The Stowe Electric Department in Vermont used a Demonstration of Energy & Efficiency Developments grant from the American Public Power Association to develop a framework for small rural utilities to evaluate the integration of microgrids into their grids.
Stowe said the DEED project allowed the utility to explore the best practices for small public power utilities to use existing talent to consider adding resilient renewable power systems without relying on consultants and merchant operators.
“We used the energyshed concept to inform our microgrid feasibility study to look at the potential to install a renewable or net-zero microgrid,” according to the DEED report that Stowe Electric Department filed.
The energyshed concept, which is similar to the concept of a watershed, was developed by the Department of Energy as a tool for helping communities understand the effects and benefits of consuming energy that they generate locally.
In November 2022, the DOE selected three projects to develop the energyshed concept including the University of Vermont, which was awarded $4.3 million to develop a tool to provide local decision makers with information on the economic, health, environmental, and other impacts of various energy decisions. After refining the models, this tool will be made available for use across the country.
“Energyshed is a valuable concept to communicate with customers, staff, and stakeholders about energy and power supply,” Michael Lazorchak, regulatory affairs manager at Stowe Electric Department, said. The energyshed concept helped the town’s energy committee “visualize our power supply and flow of electricity within Vermont’s system, he said, adding, “the concept has also helped us communicate with college interns and local customers.”
The study examined several microgrid options – a substation microgrid, a feeder microgrid, a partial feeder microgrid, a critical load customer microgrid, a campus microgrid, and a life and safety customer nanogrid – and found many of the alternatives were not economically feasible for Stowe, in part, because traditional options were financially more efficient.
Stowe initially focused on a feeder level microgrid for resiliency that would only use the utility’s single generation asset, a 1-megawatt solar array. “It quickly became apparent that this wasn’t a feasible option for a number of reasons,” Lazorchak said.
Among other things, the study found that a feeder level microgrid would create an unnecessary level of redundancy because there were insufficient generation resources interconnected to the substation to provide a meaningful amount of backup generation. In addition, the study noted there was no automated ability to switch loads between the feeders or between substations.
Even assuming there was sufficient generation interconnected and automated controls, the report noted that “Stowe does not have a suitable location or the community appetite to site a feeder scale battery storage system sufficient in size to assist with resiliency, arbitrage, or transmission system winter load shedding calls.” The utility is looking to incorporate a utility scale battery storage system in a future substation upgrade to ease siting and permitting hurdles.
The DEED study, budgeted at $62,650, also examined critical governmental and emergency management loads and the campus scale microgrid and found them more favorable.
The study noted that most of Stowe’s critical emergency loads already have backup diesel generators that are not near the end of their life span, making replacing them with a combined photovoltaic-plus-battery storage system less economically feasible. However, for critical loads that have backup generation that is close to its estimated lifespan, a microgrid could be “a perfect fit,” Lazorchak said.
Similarly, a utility-owned microgrid could be paired with a community carbon-free resource to build a community asset that can contribute to decarbonization and resiliency, the report found.
Many of the more technologically advanced options examined were not economically feasible for Stowe, in part, because traditional options were more financially efficient, the DEED study found. “We think this lesson holds true for most small public power utilities,” the report’s authors said.
Stowe Electric Department has “several miles of off-road lines and no Supervisory Control and Data Acquisition system, so the traditional vegetation management and line hardening projects appear to be the most effective at developing a more resilient system,” Lazorchak said.
Some small public power utilities may fear they are missing out on the funding available for resiliency projects such as grid modernization, battery storage paired with solar, load curtailment, and other emerging technologies, the report said. “These are all great options, but it’s a bit overwhelming for a small public power utility,” Lazorchak said. “I know it’s not flashy, but traditional vegetation management, hazard tree mitigation, AMI, pole replacement, and line hardening projects are valuable and should not be overlooked for grid 2.0 type projects.”
“Stowe hopes that this study will at least put smaller utilities on the pathway to consider the energyshed concept in their power supply planning, whether microgrids with fossil fuel backup can be replaced with carbon-free based systems with grid-forming or grid-following inverters to maximize the benefit to the local distribution system, and how a combination of traditional utility operations and maintenance can be most effectively merged into the grid of the future,” the report’s authors said.
