Progress towards better demand response:
A review of the FERC/NARUC demand response collaborative meeting
Many independent analyses point to a near future in which electricity demand is outpacing installed capacity. With nuclear and coal plants becoming more expensive due to rising commodity and construction costs, and environmental concerns leading the latter being cancelled or deferred, there is now an opportunity to release the potential of the demand side. It has long been known that energy efficiency is available at a lower cost than the baseload supply it replaces, and increasing amounts of demand response (DR) in electricity markets reveals that it can be less expensive than peaking power. These demand resources provide the additional benefit that, just as the cheapest kW (or kWh) is derived from the one that is never built, so too is the cleanest.
At the core, each of the presentations at the Federal Energy Regulatory Commission (FERC) and the National Association of Regulatory Utility Commissions (NARUC) Demand Response Collaborative meeting extolled the rise of demand response, and that its implementation at high penetration is very much desired and within our reach. The meeting was evidence that the collaborative is providing a forum to frame and outline a well thought out process for reaping the benefits from the deployment of DR. The first of the presentations, by David Kathan and Ray Palmer of FERC, outlined the commission’s upcoming assessment report, National Action Plan, and implementation proposal.
Rick Sergel, CEO of NERC, discussed the progress NERC has made in collecting DR data and advocated that high targets to be set. Liz Hicks of KEMA and the author of this article presented the preliminary research they are leading for the collaborative on barriers to demand response and policy options to mitigate them. Together, these three presentations framed ongoing efforts to ensure that demand response is developed under well-informed guidelines.
KEMA’s work on barriers and policy options is being complemented by another study, lead by the Brattle Group, which aims to quantify the national DR potential. Elements of both of these reports will be used in the 2009 FERC assessment of Demand Response. Specifically, the parts of the assessment that will be most influenced by these studies are:
The assessment is to be completed by June 17, 2009. FERC’s next major DR publication, the National Action Plan, is to be published by June 17, 2010, with an implementation proposal due in December 2010. The National Action Plan will be formed through an inclusive process, with FERC reaching out to stakeholders to identify existing resources, programs, tools and measures of DR. A preliminary, revised and draft plan will each be released for input between revisions. Ideally, the plan will provide “optimal solutions” on points where no consensus exists.
DR stakeholders should be excited by the progress made with NERC’s Demand Response Availability Data System (DADS). The system will help quantify the value of demand response to reliability. Much like NERC’s generation and transmission availability databases, demand response event analysis will provide a foundation for measurement of its capacity, energy and ancillary service benefits. Mr. Sergel also emphasized the potential for demand response to realize greater delivered amounts of renewable-based electricity. Variable generation, such as wind and solar, often need a “dancing partner,” a resource that can complement increasing penetration of wind and solar and provide operational flexibility to maintain reliability during the sharp down-ramps that can be experienced with these resources. DR has many qualities that make it particularly well-suited to play this role, which it has already shown plausible by, for example, being used in ancillary services markets. In addition to its ability to target peak demand growth, communications technologies have made the resource more dispatchable than ever before, in many cases available to operators in a matter of minutes. NERC’s most recent data on DR in ancillary services markets indicates that operators are beginning to count on the resource with more certainty than in years past.
While demand response has gained momentum from improvements to communications and metering technologies and lower costs in recent years, many barriers remain to increasing the overall level of DR as a percentage of peak load, and its effective use. As part of the FERC/NARUC DR Collaborative, KEMA was asked to produce a research report to identify barriers and outline options to coordinate retail and wholesale policies that would mitigate or remove barriers and stimulate greater amounts of demand response.
The KEMA presentation identified many barriers and compared several existing DR taxonomies. Some of the key barriers include:
high minimum load thresholds to default service on a dynamic rate
lack of metering and enabling technology infrastructure
regulator reluctance to expose customers to market volatility.
Other barriers that were identified were at a much more specific or “micro” level. In the discussion that followed, there was strong consensus that barriers should be sequenced in such a way to illustrate the interconnectedness of some and to serve as a stepping stone to developing a chronological policy “roadmap” that regulators could follow. Part of this conversation on the interplay of certain barriers addressed the question of “what is optimal participation.” This question alludes to the idea that policies should be developed that will not only mitigate barriers, but that will do so in the best possible way.
Commissioner Paul Centolella had an interesting take on the “optimal participation” question. He proposed an alternative question: “what is the optimal level of hedging?” He reasoned that regulators have assumed the optimal level to be 100%, or fixed rates, because fixed rates protect customers from market volatility and therefore maximize consumer value. However, recent studies have shown that the “insurance premium” embedded in fixed rates far exceeds those of dynamic rates, which calls into question the comparative amount of consumer value generated by fixed vs. dynamic rates. Furthermore, dynamic rates have also been shown to benefit the retailer by creating a less costly resource to meet peak demand, which in turn benefits all customers – under dynamic rates or not.
Regulators are saddled with the difficult task of providing an environment that allows for healthy returns on investment while protecting consumer value. However, for many customers, the insurance premium is simply not worth it. Premiums of 15 to 40 percent for fixed rates far exceed the 3 to 8 percent premium for dynamic and RTP rates, implying that price responsive customers could significantly reduce their electricity bills. Because not all customers are willing or able to shift their load, or use less electricity during periods of higher marginal cost, some would not benefit from the dynamic rates. Therefore, the commissioner’s question of “what is the optimal level of hedging” cannot be answered with a single quantity – it varies for every individual customer.
Instead, the answer is for retailers to offer a portfolio of dynamic rates on a spectrum from more to less hedging that best match individual consumption patterns to yield the greatest producer and consumer surplus. In that way, a customer would be able to pick one rate from many choices that delivers the greatest savings while allowing him to be comfortable with the amount of risk he is willing to take on. Increasing the amount of DR in the system will have the added benefits of lowering wholesale prices while improving reliability. The value of these benefits is delivered not just to those under dynamic rates, but to all consumers and the utility.
Dynamic rates have often been categorized as being “non-dispatchable,” implying that in times of need, resources under these contracts would not be as reliable as direct load control (DLC) or demand response “programs” with formal penalties. The latter concern can be addressed simply: the penalty of not responding to high prices under a dynamic rate is a higher electricity bill. As for the dispatchability of dynamic rates, since only customers who respond to prices would choose a dynamic rate, dispatch operators and utilities worried about reliability and high wholesale prices should not fear that the price signal will not elicit a response.
Even greater dispatchability under dynamic rats will be possible when individual customers are able to program price set-points into their appliances and thermostats. Once issues of data availability and privacy are sorted out, system operators will be able to control the demand resource as effectively as with DLC, and retailers will be able to effortlessly choose between generation and demand to meet load. And, unlike interruptible tariffs and emergency programs in which unreliable “baselines” must be quantified to estimate the amount of resource available at a given time of a particular day, dynamic rates with smart appliances and price set-points allow operators to see near real-time consumption and what reduction would result from a given price increase. This dispatchability itself is valuable to firms, and will no doubt be priced in the future.
In the meantime, retailers can work to improve their dynamic rate structures by allowing customers to respond to both day-ahead and hour-ahead (rather just than hour-ahead) prices, and by offering a menu of dynamic rates. Regulators can implement policies to allow the passing through of marginal costs to consumers by lowering the threshold customer load to be placed on default dynamic rates and by educating the public on the benefits of demand response.
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