“Times have changed.”

It’s a sentiment Tolu Omotoso, NRECA’s director of energy solutions, has felt often over the past decade or so. But a confluence of developments in behind-the-meter technologies and energy industry software have opened a promising opportunity for electric cooperatives that could be a major boost for demand response, load control, renewables integration and reliability.

Often called “virtual power plants,” the technology uses advanced software called DERMS (distributed energy resource management system) to monitor, analyze and dispatch member devices like rooftop solar, grid-connectable water heaters, battery storage, home back-up generators, smart thermostats and advanced electric vehicle chargers.

Utilities can use this real-time access and control to help with voltage regulation and frequency control, shave demand peaks, add power to the grid when needed and ride through outages.

Industry observers caution that while DERMS and VPP networks can offer greater integration of renewables and enhanced grid flexibility at the distribution level, the technologies involved are not fully mature and the challenges of scaling, reliability and stability are too great for these platforms to be suitable replacements for traditional always-available generation.

“VPP is still kind of an elusive term that everybody’s trying to figure out what it actually means and where that rubber meets the road,” says Scott Hammond, director of member programs at Central Electric Power Cooperative Inc. in Columbia, South Carolina. “It will become more and more valuable as time goes along. It’s not a situation where it will eliminate the need for new generation, but it could reduce how much is needed.”

CEPCI built its own DERMS platform called Demand Side Tools. The generation and transmission co-op began with software applications that interface with controls for thermostats. The system now involves about 3,600 smart thermostats from 11 member co-ops, which can provide up to 4.6 megawatts per event.

Arizona Electric Power Cooperative and Old Dominion Electric Cooperative both license the DST system as well.

“A lot of other G&Ts, distribution co-ops and munis have inquired about using it,” says Hammond.

And with increased access to broadband, elevated concerns about outages and decreasing prices and government incentives for new energy technologies, members are choosing to take more control of their electricity use.

“Electric cooperative members want more,” says Omotoso. “People have bought these behind-the-meter assets, and they are increasing in number every day.”

Shifting energy landscape

The Department of Energy defines VPPs as “aggregations of distributed energy resources (DERs) that can balance electricity demand and supply and provide utility-scale and utility-grade grid services as an alternative or supplement to centralized resources.”

In addition to rooftop solar, EVs, batteries and water heaters, DERs include smart buildings and flexible commercial and industrial loads.

“A variety of change is occurring in the electricity industry, including rapid growth in distributed renewable energy, load growth through electrification, decarbonization initiatives, cyber/physical attacks and natural disasters,” says Venkat Banunarayanan, NRECA vice president for integrated grid. “As power supply and demand become more distributed, weather-dependent, intermittent and less predictable, VPPs using DERMS will become an important tool in the toolbox of the grid operator for continuing to maintain a cost-effective, reliable and resilient supply of electricity.”

Omotoso notes that NRECA’s Business & Technology Strategies group recently published a report, Energy Transition Behind the Meter: DERs, DERMS & VPPs, that explains the ongoing shift in the energy landscape.

Regulatory threats to reliability and resiliency are another factor for pursuing DERMS or VPPs. DOE forecasts that the U.S. electric grid will need more than 200 gigawatts of new capacity between 2023 and 2030 to meet peak demand as some 140 GWs from retiring fossil-fuel plants goes offline.

“As regulatory pressure is placed on central-station fossil assets, it becomes more critical to be able to turn to options like DER resources managed cost-effectively through automation,” says Scott Drake, director of business and technical services at East Kentucky Power Cooperative. “We’re in the process of learning more about how those resources operate.”

Drake sees the terms DERMS and VPP as interchangeable for managing DER, “with clear visibility to the DER resources between the generation and transmission cooperative and the distribution co-ops and optimizing them through automation.”

The Winchester-based G&T has a demand response management system (DRMS) to reduce load by operating thermostats and control switches but is upgrading to a DERMS that can inject power into the grid and optimize thousands of DERs to the benefit of EKPC and its member systems.

“DERMS gives the G&T the ability to manage these distributed resources in a similar way we manage central resources today,” Drake says.

