But Hurricane Wilma, in 2005, prompted utility providers to seek approval for large-scale resiliency upgrades to systems.
For example, Florida Power & Light (FPL) spent $5 billion in the last 15 years on projects to strengthen its grid. Work included hardening main power lines that serve police and fire stations, hospitals and 911 centers.
FPL annually reviews about 15,000 miles of line, trimming vegetation where needed, and installed more than 172,000 smart devices that automatically detect faults, reroute power or provide the utility with additional situational awareness when an outage happens, according to spokesperson Marie Bertot. FPL saw the fruits of its efforts in 2017 after Hurricane Irma, Bertot said. Impacted substations were up and running a day after the storm, compared to an average down time of five days after Hurricane Wilma in 2005.
"During Irma, power for 546,000 of our customers already had been restored before it was even safe for our trucks to roll (sustained winds were still blowing at unsafe speeds)," Bertot said.
But the work wasn't done.
The utility noticed over time its overhead lines were not as reliable as underground ones, despite ongoing upgrades to its systems.
Under normal circumstances, underground lines perform 50% better than their overhead counterparts. In the aftermath of the hurricane, underground lines performed significantly better.
The utility launched a pilot program to explore cost-effective ways of moving lines underground the following year, and continues its work to bury lines today.
Oklahoma's Situation
Florida doesn't hold a monopoly on the need to improve power reliability in the country. They aren't even the only ones with natural disasters powerful enough to knock grids out for days at a time.They also aren't the only ones to put in work moving lines underground.
Edmond Electric, an electrical service provider owned by the Oklahoma City suburb, is in an enviable position compared to some of its counterparts in surrounding communities and in other parts of the state.
Glenn Fisher, director of Edmond Electric, said the system's substations take power from transmission lines and distribute it to its 42,000 customers using about 900 miles of line. About half of its distribution system is underground.
In Edmond, the burial of electrical services to a new home or business is required by code, and has been a practice most developers have followed for decades anyway.
Fisher said most of what is underground today in Edmond was put there when it was initially installed during the community's past several decades of rapid growth.
However, that doesn't mean the utility hasn't done some projects to move overhead service underground.
The utility dived into work initially when it opted to move a neighborhood-wide overhead distribution system underground about two decades ago, after determining it was in danger of collapsing.
Other targeted projects have been completed since, and Fisher said Edmond Electric is evaluating some trouble spots in its system now after the October ice storm to see if moving underground might be possible to upgrade services in those areas.
"When you have an overhead system in an older part of town, you typically have a lot of trees. We don't trim on private property unless we have an easement, and we don't trim around secondary (service drop lines) distribution at all. So, to improve reliability, we took all of those services underground," Fisher said.
There's no doubt, he said, that moving overhead systems underground improves service reliability for customers.
But, he said, getting the best bang for your buck matters when the costs run anywhere from $435,000 "on a good day where you have a clear field to dig in" to $2.5 million a line mile — a cost ranging from about $82 to $475 a foot.
As part of a project where the utility buried a distribution line during a road rebuilding project, for example, it had to find room in an easement that already was occupied by other utilities like water and natural gas lines and telephone/data trunks. The distribution line had to be placed 18 feet underground, sending that project's cost to the higher end of that scale.
Even on private properties, the locations of decks, landscaping, swimming pools and outdoor storage sheds pose additional obstacles that can add to the utility's cost to do underground work, Fisher continued.
"Especially when you start looking at an older developed area, you are competing for space, and it gets really difficult to do that when you start taking things underground. In some situations, we have rerouted some things to make our system more efficient, and have had to go in and ask property owners for additional easement. But a lot of times, that is difficult to acquire because they don't want to give up that space."
Fisher said utilities are always faced with the task of evaluating a potential expense of an improvement against numbers of customers it would benefit.
"We always try to put our dollars where the most customers are served."
PSO's Efforts
Steve Baker, PSO's vice president of distribution operations, agrees that moving an overhead distribution system underground can provide an upgrade in service reliability to customers.Direct comparisons between areas where PSO has taken overhead systems to ones that are underground are difficult to make, given Oklahoma's weather patterns are constantly shifting and because upgrades have only involved pieces of various distribution circuits at any one time.
Still, service improvements have been observed, at least anecdotally.
"It helps both us and customers in a number of different ways. We certainly don't see the numbers of outage cases or the amounts of damage that we had to our systems in areas where those conversions occurred," Baker said. "That enables us to focus our restoration efforts elsewhere when storm events happen."
The utility, a subsidiary of American Electric Power, holds a distinction in Oklahoma of being the only regulated investor-owned utility that has sought and received approval for a $23.7 million annual rider — a fee added to customers' bills — to move underground parts of its distribution system.
It received that authorization in 2005 after customers in some parts of the Tulsa metropolitan area rejected the utility's efforts to increase its vegetation management efforts on lines that served their homes and businesses.
Starting in 2005, PSO spent about $57 million to complete 38 conversion projects mostly in Tulsa, but also in Bartlesville, Lawton, McAlester and Weatherford, that involved more than 100 miles of distribution lines serving about 9,000 of its customers.
"There are a lot of challenges to converting existing overhead to underground in already developed areas," Baker said. "You have got a lot of landscaping, concrete and other types of pavement, just a lot of things you have to work with that you wouldn't have to deal with if the original installation of the system had been done underground."
The utility estimated going in it would have to use directional boring crews to install at least three quarters of the needed line, and deployed about 200 workers to carry out the job. It also hired licensed electricians to convert meter bases for affected Tulsa customers at the utility's cost so that they could accept their power from underground.
"It was tough the entire way through," Baker said. "Because we were working on customers' properties, we had to have 9,000 individual discussions with homeowners to get approval to start projects involving their properties."
PSO has also spent another $29 million on smaller overhead to move underground line conversions impacting another 2,500 or so customers as ways to upgrade pieces of its systems that had chronic reliability issues.
Because the work is so expensive, Baker said PSO has refocused its program since 2011 either to target moving underground pieces of its system that benefits numerous customers, rather than just a few or one, or to make other types of improvements geared toward enhancing reliability on a broader scale.
In 2018, it asked for a $50 million annual rider for a five-year period to aggressively modernize its distribution system (the proposal included smart grid technology upgrades and a plan to more quickly replace aging poles and related infrastructure). In a jointly stipulated settlement ultimately approved by elected members of the Oklahoma Corporation Commission, it was authorized to recover up to $40 million between the start of 2019 and October 2021 to make various smart grid improvements. The accelerated pole replacement plan was dropped.
"Where you can do other types of work that harden and make portions of your system more resilient to weather impacts for a greater number of customers while spending the same amount of money, then you get more value for what you are spending. We still take overhead systems underground, but only where it makes sense to do that," Baker said.
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