Fortnightly Top Innovators 2025

Each year, PUF pauses to recognize those across the utilities industry who are not content to accept the status quo. Our Fortnightly Top Innovators stand out for their ingenuity, resilience, and ability to move the industry forward in ways large and small.

This month, we feature the first half of this year’s twenty-four awardees – leaders from Ameren, Arizona Public Service, Baltimore Gas and Electric, Commonwealth Edison, Duquesne Light Company, Eversource, ITC Holdings, National Grid, Ontario Independent Electricity System Operator, Rayburn Electric Cooperative, Salt River Project, and San Diego Gas and Electric.

Each of the awards is named after a pioneer whose story reminds us that today’s breakthroughs build on a long tradition of courage and creativity. In the nineteen seventies, Nancy Fitzroy rose through the ranks at GE to lead one of the largest turbine programs in the world. At a time when women were rarely seen in technical management, she broke barriers and insisted on the highest standards for both safety and environmental stewardship.

San Diego Gas and Electric and Ameren, winners of this year’s Nancy Fitzroy Award in Environment and Safety, echo her determination by addressing climate challenges and safeguarding communities.

Edith Clarke, the first woman to earn an electrical engineering degree from MIT, invented mathematical methods that made long-distance transmission stable. Her calculations opened the door to electrifying vast regions that were once unreachable.

This year’s Edith Clarke Award in Reliability goes to Arizona Public Service and Salt River Project, whose innovations in reliability and resilience keep that spirit alive in the twenty-first century.

Florence Fogler, remembered as the Grand Lady of Heat Transfer, joined GE in the nineteen twenties and became a leading expert in thermodynamics. She improved turbine efficiency and, alongside Edith Clarke, helped extend the reach of transmission.

Baltimore Gas and Electric carries her legacy forward as the 2025 winner of the Florence Fogler Award in Energy Transmission Technologies, driving advancements that strengthen the backbone of our grid.

William Hammer, Edison’s chief engineer, discovered the Edison Effect and brought electric advertising signs to life, forever changing city skylines. His contributions helped electrification leap from the laboratory into daily life.

Commonwealth Edison, winner of this year’s William Hammer Award in Electrification, continues in that tradition by championing projects that redefine how power is delivered and used.

Charles Steinmetz, dubbed the Forger of Thunderbolts, was the genius who translated mathematics into practical alternating current systems. He helped make the modern grid not only possible but reliable at scale.

In 2025, Duquesne Light and ITC Holdings earned the Charles Steinmetz Award in Network and Grid Operations for their innovations in managing complex systems with the same combination of rigor and imagination.

Maria Telkes, the Sun Queen, pioneered solar thermal and storage long before renewable energy became mainstream. She believed in a future where the sun itself could be tapped as a dependable energy source.

Eversource and Ontario’s Independent Electricity System Operator embody that vision as winners of this year’s Maria Telkes Award in Distributed Energy, proving that distributed resources can be both practical and transformative.

Nikola Tesla – inventor, showman, and visionary – remains one of the most celebrated figures in science. His work on alternating current revolutionized the industry, while his eccentricity kept him in the headlines.

This year, the Nikola Tesla Award in Artificial Intelligence goes to National Grid, recognized for harnessing AI in ways that echo Tesla’s boldness in adopting the technologies of tomorrow.

Lewis Latimer, the son of formerly enslaved parents, became a central figure in Edison’s era by drafting patents and perfecting the carbon filament that made light bulbs long-lasting and affordable. His story reminds us that inclusivity and ingenuity go hand in hand.

Rayburn Electric Cooperative, winner of the 2025 Lewis Latimer Award in Technology and Process Design demonstrates how thoughtful process improvements can light the way for the industry.

Taken together, these 2025 award-winning innovators represent not just technical progress but leadership and perseverance. They stand in the company of Clarke, Fitzroy, Steinmetz, Latimer, Telkes, Tesla, Hammer, and Fogler – visionaries who remind us that every breakthrough builds on a proud legacy.

Next month, PUF will feature the remaining Top Innovators and continue to tell the story of ingenuity that drives our industry forward. m

PUF’s Lori Burkhart: Describe your role in the innovation and its positive impact.

Ameren’s Brian Martin: I’m the Senior Manager of Environmental Services at Ameren. Along with other things I do, I’m also the Program Manager for our Manufactured Gas Plant (MGP) Remediation. The Taylorville project is forty years old, and I’ve been with the project since the beginning, when I started my career at Illinois EPA.

Along the way, it became a CERCLA site, so it’s a federal Superfund project. The approved remedy is groundwater treatment, and that’s what we’ve been pursuing for nearly forty years.

In 2023, we wanted to think about this project in a new way by taking advantage of advancements in technology developed over the past forty years. Our goal was to implement the most effective solutions available, ensuring that customers and community benefit from the latest progress in groundwater treatment and site remediation.

We received approval to do a pilot study on using In-Situ Stabilization (ISS) to bind any remaining impacts in the subsurface, stop the release to groundwater, and eliminate potential impacts to the environment or the neighboring community.

Unfortunately, the pilot was not fully completed. However, we continued with our required groundwater monitoring and treatment, which showed positive effects from the ISS work. We saw reduced impacts on groundwater.

Based on modeling, our consultants, ERM and GEI, said, “It looks like we may be able to shorten our treatment schedule by several decades.”

My role as the project manager was to ask, “What does that mean? How can we apply this and proceed with approval?” We had talked about shortening the schedule, and I challenged them; “What if we shut the pumps off today?”

We looked at our models and the potential groundwater changes if pumping were to cease. Groundwater conditions did not significantly change with or without pumping. There does not appear to be any continued benefit to groundwater treatment because of the benefits of our ISS project.

We’ve approached Illinois EPA, because this is a state-lead CERCLA site, and U.S. EPA. They seemed receptive to the idea, and we’re in the process of finalizing our model, preparing reports to support our proposal to shut down the system several years early.

Our modeling, supported by in-field data, will show that continued groundwater treatment is not necessary. If our proposal is approved by the Illinois EPA and U.S. EPA, we will stop groundwater treatment but continue to monitor for some period to ensure that groundwater conditions do not impact the community.

Eliminating groundwater treatment will reduce cost and other impacts to our customers with no adverse effects. Our continued groundwater monitoring will serve to confirm our modeling over time.

PUF: Explain the City of Taylorville’s manufactured gas plant.

Brian Martin: The MGPs were a technology used roughly from the mid-1800s to mid-1900s. They produced gas from coal for gas lights.

At the time, MGPs were a source of civic pride. It is equivalent to bringing broadband internet to a town today. If you had a gas plant and gas streetlights, your town was up and coming.

Over time, they were displaced and put out of business by less expensive and better-quality natural gas when transcontinental pipelines came into play. Coal tar, a gas plant byproduct that is like asphalt, remains in some underground structures. That is the material we are cleaning up.

PUF: Talk about your roles in the development of this innovation.

GEI’s Brandon Teel: Our role was initially to provide technical expertise in support of Ameren and ERM for the development of the ISS approach for the pilot study and remainder of this project.

The Ameren, ERM, and GEI teams are familiar with implementing ISS at MGP sites. This is done to bind impacted soil in such a way that it is incorporated into a monolith, so groundwater does not flow through but rather flows around remaining impacts.

GEI’s role in this program has been to provide project management, project controls and technical resources to aid in fully developing effective remedies. We also worked with associated stakeholders, such as the local community, municipality, and agencies.

ERM’s Dan Wilkens: Our team has been involved at this site in one form or another for over thirty years. For this project, our role initially was to look at the feasibility of different remedial technologies, and one of those was ISS.

We first investigated where remaining impacts were located and came up with a plan for remediation with Ameren, which included a focused feasibility study for ISS. ISS was a clear winner to remediate the site and achieve Illinois Environmental Protection Agency clean-up goals within a reasonable timeline.

It is important to note that there is an active pump and treat system that pumps groundwater, treats it to established standards, and discharges it. Pump and treat technology was the right remedial technology in the 1990s, as ISS was not widely used when the pump and treat system was first installed.

