[BETA] Fortnightly

With just a few changes in reliability rules, regulators could call on consumer loads to boost power reserves for outages and contingencies.

 

In proposing a standard market design (SMD), the Federal Energy Regulatory Commission (FERC) makes clear that it wants customers to participate in wholesale power markets, such as by bidding an offer to curtail consumption, increase supply, and reduce upward pressure on prices.

"We believe in the direct approach of letting demand bid in the market," says FERC.

In fact, FERC much prefers this demand-response strategy to the more traditional special programs for load reduction, whereby regulators typically promise an incentive or subsidy to customers in return for cutbacks in usage.

According to the commission, letting customers bid their own demand directly in the market as a system resource "will be less costly than a program where an end-user receives payments greater than the market-clearing price to reduce its demand." ¹

To try out FERC's idea, consider the issues and opportunities in getting retail loads to provide some of the real-power ancillary services that are required to comply with reliability rules imposed on the nation's grid system. In particular, consider the three services known as contingency reserves that are commonly deployed throughout the Northeast:

(1) 10-minute spinning reserve;

(2) 10-minute nonspinning (supplemental) reserve; and

(3) 30-minute (replacement) reserve.

These three ancillary services provide insurance against outages and other contingencies that might threaten the reliability of local or regional power grids through an interruption in service or by disrupting grid operations.

Under traditional practice, the electric utility industry has relied on large-scale generating plants to supply these reserves. Reliability rules are tailored to fit that assumption. Instead, consider the possibility of meeting these reserve requirements by relying on customers to trim their power consumption at crucial times.

Ordinarily, because the time between a major outage and full recovery is so short (15 minutes), the independent system operator (ISO) will require close communication and frequent updates on the status of the resources providing contingency reserves. During an emergency, the ISO must be able to send its request for increased output (or reduced load) to participating resources quickly, and the system operator requires the resources to confirm receipt of the dispatch order rapidly. Traditionally, the generators providing contingency reserves measure and report their output to the system operator once every several seconds. Thus, these units have sophisticated and expensive metering and telecommunications systems. In addition, the system operator requires the units to have telephone (or other voice) communication links with the control center.

These technical requirements were all developed with large generators in mind. However, to what extent do these requirements make sense for demand resources? That is, what does the system operator need to know about these resources, which, on average, are much smaller than the typical generator, and how frequently must this information be updated? How much can retail loads afford to spend on metering and communications, given the likely market payments for reserves of only a few dollars per megawatt per hour?

In fact, some demand-side resources display many of