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Dynamic Scheduling: The Forgotten Issue
load and purchase all its electrical needs from one provider. Such aggregation can reduce costs for some services, especially regulation (see Table 1).
Similarly, the manager of several generating units in several control areas might want to aggregate their outputs and sell all the basic energy and capacity, as well as ancillary services, to a single customer or another control area. In addition, cost reductions might motivate dynamic scheduling. For example, if control area C pays higher prices for ancillary services (such as regulation and spinning reserve) than control area A, a generator located in control area A might want to dynamically schedule its output to C.
Examples in the U.S.
In some generation examples we have uncovered, the units are used for regulation, and in other cases they are not. The Western Area Power Administration (WAPA) operates the 17 hydroelectric units at Hoover Dam. Four other control areas in the Southwest send signals to WAPA every four seconds, requesting time-varying amounts of generation (up to their contractual allocations); because hydro units respond very quickly compared with fossil units, the four control areas use their Hoover rights for regulation. WAPA aggregates the four requests and sends the total to Hoover Dam.
Similarly, Otter Tail Power purchases supplemental regulation and load following services from Manitoba Hydro because Manitoba Hydro's hydroelectric units can provide faster regulation service at lower cost than can OTP. OTP began receiving up to 50 MW of regulation service from
Manitoba Hydro in 1990. OTP's compliance with the A1 and A2 criteria has improved substantially, from less than 80 percent before obtaining regulation service from Manitoba to more than 98 percent.
Montana Power operates the four Colstrip units in Montana, for itself and the four other owners. Although these units are operated in baseload mode, rather than as regulating units, dynamic scheduling still made sense. Absent dynamic scheduling, all the errors in plant output (i.e., differences between actual and scheduled output) would contribute to Montana Power's inadvertent interchange but not to that of the other owners. Dynamically scheduling the units equitably shares any errors in plant output and reduces the need for control-area and plant operators to manually change schedules.
PacifiCorp operates generating stations and serves loads in seven Northwestern states (Washington, Oregon, California, Montana, Idaho, Utah and Wyoming). Most of its generation is in its eastern division (Utah and Wyoming), while most of its load is in its western division. The eastern generators are primarily large coal units. The western generators are primarily hydro units. Before the merger that created PacifiCorp, the two original utilities operated separate control centers in Salt Lake City and Portland, Ore. Now, PacifiCorp operates its entire system from its Portland facility. This consolidation allows PacifiCorp to use the eastern units for baseload capacity in the West and to use the western hydro units for regulation in the East. The Idaho Power
system lies between the two PacifiCorp divisions. PacifiCorp purchased firm transmission rights for 1,600 MW of capacity flowing from east to west across the Idaho Power system. Of this total, 1,500 MW is