Since that time, the pump and treat system has done its job well but is still projected to operate for decades. The ISS pilot study that was recently completed proved that ISS is the right technology for today to effectively remediate the remaining impacts at the site.

Through the partial ISS that was completed, we’ve shortened that remedial timeline significantly to do the right thing for the community as well as Ameren’s customers.

Brian Martin: The original intent was to do the In-Situ Stabilization and bind up all the contaminants, but we couldn’t proceed to completion. Then, looking at groundwater data and effects that the partial work had on groundwater conditions, I started asking a series of what-if questions like, “How does the model change if we look at different timeframes?”

We kept looking at the model in different ways, at different evaluations, and reanalyzing groundwater. Then the technical experts at ERM and GEI would revise the models based on new conditions, and I would challenge them in different ways.

We realized stopping the pump and treatment today does not result in any adverse health or environmental impacts, so we’re preparing documentation for that. My role from here on is to liaison between our company and EPA officials to get approval for the process.

PUF: What was most rewarding about working on this project?

Brian Martin: The idea that it was unconventional. ISS is proven but usually there is a defined endpoint. But in this one we had to face the challenge of stopping before we were finished, trying to find benefits, and when we saw the positive results, it became straightforward.

It was looking at things in a new way, blending ISS technology with groundwater modeling technology. Ameren approaches all our projects in the same way. We do the right thing.

Taylorville also happens to be my hometown. On occasion you hear from the public like, “What do you care? You don’t live here.” Well, I’m from here. This is important to me.

Dan Wilkens: Brian and his team at Ameren do a great job of fostering a collaborative environment internally, with the regulators, and with the community. That was a great part of this project, the collaborative nature that you don’t find in many projects or with other clients.

The second is doing the right thing for science. I come from a small town in Illinois that had groundwater impacts. To see Ameren be proactive in remediating this site and doing the right thing for the community was gratifying. Seeing the results post-ISS is very encouraging.

Brandon Teel: Developing a remedy that worked. We did this by fully investigating the site, understanding the geology, and reviewing all that could be done to access the contaminants at depth. It was rewarding technically to develop a remedy to address the impacts effectively.

It was also rewarding in that we did so collaboratively among these three organizations. We work well together and have capable and dedicated people who understand the science. Together, this team has made concrete progress at this MGP site.

PUF: Your modeling report was submitted to the EPA, so what’s next?

Brian Martin: We are waiting for their review. We’ve had discussions. The model information was well received. We’re preparing backup information to give more detail.

We’ve given them a high-level overview, showing graphics of here’s what happens at day zero, one year, five years, and so on.

We’re in the process of compiling our groundwater monitoring reports along with backup information for the groundwater model, and we intend to make a request with a proposal to change the approved remedy to reflect current conditions and stop the pumping and treating. m

PUF’s Lori Burkhart: Describe the innovation and its positive impact.

Kerri Carnes: The innovation is the evolution of our virtual power plant and the addition of the capability for locational dispatch events. The addition of this capability is important to APS for a variety of reasons.

As we continue to develop our virtual power plant, and as peak demand continues to rise, we recognize that customer-centered resources like smart thermostats, batteries, and electric vehicles are essential to building a more flexible and responsive energy system.

Last summer, we hit a record peak of eight thousand two hundred ten megawatts as Phoenix temperatures soared to one hundred sixteen degrees. Already in 2025, we’ve exceeded that peak multiple times by hundreds of megawatts, just for context. These extreme conditions underscore the urgency of expanding our grid’s capabilities.

During a severe microburst in the summer of 2024, APS faced significant damage to poles and electrical equipment in the Phoenix area. In response, we activated a targeted conservation event through our customer smart thermostat program, APS Cool Rewards.

Using locational insights, we identified smart thermostats near the impacted zone and worked with customers to reduce strain on the grid, helping crews restore power, and protect nearby neighborhoods. Today, APS operates one of North America’s largest virtual power plants, with over one hundred thousand connected devices, contributing nearly two hundred megawatts of flexible capacity.

Our growing network currently spans thermostats, batteries, and electric vehicles, and we’re collaborating with customers to shift or reduce energy use during Arizona’s most critical peak periods.

Looking ahead, we’re focused on expanding real-time flexibility across technologies and geographies, unlocking locational value, and strengthening our grid’s resilience. These efforts are central to keeping energy reliable and affordable for all APS customers.

PUF: Let’s talk about each person’s role in the development of the innovation.

Blanca Moreno: I’m Program Leader of the Portfolio Management Team. My team is responsible for our demand response programs, as well as our energy efficiency programs. These programs include our demand response thermostat program, APS Cool Rewards, which is what this locational event was part of.

Our administration of this event involved working with our customers to reduce the load on the grid during our highest peak demand time.

Sarah Noll: I’m the Manager of our Virtual Power Plant Innovation and Strategic Initiatives. My team’s role is helping our company grow and scale our virtual power plant in a variety of ways.

One is developing creative ways to engage with customers who are adopting new technologies, as well as incorporating and expanding the use cases for these technologies into our virtual power plant.

While my team is charged with coming up with innovative ideas and new strategies, Blanca’s team is tasked with executing on those concepts and plans. Our teams collaborate on ways to evolve and refine the programs that make up our virtual power plant.

Central to our thinking around how we can continue to evolve and explore new processes for locational-based events are the guiding principles of creating value for both our customers and the grid. My team helps build upon what we have today, looking toward the future as technologies mature and are adopted more broadly across our customer base.

Blanca’s team was on the ground making this first-of-its-kind event happen, working with customers to enable APS’ first-ever locational demand-response event, and with smart thermostats, nonetheless. It’s cool because most people don’t think about smart thermostats as the leading technology.

But they are the heart of our virtual power plant and the DER that we go back to year over year because our customers continue to show up and participate. We truly value the partnership we’ve created with our customers through these types of programs.

Kerri Carnes: I’m the Director of Customer Grid Solutions at APS, so I get to work with all these talented folks who are focused on delivering the innovative solutions that are helping with expansion of our virtual power plant.

To build on what Sarah said, the other benefit of initiating targeted, surgical, locational-specific event dispatches through our virtual power plant is that we preserve the customer experience by only including customers located in the area that needs support at that moment in time and excluding all others.

When you’re developing a virtual power plant that is leveraging customer-sited resources, the customer must be front of mind. It is critical that we consider customer experiences as we design our programs.

The number of events called in a season can impact the customer experience and affect the level of comfort in their homes, businesses or cars, so all those things matter. Being as specific as possible is an important development and something we’re proud of at APS.

PUF: What have you found to be most rewarding about working on this project?

Sarah Noll: This is the first time we responded to this type of event. Prior to that first locational dispatch event, we would call on all our enrolled customers to take part in service-wide events.

Typically, when a storm comes through or there’s an outage, utilities shift to an all-hands-on-deck mode, and so it was exciting for our team to join forces across operations to provide support during that time of need.

During this locational event, we provided some relief to the grid while crews were hard at work in the summer heat to repair transmission lines. It was exciting to demonstrate that the virtual power plant can show up in this way to be part of restoration efforts.

Blanca Moreno: There was quite a bit of reward here. First, was seeing the team come together, like Sarah said, during that all-hands-on-deck situation. Second, was having the opportunity to observe the team in action, working long hours, and seeing the VPP resource at work and demonstrating its capabilities.

Having the opportunity to be part of a team that banded together to serve our customers, ensuring they were able to keep their lights on, and helping with our transmission distribution effort was the most rewarding part.

Kerri Carnes: Blanca said it perfectly. It was watching the team work hard to deliver on something we had hoped to demonstrate the efficacy of, that was most rewarding. The success of the locational event enabled us to show other operational groups at APS that there is real value in our virtual power plant.

This resource is important because it supports grid reliability affordably, and that’s a high priority for our customers. It’s also essential to make sure we’re maintaining safe, reliable, and affordable energy 24/7, even when there are storms or significant damage to infrastructure.

