Transmission lines lead away from the coal-fired Intermountain Power Plant near Delta, Utah on Monday, Feb. 3, 2025. (Photo by Spenser Heaps for Utah News Dispatch)
As PacifiCorp readies to sell its Washington service area to Gem, an affiliate of Portland General Electric Company, state watchdogs and advocates are skeptical, saying the deal in its current form may not be in the public interest.
The company has proposed to sell its Washington service area for approximately $1.9 billion. But before that, it needs the approval of the public service commissions in the states where it operates: Utah, California, Idaho, Oregon, Washington and Wyoming.
Operating PacifiCorp in six states with different policies has had its “share of difficulties,” Dick Garlish, president of Rocky Mountain Power said in a testimony to the Utah Public Service Commission in April. For example, other PacifiCorp states, excluding California, refuse to pay for costs associated with the Washington Climate Commitment Act, including making its natural gas Chehalis power plant compliant with the law.
“As a result, PacifiCorp has been forced to absorb approximately $45 million annually of the actual costs of providing power from the Chehalis plant,” he said. “This is unsustainable, and exacerbates the financial challenges PacifiCorp now faces.”
The company has been under extraordinary financial pressure in recent years, he said in his testimony. The company’s credit ratings and financial outlooks have been going down, according to different firms, stemming predominantly from wildfire liability issues and “adverse regulatory outcomes,” Garlish said.
That’s especially true in Utah, where Republican leaders have pushed the company to draft studies contemplating splitting the company into two systems, one serving blue states and another for red states with fossil-fuel focused energy strategies.
Application is lacking
When news about the Washington assets sale broke in February, Utah House Speaker Mike Schultz, R-Hooper, was enthusiastic.
“We want a divorce from the three states that don’t look like Utah,” he said then. “This is the first step forward, as I’ve had the conversations to talk with Rocky Mountain Power, they’re excited. This will be a great benefit to the citizens of the state, helping keep lower prices here in the state of Utah.”
Utah lawmakers push to split PacifiCorp as blue states move away from coal
However, different watchdogs and advocates, including the Utah Office of Consumer Services say that Rocky Mountain Power’s application is so far flawed and that the company failed to meet its burden of proof to show the sale would be in the public interest.
Garlish said the service area transfer would not harm Utah ratepayers. It would even be positive, he said, because PacifiCorp is expected to provide a $68.9 million rate credit to customers in Utah over three years, in addition to other benefits.
The sale, he said, also “improves PacifiCorp’s system load and resource balance, improves PacifiCorp’s financial position and helps manage its risk, and relieves PacifiCorp from the obligation to meet Washington’s climate laws.”
But, Leah Wellborn, a consultant speaking on behalf of Utah’ Office of Consumer Services, said in testimony before the public service commission in August that the company is only offering a short-term view of the sale’s long-term impact, and flaws in the company’s analysis led to an “overestimation of the benefits to Utah.”
A different economic analysis conducted by the office shows “net harm in the post-transition period to Utah,” Wellborn said. The Washington buyer is also getting the resources at a cost below market value.
“Any allocation of the gain on the sale to Washington or PacifiCorp should not be at the detriment of the remaining jurisdictions, given the negotiations on price were determined by (Portland General Electric) and PacifiCorp, and not the states facing increased costs due to the resource reallocation assumed and negotiated by the Company,” she said.
About $504.7 million of the $1.9 billion is the gain on the sale. PacifiCorp is proposing to retain 32% of that and share the remaining 68% with its customers. That would mean $68.9 million for Utah. However, for advocates that amount should go way up.
Because of the economic harms and risks of the sale, the office is recommending imposing several conditions to approve it, including additional rate credits of $106 million, which, with the $68 million proposed by PacifiCorp would make up a total of $175 million. They also want a commitment from the utility to reduce expenses and continued monitoring during the transition period, ensuring “risk of excess costs borne by shareholders, rather than customers.”
PacifiCorp hasn’t filed official replies to those comments. Simon Gutierrez, a spokesperson for the company said in an email on Friday “we welcome the opportunity to demonstrate the clear public benefit of this transaction through the Commission’s review process.”
The risk of coal and natural gas
The Utah Division of Public Utilities hasn’t reached a definitive conclusion, but said in testimony the company’s paperwork lacks updated depreciation schedules, decommissioning costs, estimates of the remaining life of the power generation that PacifiCorp seeks to reallocate, as well as meaningful net present value or risk studies.
The sale would provide numerous benefits to Utah ratepayers and could help further Utah’s energy goals, Matt Pernichele, a Utility Technical Consultant for the Utah Division of Public Utilities, said in the August testimony. The full company’s net power costs would decrease if the sale is approved, and could allocate additional generation to Utah, which would lead to economic growth.
However, that would also represent risks to Utah, Pernichele said, as PacifiCorp operates many aging coal and natural gas power plants, as well as some wind farms. The company hasn’t released a depreciation study of its coal plants, which went into service between 1955 and 1983. But the last depreciation study, published in 2018, called for all of them to close and be replaced by 2042.
Despite that, the company “seems to have few plans to replace these plants,” Pernichele said.
“Due to increased demand, current lead times for combined cycle gas power plants are five to seven years. This leads to the strong possibility of having to replace at least 5.5 GW of dispatchable generation in the span of a decade or so,” he said. This would be expensive and likely require PacifiCorp to greatly increase its already large debt load.”
If those plants were to retire without replacements in place, market prices in the Utah, Idaho and Wyoming service area would probably increase, Pernichele said. Operating and maintaining thermal plants also becomes more expensive as they age. So, there should be a new depreciation and decommissioning study before making a final reallocation of the company’s assets.
Thermal generation also emits greenhouse gases and other pollutants, which represent substantial risks if there are any regulatory changes during their remaining operating life.
“Such regulations could impose costs from additional pollution control measures, impose restrictions on operating times or overall emissions that would make them less economical to run, or even cause them to shut down prematurely,” he said. “Under the Company’s proposal, Utah ratepayers would take an additional 8.1 percent of these risks along with an increased allocation.”
Wind farms, as a group, are also producing less energy than expected. Their cost has, however, stayed the same, making the power from these facilities more expensive than anticipated, so the agency is also recommending a thorough economic analysis of the plants.
