Keeping coal plants open in Colorado could cost $87M, with consumers paying the tab 16%
By Mark Jaffe19%
7/21/2026, 10:21:00 AM
BS Summary: This article contains 22 faulty reasoning types, including Unattributed Quote, Negativity Bias, and Availability Heuristic, with Appeal to Authority as the most egregious example at 7.5% saturation with 111 hits. Analysis detected 1,183 faulty-reasoning hits from 1,488 analyzed words, generating a BS Score of 32.3% and a BS Rank of 16% (16,196 of 19,135 articles). This article is better (less manipulative) than 84.60% of the article peer group.
Colorado’s efforts to shut down its coal-fired power plants are being delayed by a shortfall in generation and a move by the Trump administration to keep old plants online.
The cost to Colorado customers to continue running those coal-fired plants will be somewhere north of $87 million, although analysts and utility officials say that the exact price is still difficult to determine.
The bulk of the bill — almost $67 million — comes from the continued operation of Xcel Energy’s Comanche 2 plant in Pueblo, according to a company filing with the Colorado Public Utilities Commission.
Repairing the pollution control equipment in one unit at the coal-fired Hayden Station, in Routt County, will cost up to $10 million.
Another tranche comes from the U.S.
Department of Energy’s emergency order to keep open the Craig Unit 1 plant, which had been scheduled to close at the end of December.
Just keeping the plant open has cost at least $6.5 million, according to an estimate by the Institute for Energy Economics and Financial Analysis, or IEEFA, a research group focused on clean energy.
Tri-State Generation and Transmission Association, the plant operator, is challenging the DOE order in court.
The state also has a lawsuit opposing the emergency order.
Xcel Energy, the state’s largest electricity provider with 1.6 million customers, said it is facing a shortage of generating capacity in 2027 and 2028.
Comanche 2 was scheduled to close at the end of 2025, but when the Comanche 3 unit was damaged and went offline last August, Xcel Energy received approval from the Colorado Public Utilities Commission to run the unit through the end of this year.
Comanche 3 is slated to be back in operation by Aug.
15.
The cost of repairing the unit is estimated to be $15 million to $26 million with insurance covering all but $4.6 million.
Still, Xcel Energy told the commission it is facing shortages of as much as 414 megawatts in the winter and summer of 2027 and in early 2028.
A megawatt is enough electricity to power about 300 homes, depending on usage, according to PK Energy Storage Systems.
Part of the gap comes from increased demand as the customer base grows, part from electrification of the economy and part from a lack of new generation, Michael Pascucci, an Xcel Energy regional vice president, said in PUC testimony.
Data centers are not driving this short-term generating deficit, Pascucci said
Market and supply chain disruptions have also hobbled efforts to add new generating capacity.
“Commercial operation dates for several projects slip several months or years,” Pascucci said.
“Additionally, some projects have outright failed due to increased costs or other constraints.
This has left the company seeking relief.”
Pascucci said outages at Comanche 3 and a unit of the Cabin Creek Pumped Storage Project, near Georgetown, “have exacerbated” the situation.
The Cabin Creek unit provides 162 to 183 megawatts of hydropower.
It is projected to be back online in December 2027.
The situation was complicated by the fact Xcel Energy in its planning had assumed its coal-fired, natural gas and hydro plants would be 100% available to meet peak demand and did not account for outages and underperforming plants.
Adjusting for those factors added to the generation gap.
To fill the hole the company wants to run the 335 megawatt Comanche 2 unit through March 2028 and repair Unit 2 at the Hayden Station, which will add another 65 megawatts of capacity.
In late November, Hayden Units 1 and 2 both went offline due to a partial collapse of a portion of a scrubber that removes pollutants from emissions.
After repairs, the 98 megawatt Unit 1 was brought back online in March.
Unit 2 is slated to return to operation in August.
The cost of the scrubber repairs is estimated by the company to be between $9 million and $10 million.
The unit is scheduled to close at the end of 2027.
The company, in a PUC filing, said the repairs are “cost effective relative to all other options.”
