The traditional central-station grid is evolving toward a more distributed architecture, accommodating a variety of resources spread out across the network. An open and thoughtful planning...
The Rise of Distributed Energy Resources: Calling on the Lilliputians
Is DER competitive with traditional utility investments, and if so, what are the costs and benefits?
up to double for heavily loaded lines.
Voltage/Value at Risk (Var) Benefits. DER can provide steady state and dynamic power benefits. Dynamic benefits are provided mostly by synchronous DG, which can provide voltage support during system contingencies. Steady state Var and voltage support is provided by DG and DR by virtue of load reduction, which reduces Var demand on power lines and equipment.
Deferred Central Capacity. Capacity credits may accrue when DER is available at the time of the system peak. When “behind-the-meter” DG is online or DR is called, load that otherwise would be met by generation or imports is reduced. Capacity needed to meet reserve margins—typically about 15 to 20 percent of native load—is reduced proportionally.
The level of firm DER capacity is adjusted upward by 20 to 30 percent to capture reserve margin credits and peak-loss reduction. Incremental peak losses often are significant; 10 to 15 percent reductions are common.
Relying on DER to Defer Capacity
Utilities are understandably cautious when asked to rely on customers to provide firm distribution capacity. Utilities have an obligation to deliver power safely, reliably, and continuously—distribution availability that often exceeds 99.99 percent underscores utility efforts to maintain high reliability. Massachusetts, New York, and California have introduced performance-based rates (PBR), with penalties applied when reliability falls below minimum thresholds. If DER causes reliability to degrade, utilities quickly will reject it as a solution.
Figure 2 illustrates how DER “fits” into a feeder or substation load duration curve (LDC). The difference between peak load and rated capacity represents the amount of firm DER that must be available to enable capacity deferral. For most utilities, the highest loads occur over a small number of hours. Typically, the top 20 percent of load occurs during 10 percent or less of the total hours in the year.
Figure 2 provides a useful rule-of-thumb; namely, maximum load deferred by DER should not exceed 15 to 20 percent. Thereafter, the curve flattens—hundreds or thousands of hours of DER operation then would be needed. For DR, the maximum number of hours generally is limited to less than 200 hours, which usually corresponds to the upper 5 to 10 percent of peak hours.
Utilities need absolute assurance that DG will be available when needed. Physical assurance provides greater certainty that customers who agree to operate DG when needed will reduce load, either by running the generator or by interrupting an equivalent amount of load. 3 Establishing net level of firm DER capacity recognizes that DG may be out of service due to forced outages, including not starting when called upon to operate. The cost of communications and controls can be significant, and it must be added to incentive payments to derive total DER cost. Use of control systems apply only to larger technologies such as combined heat and power (CHP), as costs for small DG and renewables would be prohibitive. Thus smaller DG is less likely to provide the same percentage of firm capacity as larger DG with physical assurance.
Moreover, some DG operates only at peak. Exceptions include CHP, whose process