Distributed Energy Resource Saturation: Page 6 of 7

Smart inverters. On utility-scale projects, dedicated substations provide a secure, reliable means for utility visibility, control and curtailment of PV systems. This is not the case on smaller DER systems because they typically do not connect through a substation. As a result, IOUs have no visibility into the quality or quantity of power those DER systems are producing. At a basic level, an IOU cannot even confirm whether the system is producing power at all. Smart inverters can help bridge the gap and allow IOUs some basic functional control of and visibility into DER systems.

Seizing on this opportunity, in 2013 the CPUC, IOUs and solar industry stakeholders convened a working group to explore the role that smart inverters can play in easing grid congestion. In a June 2016 Solar Builder article (see Resources), Brian Lydic, senior standards and technology engineer at Fronius USA, explains: “Seeing the need for not only frequency tolerance but grid-supportive functions in general, the California Public Utilities Commission and the California Energy Commission convened the Smart Inverter Working Group (SIWG) in early 2013 to start developing recommendations of technical requirements for inverter-based DER in California.”

A recent result of the SIWG is the implementation of UL 1741 Supplement A (SA). This supplement is a step toward allowing IOUs the visibility and control they need to handle high levels of DER penetration. Beginning on September 8, 2017, all California IOUs will require the design of new Rule 21 solar applications around inverters certified to UL 1741 SA. This supplement specifies an enhanced testing protocol that UL describes as an “advanced inverter grid support utility-interactive test plan” that addresses anti-islanding (with advanced features active during test), low- and high-voltage ride through, low- and high-frequency ride through, a must-trip test, ramp rate (normal and soft start), specified power factor, volt and VAR modes, and optional tests including frequency watt and volt watt. These functions have the potential to turn highly congested areas of DER from a burden to a blessing.

Additional controllability is theoretically a great asset in the context of managing overall grid congestion, but the reality is that changing operational parameters will result in lower returns on investment. The CPUC needs to explore how and when to compensate customers for grid support functionality. Lydic concludes, “In general, any of these changes will allow for higher-penetration levels and thus benefit the PV industry, but care must be taken that revenues are not unduly affected.”

Security is another area of concern, especially with regard to communication and control protocols. Tying inverters or any portion of a DER system into the utility SCADA system immediately opens a channel for hacking and potential security breaches. A safe, reliable communication system can help mitigate these risks. Any smart inverter certification program must specify a simple, widely implementable communication protocol. Ideally, the circumstances that activate grid-stability functions (and possibly reduce production) in San Diego will be the same as those in Sacramento. The CPUC should clearly define how IOUs exercise smart inverter functions and ensure consistent implementation of these standards throughout California.

Energy storage systems. As shown in Figure 3 (p. 30), increased solar generation capacity is changing California’s daily power production curve. A 2013 California Independent System Operator (CAISO) report first identified the duck curve. This term describes the shape of the daily power production curve due to periods of significantly lower electrical demand in the middle of the day followed by a steep ramp-up in the afternoon and early evening. This profile stands in stark contrast to the traditional two-peak bell curve model of power consumption, where power peaks during the midday hours, drops a little and then ramps back up during the early evening.

A side effect of identifying the duck curve is that IOUs are asking the CPUC for a change in the time of use (TOU) periods, allowing them to charge more for energy during the ramp-up period in the late afternoon rather than in the middle of the day. This change in TOU periods will result in a significant reduction in the value of power for NEM customers, but will help IOUs reduce peak afternoon demand.

Energy storage is another way for utilities to flatten the duck curve. Storage can both pull up the trough of the curve (the duck’s back) and push down the peak of the curve (the duck’s tail). It is possible to deploy both large-scale and distributed-scale energy storage to address California’s duck curve. On a large scale, for example, the utility could divert excess solar generation into utility-scale energy storage systems at the substation or subtransmission level. These front-of-meter storage assets can reduce the overall impact of DER backfeeding onto the transmission network and allow IOUs to store reserves for use during the late afternoon or early evening ramp-up periods. A complementary option is to use smaller-scale energy storage systems at the customer level. Solar-plus-storage systems are a perfect fit for these behind-the-meter applications.

Advances in power system analyses, such as the ICA tool, are going to prove crucial for identifying the best areas in which to apply distributed energy storage resources. An IOU could install a large battery bank, for example, and then incentivize solar development in that area. Essentially, the IOU would be creating a giant energy storage reservoir and asking the solar industry to help fill it. The overall effect would be greater solar development and a smoother, more stable load profile, creating a win-win scenario for IOUs and solar developers alike.

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