We can leverage VPP resources to maintain that reliability, and that matters the most, especially in the extreme heat of Arizona summers.

We said we could do it and showed we could. That’s how trust is built with other business partners and operational teams when bringing in a resource that functions differently than what we’re used to relying on. It showed up better than expected.

We exceeded the megawatt forecast that we thought we’d be able to shift away from the affected area, and that was exciting. The success of this first locational dispatch event supercharged what we thought we could do and will drive us forward. Our initial learnings from the event will allow us to sharpen our capabilities and respond more quickly next time. m

PUF’s Lori Burkhart: Describe the innovation and its positive impact.

Bob May: We have a set of circuits across the Patapsco River near the Baltimore Harbor that had experienced a series of unplanned outages. While those are not good, they also impacted the power quality to some of our important customers, like hospitals. We were tasked with trying to remediate these operations.

Instead of anti-sway devices, we pioneered a design with RIBE in Germany for interphase spacers on a two hundred thirty kilovolt circuit with the frame installed underneath the conductors, instead of above. That configuration is unique in the country.

The new configuration of these lines was challenging and became the part of the project that was innovative. The arrangement of the wires and the circuits on the structures, the installation across the Patapsco River, and the elevation we were working with all contributed to this being an innovative solution to an odd problem.

PUF: Dave, what’s your title, and what was your role in the development of this innovation?

David Outen: My role is a Section Engineer for Transmission Engineering. I was the BGE engineer during the execution phase of the project that installed the lines. When we started having problems, I worked with the contract engineering teams who had originally designed the line to help us engage vendors and get working on finding solutions for the outage problem.

That led us going down the road of the interphase spacer, and then we engaged Bob to help us with the calculations and making sure the vendors were providing the right calculations for the conditions they were being installed in.

I also reviewed what was going on and made suggestions here and there that Bob would eventually implement. One example was that we couldn’t do our normal bucket access type construction because of the installation environment that we were working in over water. Everything had to be done by helicopter, which introduced additional complexities.

We said, “We don’t know how this thing can even get installed. While we know what it looks like, how do we get it there?”

One of my suggestions was to build a mock-up on land and let the contractors and linemen work out a successful installation process that was safe and repeatable. That was another piece of the innovation, not only the hardware itself, but the how, because this environment is so complex with the weather, structure heights, and shipping traffic that must be halted at certain times. Additional safety procedures were implemented including having divers in the water to make sure if something happened to the helicopter and its crew they could get rescued quickly.

PUF: Where on Maryland’s Chesapeake Bay is this?

Bob May: The project spans the Patapsco River, a tributary of the Chesapeake. The line was built parallel to the Key Bridge, which came down in 2024. The line was built just to the inside of the harbor, toward the city, about seven hundred feet off the former bridge and was energized in May 2022. We had the line in service for two years before the bridge was lost.

We had to work around the shipping channel and establish some temporary closures during the original line construction and then had to implement the same temporary closures during the remediation. In addition, after the bridge collapse, we also had to work around temporary flight restrictions surrounding the recovery operation that created a challenging coordination effort.

PUF: Danilo, what’s your title at BGE and your role in the innovation’s development?

Danilo Policastro: Currently, I am a Section Engineer for Transmission and Substation Regional Projects, but for this specific project, I am the Transmission and Substation Innovation Lead.

I lead all the innovation ideas and projects that run through our department at BGE with the innovation team. My role is to identify the idea and say, “this is new, this has potential” and make it an innovation activity and an innovation project to walk through the program path.

PUF: Bob, what is your title and role?

Bob May: I’m the Principal Engineer in BGE Transmission Engineering Design and Standards. I’m the lead technical person for all things transmission design related in BGE.

My typical role is not just mentoring and training the new engineers and monitoring projects, but also, I get involved with day-to-day operational concerns. In addition, one of my major roles is monitoring and remediating transmission line unplanned operations.

As soon as this event happened, I was pulled in to identify the issue, to make sure we didn’t have damage, and find the locations of the issue, and as it became a repeated occurrence, to understand what we thought was going on. We had to start putting together a long-term mitigation, so I got involved to address the problem with respect to the Key Crossing Project Reliability Initiative project.

PUF: Danilo what was most rewarding about working on this project?

Danilo Policastro: Addressing the reliability of the system, to guarantee the customers are serviced with reliable power. First, we had stability issues with the circuits that supply power to important costumers like hospitals that had lights flickering. That’s the most rewarding part of the project, to supply good, reliable energy to our customers.

PUF: David, what was most rewarding about working on this project?

David Outen: I like field work and collaborating with field teams. I enjoyed seeing the field crews play around and figure out how to get this thing installed and then go out and watch them execute it flawlessly in a windy environment. We had zero safety incidents on the entire installation, which spanned two outage seasons because the bridge collapse happened right as we were going to go install the first set.

Because of the bridge collapse, there was a temporary flight restriction in place around the entire harbor, so we couldn’t fly anything, and ended up having to scramble to work with PJM to get our outages rescheduled and see what we could get worked in during summer months.

We were able to get one set done during June and then had to come back in the fall and do the second set. Between both of those times, the crews were able to train and execute on the mock-up and then go out to the actual spans and perform it.

PUF: Bob, what was most rewarding for you?

Bob May: I’ll echo everything Dave said because I find a lot of that to be rewarding – the zero safety incidents and hands-on interaction with the field. But I get involved with other industry groups and trade associations and it was great sharing this experience with other people and learning from others who may have had similar issues on their systems or encountered similar challenging installation.

Sharing our experiences, problems, solutions, and execution of it all, I found that rewarding. I’ve given a presentation on this to a couple of different groups, and it’s been well accepted. m

PUF’s Lori Burkhart: Describe the innovation and its positive impact.

Cristina Botero: This team, in collaboration with multiple teams across ComEd, designed and implemented new electric vehicle customer programs that launched at the beginning of 2024, and helped propel EV adoption in Illinois three to four times higher than in the entire U.S. We took a unique approach that puts equity front and center, and our results show our commitment to equity.

Eighty percent of the rebates paid by ComEd through our EV programs have gone to low-income customers or those located in or primarily serving Equity Investment Eligible Communities (EIEC), as defined by the State of Illinois. This is an unprecedented statistic in the EV space and is a blueprint for other jurisdictions to adopt.

ComEd’s innovation includes three new rebate programs. The first gives rebates of up to one hundred eighty thousand dollars for the purchase or lease of new or pre-owned fleet electric vehicles of any weight class for business or public sector customers. That’s our largest rebate program by dollar amount.

The second largest is also for commercial and public sector customers, offering rebates of up to five hundred thousand dollars to cover the costs to make any private or public site ready to install Level 2 or Direct Current fast charging (DCFC) infrastructure.

The third rebate program offers residential customers rebates of up to three thousand seven hundred fifty dollars for the purchase and installation of smart Level 2 chargers at home.

In addition to these programs, this team created two networks of critical stakeholders. The first is an EV dealer and manufacturer network that helps us offer fleet EV rebates at the point of purchase, directly reducing the upfront costs of fleet EVs for our customers.

The second is a network of EV service providers, which are Illinois Commerce Commission certified professionals who install charging infrastructure for residential and commercial customers. They help us educate customers, accelerate the buildout of charging infrastructure, and provide rebates up front to our customers, among many key functions.

We also created a robust customer education awareness program. It provides multiple tools and technical assistance for customers looking to adopt EVs or install charging infrastructure.

This includes free fleet electrification assessments, an interactive load capacity map to support early siting of charging infrastructure in areas with sufficient grid capacity, an EV toolkit with multiple educational resources for residential and non-residential customers, partnership with the Metropolitan Mayors’ Caucus to support and encourage communities looking to gain EV Ready status via an EV Readiness Program, and an EV Ambassador Program.

Another key element to the success of our innovation is the creation of a centralized group for EV new service connections within our new business team. This reorganization is creating efficiencies and improved customer experiences to timely manage the volume of new service requests for EVs.

