The U.S. utility sector stands at multiple transition points, whether in terms of integrating new energy sources and technologies or accommodating unprecedented load growth. As the utility industry faces significant change, public power is not just sitting back but is setting goals and overcoming challenges to embrace that change. This includes everything from bolstering reliability to shifting the power supply mix and revising their strategies to align with community goals.
Planning for change is not done on a whim; it requires yearslong undertakings that gather input from various stakeholders and aim to look into the future. The public power examples that follow show how achieving change is an exercise in both planning and adaptive learning. Each of these programs holds lessons for how change-minded public utilities can map and accomplish modernization goals while retaining a community-focused mission.
Increased Connectivity
The Marquette Board of Light & Power serves around 17,000 customers along the southern reaches of Lake Superior on Michigan’s Upper Peninsula. The region is known for its scenic beauty, which Timothy Kopacz, MBLP’s director of distribution, described as “an oasis in the middle of a sea of mountains and forests.”
However, this natural oasis means the utility’s system is farther from more central parts of the U.S. electric grid.
The utility had long been looking to bolster its grid reliability, particularly in terms of its substation security. The possibility of building a second interconnection was first explored in the early 1980s, and that exploration laid the groundwork for developments that would commence 35 years later.
“There are studies dating back to 1982 that proposed expansion of the existing 69-[kilovolt] system into a second interconnection that evolved into different options over the years. We explored probably half a dozen alternatives before we ended up with what we’re pursuing right now,” Kopacz said.
The Second Interconnection Project began in earnest with a 2018 study that examined where the second line could be built in ways that work with existing infrastructure. Another challenge in getting the project off the ground related to finding the funding to construct. Because the public power utility is not a network participant in the Midcontinent Independent System Operator, or MISO, the cost to build the interconnection to its transmission lines, including a new substation, would require significant investment from the utility.
The ultimate goal of Second Interconnection was to ensure continuity of power even if the utility’s own generation were to become inoperative.
“Between our gas units, our diesel-combustion turbine, and some hydropower that we have, we can handle our own internal loads so we can island from the system. But were one of our major generators to trip and we were to be without interconnection power to the grid, we wanted this second interconnection so we could handle those contingencies,” Kopacz said.
Once the work was done to map where the second interconnection could be built, the utility undertook the physical and financial planning necessary to bring the project to fruition. Among the achievements that distinguishes the Second Interconnection Project has been the careful financial planning that went into its construction, with MBLP engaging in years of prior allocations that allowed the utility to launch the project without needing to borrow funds.
“We saved money starting in 2016, building reserve funds for this project so that we could pay for it all out of cash,” Kopacz said.
One of the core goals of the Second Interconnection Project was to avoid disrupting the area’s natural beauty, which MBLP customers rated highly in feedback to the utility.
“The entire route we chose was along highway corridors. We felt that was less invasive than going across natural wooded corridors, especially in an area that’s full of outdoor recreation and outdoor enthusiasm,” Kopacz said.
The utility executed a rigorous work schedule over spring and summer 2025 that aimed to finish construction during the months when snowfall wouldn’t be an impediment. Kopacz noted the utility expects to energize by early December — bringing a new level of reliability right before the city’s coldest months.
Setting Up for Success
A new push for long-term development of Independence Power and Light in Missouri stemmed from recent deliberations at the city council over whether to sell the community-owned utility to private interests.
“In 2022, we did two independent studies. One was a cost-benefit analysis into the value selling the utility would bring and what that would look like from a city and customer perspective. The other asked that if we’re going to keep and operate this utility, what would a long-term strategic plan look like, and what would we need to initiate in order to move ourselves into being a fully modern utility?” said Joseph Hegendeffer, director of Independence Power and Light.
The studies found that retaining community ownership of the utility while investing in its modernization would provide the best returns in terms of both quality and affordability of service.
“We quickly found out that it was not going to be advantageous to either the city or the residents to sell the utility. I think most utilities that have sold themselves to an investor-owned utility quickly realized rates go up,” Hegendeffer said.
Since deciding not to sell, IPL has developed a road map with development benchmarks the utility works to meet. These were devised in partnership with DKMT Consulting, the firm that helped oversee the studies, and were focused on key service areas.
“We broke it down into three areas: technology, customer strategy, and operation strategy. Those drove toward a lot of technology improvements that would allow us to serve our customers better,” Hegendeffer said.
Many of these improvements have focused on technology implementations that simultaneously improve customer service and quality of life for the utility’s employees, including advanced metering infrastructure.
“AMI is a huge project we’re working to kick off, which will [be a] benefit not just from a customer service perspective but from an employee safety one as well — getting our people out of yards and away from potentially frustrated customers,” Hegendeffer said.
IPL’s emphasis on grid monitoring is also designed to provide returns for reliability and responsiveness, as these grid-reading capacities will allow the utility to more directly catch service issues.
“On the data side, we can better see things our system isn’t currently telling us. If you have a customer who reports their lights flickering all the time, it may not be enough to kick a breaker or kick a whole circuit off. There may just be a tree touching a line somewhere, and AMI gives you the ability to see that and provide better reliability for customers,” Hegendeffer said.
IPL developed a long-term strategic plan that extends to 2045 and includes the AMI deployment alongside the replacement of transformers and other components that will make its grid overall more reliable, secure, and amenable to load growth.
