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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?

Fortnightly Magazine - February 2007

steam and hot water load often require continued operation to be economic. Generation that is not available or experiences output reductions at the time of the system peak, including fuel-burn restrictions, will realize limited or no capacity credits.

Renewable generation such as PV produces maximum output during mid-day hours. If the system (or feeder) peak does not coincide with the time of maximum PV output, firm PV capacity must be reduced. 4 Figure 3 illustrates that the peak PV output does not necessarily coincide with the feeder peak.

Similarly, DR availability could be limited when the value of capacity is highest. Restructured DR programs would permit interruptions for T&D capacity purposes, with higher interruption hours and fewer restrictions. DR would continue to be used for emergencies or to meet system-capacity requirements as well. 5

A common industry practice is to price capacity seasonally, where dollars-per-kilowatt demand is multiplied by statistically derived allocation factors. 6 Intermittent DER resources, such as DR or PV, are assigned partial capacity credits based on the hours and seasons they are most likely to operate. However, derivation of “firm” DER must account for unscheduled outages (DG) or customer non-participation (DR).

DER Incentives, Options & Models

Successful DER implementation is based on a premise that incentives and marketing efforts will increase DER participation sufficiently to defer proposed capacity additions. Regulators typically will allow recovery of direct incentive payments and marketing costs for DER programs in electric rates when benefits exceed program costs. Utilities may find it useful to conduct an active marketing campaign, targeted to areas with projected capacity shortages.

The type of DG most suitable to customers is highly dependent on demographics (particularly for renewables), electric prices, and customer type (residential, commercial, or industrial), fuel (resource) availability, interconnection standards, incentive structure (state, federal, and utility), and technology status.

Customer interest and willingness to purchase DG depends on load characteristics and economic value. In several states, customer acceptance of renewables such as PV is robust, as a combination of federal and state incentives, ideal weather, and customer support of clean generation has spurred interest.

Screening methods (see Figure 4) can predict penetration limits for customer-owned DG. In Screen 1, customers whose load patterns, location, or usage preclude participation are culled from the list. Screen 2 identifies customers with suitable load and interest in DG. Screen 3 identifies the remaining subset of customers for whom DG is economically viable.

For example, studies may determine that customer suitability and interest for a specific type of DG is 50 percent and 30 percent, respectively, for Screens 1 and 2, leaving a net potential of 25 percent. The third screen is estimated using market adoption curves that predict DG penetration as a function of payback. If incentives are set to reduce customer payback to 3 years, predicted penetration is about 40 percent, with total net DG penetration about 10 percent.

Planners also must recognize that adoption rates are time-dependent; that is, penetration targets such as those cited may take many years to achieve. For example, a straight-line adoption curve of 10 years means