We’ve incentivized the construction of over six thousand new Level 2 and DCFC charging ports, which is equivalent to one new charging port every two to three hours. We have incentivized the purchase or lease of over two thousand fleet electric vehicles, including more than two dozen heavy duty vehicles and buses.

Beyond this financial commitment, ComEd conducts targeted, local outreach and education to these customers through its EV Ambassador program, which recruits local leaders from diverse organizations to champion electrification.

PUF: Talk about your roles in the development of your innovation.

Cristina Botero: I am the Senior Manager for Beneficial Electrification at ComEd. I oversee the overall strategy and implementation of our customer-facing EV programs and am ComEd’s subject matter expert and single point of contact on electric vehicles, helping EV customers navigate our organization and obtain the support they need to get projects off the ground.

Jordan Losiak: I am the Lead for the Business and Public Sector EV Rebate Program. The program provides rebates for light-, medium-, and heavy-duty EVs, alongside transit and school buses. A big part of my role since we launched this program in early 2024 has been listening to customers on ways to improve their experience and how to obtain rebates.

It can be everything from creating a dealer network, where we can meet customers where they are, adding the point-of-sale rebate that gives an instant rebate to take the cost directly off the sticker price, and making pre-owned and re-powered vehicles, which are vehicles that formerly had internal combustion engines that have been transformed with a new EV drivetrain, now eligible for our rebates. This helps our customers get into the electrification transition at a lower cost point.

Daryl Richardson: I’m the Manager of ComEd’s New Business Team dedicated to EV charging projects. My department is responsible for the design and project management of new EV charging project interconnections to the utility. I focus on making sure we are providing an enhanced customer experience, because traditionally dealing with utility construction has been a rigid process.

Customers benefit from having assistance navigating through the process, especially with companies coming in who aren’t our traditional customers. They may be nationwide EV customers that deal with multiple utilities, or customers who are not used to dealing with utilities at all.

My job focuses on meeting with them upfront, discussing our processes, making sure the accounts, service requests, and all related documents are done correctly and returned to us. And that we have everything we need prior to the job progressing.

Once they are ready to start the job and we start our design work, we then can flow through the process quickly.

Kyriakos Anastasopoulos: I oversee the regulatory and compliance aspects of the program for the ComEd Beneficial Electrification Team. I work with program managers to shape program strategies and ensure alignment of program activities with our regulatory framework.

I also support the formulation and advancement of the investment plans that we file with the Illinois Commerce Commission and related compliance activities. I lead the analytics portion of the program, which focuses on leveraging data to improve program operations and overseeing a lot of the development of backend systems and customer-facing tools to better engage customers and improve the customer journey, or meet our regulatory and compliance goals.

Tom Skawski: I’m the Senior Program Manager for the residential EV charger and installation rebate program. For innovation, I strive to make it easier for customers to apply for rebates, ensuring we have a wide geographic range of rebate distribution, and making sure we update the program design to reduce rejection rates and increase customer satisfaction.

Violeta Ryman: I’m the Senior Program Manager for the business and public sector make-ready program. My role is to oversee the customer engagement process for organizations exploring the installation of electric vehicle charging stations in the ComEd territory, which includes overseeing customer journeys.

Through this program, we provide financial incentives to support the development of the EV infrastructure in our communities, particularly equity investment eligible communities. My role is to ensure a seamless and informed experience for participating customers from beginning to end. I also manage our EV Service Provider Network.

PUF: What was most rewarding to you in working on this innovation?

Violeta Ryman: The most important part, and the most rewarding part, is knowing that we’re making transportation electrification accessible and possible for our communities and customers. I appreciate the community benefits that come with that, including air quality improvements, and related health and environmental benefits.

Daryl Richardson: The most rewarding part is the feedback from customers as they complete their jobs and the process. Having those one-off conversations with them, whether a traditional ComEd customer who’s done other new business work, and they talk about how this process is streamlined and it helps them, or national customers who talk about how our process compares to other utilities.

It lets me know we’re going in the right direction, not only for my new business department, but also with the rebates and communication with customers.

Kyriakos Anastasopoulos: The most rewarding part is understanding the level of impact these programs can have on our communities and the industry. I’m awed by the number of individuals who have been involved in shaping the strategy and executing the vision for a program like this both internally and externally.

Being in this role has provided a firsthand view into the collective effort and dedication of the individuals working to make a program like this successful. Working with stakeholders, listening to customer stories, and having the opportunity to develop the customer journey, makes it real and reinforces my confidence in the value this program brings to our communities, and where these programs can go.

Tom Skawski: The most rewarding part continues to be the number of customers we’ve reached. The residential EV charging rebate program has the smallest budget, but the highest number of participants.

We have received thousands of applications and paid out rebates for almost five thousand ports from inception until now. I’m proud of the geographic spread, the amount of EV ports we’ve incentivized in EIEC and low-income communities and the coordination with the goals of CEJA, the Climate and Equitable Jobs Act.

We want to get a million electric vehicles on the road in Illinois by 2030, and every port that’s added to the grid is ready to support one or more electric vehicles on our roads.

Jordan Losiak: The most important part is hearing from our business and public sector customers who received our rebates on the performance and cost savings of their newly acquired EV, the noticeable reduction of emissions both onsite as well as along their routes in communities, and how they plan to add more with our rebates.

Also, I could not count how many times we’ve visited a site and had a driver state they were once skeptical of the new electric drivetrain. Now those same former skeptics are advocates with a newly found skill set in public speaking because it seems everyone they interact with asks, “Is that thing even on?” They’re forced to field impromptu questions on our behalf, which most are happy to do.

Cristina Botero: It’s seeing how big an impact these programs are having in so many areas, not only in EV count, but also in customer benefits, reduced emissions, workforce development and growth, amongst many others.

It’s humbling that our work is creating such positive impacts this early on, something that would have not been possible without the engagement of many internal and external partners who have been instrumental, and I’d like to acknowledge their extensive contributions. m

PUF’s Kerry Worthington: Describe the innovation, your role in it, and its impact.

Richard Saporito: I’ve been with Duquesne Light Company (DLC) for seventeen years, mostly in distribution planning. I joined the Advanced Grid Solutions team in December 2021 and have been leading battery and innovative solution projects like this Gridware sensor deployment.

The innovation’s name is Gridware Gridscope Sensors, and they provide visibility on the grid. That’s the positive impact. Duquesne Light’s distribution system, specifically the legacy four kilovolt voltage class, doesn’t have as much visibility as the newer twenty-three kilovolt distribution.

By installing these, we can better identify where the system issues are. There are thirteen different sensors inside each Gridscope that are recording data and events then sending alerts back to DLC so we can identify faults in real time. Now we know exactly where the problems are, what is wrong, and which equipment to dispatch crews with, so system issues can be remedied in fractions of the time we used to need.

Josh Gould: I lead the Advanced Grid Solutions team, as well as our Enterprise Strategic Planning team, and corporate development. My title is Director of Advanced Grid Solutions and Enterprise Strategic Planning, and I’ve been at Duquesne Light for five and a half years. I’ve led the AGS team since January 2025.

The customer and employee impacts are that identifying issues on the circuit drives safety and improves reliability as we’re better able to go straight to the issue, instead of spending time trying to find where it is. We can more quickly warn the public of any safety hazard associated with the issue, as well.

Richard Saporito: That was the number one priority, because sensors aren’t just installed for fault identification. They can identify where there are low impedance faults, which are faults that are not high enough amplitude to operate a protective device or a fuse. So, the line remains energized and could be lying on the ground.

The Gridscopes have sensors that can detect the change in the electromagnetic field at a pole location, and state that there’s something wrong, even if a fault wasn’t identified. The scopes report in the event notification that it is a potential EMS situation. So, we can contact the police immediately to cordon the area off as we send crews.

Jessica Valentine: I’ve been on the team for the past four years and recently became Manager. Another aspect of the innovation includes where we decided to place the sensors.

