information and incentive to reduce their demand at peak times and to shift their usage from high priced periods to low-priced periods.
- Automated/Smart Metering
- Implementing Dynamic/ Real Time Pricing or Time-of-use rate structure and billing accordingly is not a complex program now. Automatic/Smart Metering successfully used by various utilities provides the best effective solution to this problem.
The most common DSM techniques can be classified as below:
- Energy Conservation and Efficiency Programs- to save energy
- Load Response Programs- To shift and reschedule energy consumption process
Energy Conservation and Efficiency programs
It is said that Energy conserved is Energy generated. Energy conservation and efficiency measures are the best alternative energy sources.
There are various opportunities and techniques available for reducing energy consumption such as efficient lighting, variable speed drives, solar hot water systems etc. These technologies reduce demand, help in lowering high peak prices and also reduce greenhouse gas emissions due to less stress on generating plants. Load Response Programs (LRP)
Load Response Programs are an effective part of Demand Side Management. These are the actions undertaken in response to electricity supply position and wholesale market price of electricity. Or in other sense these refer to switching off or reschedule of non-essential and non-critical loads by the end users in response to the request of IMO or the utilities. This can lead to save the system network from exceeding its peak rating.
There are a large variety of load equipments and applications that can be switched on or off at a particular times to reduce electricity demand from the network.
Depending upon the market drivers these can be classified in two broad categories:
These programs operate in response to the system contingencies. That is why these can also be called as “contingency” programs. These are used whenever there is an emergency of power supply in case of acute shortage due to less generation or more demand or due to some other system constraints. These programs are also called Emergency Demand Response Program (EDRP)
Market/Price based programs:
These programs are based on market price signals of electricity. This category includes programs that use time-of-use (TOU) rates/Real Time Prices, Interruptible Rates and Two-part Tariff. These rates are intended to reduce consumer bills through the application of time-differentiated rates. The consumer participants of these programs that curtail their loads at critical times of very high prices can also be paid some extra financial incentive to help maintain system reliability.
These programs can include Day Ahead Demand Response Program, where the end users respond to price signals and reduce loads when the price exceeds their set Base Price on day to day or day-ahead time basis.
Depending upon the participants and implementing agencies, these can be of two types as IMO based Programs and Utility/Supplier Based Programs.
Based on type of Load control, these programs can be implemented in two ways as Direct Load Control by IMO/Utility Operator and Load Control by Consumer
Factors effecting Load Response Programs:
However implementing these technologies and techniques is not always so cheap. Though there are many opportunities where we can apply these without any additional cost or investment. But to apply them at large scale for the whole market there are various factors to be considered as:
- Cost to the customer to shed and reschedule the load
- Time it takes to activate the load response
- The variation in wholesale price
- Losses to occur in case of reliability problems due to acute shortage
- Any losses in production by implementing these programs
Infrastructure for LRP
Normally these programs are internet/web based. Different packages provide different services to the consumers. In some internet based programs the participants are alerted on real-time and day ahead prices. The customer can access the web site, check the prices and give their price option and the load to be curtailed. The supplier gives notification to the customer by e-mail, cell phone, pager, or fax about the curtailment.
Benefits of DSM:
The benefits of DSM to consumers, enterprises, utilities, and society can be as:
- Reduction in customer energy bills.
- Reduction in the need for new power plant, transmission, and distribution network
- Stimulating economic development.
- Creating long-term jobs due to new innovations and technologies
- Increasing the competitiveness of local enterprises.
- Reduction in air pollution.
- Reduced dependency on foreign energy sources.
- Reduction in peak power prices for electricity
DSM Program Approaches:
Various approaches can be adopted to achieve benefits of Demand Side Management as:
- General information programs for customers about energy efficiency options.
- Information programs about specific DSM techniques appropriate for industry
- Financing programs to assist customers to pay for DSM measures
- Turnkey programs that provide complete services to design, finance, and install a package of efficiency measures at the consumer end.
- Alternative rate programs by the utilities like time-of-use rates and interruptible rates to shift loads to off-peak periods.
- Schemes and incentives to invest in energy conservation and efficiency programs
- Incentives for new innovations and technologies for Load Response/Load Management Programs.
These DSM programs and policies can be promoted and implemented at different levels of the society as:
- Government policies and regulations
- Utilities programs
- Customer participation.
Each of these units has its own significant role to play. But the optimum results can be obtained by coordinating all the three. Government agencies can make various policies and regulations, provide subsidies for these programs and Utilities can implement these more effectively through different cost-effective and customized programs in coordination with the end-users i.e. the consumers.
