Experts cite increasing necessity of undergrounding power lines
Energy industry experts agree that it’s important for investor-owned utilities (IOUs) to do more undergrounding of power lines to minimize the risk of electric wires sparking wildfires.
Not only does undergrounding enhance reliability and community safety by protecting power lines from extreme weather events, such as wind storms, ice storms, wildfires and earthquakes, it also results in less frequent outages, according to John Quackenbush, president of JQ Resources LLC, a New Buffalo, Mich.-based firm that assists clients with utility regulatory activities, provides strategic advice, and works to bridge the gap between the regulatory and investment communities.
And as extreme weather events increase, the reliability benefits of undergrounding correspondingly increase, said Quackenbush, who served as Michigan Public Service Commission (PSC) chairman from 2011 to 2016.
“IOUs should be authorized to do more undergrounding of power lines because of growing customer reliability benefits and reduced costs per mile,” he told Daily Energy Insider. “Undergrounding benefits have long been recognized, but sometimes penciled out as too expensive in the past.”
That’s partly what’s happening with the California Public Utilities Commission (CPUC), which is expected during its Nov. 2 meeting to consider two proposed decisions in response to Pacific Gas and Electric Company’s (PG&E’s) most-recent rate case, which includes increased customer rates to help cover safety investments like undergrounding.
The CPUC says the proposed decisions related to PG&E’s General Rate Case covering its operational and infrastructure costs for 2023-2026, strike a balance between strengthening the electric grid for the future and affordability.
But according to PG&E’s Chief Executive Officer Patti Poppe, the commission’s two proposals aren’t enough to keep PG&E customers and hometowns safe.
“In fact, they gut our long-term undergrounding program that would permanently reduce wildfire risk and cut funding for some critical gas-safety programs,” Poppe wrote in a Sept. 26 opinion piece published in The Mercury News.
Specifically, PG&E wants to move 2,100 miles of power lines underground over the next three years at an additional cost of $3.40 a month for the typical customer. And the utility confirmed on Oct. 11 that it’s on track to put at least 350 miles of power lines underground by the end of the year, achieving permanent wildfire risk reduction for a specific portion of its electric distribution system.
In comparison, the CPUC’s two counter proposals would fund as few as 200 miles over four years.
“We couldn’t agree more that the CPUC must make the safety of our customers its top priority,” wrote Poppe. “Unfortunately, neither of the CPUC’s counter proposals to our plan would do enough to keep our customers and communities safe.”
Ronald Brisé, former chairman of the Florida PSC and a previous member of the Florida House of Representatives, pointed out that IOUs should be allowed to underground in a meaningful way, at a rate that will produce measurable benefits to the grid.
“The PG&E proposal submitted to place about 2,000 miles underground in the next three years is reasonable considering that it will eliminate 98 percent of the risk associated with wildfires to those lines for a $3.40 per month cost to consumers,” said Brisé, a government affairs consultant at the Orlando-based law firm Gunster.
“For about $40.80 for the year, a 98-percent reduction in the risk sounds like a good deal to me versus addressing the same issue over 10-20 years if they are limited to 200 miles per year or even worse 50 miles per year,” he added. “The benefits to both the customer and utility are similar, cost effective, and timely risk mitigation results.”
The Florida PSC just last year helped support resilience efforts, which include undergrounding, by allowing $22 billion dollars to be invested in hardening the grid, Brisé said, adding that the Florida legislature in 2019 passed legislation requiring undergrounding of power lines in recognition of the benefits to the grid, health, safety and economy.
“Hurricane Ian cost Florida’s economy $112 billion and the cost would have been much higher if 98 percent of those that were able to take power within four days were without power for an extended period of time,” Brisé told Daily Energy Insider. “The state has found that investing in resilience yields very positive returns.”
Quackenbush also pointed out that Florida, Virginia, Wisconsin, and the District of Columbia have engaged in significant undergrounding.
“Florida stands out as a state that proactively addresses severe weather-related risks by incorporating undergrounding into its grid-hardening program,” he said, while “Michigan is engaging in strategic undergrounding pilot programs.”
PG&E’s Poppe says undergrounding reduces the risk of ignitions in areas at the highest risk of wildfire by nearly 98 percent. “There is no more effective solution to reducing the risk of wildfire ignition from electrical equipment,” she says. “However, the CPUC is proposing we instead install insulated overhead power lines, which by themselves only reduce ignition risk by 65 percent.
“Rather than prioritizing safety, the CPUC’s proposals call for less-effective wildfire mitigation measures,” added Poppe.
Peter Kenny, PG&E’s senior vice president of Major Infrastructure Delivery, which includes undergrounding, said the IOU’s team has learned and accomplished a lot in the past two and a half years since the company announced its 10,000-mile undergrounding program.
“That learning equates to greater efficiency and means we’re able to safely put power lines underground more quickly and reduce the cost per mile,” Kenny said.
For example, PG&E plans to put 2,100 miles of lines underground between now and 2026, with the annual mileage increasing from 350 in 2023 to 750 in 2026. Based on those miles, PG&E anticipates the cost per mile of undergrounding will decrease from $3.3 million in 2023 to $2.8 million in 2026.
Quackenbush said that the typical IOU already has undergrounded about 20 percent of its electric distribution system, a percentage that he expects to grow for most IOUs in order for them to upgrade reliability and resilience at increasing cost-effectiveness.
“Utility customers and regulators value reliability and resilience,” he wrote in an email. “IOUs, their customers, and regulators increasingly recognize that adaption, hardening, and resilience (AHR) investment is necessary to meet customer reliability expectations. Undergrounding power lines is a primary example of AHR capex.”
Quackenbush also said that utility commissions already scrutinize test year distribution investment for inclusion in rate base in rate cases. Undergrounding is one component of distribution capex, he said, and it’s contextually useful to expand that view of distribution capex to a five or 10-year window.
“More and more commissions are asking IOUs to submit multi-year grid plans for review,” he said. “Multi-year capex reviews are most useful when they conclude with the commission pre-authorizing or endorsing certain investments such as undergrounding. Some commissions are considering and approving multi-year rate plans.”
Moving forward, Brisé thinks that there should be a cost benefit analysis done and cost recovery mechanisms should be put in place to allow the investments to be made with a review of the costs in regular intervals. “In Florida we use cost recovery clauses to accomplish this,” he said.
Greater undergrounding efficiencies are achieved with improvements in trenching and directional drilling, added Quackenbush, who said that undergrounding also minimizes the need for tree trimming and reduces vegetation management costs during a time when city planners seek to increase tree canopies.
“As benefits increase and costs decrease, it makes sense that more undergrounding will prove cost-effective over time,” he said.
Utility commissions can support and enhance reliability goals by analyzing and studying undergrounding benefits and costs and then authorizing undergrounding investment where it makes sense, said Quackenbush.
“It is likely that some areas of a utility’s service territory have a higher benefit-to-cost ratio than others,” he said. “Cost recovery includes rate base treatment and adequate returns to support the undergrounding investment.”