Richard gave a detailed evaluation of where these sensors would have the biggest impact in terms of improving reliability and where they were most needed based on other grid factors. That was a big part of the successful deployment.

PUF: For each of you, talk more about your role in the innovation.

Jessica Valentine: I’ve been more of a supporter of the technology and am also working on getting additional funding for further deployment of this technology. I’m a couple of steps removed from the work on the ground and am driving additional deployments in our organization, helping with integrating this into some of our other systems.

Josh Gould: I was lucky enough to come across the technology and the entrepreneur in the first place. I was at a wildfire conference at the end of 2023 run by a venture capital firm named Convective Capital.

Convective’s entire purpose is to fund wildfire mitigation and discovery technologies. This technology was started as something that would help – particularly west coast utilities – address wildfire related issues.

I went to this conference with the idea that if there are technologies addressing these catastrophic environmental conditions, identifying them, and trying to avoid them, there might be applicability to other resiliency related conditions.

I happened to meet the folks from Gridware at the conference, which is a portfolio company of Convective Capital. Then I involved a broader group of folks at Duquesne Light, and we partnered to highlight this technology.

PUF’s Rachel Bryant: The sensors sit there, and based on disturbances from animals or vegetation or other interference on the line, how is that communicated to the utility?

Richard Saporito: The sensors are completely plug and play. They’re not connected to the electrical grid at all. They’re solar-powered and have a battery inside that even with no solar power, can last over a month.

They are activated when one of the sensors is triggered by vibration, a change in inclination, an electromagnetic field change, or fault current. Once it’s triggered, it begins collecting data and performs data analytics. For example, if a tree falls on the line or a car hits the pole, it triggers a vibrometer.

The database has a catalog of different types of vibrations that are recognized when contact is made with the lines or with a pole. It records the vibrational pattern and compares it to the database.

It can then say, “A motor vehicle hit this pole. A tree fell on the line.” It can also recognize routine maintenance. The devices communicate between themselves within the event area. The devices send the information back to Gridware, which communicates to us through phone calls, emails, texts, and a dashboard where we can look at the pole on a map and read the event record.

PUF: When that reporting is going back and forth, is that instantaneous?

Richard Saporito: It records events in real time. However, the full event report can take between five to forty minutes. Forty minutes is rare, but that’s the long end depending upon the situation.

If it’s something unusual, it must go to a person who is investigating it as opposed to the devices pulling from their own data. There is latency between the event and when it’s reported. But even if it takes forty minutes, we know where to send a crew, when before, an investigator would spend hours finding that trouble point.

Josh Gould: Most notifications tend to be at the lower latency simply because they’re common. It’s only the outliers that take longer notification time because they’re different or unusual.

Jessica Valentine: We plan on integrating it with our SCADA system, so we won’t be as reliant on manual phone calls or alerts. Hopefully, that’ll further reduce latency and make it more seamless. We’re an early adopter of the technology and on the earlier side of integrating it with our SCADA systems.

PUF: What was most rewarding about working on this innovation?

Richard Saporito: I worked with distribution planning to find the most useful places to pilot the technology, wrote a scope of work to send to Gridware, and gathered GIS data so we could implement this. Within a few months, we had sensors installed and had picked circuits where we knew there were issues.

By December 2024, our vice president of operations had greenlit a scaled installation effort, which is what we’re involved in now.

It benefits the company’s safety, reliability, and makes things easier for the crews and control center. The fact that I was involved in a project that is so highly regarded is special.

Josh Gould: Utilities are stereotyped, sometimes unfairly, that we move slowly. This is an instance where we moved quickly. We went from the first discussion in February 2024 and had sensors installed and active before the end of September 2024.

Into 2025, we scaled it into the thousands, and we’re underway with integrating into our SCADA system. Where we find a benefit, we can move quickly. It’s fulfilling to fight the stereotype of utilities being slow moving.

Jessica Valentine: What was most rewarding about this project is it has a strong foundation in safety and improving safety. That’s one of Duquesne Light’s core values. m

PUF’s Lori Burkhart: Meiyan and Bin, please describe the innovation and its positive impact.

Meiyan Li: The team delivered a comprehensive, utility-grade solution to modernize and automate the inverter model validation and compliance process. The innovation comprises two integrated components: a plug-and-play inverter model validation testbench and an intelligent PSCAD interpretation tool.

We have encountered challenges. The first issue was the quality of the PSCAD models. Many DER developers submit the generic PSCAD models from the manufacturers, rather than specific models tailored to the actual designs.

The second challenge was the lengthy process to collaborate with developers to rectify their model deficiencies. Third, we found that the technical requirements for the PSCAD models can be difficult for the developers to understand and to modify their models accordingly.

Finally, there was a lack of efficiency and consistency in the PSCAD model review process. Therefore, we needed to standardize our model validation procedures and provide uniform feedback.

For the first part, we developed a testbench. We established a standardized process in our testbench, which enables us to evaluate different OEM inverter models and resolve issues with customers before commencing with transmission studies.

By doing this, we can enhance the quality and reliability of the inverted models and standardize our verification process within Eversource. Our testbench also improves the modeling efficiency and reduces some modeling burdens on project developers.

We also further refined the testbench by automating the PSCAD validation tests by using Python scripts to run all the tests sequentially or simultaneously. Recently, we have successfully black boxed this comprehensive testbench, which enables us to share with the customers for self-validation prior to their submissions to our final review by the Eversource transmission planning team.

Bin Huang: I’m mainly working with Junhui Zhao, and we are part of the power system automation team at Eversource. In this project, we work closely with the transmission planning team led by Meiyan, and they run simulations using PSCAD and the results are saved in a special data format.

The job of our team was to build an automation tool that can read and interpret those data files automatically. These automation tools can help with the post-processing reporting, analyzing, and making sure everything follows internal procedures and regulatory grid codes. It also uses advanced analytics and machine learning, so the results are processed quickly and presented in a clear, automated report.

PUF: What is your specific role in the development of the innovation?

Melanie Bennett: My role as Senior Engineer in Transmission System Planning mainly has been to help facilitate Bin and Jun’s team in automating the reading of our results from our testbench automation tool, which is through Python API.

I helped improve our automated test procedure and saved the results to a readable format so that Bin’s tool can analyze the results.

Jaryn Vaile: My role as Principal Engineer of Eversource Transmission System Planning was the initial implementation and development of the testbench and process used for testing the PSCAD inverter models against the applicable standards.

Bin Huang: My role as a Senior Data Scientist is that I work closely with the transmission training team. They filter the relevant criteria to be checked and share it with us; then I turn those into the code that the software can understand.

I also meet with the transmission planning team regularly to align the expectations, test the software, and finally package the software so it can be used both internally and by external DER developers.

Meiyan Li: As the team Lead Engineer of Transmission Planning, I recognized the necessity for a comprehensive testbench to comply with both internal and external standards and requirements. Our Principal Engineer Jaryn took the initiative to design and develop this comprehensive testbench. Also, I guided the team members like Koustubh and Melanie to refine the testbench over time.

I ensured we effectively addressed all the relevant standards and requirements. Recently, we implemented a testbench approach, so we are now able to share our remarkable innovation with the industry, allowing everyone to benefit from this invention.

PUF: Jun, what was your role in the development?

Junhui Zhao: We are the Engineering Data Innovation team at Eversource. Our role is to support engineering, planning, and operations teams through data analytics and AI solutions.

In this project, Meiyan and her team achieved remarkable progress by developing an automated testbench for DER integration studies. Building on their work, we collaborated closely to identify opportunities to further automate the reporting and analysis process by streamlining study reporting, enabling automatic interpretation of results, and improving the efficiency of communication with DER developers.

Together, we defined objectives and deliverables, while maintaining timely communication to ensure the tool was not only accurate in its reporting but also intuitive, interpretable, and practical for end users.

PUF: What do each of you find to be most rewarding from work on the innovation?