DSM Programs Strategies
The following strategy may be adopted to design and implement DSM program:
- Identify the sectors and end-users as the potential targets
- Visualize the needs of the targeted sectors
- Develop the customized program
- Conduct analysis for cost-effectiveness
- Prepare an implementation plan to market the program
- Implement programs
Successful DSM Studies
We have many successful examples and models studies showing substantial benefits by adopting Demand Side Management tools and techniques.
It has been studied in U.S. that with universal application, peak energy demand could be lowered by at least 30,000 MW nationally, equivalent to perhaps as many as 250 peaking plants that would not need to be built. Society could avoid the burning of 680 bcf of gas per year and 31,000 tons of NOx emissions.
A study in 2002 showed that New York’s electricity market along with its grid operator and large electric utility companies has the potential to reduce demand for electricity by at least 1300 megawatts (MW) through Demand Side Management techniques, which is enough to supply power to 1.3 million homes.
Similarly the Internal Energy Efficiency Program of Ontario Power Generation (OPG) in Canada since 1994 has helped to save 2,131 GWh of energy every year, 2.4 million metric tonnes of emission savings for CO2, NOx and SO2 and a saving of US$85.2 million every year.
Demand Side Management programs play an important role in mitigating electrical system emergencies, avoiding blackouts and increasing system reliability, reducing dependency on expensive imports, reducing high energy prices, providing relief to the power grid and generation plants, avoiding high investments in generation, transmission and distribution network and leading to environmental protection.
Thus it provides significant economic, system reliability and environmental benefits.
DSM techniques are the cheapest, fastest and cleanest way to solve our electricity problems. These can be immediately implemented and many times at one-tenth the cost of building new power plants.
This is what needed at this moment in Ontario when it is passing through the phase of uncertainty, already partially backed out from its deregulation policies by placing price caps or regulating prices. Forecast about power shortage in Ontario in the coming years, aging existing power plants with less investments in new generation compel us to go for the only option left i.e. controlling demand through Demand Side Management to avoid blackouts and power imports at high prices.
Electric Utility Demand Side Management Glossary of Terms
Actual Peak Reduction – The actual reduction in annual peak load (measured in kilowatts) achieved by consumers that participate in a utility DSM program. It reflects the changes in the demand for electricity resulting from a utility DSM program that is in effect at the same time the utility experiences its annual 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 peak load.
Annual Effects – The total changes in energy use (measured in megawatthours) and peak load (measured in kilowatts) caused by all participants in your DSM programs. This includes new and existing participants in existing programs (those implemented in prior years that are in place during the given year), all participants in new programs (those implemented during the given year), and participants in DSM programs that were terminated after 1992. Please note that Annual Effects are not a summation of 12 monthly peaks or the aggregate of the Incremental Effects for the reporting year, but are the total effects of all DSM programs for all participants (new and existing) for the year.
Direct Load Control – DSM program activities that can interrupt consumer load at the time of annual peak load by direct control of the utility system operator by interrupting power supply to individual appliances or equipment on consumer premises. This type of control usually involves residential consumers. Direct Load Control as defined here excludes Interruptible Load and Other Load Management effects.
Energy Effects – The changes in aggregate electricity use (measured in megawatthours) for consumers that participate in a utility DSM program. Energy Effects represent changes at the consumer’s meter (i.e., exclude transmission and distribution effects) and reflect only activities that are undertaken specifically in response to utility-administered programs, including those activities implemented by third parties under contract to the utility. To the extent possible, Energy Effects should exclude non-program related effects such as changes in energy usage attributable to nonparticipants, government-mandated energy-efficiency standards that legislate improvements in building and appliance energy usage, changes in consumer behavior that result in greater energy use after initiation in a DSM program, the natural operations of the marketplace, and weather and business-cycle adjustments.
Energy Efficiency – DSM programs that are aimed at reducing the energy used by specific end- use devices and systems, typically without affecting the services provided. These programs reduce overall electricity consumption (reported in megawatthours), often without explicit consideration for the timing of program-induced savings. Such savings are generally achieved by substituting technologically more advanced equipment to produce the same level of end-use services (e.g., lighting, heating, motor drive) with less electricity. Examples include energy saving appliances and lighting programs, high-efficiency heating, ventilating and air conditioning (HVAC) systems or control modifications, efficient building design, advanced electric motor drives, and heat recovery systems.
