When it comes to reliability metrics, public power utilities have long maintained an edge compared to their investor-owned and cooperative utility counterparts. In the latest data from the Energy Information Administration, in 2020, public power utilities had an average System Average Interruption Duration Index, or SAIDI, for non-major events that was 50 minutes shorter than the average for IOUs, and more than 90 minutes shorter than the average for cooperatives. For major events, public power utilities reported less than half the average outage time for customers — about 3.5 hours compared to almost 8 hours.
Part of this is a matter of geography. A recent report from the Minnesota Public Utilities Commission regarding declining reliability at Xcel Energy went so far as to suggest that the IOU investigate selling portions of its service territory in southern Minnesota to neighboring utilities. The report noted that reliability was worse in the utility’s rural areas, and that staff might have to drive for hours to even reach an outage location to perform necessary restoration work.
Aside from usually having smaller service territories, allowing lineworkers to quickly arrive on the scene for repairs, public power utilities take steps to keep their reliability edge — continually improving for their customers and preparing for the future.
The following reflections from public power utilities that have earned the eReliability Tracker Certificate of Excellence, awarded to utilities that subscribe to the service and fall within the top quartile for lowest average SAIDI over time, revisit how these utilities prioritize reliability.
Identifying Needs
According to Todd Dusenberry, assistant general manager at Vernon Public Utilities in California, an important start to ensuring the public power utility maintains its high standards is to track and measure the number of outages, the cause, and the duration. From there, the data helps the team to identify aging infrastructure and equipment and proactively develop a replacement program that helps the utility budget to minimize unanticipated large capital costs.
Although its service territory is only 5.2 square miles, VPU has a number of large commercial customers that run 24/7, so its peak load of approximately 200 megawatts is comparable to many of its neighboring publicly owned utilities. These customers can’t afford extended outages, said Dusenberry. About half of the utility’s outages are momentary, which VPU defines as lasting less than 10 seconds.
In the last few years, VPU has embarked on several efforts to improve system reliability, such as converting overhead distribution lines from 7 kilovolts to 16 kilovolts; installing high-capacity, steel-core-stranded overhead conductor wires; integrating mid-circuit automatic reclosers; and replacing a majority of its substation transformers. The majority of VPU’s system is overhead, and most outages are mylar balloon- and bird-related, so the conversion from 7 kV to 16 kV creates larger spacing between conductors on poles, which, in turn, reduces the vulnerability of phase-to-phase contact and helps reduce the number of outages.
Replacing the lines is only one type of upgrade VPU has made. The utility has also added several technologies to boost its reliability.
“While all our distribution lines have automatic circuit reclosers, VPU has installed mid-circuit reclosers to further limit the impact of outages in areas with higher risk,” said Dusenberry. “Additionally, we’ve reconductored our lines and installed aluminum conductor steel-reinforced cable so when there is an interruption on the line, it minimizes sustained outages and helps with restoration efforts.”
Dusenberry also credited VPU’s efforts to replace the majority of transformers at substations and an aggressive pole replacement plan with reducing outages related to aging equipment.
“The eReliability Tracker has been extremely helpful as it offers a level of automation, where we are able to easily input the information, the tracker aggregates data, and then provides comparative analytics,” he said. Having the comparative analytics allows VPU to identify efforts to proactively focus on improving system reliability. Prior to utilizing the eReliability Tracker, VPU was manually tracking stats on a spreadsheet and then receiving comparative data via a third-party consultant. Dusenberry noted that this data from other utilities was limited and took longer to access, which reduced VPU’s ability to be responsive.
“It’s not so much the data, but the ease with which you can extract it,” he said.
The metrics VPU gets also help staff respond to customer inquiries within minutes, particularly from large commercial customers, who make up approximately 70% of its load. Staff can extract details on outages from the tracker to develop a reliability report on a circuit.
Relaying metrics to customers also means knowing what is meaningful to them.
“From a customer perspective, I have always found [customer average interruption duration index to be] an impactful metric. The amount of downtime is exactly what the customer remembers,” said Kevin Sullivan, general manager at Ashburnham Municipal Light Plant in Massachusetts. The public power utility serves a primarily residential community of about 3,000 customers in the north central part of the state. “If [CAIDI] could be held to 60 minutes or less, I am pleased and have always found that the customer understands that an outage will happen, albeit infrequently.”