The Salt River Electric Cooperative and PacifiCorp each own a share of Hayden 2, but have not committed to pay for repairs, Xcel Energy said in a PUC filing.
The company is proposing recovering the repair costs as a direct charge on customer bills.
The cost of keeping Comanche 2 running through March 2028 — including capital and fixed costs, operating and maintenance costs and fuel — is nearly $65 million, according to a company filing.
State air quality fees add another $1.6 million.
Xcel Energy isn’t solely relying on the two coal-fired plants to fill its generating gap.
It is also looking to accelerate the start date of two new natural gas-fired turbines at its Fort St.
Vrain plant, use programs to reduce demand and expand power purchases from independent power producers.
Owners, state sue to end emergency order requiring Craig 1 to operate
Tallying the cost of keeping Craig Unit 1 open is harder to do.
On Dec. 30, 2025, one day before Craig Unit 1 was slated to shut, DOE issued a 90-day emergency order to keep the 45-year-old plant open and available for operation.
It had not been running because of a valve failure
The emergency order said that there was a risk of a generating shortage in the Rocky Mountain region.
The order was extended in April.
DOE issued emergency orders under a little used provision of the Federal Power Act to eight fossil fuel-fired power plants set to close, from Florida to Washington state.
The provision — aimed at ensuring power during emergencies or war — had never been used by DOE to stop plants from closing down.
Tri-State and the Platte River Power Authority, a co-owner of the unit, challenged the order administratively and are now in appellate court arguing “it requires the operation of an uneconomic resource” and that “members and customers must pay those costs even though neither Tri-State nor Platte River are experiencing these shortages.”
The association provides wholesale power to 39 rural electric cooperatives and public power districts in four states, including 15 in Colorado.
Its Nebraska and New Mexico members are not in the Rocky Mountain region.
In March, Colorado also sued the DOE in federal court.
“The order is an unlawful abuse of the department’s emergency authority and should be rescinded,” Attorney General Phil Weiser said at the time.
It is difficult to calculate cost and who will bear it since Craig Unit 1 is co-owned by Tri-State, Platte River, Xcel Energy and the Salt River Project.
Complicating the calculation is that the two orders to run the plant — in April and July — came from the Southwest Power Pool, the regional grid operator Tri-State joined April 1.
SPP has 154 members across 17 states.
Tri-State will bear the cost of keeping Craig Unit 1 open “unless a method is identified to share those costs with others in the region, who benefit from the operation of the unit,” Mark Stutz, an association spokesperson, said in an email.
“To date, a clear path for doing so has not been identified, and Tri-State continues to evaluate its options,” Stutz said.
The emergency orders at the eight plants have cost customers more than $300 million through May, according to an analysis by IFEEA researcher Seth Feastert.
Keeping Craig Unit 1 open is costing about $1 million a month.
At the same time most of these units are not making much electricity or burning much coal.
SPP issued an order in April to run Craig Unit 1 to help balance its Western grid and avoid outages.
The unit ran from April 10 to April 25 and then shut down.
The unit ran at an average of 17% capacity and generated 56,782 megawatt-hours, according to the U.S.
Energy Information Administration.
The story is similar at the other coal plants under energy orders.
The J.H.
Campbell plant in Michigan, which was scheduled to close in May 2025, was running at 46% capacity in the first quarter of 2026.
Consumer Energy, which operates the facility said over 10 months the costs for keeping the plant open were $185 million.
The SPP again asked Tri-State to run Craig Unit 1 from July 2 to July 6 and then it shut down again.
Ramping up and shutting down old coal-fired plants is both inefficient and expensive, Feaster said.
“No one really knows exactly how much this all is going to cost ratepayers.”
One other thing the orders aren’t doing is bolstering the coal industry.
The plants have consumed less than 1% of the 350 million tons of coal used for electricity between June 2025, when the first DOE orders were issued, and March 2026, according to IEEFA.
“These emergency orders aren’t helping the coal industry, they aren’t producing much electricity and there is no emergency,” Feaster said.
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