The utility’s role is changing, and regulation must change along with it – to spur innovation and respond to evolving customer needs. Modernizing the industry will require a dynamic approach.
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?
is to gain widespread acceptance by utilities and customers. Defendable DER valuation methods capture not just deferred T&D investments, but also avoided central generation, improved efficiency via reduced losses, and reduced Var demand. DER may be a better choice when benefits are sufficiently high to offset incentive payments, and the benefit-to-cost ratio exceeds those of traditional investments. The likelihood DER can provide a long-term solution is low, but can be valuable over the short term, typically 3 to 5 years. Extending the analysis to include indirect and difficult-to-quantify societal benefits could extend DER value beyond those cited in this article.
1. DER options include distributed generation (DG) and demand response (DR), but could include other technologies such as energy storage.
2. Utilities often accept the greater outage exposure of radial facilities when loads are low or in rural areas where long lines or absence of feeder ties do not justify the cost of redundant facilities. Some utilities set a load threshold—for example, 20 to 25 MW—above which redundant or back-up facilities are installed.
3. Physical assurance is an arrangement whereby customers agree to interrupt load in an amount equivalent to the capacity rating of the generator as a condition of receiving capacity payments from the electric utility. Isolation is performed by utility distribution control center staff, if needed, when DG is needed but off line.
4. Statistical studies that utilize historic weather data can provide equivalent availability factors; 20 percent is often cited for PV. If variable tilt with solar tracking is employed, the equivalent PV availability can increase dramatically—up to 60 percent in some regions.
5. Often, the system peak is coincident with the day and time of the feeder or substation peak.
6. For example, probability of dispatch employs loss-of-load expectation methods to estimate the value of generation at any given hour.