Bin Huang: The most rewarding is that these automation tools help improve our internal efficiency and it makes the whole validation process more reliable. It also lets us to better support our external developers, such as the DER developers, by reducing turnaround time and improving their satisfaction. That ultimately helps the integration of cleaner energy.

On a personal level, I learned a lot about software development project management and how to combine power system expertise with software development.

Melanie Bennett: I echo what Bin said. Automation in general is rewarding. First, it standardizes processes and improves efficiency. Second, as someone who personally benefits from this tool, it saves me time and mental capacity. I don’t have to keep checking on things.

I can let something run overnight and come back to all the data I need in the morning. Automation helps ease my workload. And now with the result interpretation from Bin’s tool, we have another significant time saver.

Jaryn Vaile: The most rewarding part has been seeing the adoption and use of the testbench process by Meiyan’s team to review what are likely hundreds of different DER models. It has also been rewarding to see the resulting improvement in the quality of the DER models we’re receiving and the analysis that those models have enabled us to perform.

Junhui Zhao: The most rewarding aspect is the strong teamwork. We view this project not only as a successful innovation, but also as a successful case for building an effective internal collaborative process. Meiyan’s team brought forward the business needs, and our team applied analytics and automation technologies to make it a reality.

Another rewarding element is the opportunity to learn from the planning team. Collaborating closely with them gave us deeper insight into their challenges, where analytics can add significant value.

Finally, this collaboration extends beyond the immediate project. It has broadened our perspective on future opportunities – such as leveraging AI, large language models, and agentic technologies – to further streamline workflows.

Meiyan Li: The most rewarding aspect is not just the technical success of the testbench but leading the team through the process of creating the solution and delivering the real value.

Getting the team to design, develop, and refine the testbench was rewarding. Implementing the black box approach and empowering both our developers and our team to then share this innovation with the entire industry is the most fulfilling reward of all. m

PUF’s Rachel Bryant: Please describe the innovation and its positive impact.

Adam Cianfarani: The innovation, in a nutshell, uses GIS technology to bridge data and workflows from the field to the office. GIS is not new as ITC has used it for more than a decade, but in a limited way, mostly to get assets on a map.

The real leap happened when we created a dedicated GIS team and gave them the resources and time to push the technology further. The result is a common operating platform for the entire company.

Instead of siloed systems and processes, we now have one place where everyone can see the same data in real time. That means significant gains in efficiency, accuracy, and decision making, whether it’s in the middle of a major storm or just managing day-to-day operations.

PUF: Ethan, talk about one of the tools your team developed.

Ethan Ehrisman: The tool I’ve worked on most is what we call the Outage Restoration App. It grew out of an early work experience.

In 2020, only six months into my job at ITC, a derecho storm hit eastern Iowa and took out about twelve hundred poles. More than one hundred circuits went out of service.

At the time, we didn’t have a spatially aware system to track outage restoration efforts. All we had were PDF reports from the control room and spreadsheets from the field.

I was asked to create some sort of mapping interface. At first, it was manual. I referenced and marked lines one by one in GIS to depict which circuits were still out of service or restored.

It was clunky but proved how valuable a visual map could be. Since then, we’ve automated the process and integrated it directly with our transmission management system. Now, instead of a static report, we have a near real-time view of outages across our system.

That alone makes a huge difference during storms. Dispatchers and field crews can see exactly which lines are out, what the status is, and when the restoration is complete.

We also included planned outages, so the tool benefits daily operations too. It’s no longer just a storm-response map, it’s a living, operational resource.

PUF: What’s the biggest change for crews on the ground?

Ethan Ehrisman: The interactivity. Field crews now use mobile apps to mark damaged assets, report restoration status, and even upload photos.

That data flows back into the system instantly. So, instead of sending around spreadsheets or making phone calls, everyone sees the same information in real time.

For example, during the derecho, engineers needed to know exactly where poles were down before design efforts could begin. With the outage restoration tool, that information is captured and visible immediately, so engineers can design replacements and logistics teams can source materials faster. It’s faster, more accurate, and coordinated. 

Adam Cianfarani: It’s also a culture shift. When we activate our Emergency Operations Center during a storm, people from across the company jump in; engineers, operations, communications, IT.

Having a common platform means everyone is working from the same playbook. Crews can geotag photos, notes flow back in real time, and fleet vehicles with GPS trackers appear on the same map. Instead of piecing together scattered emails and phone calls, we can see the whole event unfold on one screen. That’s powerful.

PUF: Dan, you brought a field perspective to this innovation. How did that shape what you built?

Dan Hutchison: It shaped everything. Before joining ITC full-time, I spent years as a vegetation management contractor, walking utility corridors day after day. Out there, you see things no one in the office would ever know about; equipment conditions, land-use issues, potential hazards.

The problem was, there was no good way to communicate those observations. We relied on phone calls, texts or emails, and most of the context got lost.

When I became a GIS Analyst at ITC, I knew there had to be a better way. I turned to ESRI’s mobile apps: Survey123, QuickCapture, Field Maps. Each is designed a little differently, but they all focus on making field data collection easy. That matters when you’re wearing gloves in five-degree weather and trying to use a touchscreen.

Now, observations from the field are captured as GIS data points, complete with photos and GPS coordinates. They show up on the map instantly. It’s a win for the vegetation team, but also for engineering, asset management, and even legal, because everyone can see exactly what’s happening in the corridor.

PUF: Brian, as COO, how do you see the broader impact?

Brian Slocum: To me, the innovation isn’t just the individual apps, it’s the integration. GIS used to be applied in pockets: engineering used it for one thing, vegetation for another, operations for something else. The breakthrough was bringing it all together into one team and one platform.

That required a cultural shift. Every group was used to doing things their own way. We had to convince people to give up a little control and trust that sharing data would pay off for everyone. It’s like giving up your favorite child – not easy – but once people saw the benefits, it stuck.

Now, instead of each team having its own silo, we leverage various data across the whole company. That makes us more efficient but also builds a foundation for the future.

GIS is the backbone of how we’ll apply data, AI, and predictive analytics down the line. It’s setting us up for the next decade of innovation.

PUF: Talk about your roles in the innovation’s development?

Brian Slocum: My role was high-level, empowering the team, pushing for centralization and fighting for adoption. The hard part wasn’t the technology; it was convincing teams to give up their silos. My job was to make sure people trusted the process and give the GIS team the runway to prove themselves.

Adam Cianfarani: I was the first member of this new GIS group in 2024, and my role as Manager of GIS and Engineering Data was to chart the roadmap. That meant identifying which solutions would deliver the most value and which barriers we had to break down first.

One of the biggest was cybersecurity. Any time cloud-based services are utilized, there are risks. We had to work closely with IT and cybersecurity to make sure we were protecting critical data while still unlocking the software’s potential.

I also had the responsibility of hiring Ethan and Dan. They’re the ones who brought these ideas to life. My role has been about vision, communication, and removing obstacles so they can innovate.

Ethan Ehrisman: My role as a Senior GIS Analyst was very hands-on. The outage restoration app started as my personal side project. I built it piece by piece, outside of my regular design work, because I saw the need during the derecho.

It was a lot of trial and error, experimenting with coding and integrations, testing different ways of automating things. Over time, it became a full-fledged tool that the company now relies on.

Dan Hutchison: I developed the mobile applications and dashboards for field data collection and trained staff to use them. What’s special is that I’m building tools I wish I’d had when I was in the field.

I know how frustrating it is to fumble with bad software in tough conditions. That experience guided every design decision. My role as a Senior GIS Analyst has been to make sure these tools aren’t just functional, but truly user-friendly for the people who need them most.

PUF: Finally, what was most rewarding about working on this project?

Brian Slocum: The most rewarding part was watching the culture shift. Seeing teams realize they could achieve more by sharing than by guarding their own processes validated the whole vision.

It was also powerful to see the efficiencies the tool introduced and how it enabled us to engage more effectively with the outside world to the benefit of our customers. It reinforced that innovation isn’t just about technology, it’s about empowering people.

