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Demand response is a change in the power consumption of an electric utility customer to better match the demand for power with the supply. Until the 21st century decrease in the cost of pumped storage and batteries, electric energy could not be easily stored, so utilities have traditionally matched demand and supply by throttling the production rate of their , taking generating units on or off line, or importing power from other utilities. There are limits to what can be achieved on the supply side, because some generating units can take a long time to come up to full power, some units may be very expensive to operate, and demand can at times be greater than the capacity of all the available power plants put together. Demand response, a type of energy demand management, seeks to adjust in real-time the demand for power instead of adjusting the supply.
Utilities may signal demand requests to their customers in a variety of ways, including simple off-peak metering, in which power is cheaper at certain times of the day, and , in which explicit requests or changes in price can be communicated to customers.
The customer may adjust power demand by postponing some tasks that require large amounts of electric power, or may decide to pay a higher price for their electricity. Some customers may switch part of their consumption to alternate sources, such as on-site and batteries.
In many respects, demand response can be put simply as a technology-enabled economic rationing system for electric power supply. In demand response, voluntary rationing is accomplished by price incentives—offering lower net unit pricing in exchange for reduced power consumption in peak periods. The direct implication is that users of electric power capacity not reducing usage (load) during peak periods will pay "surge" unit prices, whether directly, or factored into general rates.
Involuntary rationing, if employed, would be accomplished via rolling blackouts during peak load periods. Practically speaking, summer heat waves and winter deep freezes might be characterized by planned power outages for consumers and businesses if voluntary rationing via incentives fails to reduce load adequately to match total power supply.
In electricity grids, DR is similar to dynamic demand mechanisms to manage customer consumption of electricity in response to supply conditions, for example, having electricity customers reduce their consumption at critical times or in response to market prices.[1] Description of French EJP demand reduction tariff The difference is that demand response mechanisms respond to explicit requests to shut off, whereas dynamic demand devices passively shut off when stress in the grid is sensed. Demand response can involve actually curtailing power used or by starting on-site generation which may or may not be connected in parallel with the grid. This is a quite different concept from energy efficiency, which means using less power to perform the same tasks, on a continuous basis or whenever that task is performed. At the same time, demand response is a component of smart energy demand, which also includes energy efficiency, home and building energy management, distributed renewable resources, and electric vehicle charging. (2017). 9781509059638 ISBN 9781509059638
Current demand response schemes are implemented with large and small commercial as well as residential customers, often through the use of dedicated control systems to shed loads in response to a request by a utility or market price conditions. Services (lights, machines, air conditioning) are reduced according to a preplanned load prioritization scheme during the critical time frames. An alternative to load shedding is on-site generation of electricity to supplement the Electrical grid. Under conditions of tight electricity supply, demand response can significantly decrease the peak price and, in general, electricity price volatility.
Demand response is generally used to refer to mechanisms used to encourage consumers to reduce demand, thereby reducing the peak demand for electricity. Since electrical generation and transmission systems are generally sized to correspond to peak demand (plus margin for forecasting error and unforeseen events), lowering peak demand reduces overall plant and capital cost requirements. Depending on the configuration of generation capacity, however, demand response may also be used to increase demand (load) at times of high production and low demand. Some systems may thereby encourage energy storage to arbitrage between periods of low and high demand (or low and high prices). Bitcoin network is an electricity intensive process to convert computer hardware infrastructure, software skills and electricity into electronic currency. Bitcoin mining is used to increase the demand during surplus hours by consuming cheaper power.
There are three types of demand response - emergency demand response, economic demand response and ancillary services demand response. Emergency demand response is employed to avoid involuntary service interruptions during times of supply scarcity. Economic demand response is employed to allow electricity customers to curtail their consumption when the productivity or convenience of consuming that electricity is worth less to them than paying for the electricity. Ancillary services demand response consists of a number of specialty services that are needed to ensure the secure operation of the transmission grid and which have traditionally been provided by generators.
