How Digital Tools Are Strengthening Reliability and Resilience Across the Tennessee Valley

When Mathew Stinnett, Director of Operations at Knoxville Utilities Board, talks about how far KUB has come, he thinks about the processes that came before him. “We were managing paper orders during the Blizzard of ’93,” he said. Today, KUB’s operators can see trouble on the system — often before a single customer picks up the phone to call it in.

That kind of transformation is playing out across the Tennessee Valley. Local power companies of all sizes are investing in digital tools that don’t just strengthen the physical grid, but also change what operators can see, what they can do, and how fast they can respond when things go wrong.

From advanced distribution management platforms to automated smart switches and emerging tools like drone-based vegetation analysis and AI-enabled infrastructure inspection, the range of technologies now available reflects a broader shift: resilience increasingly depends not just on stronger equipment, but on better information and faster response.

Building the Foundation

For decades, reliability investments focused on physical measures like stronger construction standards, vegetation management, and targeted undergrounding. Those strategies remain essential. But they are now complemented by digital platforms that help utilities understand system conditions in real time and plan more strategically for the future.

Modern Advanced Distribution Management Systems (ADMS) integrate SCADA, outage response, feeder reconfiguration, and automation into unified control-room platforms. GIS modernization ensures utilities have accurate connectivity models of their systems. Enterprise asset and mobile workforce platforms help coordinate restoration during major events.

Beyond those foundational systems, utilities across the Valley are beginning to layer in emerging technologies, including AI-enabled cameras that can detect pole damage or infrastructure risks during inspections; drone-based vegetation analysis programs that help crews identify hazards along rights-of-way more safely than traditional inspections; and distributed energy resource programs that create new opportunities to manage load and improve operational flexibility.

Taken together, these tools represent the breadth of what’s available, from field inspections to customer-side resources, all aimed at strengthening reliability and reducing risk. But the utilities that are seeing the most impact aren’t just collecting tools. They’re integrating them.*

From Substation to Customer: EPB’s Automation Story

Few Valley utilities have leaned into distribution automation as long or as deeply as EPB of Chattanooga. Beginning around 2009, EPB deployed approximately 1,200 automated switches across its distribution system, allowing the system to detect faults, isolate affected sections, and restore power to unaffected customers automatically, often within seconds.

But the impact goes well beyond faster outage response. Ryan Keel, President of Energy and Communications at EPB, described what automation has meant for how his team actually sees and understands the system.

“For decades, EPB had SCADA, which gives us visibility, information, and control at the substation level,” Keel said. “Now we have basically that same level of information all the way out to the end of the distribution circuit for all of our distribution circuits. We can see current levels, load levels, voltage levels, and we have more devices we can operate far deeper into the system. All of that information comes back to our operators. We just have so much more information further down into the system, closer to the customer.”

That visibility doesn’t just help during an outage, it improves planning as well. When you can feed measured, known values from automated devices into your distribution planning model, Keel explained, you replace assumptions with real data. “You know more instead of having to calculate more,” he said. “You get a better model of the system.”

As for the cost question — the one every LPC leader eventually has to answer — Keel was direct. “For the amount of customer interruption minutes you can avoid or eliminate, automation is one of the best investments utilities can make in terms of cost versus benefit,” he said. “Compared to things like undergrounding, which is part of what we do too, the CMI savings per dollar from automation just perform at a different level.”

The benefits, he added, extend well beyond reliability metrics. EPB’s fiber-enabled automation infrastructure has supported broader community outcomes that are central to the utility’s mission. “Our mission is to enhance the quality of life for our community,” Keel said. “Electric service is one way we do that. But this technology has given Chattanooga a competitive advantage in economic development and reputation, too. You get a lot of benefit when you’re using technology to try to make things better for your customers.”

Seeing the Whole System: KUB’s Integrated Approach

At KUB, the journey from paper orders to a fully integrated digital platform has been a three-decade evolution.

“We went from managing paper orders in the Blizzard of ’93 to getting an outage management system on top of SCADA. Then, AMI in 2015 and 2016, that gave us a lot more visibility into the actual status of our customers and our system,” Stinnett said. “Having reliable, high-speed communication opened the door to a lot more downline technologies, all the way from the feeder down to the customer.”

That visibility shift has been fundamental. In the past, Stinnett explained, KUB had strong visibility and control inside the substation fence, but once a problem moved downstream, things got murky fast. “Now we’re able to see further downline and respond much more quickly. I know that meters down beyond a certain point are reporting out, which means I know exactly where my trouble is. That’s very different from starting at the feeder and working your way down by brute force.”

KUB’s ADMS serves as the central hub for incident response across its electric, gas, water, and wastewater utilities. On the electric system, the ADMS tracks all active trouble work, queues up crew prioritization and dispatch, and connects directly to a public-facing outage map where customers can track restoration progress in real time. Automated text alerts keep customers informed without requiring them to call in.