Incremental Effects – The annual changes in energy use (measured in megawatthours) and peak load (measured in kilowatts) caused by new participants in existing DSM programs and all participants in new DSM programs during a given year. Reported Incremental Effects are annualized to indicate the program effects that would have occurred had these participants been initiated into the program on January 1 of the given year. Incremental effects are not simply the Annual Effects of a given year minus the Annual Effects of the prior year, since these net effects would fail to account for program attrition, equipment degradation, building demolition, and participant dropouts. Please note that Incremental Effects are not a monthly disaggregate of the Annual Effects, but are the total year’s effects of only the new participants and programs for that year.
Interruptible Load – DSM program activities that, in accordance with contractual arrangements, can interrupt consumer load at times of seasonal peak load by direct control of the utility system operator or by action of the consumer at the direct request of the system operator. This type of control usually involves commercial and industrial consumers. In some instances, the load reduction may be affected by direct action of the system operator (remote tripping) after notice to the consumer in accordance with contractual provisions.
Load Shape – a method of describing peak load demand and the relationship of power supplied to the time of occurrence.
Other Load Management – DSM programs other than Direct Load Control and Interruptible Load that limit or shift peak load from on-peak to off-peak time periods. It includes technologies that primarily shift all or part of a load from one time-of-day to another and secondarily may have an impact on energy consumption. Examples include space heating and water heating storage systems, cool storage systems, and load limiting devices in energy management systems. This category also includes programs that aggressively promote time-of-use (TOU) rates and other innovative rates such as real time pricing. These rates are intended to reduce consumer bills and shift hours of operation of equipment from on-peak to off-peak periods through the application of time-differentiated rates.
Potential Peak Reduction – The potential annual peak load reduction (measured in kilowatts) that can be deployed from Direct Load Control, Interruptible Load, Other Load Management, and Other DSM Program activities. (Please note that Energy Efficiency and Load Building are not included in Potential Peak Reduction.) 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.
Program Cost – Utility costs that reflect the total cash expenditures for the year, reported in nominal dollars, that flowed out to support DSM programs. They are reported in the year they are incurred, regardless of when the actual effects occur.
Demand-side management (DSM) programs consist of the planning, implementing, and monitoring activities of electric utilities which are designed to encourage consumers to modify their level and pattern of electricity usage.
In the past, the primary objective of most DSM programs was to provide cost-effective energy and capacity resources to help defer the need for new sources of power, including generating facilities, power purchases, and transmission and distribution capacity additions. However, due to changes that are occurring within the industry, electric utilities are also using DSM as a way to enhance customer service. DSM refers to only energy and load-shape modifying activities that are undertaken in response to utility-administered programs. It does not refer to energy and load-shape changes arising from the normal operation of the marketplace or from government-mandated energy-efficiency standards.
Additional Historical DSM Information
In 1997, 971 electric utilities reported having DSM programs. Of these, 561 are classified as large and 410 are classified as small utilities. The 561 large utilities account for 89.5 percent of the total retail sales of electricity in the United States.(1)
Energy savings for the 561 large electric utilities decreased to 56,406 million kilowatthours (kWh), 5,436 million kWh less than in 1996. These energy savings represent 1.8 percent of annual electric sales of 3,140 billion kWh to ultimate consumers in 1997.
Actual peak load reductions, the goal of the DSM program, for large utilities was 15.4 percent lower in 1997, at 25,284 megawatts, than in 1996. Potential peak load reductions were 14.7 percent lower in 1997 than in 1996.
DSM costs continued to decrease from $1.9 billion in 1996 to $1.6 billion in 1997.(2) This is the fourth consecutive year that DSM costs have decreased from a high of $2.7 billion in 1993.
For 1997, incremental energy savings for large utilities were 4,832 million kilowatthours, and incremental actual peak load reductions were 2,326 megawatts.
- Large utilities are those reporting sales to ultimate consumers or sales for resale greater than or equal to 120,000 megawatthours. Small utilities with sales to ultimate consumers and sales for resale of less than 120,000 megawatthours are only required to report incremental energy savings and peak load reduction, and total utility and total DSM costs for the reporting year and for the first forecast year.
- It is tempting, but misleading, to compare DSM costs to supply-side investments on an unadjusted cost-per-kilowatthours or cost-per-kilowatt basis. The calculation of appropriate measures for economic comparisons of DSM and supply-side investments requires that consideration of the life-cycle cost of the options being compared be addressed on an integrated basis (i.e., the interaction of the change in end-use patterns with the production function of the utility must be considered over the expected life of the various options being compared). In addition, the rate impacts of each alternative must be compared because alternative DSM/supply-side combinations may result in differing patterns of revenue requirements over time. The data presented are not sufficient to allow for such comparison.