The Utah Legislature’s pro-coal bills passed both chambers and await Gov. Spencer Cox’s signature. They won’t take effect until May 1, but here are answers to questions about what lies ahead.
What’s next for two Emery County coal plants?
The Legislature adopted two bills, SB224 and HB191, with the intent of keeping Utah’s largest electrical utility from shutting down the Hunter and Huntington coal-fired power plants by 2032 — as Rocky Mountain Power announced last year.
Both bills deliver specific instructions to the Utah Public Service Commission, which sets rates and regulations for Rocky Mountain because it is a government-approved monopoly. HB191 instructs the PSC to follow the state’s energy policy.
SB224 goes further, essentially telling the PSC it must let Rocky Mountain pass along all costs of keeping the coal plants running to its Utah customers. Rocky Mountain does not have to prove the coal plants are the lowest cost, lowest risk option for Utah customers. Others have to prove they are not.
Will the retirement dates for the coal plants be pushed back?
On April 1, Rocky Mountain will put out an update to its 2023 Integrated Resource Plan, which the PSC has yet to formally acknowledge. Ratepayer advocates and others have questioned aspects of the plan, including whether the company has enough time to build smaller nuclear power plants to replace the coal plants by 2032, and that has prompted the update.
In other words, Rocky Mountain’s plant-closure dates were uncertain even before the Legislature passed its measures.
“The 2023 IRP Update on April 1 will include the company’s latest analysis on coal unit retirement dates,” said Dave Eskelsen, spokesperson for Rocky Mountain and its parent, PacifiCorp.
Is Rocky Mountain still pursuing clean power?
The utility’s plans are further complicated by the fact that it has suspended its request for proposals for new energy projects because it is coping with the financial impact of billion-dollar wildfire claims. In a world where electrical demand is growing fast and expected to grow even faster, acquiring new resources has become essential.
SB224 also creates a self-insurance fund in which Utah customers will contribute to a Rocky Mountain account that can be used for wildfire payouts in the state. That is expected to improve the company’s bottom line.
Eskelsen said the status of the request for proposals for new energy projects also will be addressed in the April 1 update.
Will Rocky Mountain customers’ monthly bills go up?
Once the PSC has signed off on the Utah Fire Fund (likely later this year), as the self-insurance account is known, Rocky Mountain will start collecting a fire fund surcharge from its Utah customers. For the average residential customer, that is expected to be no higher than $3.70 a month.
Legislators were warned by ratepayer advocates that favoring the coal plants would likely lead to higher costs for Utahns, but it could be years before the true impact of that is known. The first effects could come when Rocky Mountain asks the PSC to have Utah customers cover maintenance or upgrade costs at the plants, including environmental improvements that the company had earlier tried to avoid.
What changed for the plant in Millard County?
The Intermountain Power Authority, which has operated the coal-fired Intermountain Power Plant for 40 years, plans to shut down the facility next summer and switch to a gas-powered plant called IPP Renewed that will run on natural gas and hydrogen. The Legislature embraced SB161 with the intent of keeping the coal plant running after the gas plant starts up.
SB161 requires the power authority, which is run by 23 Utah cities, to file with the Utah Division of Air Quality for a new permit that would allow the gas plant and half the coal plant to continue operating.
Can the power authority update its air quality permit?
A consultant hired by the state said it is theoretically possible to update the permit without endangering the new gas plant, and legislators have said they don’t want to stop IPP Renewed.
But the state already has submitted its statewide plan for controlling ozone to the U.S. Environmental Protection Agency, which is analyzing the plan and has yet to approve it. That plan was contingent on closing IPP’s coal plant to meet federal air standards, so updating it to add back half the coal plant could make it harder to win EPA approval.
If the coal plant does continue, who will use the power?
No buyers have emerged so far. The major transmission line coming out of the plant goes to California, which has forbidden coal power after 2025. So any buyer of the power would have to either build new transmission lines to transport the power or locate the power near the plant in Delta.
That has brought speculation that a data center could locate there and use the power, but, generally speaking, technology companies that operate data centers have clean energy mandates and are not interested in a coal-fired center.
The consultant advised that a buyer of the coal power should be found before committing to continuing the plant, so legislators hope that a buyer can be found over the next year before it closes. But they will have to move ahead with updating the air quality permit before then.
What if the power authority doesn’t apply for the new air quality permit?
According to SB161, that filing must happen by June 30. If it doesn’t, the Legislature can assert its authority under the bill and take over the power authority. But it also is possible that the power authority could challenge the law in court.
“As approved, the bill imposes an expensive unfunded mandate on the 23 cities that own IPP to pursue a permitting process that will not benefit them,” said power authority spokesperson John Ward. “And the permitting process it imposes will likely trigger disputes with federal environmental regulators that will not only affect IPA but could harm other major emitters throughout the state.”
Correction: The photo caption with this story incorrectly identified the power plant. it is the Hunter Power Plant.
