Historically, grid operators tapped into voluntary load reduction as a last resort for keeping the lights on. But now, smart grid technologies and dynamic pricing mechanisms bring vastly greater...
An Inconvenient Fact
Why the standard market design refuses to die.
with power plants, thus violating the long-established federal-state jurisdictional divide over the regulation of transmission (a federal matter) and generation (left to the states).
For example, as a counterweight to PJM’s TDA coalition, Entergy, Southern Co., Progress Energy, and the Salt River Project formed the so-called Community Power Alliance to defend the status quo. It saw open dispatch as “insensitive to the concerns of state regulatory commissions.”
Progress Energy, filing its own comment, then blasted open dispatch as violating native-load protections and due-process guarantees: “Open dispatch is a shorthand term for … confiscating the power supply resources of vertically integrated electric utilities in order to serve loads that they have no obligation to serve.”
Entergy advised that FERC and its staff had long recognized and understood “all of these concepts,” but had simply “knowingly chosen to adopt a different approach than that previously taken with the SMD.” Continuing in the same vein, the large Public Power Council warned that “Chandley/Hogan may feel free to quarrel with Congress, but the commission does not have that luxury.”
The analysis starts with short-term grid imbalances, as when generators run short or long of scheduled output, or load exceeds forecasts or fails to show up. That’s when mischief begins—but only if imbalances are priced incorrectly.
Entergy’s service area offers the prime example, where some 17,000 MW of new merchant generation has put down roots, though Entergy’s grid system claims only 4,000 MW of simultaneous transport capability. For years, Entergy complained how merchant plants leaned on its system over short-term intervals. They allegedly would ramp up and down ahead of schedules, shaving minutes so as not to leave money on the table (not to mention start-up and minimum-run costs), while Entergy’s native units (even coal plants) would scramble to maintain frequency control. That led Entergy to negotiate a special generator imbalance agreement (GIA) with merchants. (See Docket ER04-901, June 1, 2005, 111 ¶FERC 61,314.)
In fact, while it opposes open dispatch, Entergy defends its GIA as offering real-time features for managing imbalances that go far beyond the crude monthly accounting requirements of FERC’s OATT revised plan. Thus, Entergy urges FERC not to jeopardize its own “uniquely tailored” plan. (Entergy, initial comments, pp. 26-35.)
Another open dispatch opponent, the Edison Electric Institute (EEI), recognizes nevertheless how important it is for FERC to distinguish between imbalances in peak- and off-peak periods: “Otherwise,” says EEI, “energy imbalance customers will have an incentive to underschedule in high-load periods when costs and prices are high, and to repay … when costs and prices are low.” (EEI, initial comments, p. 71.)
Meanwhile the Western Electricity Coordinating Council (the western reliability region) has noticed that FERC-mandated imbalance penalties have proven problematic. It seems that some generators use “set-point controllers” to “override governor action” to avoid imbalance charges, but erode frequency control in the process. Meanwhile “those with properly operating governors” will help control frequency, but “may be punished,” says WECC, “for deviating from scheduled output to respond to system reliability needs.” (WECC, initial comments, pp. 19-20.)
Chandley/Hogan were quick to spot this