In virtually all power systems electricity is produced by generators that are dispatched in merit order, i.e., generators with the lowest marginal cost (lowest variable cost of production) are used first, followed by the next cheapest, etc., until the instantaneous electricity demand is satisfied. In most power systems the wholesale price of electricity will be equal to the marginal cost of the highest cost generator that is injecting energy, which will vary with the level of demand. Thus the variation in pricing can be significant: for example, in Ontario between August and September 2006, wholesale prices (in Canadian Dollars) paid to producers ranged from a peak of $318 per MW·h to a minimum of - (negative) $3.10 per MW·h. It is not unusual for the price to vary by a factor of two to five due to the daily demand cycle. A negative price indicates that producers were being charged to provide electricity to the grid (and consumers paying real-time pricing may have actually received a rebate for consuming electricity during this period). This generally occurs at night when demand falls to a level where all generators are operating at their minimum output levels and some of them must be shut down. The negative price is the inducement to bring about these shutdowns in a least-cost manner. (2025). 9781538642795 ISBN 9781538642795
Two Carnegie Mellon studies in 2006 looked at the importance of demand response for the electricity industry in general terms and with specific application of real-time pricing for consumers for the PJM Interconnection Regional Transmission authority, serving 65 million customers in the US with 180 gigawatts of generating capacity. The latter study found that even small shifts in peak demand would have a large effect on savings to consumers and avoided costs for additional peak capacity: a 1% shift in peak demand would result in savings of 3.9%, billions of dollars at the system level. An approximately 10% reduction in peak demand (achievable depending on the elasticity of demand) would result in systems savings of between $8 and $28 billion.
In a discussion paper, Ahmad Faruqui, a principal with the Brattle Group, estimates that a 5 percent reduction in US peak electricity demand could produce approximately $35 billion in cost savings over a 20-year period, exclusive of the cost of the metering and communications needed to implement the dynamic pricing needed to achieve these reductions. While the net benefits would be significantly less than the claimed $35 billion, they would still be quite substantial.The Brattle Group, The Power of Five Percent, How Dynamic Pricing Can Save $35 Billion in Electricity Costs, May 16, 2007. In Ontario, Canada, the Independent Electricity System Operator has noted that in 2006, peak demand exceeded 25,000 megawatts during only 32 system hours (less than 0.4% of the time), while maximum demand during the year was just over 27,000 megawatts. The ability to "shave" peak demand based on reliable commitments would therefore allow the province to reduce built capacity by approximately 2,000 megawatts.
Demand response may also be used to increase demand during periods of high supply and low demand. Some types of generating plant must be run at close to full capacity (such as nuclear), while other types may produce at negligible marginal cost (such as wind and solar). Since there is usually limited capacity to store energy, demand response may attempt to increase load during these periods to maintain grid stability. For example, in the province of Ontario in September 2006, there was a short period of time when electricity prices were negative for certain users. Energy storage such as pumped-storage hydroelectricity is a way to increase load during periods of low demand for use during later periods. Use of demand response to increase load is less common, but may be necessary or efficient in systems where there are large amounts of generating capacity that cannot be easily cycled down.
Some grids may use pricing mechanisms that are not real-time, but easier to implement (users pay higher prices during the day and lower prices at night, for example) to provide some of the benefits of the demand response mechanism with less demanding technological requirements. In the UK, Economy 7 and similar schemes that attempt to shift demand associated with electric heating to overnight off-peak periods have been in operation since the 1970s. More recently, in 2006 Ontario began implementing a "smart meter" program that implements "time-of-use" (TOU) pricing, which tiers pricing according to on-peak, mid-peak and off-peak schedules. During the winter, on-peak is defined as morning and early evening, mid-peak as midday to late afternoon, and off-peak as nighttime; during the summer, the on-peak and mid-peak periods are reversed, reflecting air conditioning as the driver of summer demand. As of May 1, 2015, most Ontario electrical utilities have completed converting all customers to "smart meter" time-of-use billing with on-peak rates about 200% and mid-peak rates about 150% of the off-peak rate per kWh.
Australia has national standards for Demand Response (AS/NZS 4755 series), which has been implemented nationwide by electricity distributors for several decades, e.g. controlling storage water heaters, air conditioners and pool pumps. In 2016, how to manage electrical energy storage (e.g., batteries) has been added into the series of standards.
