Miriam Goldberg & Mitchell Rosenberg, KEMA
Recent years have seen renewed interest in demand response programs across the U.S. These programs use a variety of pricing mechanisms to encourage demand reduction during periods of severe supply constraints and/or extreme spot market prices for electricity. Load management options have been in place for many years. The combination of a new market orientation and technological advances, further spurred by the 2000/2001 energy crises in the U.S., has led to substantial innovation in program design.
Refinements to these designs are now emerging that may allow demand response to be viable and valuable even in the face of the current glut of generation capacity. Moreover, other market developments give reasons for regulators and operators to sustain interest in these programs over the long run.
What the new programs look like
The new generation of programs uses new technologies to provide operators with greater control over the timing, amount, and location of load reductions. Some programs provide participants with the opportunity to incorporate market price and risk information into their load reduction decisions. Program types being offered are as follows.
“- Reliability programs provide incentives to customers to be on call to reduce demand on notice from the program sponsor (an ISO or vertically integrated utility), primarily to avert capacity shortages.
“- Market-oriented programs are designed primarily to protect sponsors and their customers from the price risks associated with tight demand conditions. The most common approach is customer bidding, under which participants submit bids to reduce load directly into the day-ahead wholesale market.
“- Critical peak pricing programs represent a blend of time-of-use and real-time pricing. The customer pays for whatever energy it uses, and pays a high premium for energy used during periods declared a day ahead as “critical peak.”
What we can learn from recent evaluations
Evaluation results from 2002 and 2003 programs can help us understand what’s working and what’s not. For example, in 2002 customers representing 9 percent of the total eligible load participated in the New York ISO’s emergency (reliability) program, reducing system load by 2 to 3 percent during called events. Financial savings, primarily the value of increased system reliability, greatly outweighed program costs. Other programs, however, have been less successful in attracting customers.
Key success factors include reducing the hassle of participation, reducing risk to the participant, and providing higher incentives. Participation in market-oriented programs remains low, primarily due to the high level of attention and market knowledge they demand of customers. In 2002 New York for example, load reductions accomplished through the emergency program totaled 668 MW, versus eight MW for the day ahead market-oriented program.
Resource adequacy requirements
Stakeholders in restructured markets are increasingly recognizing that market forces alone will not ensure adequate supply. Recommendations for regional planning along with “resource adequacy” or reserve margin requirements have emerged, for example, in FERC’s 2002 Standard Market Design (SMD) guidelines and in California’s recently issued Energy Analysis Plan.
How resource adequacy will be defined and what structures will be put in place to ensure it will be the subject of debate in each market over the next few years. Regardless of the outcomes, we can expect that explicit resource adequacy requirements will mean more explicit recognition and valuation of demand-side resources.
Locational marginal pricing (LMP)
Many markets are moving toward finer-grained geographic price variation. That is, prices are determined not for the market as a whole, but for each zone or node within the market. Changing to a more geographically fine-grained market will mean that the value of demand response will vary in each zone or locally constrained area. As a result, there will be stronger market forces in favor of demand response in congestion pockets. Consequently, we may see programs and market rules that support localized demand response activity, rather than broader offerings.
Integrated planning frameworks
In the early 1990s, most demand-side management programs design operated under integrated resource planning (IRP) or least-cost planning (LCP) frameworks. Under these frameworks, demand-side resources competed directly against supply-side resources in investment decisions.
Along with the recognition that markets by themselves may not provide adequate supply over the long run has come a renewed discussion of the need for integrated planning. This trend can mean that generation, transmission, efficiency and demand response will be evaluated as a group, so that some “optimal” mix may be determined.
One challenge for establishing effective integrated planning frameworks is how to value and make trade-offs among the different types of resources. The trade-offs must address not only the direct cost per kWh, but also the value of other dimensions, such as dispatchability, ramp-up time, land use, or air quality.
Another challenge is in determining who has the authority to enforce this kind of planning. In many areas, the regulatory authority rests with the state, while the planning responsibility belongs to the ISO, at a regional level.
One positive example where these challenges are being met is in southwest Connecticut. There, ISO New England (ISO-NE) has recently issued an “all-resource” request for bids. This area of Connecticut suffers from a severe transmission constraint, which has already prompted implementation of locational marginal pricing for 52 towns and cities. Already-high prices may jump by another 200 to 300 percent.
To avoid the price spike and potential brownouts, the ISO NE asked interested parties to offer bids for net supply increase. The bids could be either for standby generation capacity from emergency turbines; to implement a new demand response pricing scheme; or to subsidize energy efficiency improvements.
Where to from here?
Several trends point toward an ongoing and increasingly robust role for demand response in U.S. markets. These trends include increased interest in integrated and regional planning, formal requirements for resource adequacy, and expanded use of locational pricing. Taken together, these movements suggest that a resource that can be on call for rare and geographically dispersed emergency conditions will have an explicit, recognized value, and an important place in the overall resource mix.
Experience in the next few years will refine our understanding of how to make demand response programs successful and cost-effective. This experience will also help us refine the market structures and planning frameworks that will make the best use of the opportunities these programs offer.
Goldberg is senior vice president, research and evaluation, and Rosenberg is vice president, East Coast research and evaluation for Burlington, Massachusetts-based KEMA Inc. They can be reached at firstname.lastname@example.org, and email@example.com.