“From a utility perspective, SAIFI provides me with a 30,000-foot view of outage that I can offer a comparative to by month, year, etc.,” Sullivan added.
Staying Ahead of the Game
The City of Kirkwood Electric Department in Missouri is also proactively working to harden its distribution system to boost reliability. It identifies needs for system upgrades via analyzing its reliability data.
“It’s the analytic way of looking at things instead of firefighting, because we used to react and we knew the calendar. So, we’d say we’ve got to make sure we’re going to be available with crews and we have a mutual aid agreement — all the things that you would do to brace yourself and get ready for the inevitable,” said Mark Petty, director of the Kirkwood Electric Department.
But now, because Kirkwood Electric has the data associated with power outages, “the history of them, where they were located, what the causes were, we’re able to do proactive things,” he said.
Kirkwood Electric is able to have a capital program that “gets out in front of outages and does some things to try to slow them down or prevent the impact of the weather on us,” Petty said. First and foremost, the utility focuses on tree trimming.
He noted that during the pandemic, “we had to suspend a lot of our contractor access and operations just because we were trying to keep people safe.” Therefore, the utility was not able to work on things like the hardening of the distribution system and tree trimming. “It came back to haunt us in the hurricane season of June, July, and August of last year,” Petty said.
Starting in October 2021, personnel were deployed into the field and able to “do a lot of good tree trimming in particular,” so that by the time colder weather and snow arrived in early 2022, “we were able to have great reliability.”
“Tree trimming is without question the single biggest task for the greatest gain,” noted Sullivan. He said that Ashburnham Municipal Light Plant works with an arborist annually to provide a growth study and to ensure its trimming methodology is current.
Increased Technology
“Utilities must take every advantage possible to ensure reliability,” said Sullivan. “Reliability coupled with low rates and great customer service should be the hallmark of every public power utility.”
Being able to extract meaningful information about reliability often means needing to rely on an increasing array of technologies to provide enhanced data.
“You’ve got to be a smart utility. You’ve got to have that AMI system that gives you the information real time on your outages and then helps you to fold that in for your analytics later on,” stressed Petty. “You’ve got to have a GIS system. You’ve got to train your people to be able to use the analytics or the information. You get to those things — [and] that means you’ve been able to pivot from being reactive to starting to be analytical — and it certainly helps during outages.”
Embracing technologies, like drones and infrared camera imaging, has been an extremely useful tool for VPU, and it has used such technologies to conduct assessments and evaluations on electric infrastructure. Dusenberry credits such technologies as useful and effective for hard-to-access areas as they help to proactively identify potential equipment failures. VPU utilizes infrared camera imaging to visually inspect wires and substation conductors and equipment, and then the utility proactively replaces or identifies any equipment that shows signs of the potential for overheating for near-future replacement.
Taking advantage of this technology meant needing to train staff on how to fly a drone and obtain certification for infrared camera use. Moving forward, VPU is looking to outfit drones with infrared cameras to help elevate visual inspections and is installing automation equipment such as reclosers and converting equipment to smart grid applications.
“Vernon Public Utilities is always exploring technology that can improve our responsiveness, safety and reliability and connect with other APPA utilities to learn about what has helped in their service territories,” added Dusenberry.
He mentioned that as a smaller utility, having auto reclosers tied to SCADA helped to enhance efficiencies. Having such data easily accessible across the utility helps not only with identifying and resolving any issues, but also in letting business customers know in a timely way the likely duration of any outage and what steps are being taken toward a resolution.
Technology, such as auto reclosers, and simpler tools, such as wildlife fault protectors, could be helping to lower the incidence of outages public power utilities see that are caused by a common nemesis: squirrels. Data from the eReliability Tracker from 2017 to 2021 shows that the average rate at which public power customers experienced squirrel-caused outages in 2021 was lower than in each of the preceding years in 10 out of 12 months of the year. The average rate of 1.4 squirrel-caused outages per 1,000 customers in 2021 was the third-leading cause of outages, behind tree-caused outages and utility maintenance and repairs.
