Liam Baker, vice president for regulatory affairs at US Power Generating, questions whether his company’s power plants and control systems in New York and Massachusetts must comply with the...
Dynamic Scheduling: The Forgotten Issue
used for base capacity, and the additional 100 MW is assigned to regulation. PacifiCorp also compensates Idaho Power for losses on the Idaho transmission system based on contractually agreed upon assumptions, not based on metered flow or detailed calculations.
Several utilities in the Southwest co-own several generating units (see Figure 1). The outputs from these units are dynamically scheduled from the plant's operator to the other owners. The coal-fired Navajo station is operated by the Salt River Project (SRP) but is physically located within the control area of Arizona Public Service (APS). The reverse is true for the Palo Verde nuclear plant, which APS operates and located within the SRP control area.
Using it to Schedule Loads
The examples of dynamically scheduled loads show that the amounts of power transferred are generally much smaller per delivery point than for generation. For example, the Geneva, Ill., load of about 45 MW is the aggregate of loads collected at eight points on the Commonwealth Edison transmission system. The city of Geneva aggregates the load and then sends the aggregate signal to both Commonwealth Edison (the physical host) and Wisconsin Electric (the electronic host).
The Cajun Electric Power Cooperative load, which is scattered throughout the service territories of four investor-owned utilities, involves the separate metering and telemetering of loads from about 125 points to the Cajun
control center as well as to the physical-host control centers. On average, each load point is about 10 MW. (Cajun also uses dynamic scheduling for five generating units that it operates, which are located outside its control area.) Cajun has many transmission contracts with the surrounding utilities to cover these transactions. Losses are handled on a contractual basis, depending on the utility and the voltage levels at which loads are measured.
The Central Arizona Project is perhaps the most interesting example uncovered in this study because it involves the simultaneous scheduling of loads and generation. The project brings Colorado River water to the areas around Phoenix and Tucson in Arizona. It is the largest irrigation project in the world. It includes 15 major pumping stations with a load of about 550 MW, all in WAPA's control area. WAPA dynamically aggregates these loads and sends the aggregate signal to the Salt River Project control center in Phoenix. SRP meets the project's load with output from the coal-fired Navajo plant in Page, Ariz. SRP meets any regulation requirements for the project from its overall resource pool. The Navajo plant is located in the APS control area, so it schedules the plant's output across its transmission system. The three, 741-MW Navajo units total 2,223 MW and are co-owned by six utilities: Los Angeles Department of Water and Power, Nevada Power, Tucson Electric, SRP, WAPA and APS. APS is the physical host for the power plant, and SRP is the electronic host. WAPA is the physical host for the project load, and SRP is the electronic host.
The Lower Colorado River Authority (LCRA) traditionally had difficulty meeting its performance criteria, primarily because of a volatile steel-mill load in its service area with a