Powering Strong Communities

Making New Connections: Incorporating and Preparing for Distributed Energy Resources

An increasing array of energy technology is making the electric system less predictable — both in terms of what utility operations staff can expect to see with regard to energy being generated on the system and in how it is getting used.

Whether in managing variable assets the utility owns, such as community solar developments, or understanding customer-sited assets, from solar panels to storage units and even electric vehicle batteries, public power utilities are taking important steps to better understanding and preparing to manage a complex set of distributed energy resources.

Passing Along Expertise

American Municipal Power, Inc., a joint action organization serving 134 utilities across nine states, looks at how distributed generation and other resources can help its members both in terms of direct operating benefits and in building customer relationships.

Willey Sandell, vice president of generation operations and development, noted how for AMP and its members within the PJM market territory, installing behind-the-meter generation and resources can provide significant savings and help to counter rising capacity and transmission costs. AMP has about 60 megawatts of solar capacity, over 200 MW of natural gas combustion turbines, and another 80 MW of small reciprocating diesel generators that help with peak shaving. Sandell said these assets also can be isolated to support overall reliability for the system or for specific areas that otherwise would experience an outage.

Sandell noted how despite many DERs being newer technologies, utilities and organizations like AMP have been exploring and working to understand these technologies from their onset, making them experts on the technologies. And that experience can be transferrable to utility customers with questions about DERs.

“We want to make sure our members are prepared and are at the table to ensure the DERs deployed benefit the customer and community,” said Erin Miller, AMP’s assistant vice president of energy policy and sustainability.

As costs for DERs and behind-the-meter assets have come down, Miller noted that interest in the technologies has gone up. AMP has developed sample interconnection agreements, applications, and materials for its members to develop behind-the-meter rooftop solar policies to help members bring these assets into the utility’s fold. It has also created guides for members to share with customers on asking the important questions about the real costs and considerations that need to go into deployment, such as how installing rooftop solar might affect a home’s roof warranty. This type of support helps member utilities to serve as a resource to their customers.

Beyond helping with customer relationships, providing this kind of guidance to utilities helps to make sure they're at the table “so that they know what's happening on their distribution system for the safety of their lineworkers, and the reliability of the system,” added Miller.

Building for the Future

Laura Duncan, manager of origination and renewable support at the Tennessee Valley Authority, sees the work that utilities and TVA are doing now around tracking and encouraging distributed energy resources as helping set the foundation for the grid of tomorrow. She sees the role for TVA and utilities changing to become more of partners, or trusted energy advisers, to a growing array of customers and stakeholders. 

Duncan said that “proactive engagement is the key” to managing and monitoring adoption of DERs. This includes having conversations and forming partnerships with utilities, business customers, solar installers, and others who have an interest in DERs. Duncan has been supporting TVA’s Green Connect program, which helps local utilities and businesses to invest in DERs, mostly small-scale solar. Since launching in 2021, the program has helped customers install nearly 200 systems with a collective capacity of about 1.5 MWs.

For Duncan and TVA, advising on and managing DERs comes back to the fundamentals of the public power model, which is “driven by the public benefit, doing what’s best for our communities in the areas we serve,” said Duncan. That includes being able to attract and support businesses in meeting their sustainability goals, with an eye on how to keep energy costs low for the region, and adequately supporting customer choice.

That means being part of conversations that influence where DERs get installed, so that they can support the grid and offer value to the grid and the customer. The other side is for utilities to make sure that interconnection technology and procedures are in place.

“We really need to be working together to identify which technologies are most critical and how we’re going to manage those technologies,” said Duncan.   

TVA has its regional grid transformation initiative, which is working with the 153 local power companies across the region to identify when new system capabilities and technologies can be introduced, and then how each area can do so in a strategic, cost-effective way. The initiative, like TVA’s green programs, rely on ongoing communication and bringing a variety of players to the table to ensure everyone’s perspective is heard.

“It’s not like everyone’s coming together in agreement saying these are all the great benefits from day one,” noted Duncan. “It’s really that working through it together, building trust.”

Preparing for Electrification

Lincoln Electric System in Nebraska wanted to stay ahead of the curve and understand how electric vehicle drivers in its territory charged, and to what extent utility actions and communication could affect charging during expected periods of peak demand.

Getting to this data started with examining EV charging habits beginning in 2019. That involved putting a module into the car’s diagnostic port that could track when and where the car charged. To recruit for the study, explained Scott Benson, manager of resource and transmission planning, LES hosted a breakfast for owners of both battery electric vehicles and plug-in hybrid vehicles in the area to talk about the study and ask attendees to spread the word to other EV drivers they knew. LES also trained its board and staff to recognize different EV models that might be in the area and gave them copies of an informational card about the study to give to drivers or put in car windows. The effort led to getting about 90 participants in the study, which Benson estimated represented about one-third of the EV drivers in the area at the time.

From there, LES asked study participants about participating in a demand response pilot in 2021. The pilot consisted of LES sending participants an email and text about 24 hours before an expected peak load period, asking them to refrain from charging during the predicted peak window. Drivers could receive a $10 credit on their bill if they did not charge during all of the peak windows in a month. All of the study participants who were still active and within the service territory — about 70% of the original study participants — participated in the pilot. 

The pilot mostly looked at summer weekday evenings, June through September, when the public power utility typically sees its highest peaks, but also during its winter peaks in mornings and evenings in January and February. Benson said there were about five events in a given month, and that most of the participants refrained from charging during about four out of the five events. The average compliance across all 30 individual peak events was 88%. 

Benson stressed that changing up EV charging is different than asking people to reduce usage of air conditioning systems, as the load is neither constant nor directly driven by the weather.

“On a 100-degree day, the one thing you know, everybody’s air conditioner is going to be on probably for the whole two-hour window, unless you do something about it. This is not the same,” said Benson. Most drivers in the area, he mentioned, will charge every two or three days and can easily move up or bump back charging if there is an identified need.

In the LES service territory, Benson said, area drivers do more than 90% of charging at home, and usually this charging occurs in the evening when EV owners return from work. As such, there wasn’t a noticeable difference in charging behavior for the winter morning peaks, but the number of vehicles charging during both the summer and winter evening peaks did decrease.

Benson said the pilot wasn’t about getting a payoff in terms of peak reduction at this scale, but it can translate to savings if the findings are representative of charging behavior and norms for when adoption is much higher. “When we call an event, if only 10–15% are going to be charging anyways, but if you have tens of thousands, that makes a difference,” he said. The findings could also help the utility to avoid overload at the feeder or distribution level, if there was a recognized cluster of EV owners in a specific neighborhood or area. LES found that the average instantaneous charging demand for at-home charging for all-electric models seen in its territory is about 8 kilowatts, and about 4 kWs for plug-in hybrids.

However, Benson did note that the study participants, who consist of early adopters, likely are already more tuned into the utility’s resource needs and the importance of conserving energy.

“If you project going forward and want to do this with a lot of your customers when EVs aren’t special … you’re going to need some kind of incentive,” said Benson.

He noted that having the module plug into the car is not ideal at greater scale and would prefer a system where the utility could interact with a home charger over Wi-Fi. Such a system would be more akin to demand response programs that interact with water heaters, for example, as people who have signed up for the program could authorize LES to instruct any connected chargers not to charge during peaks, instead of having to solely rely on people to remember not to plug in during those peaks.