When customers sell demand response into a regional capacity market (such as PJM’s Reliability Pricing Model, known as the RPM), how much credit should they earn for agreeing to curtail demand and...
DR design flaws create perverse incentives.
New York ISO and ISO-New England implemented economic DR in 2001 and were closely followed by the PJM Interconnection in 2002. 5 The Electric Reliability Council of Texas implemented several economic DR programs in late 2003 that allowed limited load participation through their respective retail electricity providers (REPs). The Midwest ISO and the California ISO implemented economic DR programs somewhat later and currently have proposals before FERC for expanding these programs to accommodate the participation of third-party aggregators of retail customers (ARCs). 6 The Southwest Power Pool currently has no economic DR program as it operates only a real-time energy balancing market.
The current interest in wholesale economic DR programs has obscured the fact that they are poor substitutes for the best solution, which is to fix the retail tariffs. Anyone who doubts their second-best status need only contemplate the substantial transaction costs these programs introduce, such as those incurred by ARCs in recruiting retail customers, developing and aggregating the customers’ price offers, communicating load interruption instructions to them, estimating their response to these instructions and paying them for the estimated load reductions. In addition, the sponsoring ISOs/RTOs incur higher costs in settling these transactions and in recovering the payments made to ARCs from other wholesale market participants. Virtually none of these costs would exist if those same retail customers had the ability to respond directly to wholesale market prices ( i.e., through smart meters combined with dynamic, hourly rates) rather than relying on ARCs to coordinate the interruption of their loads.
In addition to high transaction costs, economic DR programs must rely on statistical techniques ( i.e., measurement and verification) to indirectly estimate what each customer would have done but for the payments received through the program. The measurement and verification activity is the Achilles’ heel of these programs, because it not only introduces unavoidable measurement errors but also creates opportunities for DR providers to game the system to get paid for demand reductions never delivered. 7
For example, in New England, DR providers were offering nominal amounts of DR into the market at low prices to ensure that their offers would be accepted in order to exclude their actual consumption for that day from calculations updating their consumption baselines. By selectively repeating this strategy, a provider could maintain an inflated consumption baseline and thereby get credit for demand reductions that it never delivered. In February 2008, ISO-New England countered this scheme by indexing the minimum DR offer to the price of natural gas, which increased the minimum offer price from $50/MWh to approximately $100/MWh, and thus limited the number of hours when such gaming activity could occur. 8
Last, all of the existing economic DR programs ignore the benefits of building off-peak loads when wholesale market prices—and production costs—are low and sometimes even negative. Such load-building activities will become increasingly important as power systems accommodate increasing amounts of wind, solar and other variable energy resources.
While it’s possible to design economic DR programs that include appropriate incentives for efficient consumption in all hours, doing so would increase the