In addition to helping shave peak and reduce power purchases or capital expenditures, DERMS “gives our distribution system visibility into how we’re operating those assets and not causing problems on their system,” he says.

To convert to a DERMS, EKPC and Jackson Energy Cooperative are seeking funding for two microgrids from the Infrastructure Investment and Jobs Act through an NRECA-led consortium application.

Equipped with batteries and solar power, the microgrids will help keep critical services running in two small, disadvantaged communities during a natural disaster or other unplanned outage.

“That starts our learning curve of how to manage those assets,” Drake says, noting that that DERMS leader North Carolina’s Electric Cooperatives has helped move co-ops forward by sharing its experience of operating several microgrids over the past few years.

“Traditionally, among co-ops nationwide, a few blaze the trail then they share those lessons and help others.”

Drake anticipates a time when DER could substantially meet demand while utilities remain responsible for balancing the grid.

“Five years, 10 years down the road, we as a nation could become more dependent on DERs to help us cost-effectively balance the grid during the ‘duck curve,’” he says, referencing the phenomenon where the need for baseload generation in solar-heavy regions approaches zero during daylight hours and rapidly increases during evening peaks when the sun goes down.

“We’ve got to learn and be able to manage that situation. The expectation of our end-use members is that even though the delivery of energy is going to be challenged, reliability is always going to be the utility’s responsibility.”

'Ensure it's bringing value'

Hammond says Central plans to expand its DERMS to include residential battery systems and microgrids and monitoring and controlling them as real-time energy and storage resources.

“A lot of it is still based around doing demand response, just using new and probably more data-intensive equipment, whether it be smart thermostats, batteries and EVs,” he says. “It’s a progression over time. We’ve been very deliberate about how we’re building out our software solutions such that we don’t get too far ahead of what our members’ needs are.”

Hammond has some key suggestions for those contemplating a DERMS:

  • Determine your needs and how your members will benefit before investing.
  • Look for flexibility in a system that will grow as more DERs and new smart devices come online.
  • Educate your members on the benefits of working with the cooperative to install DERMS so they are prepared to make an informed decision if third-party developers offer additional choices in your service territory.

“We structure our programs here to incentivize our co-ops and their members based off of what makes sense from an integrated resource planning perspective and to ensure it’s bringing value to the system,” he says.

For one Colorado distribution co-op, the proverbial lightbulb went off in 2019 when an unplanned outage hit a pilot project for affordable all-electric houses.

Four houses that Holy Cross Energy had outfitted with DER and bidirectional meters never went dark.

The homes had 8-kilowatt rooftop solar systems, smart inverters, EV charger hookups, water heaters and smart appliances. Member rebates and other incentives were included.

“The fact that the members in the Basalt Vista program still had service during this unplanned outage helped us really understand where the opportunity space was,” says Bryan Hannegan, CEO of the Glenwood Springs-based co-op.

“How can these DER provide us with the balancing and the grid services that we need to run a reliable grid on the blue-sky days when everything’s going well?”

Today, HCE’s voluntary “Power Plus” program has over 3 MW of battery capacity, which is about 2% of the co-op’s summer peak.

Its community energy systems team raises awareness of the co-op’s services at county offices, municipalities and with developers to “help folks meet whatever their energy goals are,” says Jenna Weatherred, vice president of member and community relations. At the moment, they’re working with 48 developments, including housing, school districts and a health facility.

At its core, the program “helps members understand that, if they want to, they can put their home or their business in the service of making the grid more reliable,” Hannegan says. “They can be part of our fleet that helps us keep the lights on for everybody else. I don’t know of anything that’s more co-op than that.”

Holy Cross Energy believes its path to a mutually beneficial relationship with its members through DERMS is not unique.

“If I’m looking for a little extra bit of power, would I rather buy it from the wholesale market, or would I rather buy it from my co-op members who are my owners?” says Hannegan. “Gone are the days when the utility was the only game in town for providing electricity to a member. The member can now generate their own electricity, and moreover, they can provide it back to us. And we have to adjust our relationship with our members to reflect that.”