Adam Cianfarani: The reward is twofold. First, seeing the ideas on our roadmap turn into real tools that people use every day.

Second, watching colleagues from across ITC bring us their ideas and being able to say yes to them. That validates the trust that leadership placed in us and proves the value of this team. We have shown that the sky is the limit – or in this case – the map is the limit.

Ethan Ehrisman: What I love is the feedback received from users. When someone stops me in the hall and says, “Hey, that tool you built really helped us,” that makes my day. It motivates me to keep refining and improving.

And on a personal level, there’s nothing like the satisfaction of cracking a problem after hours of trial and error. That “aha” moment, when it finally works and you can roll it out into production, is incredibly rewarding.

Dan Hutchison: It’s seeing how these tools make life easier for people in the field, my former colleagues. They work in extreme conditions, and anything that reduces their burden is meaningful. Watching their observations gain a bigger voice in the company, instead of getting lost in emails or forgotten, is the best reward. m

PUF’s Lori Burkhart: Please describe the innovation and its positive impact.

David Roman Ubeda: National Grid partnered with EnergyHub to test new functionality called Dynamic Load Shaping (DLS), which uses machine learning to optimize the dispatch of distributed energy resources (DERs) within our virtual power plant (VPP).

Unlike traditional demand response, DLS allows us to automatically coordinate thousands of DERs – specifically batteries and smart thermostats – to follow a custom, sustained load shape over multiple hours. During our proof-of-concept test, EnergyHub dispatched twenty thousand thermostats and twenty-four hundred batteries to deliver a four-hour continuous load reduction, effectively mimicking the output of a conventional power plant with minimal snapback.

This capability has the potential to defer infrastructure upgrades, reduce wholesale energy costs, and enhance grid reliability, all while maintaining customer comfort and creating a pathway to lower energy costs for all customers.

PUF: Talk about your role in the innovation’s development.

David Roman Ubeda: As Program Manager of Massachusetts Residential Connected Solutions and Behavioral Programs, I worked alongside Paul Wassink to support EnergyHub’s deployment of their Dynamic Load Shaping feature in a real-world grid event.

EnergyHub came to us with a fully developed proposal, including the operational goals, target load shape, and dispatch strategy. Our role was to review and approve the use of our customer DERs for the pilot and ensure alignment with our program objectives. We also monitored the event’s execution and outcomes to validate its performance and potential value to the grid.

PUF: What was most rewarding to you about working on this project?

David Roman Ubeda: The most rewarding part of this project was proving that we could seamlessly call extended events that mix participation from both thermostats and batteries, without compromising customer comfort.

EnergyHub’s DLS feature allowed us to test an extended four-hour dispatch strategy that transitioned smoothly between device types. We were especially pleased to see that such a long event was possible while maintaining customer comfort and satisfaction while still delivering meaningful grid benefits.

This pilot showed that virtual power plants can evolve beyond simple peak-shaving into flexible, dispatchable assets that support grid reliability and affordability. It’s gratifying to know that our customers’ devices can contribute to a more resilient energy system without sacrificing comfort or convenience. m

PUF’s Kerry Worthington: Talk about the innovation and its positive impact.

Mary Bernard: I’m the supervisor of a team called Residential Program Performance, and we’re responsible for residential programs under the Save on Energy banner. I’m with the Independent Electricity System Operator, which manages the transmission grid in Ontario, among other things.

The innovation is the Save on Energy Peak Perks program, a residential demand response program that has grown to be the largest virtual power plant ever in Canada. We have opened it up to small businesses, as well. It essentially adjusts the smart thermostats of participants on high-demand days.

Participants get seventy-five dollars for enrolling in the program in the form of a prepaid MasterCard, and a twenty-dollar prepaid MasterCard for every year they stay in the program. We only adjust temperatures up to two degrees Celsius and normally do a pre-cooling prior to an activation event so people stay comfortable in their homes.

What’s innovative about our program – lots of places have smart thermostat programs – is how big it’s grown. We launched in late June 2023. By January 2024, we had reached one hundred thousand participants.

In June of this year, we reached two hundred fifty thousand participants. The growth has been exponential. We believe it’s the biggest in Canada and are excited to be part of this.

PUF’s Rachel Bryant: Do you know what the statistics are? Are you monitoring how much peak load reduction you’re seeing?

Mary Bernard: Near the end of August 2025, we’re at two hundred seventy-three thousand participants, and we’re seeing anywhere between two hundred to two hundred fifty megawatts of demand reduction as a result of the program.

In addition to Peak Perks, my team also does other innovative work. We have introduced several new programs into the Ontario market. Most of them are not province-wide programs.

We call them local initiatives, and all were new and different when introduced, and they include our first business distributed energy resource (DER) offer – an incentive to install solar panels – through our Save on Energy Retrofit program.

We started that in Ottawa and it was so successful, we’ve expanded it to be province wide. We also introduced regional adders through our Retrofit program for business. That intends to reduce demand in a specific geo-targeted area, where transformer stations are constrained and where reduced demand would defer investment.

We also have three programs in market in local areas. Two of them, one for residential, one for businesses, are air conditioning tune-up programs that are seasonal and only operate in the summer. These are called CoolSaver and Commercial CoolSaver.

Another local business program, called BizEnergySaver, directly installs variable frequency drives (VFDs) and lighting to help reduce demand in those areas. It’s operating in two regions, parts of Toronto and Ottawa.

We had two programs that are no longer in market but were also new and innovative for our suite of programs. One was called HomeEnergySaver, and it incented installation of heat pumps in electrically heated homes in constrained areas; that program has been replaced by a new program called Home Renovation Savings, co-delivered with Enbridge Gas, the major gas distribution company in Ontario.

The other new program my team introduced was called HomeSealSaver; it operated in a small residential community in Ontario. It didn’t do very well, but we learned a lot from it.

PUF: What was your role in this innovation?

Mary Bernard: With respect to Peak Perks, I lead the team that manages the program and has seen its unprecedented growth. I was not part of the team that developed it, but it was handed to me once launched. I have six people on my team, which doesn’t include the marketing group.

We’ve done all this through close partnerships with both our service provider, which is EnergyHub, as well as with the smart thermostat manufacturers. We meet regularly with Nest, ecobee, and Honeywell – we have a robust list of thermostats eligible for the program – to encourage them to market, tell how they’re doing in our program, how many of their thermostats are enrolled, what the other device partners are doing, and what more they could do.

We also have a great marketing team at the IESO, which has developed partnerships with influencers. We did three or four this year alone, and they have gotten us on television spots to push the program, especially as the cooling season was starting.

PUF: What was most rewarding in working on this innovation?

Mary Bernard: The most rewarding is seeing the impact it’s making on grid reliability. When we first launched Peak Perks, we reached out to our operations team and the control room and they said, “Call us when you’re at two hundred megawatts.” Now we’re there and it’s become another tool in the control room’s toolkit.

In Ontario, we’ve had four heat waves this summer with temperatures over thirty degrees Celsius. We’ve had the highest demand in our province that we’ve ever seen, and Peak Perks has been activated numerous times and has delivered the demand reduction that the control room was counting on.

It’s been rewarding, seeing how the work in energy efficiency and in demand-side management is contributing to keeping the lights on in Ontario when grid demand is high. Reducing demand is more cost-effective than building new generation. It’s important that we maximize our efforts on the energy-efficiency front to the extent we can. m

PUF’s Lori Burkhart: Please describe the innovation and its positive impact.

David Naylor: The acquisition of Rayburn Energy Station (RES) marked our first major step into local, dispatchable natural gas generation, and the planned RES II expansion builds directly on that foundation. Together, the two facilities add more than thirteen hundred megawatts of local generating capacity.

With electricity demand in Texas projected to climb twenty-five percent over the next decade, and northeast Texas leading that surge, this investment couldn’t be timelier.

These projects redefine what it means for a generation and transmission cooperative to lead through reliability investment. By locating generation close to the communities we serve, we reduce exposure to market volatility, ease transmission bottlenecks, and ensure power is available when members need it most, especially during peak demand and extreme weather.

