A case study shows how today's typical tariffs can force some industrial electric customers to subsidize others.
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load that can change rapidly by as much as 100 MW. Beginning in January 1995, LCRA purchased supplemental regulation service from Houston Lighting & Power. Since then, LCRA's compliance with the North American Electric Reliability Council A2 criterion has improved from 74 percent to more than 92 percent. LCRA uses its own generating units to provide regulation service within a ±12- or ±25-MW bandwidth. When the LCRA area control error, or ACE, moves outside this bandwidth, usually because of steel-mill operations, HL&P provides supplemental regulation to move the ACE back inside the bandwidth (see Figure 2).
This transfer is profitable for both utilities, in part because HL&P's generating capacity is about six times as much as LCRA's. This supplemental regulation can be considered dynamic scheduling either of load or of generation. In one sense, this example is the inverse of what Manitoba Hydro provides to OTP. In another sense, LCRA is dynamically scheduling the volatility associated with its steel-mill load to HL&P. Because the two control areas are generally not contiguous, LCRA pays wheeling plus loss charges to the intervening utilities.
What Is the Cost?
Dynamic scheduling involves both initial and ongoing costs. Initial costs include those related to the purchase and installation of additional metering, telemetering, communications and computing equipment. For example, utilities may need to obtain or upgrade communications systems, such as leased telephone lines, microwave systems, or fiber-optic-cable systems. Energy-management systems in control centers may need expansion, involving both hardware and software. In other cases where data are already being collected and telemetered to the control center, initial investments might be quite modest. The primary ongoing costs relate to communication systems (especially to lease telephone lines) and to periodic inspections, maintenance and repair of field equipment.
Because these costs are so dependent on the specific circumstances, we obtained only a few estimates of the initial and ongoing costs of dynamic scheduling. Based on these estimates, the incremental initial cost is $10,000 per metering point and the ongoing costs are $2,000/month.
For a single metering point (e.g., the output of a single generator), the monthly payments are $2,130. For a 100-MW generator with a load factor of 65 percent, this $2130/month is equivalent to 0.045 mills/kWh. Compared to spot prices (roughly 25 mills/kWh), dynamic scheduling is very cheap (em well less than 1 percent of the cost of power.
If dynamic scheduling involves the use of another utility's transmission system (as it often does) and if that utility charges for transmission service and losses, then the cost increases dramatically. %n*%n Assume that this dynamic scheduling of a 100-MW generator involves a transmission charge of $1.5/kW-month and losses of 3 percent charged at an average price of 25 mills/kWh. Now the cost increases from 0.045 to 3.96 mills/ kWh (0.045 for dynamic scheduling + 3.16 for transmission + 0.75 for losses). These results suggest that the costs of dynamic scheduling itself might be a very small percentage (about 1 percent in this example) of the costs of transmission and losses (see Figure 3).
Some Issues to Consider
Dynamic scheduling is a