When the goals of a utility and its host community aren’t in sync, breakups happen.
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?
Not all utilities add or upgrade equipment based solely on deterministic criteria; that is, adding capacity when normal ratings are exceeded. A joint probability analysis of outage exposure and equipment failure rates establishes the level of exposure caused by insufficient capacity. The result, when multiplied by the value of unserved energy, represents the risk avoided by adding capacity.
Most agree that the value of energy unserved exceeds retail electricity cost; some suggest at least by an order of magnitude. Some utilities apply value-of-service (VOS) methods to quantify the avoided risk associated with unserved energy. Surveys yield values of $5/kWh to $25/kWh that query residential, commercial, and industrial customers on the degree that outages impact production, inconvenience, productivity, company image, and other factors.
The savings achieved by T&D deferral should not be confused with the value of avoided risk— i.e., the cost of unserved energy. For the latter, a risk-based VOS approach is applied, where the annual value of avoided risk is derived by multiplying VOS times the amount of unserved energy due to insufficient capacity. A VOS calculation yields values that typically are far higher than the avoided cost of annual capacity deferral, and should be used to compare T&D to DER via comparable metrics.
Use of probability methods implies that the value of avoided risk is low for minor overloads with low exposure hours. These values increase commensurate with outage exposure and capacity deficits. As loads increase, the likelihood of equipment failure rises as well. Industry standards and professional organizations provide guidelines that predict transformer failure as a function of loading. Figure 1 illustrates how transformer failure rates increase exponentially as loads increase. Hence, the value proposition for new capacity rises significantly when loads extend beyond the knee of the curve.
A range of direct and indirect benefits may apply to DER. Table 1 groups these benefits by two categories: (1) direct versus indirect; and (2) degree of difficulty to quantify values. Direct benefits that are relatively straightforward to quantify appear in the upper right quadrant. Indirect or difficult-to-quantify benefits are part of the evaluation process.
Potential DER benefits include:
Deferred T&D Capacity. Benefits associated with deferred T&D upgrades or additions assume that “firm” DER, when combined with existing T&D capacity, is sufficiently reliable to meet feeder or substation peaks. DER may be a viable solution only for a limited number of years on high-growth circuits, after which the traditional T&D solution is necessary. Accrued benefits also must be restricted to those years in which DER is a solution.
Losses. Line and equipment loss reduction is in direct proportion to the square of the capacity of online DER. When loads are high, loss savings can be substantial. Savings include: (1) demand reductions at the time of the feeder or substation peak; and (2) energy losses over the entire period when DER is operating. For DR, operating hours are low, and savings mostly are demand-related. Loss credits are calculated on an incremental basis. This distinction is important as incremental losses tend to be higher than average;