The innovation is as much about process as technology: building new generation quickly, at competitive cost, and within the cooperative business model that prioritizes member value.

In a region where population and data center demand are surging, the benefits are immediate and measurable. Families, schools, and businesses now have added peace of mind that the power they rely on is generated locally and built for the future.

PUF: What is your role in the innovation’s development?

David Naylor: My role as CEO has been to work closely with our board to shape the vision and set the course for how generation could best serve Rayburn’s members. That has meant building and maintaining the right partnerships to move these projects forward, aligning internal and external stakeholders around a shared purpose, and clearing obstacles so our team could focus on execution.

While I’ve been deeply involved in setting the direction, the real credit belongs to the engineers, operators, and staff who turned that vision into reality. They designed the systems, solved the technical challenges, and worked tirelessly to bring these projects online.

In many ways, my role has been less about the nuts and bolts of technology and more about ensuring we had the right culture, processes, and partnerships in place to make innovation possible.

PUF: What was most rewarding to you about working on this innovative process?

David Naylor: What I’ve found most rewarding is the impact these projects will have on our communities. Knowing that families and businesses across North Texas can count on greater reliability makes all of the work worthwhile.

Equally rewarding has been watching our team rise to the challenge. These projects required speed, creativity, and perseverance, and our people delivered on every front. When talented professionals are trusted to innovate, they will exceed expectations. Seeing that in action has been one of the highlights of my career.

It’s also meaningful to demonstrate that a cooperative can lead the way in innovation, not just follow it. RES and RES II prove that local ownership and forward-looking investment can go hand-in-hand. For me, that combination of community impact and organizational growth has been the most gratifying outcome of all. m

PUF’s Kerry Worthington: Please describe the innovation and its positive impact.

Jon Cook: As senior Principal Analyst on the Resource Analysis and Planning Team at Salt River Project, my work is focused on resource adequacy, which is an element of the long-term reliability of the power system. Within the industry, we used to be able to study resource adequacy in a simplified way that focused on the peak demand hour for the year.

We planned our resources, and studied the risks associated with having enough resources available to serve that peak hour of demand in any particular year. As the resource mix is evolving, we need to study all other hours of the year as well, because we’ve got a resource mix that is no longer fully dispatchable and our supply fluctuates.

We need to incorporate how weather affects supply and demand as well as simulate the operation of new technologies, like battery storage, where only so many megawatt hours can be stored. Where you are going to use those megawatt hours becomes an important question that’s going to affect reliability.

The industry has made a lot of progress in updating and improving the tools, data, and methods used to do adequacy analysis. My work has been about two things. It’s about taking those advancements and incorporating them into SRP’s official planning processes, so taking the improvements, and getting them into our study and decision-making processes.

Second, is collaborating with folks internally and externally to continue moving those innovations forward. That could be with researchers outside of SRP or with consulting firms we partner with on specific projects. It’s trying to find areas where there’s still more research, and more advancement needed, and helping move those advancements forward, as well.

In terms of positive impact, these advances are meant to improve the accuracy with which we do our analysis. That means more accurately understanding the reliability risks to the system and improving our understanding of how different resource types contribute to reliability. Ultimately, that will allow us to make better plans, which are going to help us build a reliable system for our customers.

PUF: What was your role in the innovation’s development?

Jon Cook: The resource planning team is the home for resource adequacy analysis. Our group’s primary function is long-term planning for the company. That involves developing the resource plan that goes out for ten, twenty, or thirty years.

Part of that planning is understanding the reliability impacts of future resource mixes. We want to make sure the plan we build is going to be reliable under a wide range of conditions the system might face.

That’s where adequacy analysis comes in. We own those models and the data that goes into those models but also work closely with other groups at SRP to make sure we’ve got the right data.

PUF: What was the most rewarding to you about working on this project?

Jon Cook: It’s the collaboration, both internally and externally. Internally, it’s working with groups across SRP to find the right data and talk about how different parts of the system work and operate.

We talk through how we can best represent that in the tools we have. Those are interesting discussions. We’re trying to push these models forward into places where they haven’t been before.

There’s an element of newness that’s exciting, and it’s impactful when talking about the future reliability of the grid. That’s a big topic and it’s a big deal. It’s exciting to work on something that is impactful.

Then, it’s to have a foot outside of SRP, to talk to thought leaders and researchers across the industry who are thinking in deep ways about these tools, methods, and data.

We engage with them to bridge the gap between theory and concepts; to see how we do this in a real utility environment, and how we build a planning process around these ideas. That’s both exciting and rewarding.

PUF: How long did it take to drive some of that change internally and externally?

Jon Cook: It took a few months to scope out the limitations of the data, tools, and methods that we had been using. We needed to get our arms wrapped around all the advancements in the industry.

We decided we needed a new tool and a new model to run these studies, so we went out and got one. It took us six to eight months to build out a model of the SRP system within that new tool, test it, get the data in it, and make sure the results were reasonable and calibrated. It’s all those things that go into model building.

After that, it took another couple of months to start producing our first real new loss-of-load studies, debug those, see what they’re telling us, poke and prod to stress test, and make sure we’re not missing anything, that everything’s working the way we expected.

All in all, it took about a year from concept to having a functional model. Since then, it’s been about applying the model to various use cases, and questions, and then making continuous improvements to expand what we can do within the model.

There’s always new functionality being developed. There’re pieces of the model we haven’t used before that we think could be valuable. It’s a continuous improvement situation where we’re trying to keep pushing forward and do more in a better way. m

PUF’s Lori Burkhart: Please describe the innovation and its positive impact.

Brian D’Agostino: The Wildfire and Climate Resilience Center (WCRC) is far more than a building; it is the physical embodiment of our commitment to a safer, more resilient future. This center represents a fundamental shift in how a utility can confront climate-driven challenges.

By unifying our emergency operations, fire science research, climate adaptation planning, and risk mitigation teams under one roof, and powering it with AI-driven predictive models and real-time data, we have created a nerve center for climate resilience. The positive impact is profound: we are not only enhancing grid reliability and reducing outages for our customers but, most importantly, providing our region with an unprecedented level of preparedness.

This innovation allows us to move from reactive response to proactive prediction and prevention, safeguarding our communities, environment, and the critical infrastructure that powers our lives. It’s a model for the nation, proving that through innovation, we can meet the challenges of our changing planet head on.

PUF: Describe your team’s role in the development of the innovation.

Brian D’Agostino: This was never an endeavor we could undertake alone. My team’s role was to act as architects and conveners, strategically weaving together the brightest minds from across science and industry. We knew that the complex challenges of the future require unprecedented collaboration.

That’s why we partnered deeply with leading institutions like the Scripps Institution of Oceanography and the San Diego Supercomputer Center, integrating cutting-edge climate and data science into our operational DNA. We brought together emergency management agencies, academic researchers, and data scientists to develop the advanced tools and processes that make the WCRC so powerful.

Our role was to build the bridge between theoretical research and real-world application, fostering a collaborative ecosystem where academia and industry experts could exchange ideas. This center is a testament to what we can achieve when we break down silos and work toward a common goal.

PUF: What was most rewarding to you about working on this project?

Brian D’Agostino: As Vice President of Wildfire and Climate Science, the most rewarding aspect is seeing our nearly two-decade-long commitment to safety and innovation crystallize into a platform that actively protects our region. While we are proud that SDG&E has successfully helped prevent a catastrophic wildfire for nearly twenty years, we never take that success for granted.

This center ensures that the legacy of safety is not just sustained but accelerated for the challenges of tomorrow. Witnessing students in our Resilience Zone get inspired by climate science or hosting international delegations eager to learn from our operating model and team, fills me with immense hope.

It’s a powerful reminder that our work has a ripple effect far beyond our service territory. The greatest reward is knowing that every day, the WCRC empowers our teams to uphold our culture of safety, build upon our innovations, and deepen our partnerships to fulfill our most critical mission: to keep our communities powered and protected.

 

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