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?
The role of distributed energy resources (DER) in electric-utility planning continues to foster robust debate. 1 Despite best efforts, utility planners and policy analysts often are stymied or unable to reach consensus in attempts to capture the range of values that DER might provide as an alternative to traditional utility solutions.
Driven by public-policy initiatives, utilities are responding to recent mandates to integrate nontraditional resources into their distribution systems. In several states, renewable portfolio standards (RPS), and incentives—tax and end-user direct—are driving photovoltaic (PV) and wind-system growth. California has a 33 percent RPS goal by 2020 and its related Solar Initiative has a PV goal of 3,000 MW by 2017; investor-owned utilities have a mandate to achieve 5 percent of peak supply via demand response by 2007. Utilities throughout the United States are making large investments over the next several years in distribution. To manage a budget that could reach several billion dollars within years, utilities will make hard tradeoffs regarding which investments offer greatest value. Specifically, utilities will need to use innovative methods to quantify DER value when integrated into the electric-utility distribution grid.
Role of DER in Electric Utility Planning
Utilities are being asked to view non-traditional technologies such as distributed generation (DG) and demand response (DR) from a fresh perspective, including redefining the role of DER when considering distribution capacity additions. In so doing, utility planners should consider the extent to which DER is an opportunity to meet load growth; i.e. , the level of capacity that should be viewed as “firm.” Second, new analytics are needed to compare nontraditional resources (DG and DR) as viable alternatives, technically and economically, with traditional distribution investments.
The costs of traditional transmission and distribution (T&D) options include up-front investment costs, such as new feeders or substations. In contrast, DER costs could include incentive payments, typically to customers who install DG or participate in DR programs. DG also could represent a direct cost to the utility if it owns the device. DER typically is added in smaller increments, with costs accruing continuously over the planning interval.
Traditional T&D benefits include the avoided risk of outages that might otherwise occur absent the upgrade. The relative value of the T&D option versus other solutions can be derived by dividing the net present value benefit achieved by avoided outage risk by cost; projects with the highest benefit-to-cost ratio are deemed the best choices.
Traditional Capacity Planning
Utilities add distribution capacity when normal or post-contingency loadings reach capacity limits. Where backup support does not exist, such as a single transformer substation without feeder ties, capacity is added when loads are expected to exceed normal ratings. 2 Beyond 10 to 20 percent overload, the potential that equipment emergency ratings will be exceeded