Commercial and industrial power users might impose load shedding on themselves, without a request from the utility. Some businesses generate their own power and wish to stay within their energy production capacity to avoid buying power from the grid. Some utilities have commercial tariff structures that set a customer's power costs for the month based on the customer's moment of highest use, or peak demand. This encourages users to flatten their demand for energy, known as energy demand management, which sometimes requires cutting back services temporarily.
has been implemented in some jurisdictions to provide real-time pricing for all types of users, as opposed to fixed-rate pricing throughout the demand period. In this application, users have a direct incentive to reduce their use at high-demand, high-price periods. Many users may not be able to effectively reduce their demand at various times, or the peak prices may be lower than the level required to induce a change in demand during short time periods (users have low price sensitivity, or elasticity of demand is low). Automated control systems exist, which, although effective, may be too expensive to be feasible for some applications.
One advantage of a smart grid application is time-based pricing. Customers who traditionally pay a fixed rate for consumed energy (kWh) and requested peak load can set their threshold and adjust their usage to take advantage of fluctuating prices. This may require the use of an energy management system to control appliances and equipment and can involve economies of scale. Another advantage, mainly for large customers with generation, is being able to closely monitor, shift, and balance load in a way that allows the customer to save peak load and not only save on kWh and kW/month but be able to trade what they have saved in an energy market. Again, this involves sophisticated energy management systems, incentives, and a viable trading market.
Smart grid applications increase the opportunities for demand response by providing real time data to producers and consumers, but the economic and environmental incentives remain the driving force behind the practice.
One of the most important means of demand response in the future smart grids is electric vehicles. Aggregation of this new source of energy, which is also a new source of uncertainty in the electrical systems, is critical to preserving the stability and quality of smart grids, consequently, the electric vehicle parking lots can be considered a demand response aggregation entity.
In addition, the increased presence of variable renewable generation drives a greater need for authorities to procure more ancillary services for grid balance. One of these services is contingency reserve, which is used to regulate the grid frequency in contingencies. Many independent system operators are structuring the rules of ancillary service markets such that demand response can participate alongside traditional supply-side resources - the available capacity of the generators can be used more efficiently when operated as designed, resulting in lower costs and less pollution. As the ratio of inverter-based generation compared to conventional generation increases, the mechanical inertia used to stabilize frequency decreases. When coupled with the sensitivity of inverter-based generation to transient frequencies, the provision of ancillary services from other sources than generators becomes increasingly important.
Some utilities are considering and testing automated systems connected to industrial, commercial and residential users that can reduce consumption at times of peak demand, essentially delaying draw marginally. Although the amount of demand delayed may be small, the implications for the grid (including financial) may be substantial, since system stability planning often involves building capacity for extreme peak demand events, plus a margin of safety in reserve. Such events may only occur a few times per year.
The process may involve turning down or off certain appliances or sinks (and, when demand is unexpectedly low, potentially increasing usage). For example, heating may be turned down or air conditioning or refrigeration may be turned up (turning up to a higher temperature uses less electricity), delaying slightly the draw until a peak in usage has passed. In the city of Toronto, certain residential users can participate in a program (Peaksaver AC) whereby the system operator can automatically control hot water heaters or air conditioning during peak demand; the grid benefits by delaying peak demand (allowing peaking plants time to cycle up or avoiding peak events), and the participant benefits by delaying consumption until after peak demand periods, when pricing should be lower. Although this is an experimental program, at scale these solutions have the potential to reduce peak demand considerably. The success of such programs depends on the development of appropriate technology, a suitable pricing system for electricity, and the cost of the underlying technology. Bonneville Power experimented with direct-control technologies in Washington and Oregon residences, and found that the avoided transmission investment would justify the cost of the technology. Demand-Side Management Technology Avoids Grid Construction for Bonneville Power (Case Study) April, 2006
Other methods to implementing demand response approach the issue of subtly reducing duty cycles rather than implementing thermostat setbacks. These can be implemented using customized building automation systems programming, or through swarm-logic methods coordinating multiple loads in a facility (e.g. Encycle's EnviroGrid controllers).
