A new study conducted for Austin Energy has some insights that will likely interest utilities examining how distributed energy resources (DERs) are expected to arrive in their service areas, how they might be managed, and what the implications might be for their business cases. Austin Energy is the distribution utility for the city of Austin, Texas.
SHINES, the Sustainable and Holistic Integration of Energy Storage and Solar PV, is a project funded by grants from the U.S. Department of Energy, the Texas Commission for Environmental Quality and Austin Energy. The project studied data from and modelled the business case for a relatively complex distributed energy situation in the city, comprising two utility components, each with battery storage, a community solar array and a neighborhood development with rooftop solar; a commercial component with three energy storage installations under an aggregator; and a residential component with 25 residences, partly under an aggregator and partly not, with a mix of solar and solar plus storage. Some elements were under direct utility control and some not. Altogether the customer configuration represents a fairly complex picture overall, but one that may well be indicative of the variable ways in which DERs can be expected to enter the picture in the future of any given utility.
A notable conclusion that the modelling exercise reached was that, even with the range of values DERs could provide the grid, in the case of Austin there was not much of a financial business case, from the perspective of the utility, for installing system controls for solar and battery DERs. SHINES committed to the DOE to demonstrate two firm economic metrics for DER and DER integration. The first is to meet a 14 cent levelized cost of energy produced by local solar, stored within an energy storage system and dispatched back onto the grid. The second metric is to demonstrate the potential for DER managed by an integrated optimization platform, DERMS, to realize a 20% cost benefit relative to the baseline cost of the same level of DER deployed without optimization and integration. In the case of Austin Energy, its studies indicate that system behaviour is not likely to be affected by DER penetration below 40%, whereas currently penetration levels there are only around 6%. The utility’s business case still benefits most from conventional demand response and efficiency measures.
However, that is not the only perspective the study found worthy of consideration. Continuing to assess options from the utility perspective, it found that DER power quality would provide appreciable system benefits from improved system integration measures, allowing stacking of system attributes like reactive power: “Existing solutions to provide reactive power control are effective but often do not provide the same optionality provided by DERs. Utilities commonly use substation load tap changers (LTCs) and deploy capacitor banks as the main methods of reactive power support due to low cost, but DERs have the potential to supply or consume VARs with smaller resolution and faster reaction time. For areas experiencing increased distributed generation by intermittent renewable energy resources, deploying DERs with quick reactive power control becomes increasingly valuable.”
As well, from the customer perspective, customers could see considerable benefit from better battery utilization during peak demand events. The graph shows how the current control system left customer-owned and neighbourhood battery storage during a typical peak demand event, having been drained to 6% earlier in the morning (red line), precisely at the moment when peak demand and prices hit their maximum and batteries would have provided maximum value to customers.
In short, full consideration of the value of more sophisticated integration of DERs means assessing results from the perspective of everyone involved: the utility, the customer and any DER integrators; from the perspective of the full range of values – economic, power quality, reliability, environmental and more; and bearing in mind what values can be realized within the given market structure.
As the study observes:
Economic modeling has revealed that to realize a positive differential value of DER from a control perspective, some combination of the following would need to occur.
• Additional market opportunities that require sophisticated controls, such as fast frequency response, would need to become available in the ERCOT.
• Market prices would need to rise and/or become more volatile.
• Reliability issues would need to start occurring on Austin Energy’s system, likely due to higher renewable penetration, and the values of various reliability services would need to be quantified.
• The costs of communicating with smaller DER assets behind the meter would need to be reduced.
• Additional DER types, such as electric vehicles and load control, would need to be integrated at larger scales to realize the benefits of value stacking through asset diversity.
In summary, the concept of holistic control and value stacking is appealing, but it is not easily realized given current conditions. Austin Energy is best suited to engage in “readying” activities such as streamlining control system architecture, developing integrations for additional DER types, and developing tools to monitor key trigger points rather than engaging in wider-scale deployment of DERs at the current time.