Distributed energy resources (DERs) like household solar and battery storage
could provide enormous support to large and small electric systems that are now threatened by rising penetration of these technologies. DERs bring new capabilities and value. But, here’s the problem. Few jurisdictions facilitate distributed energy participation in grid markets to promote grid reliability and power quality.
California is just now testing the waters. In June, the California Independent System Operator (CAISO) proposed a new class of participants who can bid into the state’s energy markets. Called distributed energy resource providers (DERPs), these organizations can aggregate DERs and dispatch them to serve the grid, just like utility-scale generation resources. Also, at the end of August, California’s distribution utilities submitted Distribution Resource Plans (DRPs) to enable greater use of DERs.
New York and Texas have been working on related but quite different initiatives, with New York examining new business models to provide integrated distributed energy solutions and Texas looking at ways to support DER participation in the state’s wholesale market using multiple channels. Retail energy providers in Texas may also step up to provide retail DER solutions.
Capabilities are growing to aggregate DERs and provide capacity and energy value into wholesale and retail markets. In so doing, aggregators aim to smash the biggest of the big-picture barriers to DER deployment. Why? Because DERs will increasingly take up a larger share of new generation additions and reduce distribution costs as well. Based on historic growth, the Solar Energy Industry Association forecasts that solar installations will likely account for half of all new capacity installed each year in the U.S. between now and the year 2020. And, since much DER generation is variable, it impacts the local electricity grid enough to have utilities crying “uncle.”
So, for now, a few big barriers to fully leveraging distributed energy resources include:
Lack of consideration: Very few state utility commissions are evaluating the role behind-the-meter energy resources can play in helping utilities defer infrastructure investments. Little thought is being given to DER integration in resource planning and rate-recovery mechanisms.
Lack of pay-back: When a DER or fleet of DERs provides services at multiple levels of the electricity grid – transmission and distribution levels as well as behind-the-meter – how do utilities get rate recovery for coordinating these services? They don’t. “The Economics of Battery Energy Storage,” a recent report by the Rocky Mountain Institute (RMI) noted, “Under prevailing ISO/RTO rules, a utility would not be allowed to use a fleet of batteries to participate in the wholesale electricity market while simultaneously providing distribution upgrade deferral services and collecting cost-of service recovery payments. Furthermore, most utilities are not incentivized to invest in energy storage systems that provide multiple services, as only part of the investment can be rate-based under prevailing regulations.”
IEEE 1547: Many jurisdictions use IEEE 1547 as the basis for interconnection requirements. This standard can trip off devices in the event of even minor grid frequency fluctuations. California is now mandating smart inverters, which provide frequency ride-through and other dynamic grid support. Because the inverters can be controlled by an optimization platform like Enbala’s they could facilitate DER participation in providing a variety of ancillary grid services.
The RMI paper noted earlier isn’t intended to delve deeply into regulatory issues, but it offers some great ideas. It advises regulators to eliminate barriers preventing behind-the-meter resources from providing multiple, stacked services to the grid and consider DER as an alternative to wires and centralized generation investments. It’s worth a read. You can find it on the RMI site by following this link.