Similar approach can be implemented for managing air conditioning peak demand in summer peak regions. Pre-cooling or maintaining slightly higher thermostat setting can help with the peak demand reduction.L. Liu, W. Miller, and G. Ledwich, "Community centre improvement to reduce air conditioning peak demand," presented at the 7th International Conference on Energy and Environment of Residential Buildings, Queensland University of Technology, Brisbane, Qld, Australia, 2016. Available: http://eprints.qut.edu.au/101161/
In 2008 it was announced that electric refrigerators will be sold in the UK sensing dynamic demand which will delay or advance the cooling cycle based on monitoring grid frequency but they are not readily available as of 2018.
Residential and commercial electricity use often vary drastically during the day, and demand response attempts to reduce the variability based on pricing signals. There are three underlying tenets to these programs:
The report estimates that in 2004 potential demand response capability equaled about 20,500 megawatts (megawatt), 3% of total U.S. peak demand, while actual delivered peak demand reduction was about 9,000 MW (1.3% of peak), leaving ample margin for improvement. It is further estimated that load management capability has fallen by 32% since 1996. Factors affecting this trend include fewer utilities offering load management services, declining enrollment in existing programs, the changing role and responsibility of utilities, and changing supply/demand balance.
To encourage the use and implementation of demand response in the United States, the Federal Energy Regulatory Commission (FERC) issued Order No. 745 in March 2011, which requires a certain level of compensation for providers of economic demand response that participate in wholesale power markets. The order is highly controversial and has been opposed by a number of energy economists, including Professor William W. Hogan at Harvard University's Kennedy School. Professor Hogan asserts that the order overcompensates providers of demand response, thereby encouraging the curtailment of electricity whose economic value exceeds the cost of producing it. Professor Hogan further asserts that Order No. 745 is anticompetitive and amounts to "...an application of regulatory authority to enforce a buyer's cartel."Hogan, William W., Implications for Consumers of the NOPR's Proposal to Pay the LMP for All Demand Response, Statement submitted on behalf of the Electric Power Supply Association in FERC Docket No. RM10-17-000, May 12, 2010. Several affected parties, including the State of California, have filed suit in federal court challenging the legality of Order 745.Electric Power Supply Association, et al, JOINT REQUEST FOR REHEARING OF THE ELECTRIC POWER SUPPLY ASSOCIATION, THE AMERICAN PUBLIC POWER ASSOCIATION, THE ELECTRIC POWER GENERATION ASSOCIATION AND THE NATIONAL RURAL ELECTRIC COOPERATIVE ASSOCIATION, FERC Docket No. RM10-17-001, April 14, 2011, California Public Utilities Commission, Demand Response Compensation in Organized Wholesale Energy Markets, Docket No. RM10-17-000, Request For Clarification or, in theAlternative, Request for Rehearing of the Public Utilities Commission of the State of California, April 14, 2011. A debate regarding the economic efficiency and fairness of Order 745 appeared in a series of articles published in The Electricity Journal.Jonathan Falk, Paying For Demand Response at the Wholesale Level, The Electricity Journal, November 2010, Vol. 23, Issue 9, pp. 13-18.Robert Borlick, Paying For Demand Response at the Wholesale Level: The Small Consumer's Perspective, The Electricity Journal, November 2011, Vol. 24, Issue 9, pp. 13-19.Constantine Gonatas, Areas of Congruence, Yes, But 'Pseudo-Agreement' on LMP, The Electricity Journal, Jan./Feb. 2012, Vol. 25, Issue 1, pp. 1-4
On May 23, 2014, the D.C. Circuit Court of Appeals vacated Order 745 in its entirety. On May 4, 2015, the United States Supreme Court agreed to review the DC Circuit's ruling, addressing two questions:
On January 25, 2016, the United States Supreme Court in a 6-2 decision in FERC v. Electric Power Supply Ass'n concluded that the Federal Energy Regulatory Commission acted within its authority to ensure "just and reasonable" rates in the wholesale energy market.
FERC issued its Order No. 2222 on September 17, 2020, enabling distributed energy resources to participate in regional wholesale electricity markets. Market operators submitted initial compliance plans by early 2022.
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