The philosophy behind the platform was simple, according to Stinnett. “Our goal was to have a central platform so crews in the field spend less time figuring out the technology and more time doing what they’re good at: fixing trouble.”

Smart switching has been a major driver of measurable reliability gains. KUB began deploying FLISR (Fault Location, Isolation, and Service Restoration) technology, what many utilities now call “smart switches,” for its intuitive description, starting in 2017. Since then, the technology has helped KUB avoid more than 30 million customer minutes of interruption. With roughly 150 new devices deployed each year, KUB is working toward a corporate goal of reducing its SAIDI (System Average Interruption Duration Index, a standard industry reliability metric) to approximately 60 minutes over the next decade.

“Our journey toward ADMS began with integrating SCADA and AMI,” Stinnett said. “Those software programs are truly foundational. Without those, it’s difficult to expand into automation or other advanced grid technologies.”

KUB is also planning ahead for future operational flexibility, with a utility-scale battery energy storage system focused on peak shaving, dynamic voltage reduction (DVR) being scaled across the system, and an early-design-phase microgrid on the KUB operations campus. The microgrid project, said Jeremy Walden, KUB’s Manager of Electric Systems Engineering, is designed to position KUB as a trusted partner when customers in its territory want to build microgrids of their own. “What better way than to implement it on our own campus first so we’re familiar with it, we know how it works, and we can partner with others from a place of experience,” Walden said.

Starting Smart: Advice for Smaller LPCs 

Both EPB and KUB are clear that their scale of investment isn’t the only path to meaningful reliability gains. The foundational question, “Where do I start?” has a consistent answer from utilities that have been building these systems for years.

“SCADA is fundamental,” Keel said. “I’ve worked at EPB for 28 years, and we had SCADA before that. I’ve never known what it’s like to run an electric system without it. Having some level of remote capability and control is a fundamental thing I think all LPCs should do.”

From there, both Keel and Stinnett point to a solid GIS model as the next critical piece, one that gives utilities an accurate picture of how their facilities are connected and how customers tie into the system. That foundation makes everything else possible, from outage management to automation.

When it comes to automation specifically, the message is: start targeted, not total. “You don’t have to deploy thousands of devices right away,” Keel said. “Take some of your more challenging circuits and automate the tie points between that circuit and an adjacent feeder, maybe one or two other devices placed strategically where you tend to have issues. You don’t have to go with 1,200 devices right out of the gate to still make a pretty good impact.”

Stinnett echoed that. “Start with the circuits that cause the most problems and automate strategically.” TVA’s capability progression model, he added, is a useful roadmap for LPCs thinking through which investments to prioritize and in what order. In essence, the TVA CPM is a framework developed in collaboration with a broad cohort of Valley utilities.

Equally important is making sure your operational systems work together. Integrating outage management with GIS, meter data, and crew dispatch doesn’t just improve response speed, it gives operators a clearer, more accurate picture as events unfold. As technologies like AMI and smart switches generate more data, the utilities that can make sense of that data in real time will be the ones that respond most effectively.

Both KUB and EPB also note that as technology adoption increases, the job of system operator grows more complex. Both utilities addressed this primarily through training, creating programs that allow interested employees to build the technical skills the job now requires, rather than through wholesale staffing changes.

Innovation Across the Valley

Beyond individual utilities, the Tennessee Valley’s collaborative public power model continues to support innovation through shared research and pilot programs. Through TVA partnerships and TVPPA’s Research & Development initiatives, Valley utilities are exploring technologies that range from inspection automation and drone-based analytics to distributed energy resource programs that help manage load and improve grid flexibility.

These initiatives reflect a shared understanding: resilience isn’t a single technology or a one-time investment. It’s built through accurate system data, coordinated operational platforms, strategic automation, proactive inspection and maintenance, and flexible customer-side resources all working together.

Seeing More, Responding Faster, Planning Better

Across the Tennessee Valley, LPCs of all sizes are navigating a rapidly changing operating environment shaped by growing demand, evolving technologies, and increasingly complex weather risks. The experiences of utilities like EPB and KUB demonstrate that investments in visibility, automation, and integrated system planning can deliver measurable improvements, not only in outage metrics but in operational efficiency, customer confidence, and community development.

As Keel put it, the goal has always been the same. “Using technology to improve service has been a core part of our strategy for many years. It helps you deal with weather events and system challenges. It helps you analyze, plan, and determine where to invest. And when you do it well, the community benefits in ways that go beyond the electric bill.”

For public power providers across the Valley, this digital tools era holds the promise of seeing the system more clearly, responding more quickly, and planning more intelligently for whatever comes next.

*(You can read more about some of these cutting-edge technology initiatives in our Winter 2023 Research & Development Issue.)