Technologies discussed at the workshop could shape the electric grid in coming years. Clark Gellings, EPRI, noted that integrating new and existing technologies could address the issues of prevention, recovery, and survivability. Much of this focus is on distributed generation and smart grid technologies. David Owens, Edison Electric Institute, suggested that an important issue is how to ensure reliability, safety, and fairness, particularly in light of increasing renewable portfolio standards and public policy driving much of the emphasis on distributed generation.
Mr. Owens noted that distributed generation can offer stability but will require increased coordination. Currently, utilities look at very discrete customers with distributed power sources, but moving forward there is the potential for a much wider deployment of distributed generation, which could pose a challenge for reliability and safety as power flow becomes a two-way street. Mr. Gellings recognized that such change will be inevitable—the question is not whether more connection is going to happen but how best to adapt when it does (Figure 5-1).
FIGURE 5-1 Operational evolution of the grid, showing a historical diagram of the typical grid structure from 1978 to 2001 (left) compared to the evolving grid structure incorporating microgrids (right). SOURCE: Adapted by Newport from the California Institute for Energy and Environment and presented by David Owens, Edison Electric Institute, February 27, 2013.
One audience participant asked why, if distributed generation is such a certainty, there is not currently a wider deployment of microgrids. Granger Morgan, CMU, pointed to issues with interconnections as well as evolving IEEE standards related to the issue of islanding; additional resilience is one of the benefits of a microgrid, but utilities are also concerned about safety issues with a partially activated system, according to Mr. Owens. There is also significant concern about funding and cost recovery—Mr. Owens pointed out that while there is an increased interest in improvements to the distribution system, much of the investment is falling on the utilities to ensure reliability and eliminate vulnerabilities associated with increased use of distributed generation. It is difficult to fairly account for these additional costs, many of which are coming under review by FERC and state PUCs. Mr. Owens cited net metering as one particular case that does not adequately account for the fact that a customer’s renewable generation from rooftop solar, for example, is not equivalent to power generated by the grid. John Kassakian, MIT, also pointed to renewable portfolio standards as a key cost burden being placed unfairly on utilities through public policy. Dr. Morgan noted that one policy prohibiting the existence of microgrids in some areas of the country involved exclusive service territory rules1 and suggested examining the loosening of such rules to allow modest-size microgrids.
Because of an increasing focus on distributed sources of generation, energy storage is a particular issue of concern. Patricia Hoffman, DOE, pointed to work with Southern California Edison on an 8-MW Li-ion battery-based storage plant to complement a Tehachapi Pass wind farm as an example of ongoing research in this arena, noting that the evolving grid system needs to be thought about holistically.
Much of what has enabled distributed generation is related to smart grid technologies. Anjan Bose, Washington State University, noted that smart metering allows for consideration of distributed load as well as distributed generation. Dr. Bose suggested that the data currently being collected needs to feed into control systems. Mr. Owens pointed out that legacy distribution systems will have to be redeveloped to support such bi-directional and variable power flows safely and reliably.
In addition to greater real-time control, smart grid technologies can be used to reduce load through demand response. Ms. Hoffman pointed to a number of examples of utilities that have used smart grid technologies successfully. On the customer side, Oklahoma Gas and Electric
1 K. Twaite, 2012, Monopoly money: Reaping the economic and environmental benefits of microgrids in exclusive utility service territories, Vermont Law Review 35:975-998, available at http://lawreview.vermontlaw.edu/files/2012/02/twaite.pdf.
was able to implement time-of-use and variable peak/critical peak pricing to reduce peak load by 30 percent. On the distribution side, automated circuit switches and sensor equipment implemented by the Electric Power Board of Chattanooga are estimated to have reduced customer outage minutes by 40 percent. And on the transmission side, 18 transmission owners within the Western Electricity Coordinating Council are installing and connecting 341 power management units and 62 power distribution centers to modernize transmission in the Western Interconnection. According to Ms. Hoffman, such implementation can enable a truly active distribution system that can be managed cost-effectively through a broad selection of technologies.