The Colorado Public Utilities Commission on June 10 balked at approving a billion-dollar price tag to shut down Xcel Energy’s five remaining coal-fired generating units — to be paid by customers — and instead is seeking more detailed financial analysis.
The proposed closing costs were part of a settlement agreement between Xcel Energy, the state’s largest electricity provider, and a group of state agencies, local governments and labor and environmental groups.
The commission, however, wanted more scrutiny of the finances. “We’ve expressed concern over understanding these costs,” Commissioner Megan Gilman said. “We owe that to the ratepayers.”
At issue is the financial method Xcel Energy is proposing to recover the closure costs. The commission said it wants Xcel to analyze a range of options, particularly using securitized bonds, which are seen as a potential cheaper financing mechanism.
“It is incumbent upon the company to model securitization and other options,” Commissioner John Gavan said. “We will need to take this off to a separate proceeding.”
As part of its electric resource plan — which forecasts the utility’s electricity demand for the next four years and the generating resources to meet it — and its Clean Energy Plan, aimed at cutting the utility’s greenhouse gas emissions, Xcel Energy is moving to close all its coal-fired plants.
The plan is to close the utility’s five remaining units — in Craig, Hayden, Fort Morgan and Pueblo — between 2027 and 2031 at a cost of a little more than $1 billion.
The bulk of that figure — $732 million — is for shutting the 750-megawatt Comanche 3 unit, in Pueblo. The $1.3 billion plant only went into operation in 2010 and will be the last to close at the end of 2030.
The plant has been beset with operating, equipment and financial problems, leading to more than 800 days of shutdowns. Initially, Xcel proposed running the plant until 2040 and then under pressure cut the closure date to 2035 and eventually 2031.
The commission also asked for more detailed data on project operation and maintenance costs for Comanche 3, while it is still in use. “We have seen escalating unexpected costs in terms of unit 3 maintenance,” Gavan said.
Xcel Energy is proposing using securitized bonds to finance the Comanche 3 closure which includes $690 million to pay for the unamortized part of the utility’s investment in the unit, $32 million in cleanup costs and $10 million in bond costs.
The securitized bonds are linked to a guaranteed revenue source from the utility and as a result can be offered lower interest rates, reducing overall costs.
For the three other units, however, Xcel Energy proposed, in the partial settlement of its resource plan submitted to the PUC, using other financing mechanisms, such as accelerated depreciation and a so-called regulatory asset.
A regulatory asset is a financial device in which all the costs associated with closing a coal-fired unit would be gathered in one place and paid off by customers over time — with Xcel Energy also getting an interest payment on the account.
The PUC move may be a concern for the settling parties, said Gwen Farnsworth, a managing senior policy advisor for environmental group Western Resources Advocates, which signed on to the agreement.
One of the goals of the settlement was to close the coal-fired plants as quickly as possible with Pawnee closing its coal-fired unit and switching to natural gas in 2025, followed by the Hayden 2 unit in 2027, and Hayden 1 and Craig closing in 2028.
Breaking the retirement costs off to a separate proceeding could delay the closure process and even lead to knock-on-effects in delaying the acquisition on new, clean resources, Farnsworth said.
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