IPL’s grid modernization and strategic plan was made with an eye toward supporting the city’s economic development, another key area where being municipally owned fosters a collaborative relationship between a city and its supporting utility. Hegendeffer anticipates that IPL’s technology investments will leave the city better positioned to accommodate new businesses with load demands of their own.
“One of the first questions a company asks when they come to a city nowadays is, ‘Can you supply me the energy, especially larger loads?’ We’re not just talking data centers. It’s a concern among manufacturers as well. The cities who are set up to meet that [demand] become contract winners, and we’re trying to set ourselves up for that as well,” Hegendeffer said.
Mapping Transition
Other public power utilities have been working toward meeting clean energy goals. These goals are woven into detailed plans with annual benchmarks for generation and technology road maps for how to get there, such as implementing new solar and battery storage.
Longmont, Colorado, for example, has been partnering with three other public power utilities in the state and their joint action agency, the Platte River Power Authority, on a plan to reach a goal of 100% noncarbon electricity generation by 2030.
The strategic plan was first launched by a 2018 city council resolution that aimed to set the stage for a yearslong renewable energy road map.
“There was a lot of discussion in the 2017-2018 timeframe about decarbonization, and the city of Longmont was no exception among cities on the Front Range. So, the city council passed a resolution directing the distribution utility to move toward a 100% renewable energy goal,” said Darrell Hahn, Longmont’s electric utility director.
Around the same time, Longmont’s representatives on Platte River’s board of directors joined their municipal partners in passing a Resource Diversification Policy, directing the joint action agency’s CEO to proactively work toward a 100% noncarbon energy mix. While the plan is focused on decarbonizing as fast as possible, it emphasizes that reliability and financial sustainability must be maintained as the utility makes the energy transition.
“We’re looking at the retirement of our coal units and bringing in more wind and solar,” said Tim Blodgett, Platte River’s chief strategy officer. “To balance the intermittency of renewables, we’re adding natural gas and batteries to maintain reliability, and working with Longmont and our other owner communities to develop a virtual power plant.”
Hahn noted that the broad support Platte River has provided its member utilities has been instrumental in bringing Longmont’s strategic plan to fruition. “We are proud to be part of Platte River’s accomplishments. We have two board members of the eight that are helping steer things forward,” Hahn said.
While Platte River has made considerable strides, the utility’s current resource plan puts them closer to 85% noncarbon generation by 2030. Still, its team and board members have gained a fuller understanding of how to adapt to unforeseen economic and supply chain shifts — including how to sustain progress in the face of these developments.
“We are living in a time when new generation demands are greatly exceeding the available supply. This is driving equipment and workforce shortages, which result in higher prices and longer lead teams to install any type of new generation. As long as everybody is demanding the same solar panels, the same wind turbines, the same batteries and the same natural gas turbines, we will all encounter challenges on the pricing front,” Blodgett said.
One of the most valuable lessons Longmont learned while executing its energy transition road map was to continue to pursue its goals even if the timeline and economic landscape shift. Regular resource planning has helped both Platte River and Longmont remain agile, able to keep progressing toward increased renewable energy while also maintaining reliability and fiscal sustainability.
“We’re extremely proud of the progress we’ve made. It hasn’t come without its headwinds but we’re not quitting,” Blodgett said. “Just because we aren’t able to hit 100% noncarbon by 2030 doesn’t mean we’re giving up on the goal.”
Finding a Path Forward
In Michigan, Traverse City’s public power utility has been pursuing a decarbonization plan of its own. As Brandie Ekren, Traverse City Light & Power’s executive director explained, the utility has consistently been a frontrunner in renewables adoption.
“Our clean energy began back in 1996, when they pioneered the first utility-scale windmill in the state,” Ekren said.
Traverse City laid out a 100% renewable generation goal in 2018 that the utility has since been pursuing. Ekren has made it a priority to drive the utility’s decarbonization goals forward, and those goals have advanced considerably over the past three years.
“In 2018, the utility board set a 100% renewable goal by or before 2040. But it really wasn’t until 2022 and 2023 that we affirmed what that path forward would look like in terms of resources and investments,” Ekren said.
She noted the utility has set chronological benchmarks to measure progress.
“The interim goal was to be 40% renewable by 2025, and we’re a little over on that goal, meaning that we are probably going to be past 40% by the end of this calendar year,” Ekren said.
Traverse City fleshed out its integrated resource plan through extensive consultation with experts and local stakeholders who ensured its benchmarks were both concrete and achievable.
“When we worked on our integrated resource plan, we had a very robust stakeholder engagement process in 2022-2023 that was a combination of one-on-one meetings with commercial and industrial customers. We also took advantage of a third-party customer survey,” Ekren said.
Traverse City has focused on developing its solar resources, with the utility leveraging outside partnerships to install solar facilities as economically as possible.
“We have contractors that are overseeing larger procurement of solar panels so they can get a good economy of scale [on the] price and be able to use them on homes,” Ekren said.
These have been paired with expansion in the utility’s wind-power purchases, with the utility purchasing from the nearby Stoney Corners Wind Farm, which is managed by investor-owned utility DTE Energy.
Ekren tied the utility’s energy transition efforts back to its community-focused mission and respect for its customers, with its strategic road map designed to advance all of them.
“One of the things that’s ingrained in the culture up here in northwestern Michigan is the appreciation for the natural beauty and the environment that we live in. It really is cultural, being able to preserve the natural resources that we have around us and being able to ensure there’s clean air regardless of where you are on the economic scale. Those are inherently important to us,” she said.
