Why the company wants to spend $77 million-plus to shore up generating capacity for 2027 and 2028
by Allen Best
Xcel Energy was going to get out of coal in Colorado by the end of 2030. It still plans to do so.
But the journey toward that goal post has become somewhat circuitous. Even two years ago, Xcel said it had some problem nailing down new generating capacity. That was not an uncommon problem, given the kinks coming out of Covid.
Then came another breakdown of Comanche 3, the largest and youngest coal plant in Colorado. That was last August. It was not the first lengthy downtime for the unit since it began producing electricity in 2010. Some questioned the value of spending the money on repairs for the unit at Pueblo given its retirement by the end of 2030.
Xcel said it needed Comanche 3. And while it was fixing Comanche 3, it needed to postpone the retirement of Comanche 2. That smaller unit, which was commissioned in 1975, the year that the movie Jaws debuted, had been scheduled to close by the end of 2025.
The Public Utilities Commission said yes, you can keep Comanche 2 operating and repair Comanche 3.
In northwest Colorado, Xcel also operates two coal-burning units at Hayden. In 2021, the company announced it would close Hayden 2 in 2027 and Hayden 1 in 2028. But again, there were problems.
The second unit was down for repairs late in 2025. It has been fixed but is not at full capacity. Getting that additional capacity by completing repair of the unit’s scrubber would cost $9 to $10 million. The repairs would be for a unit with a “limited remaining useful life but significant near-term benefits,” says Xcel.
All the while, markets have been tightening, says the company, making purchases of power from other suppliers problematic. “Market purchases are neither certain in terms of availability or cost, nor are they available in infinite quantities,” said the company.
On Tuesday, Xcel laid out what it wants to do going forward. It says it has concerns about near-term capacity shortfalls. The general term is “resource adequacy.”
Resource adequacy has been a “persistent and ongoing issue on the Company’s electric system the last few years,” said Xcel’s Michael V. Pascucci, the company’s regional vice president for planning and policy.
“Some flexibility/length has proven an important — but missing — component of our approved recent resource plans that I believe we need to keep in mind going forward,” added Pascucci.
Foremost in its explanation are worries about having enough electricity to meet demand in the summer of 2027, the winter of 2027-28, and the summer of 2028. By the end of 2028, the company seems to think it won’t be as worried about resource adequacy.
What Xcel proposes
• Key to the Xcel’s proposal is to keep Comanche 2 operating even after Comanche 3 is fixed and operating again. The company now projects the resumption of electrical production at Comanche 3 by mid-August.
“Comanche 2 operating through the first quarter of 2028 provides the highest levels of optionality and flexibility if other RA (resource adequacy) actions do not materialize,” said the company.
• Xcel also wants to repair the second unit at Hayden, adding another 64 megawatts of capacity — and use that capacity. The other owners of that unit, Salt River and PacifCorp, say they don’t want to share in the cost of the repair.
• At Fort St. Vrain, the gas-fired power plant near Greeley, Xcel has been adding two gas units to the existing six units. They will, when completed, deliver another 400 megawatts of capacity. The work is scheduled to be completed in January 2028. With $6 million incentives, the company believes there’s a good chance the new units can be operating by late October 2027, before the winter heating season picks up.
• Xcel already has contracts for electricity from owners of natural gas plants, and it proposes to expand those power-purchase agreements. It also wants to add another contract from another provider of electricity from natural gas generation.
• It can improve the demand-response programs, effectively shaving off-peak demands. Those programs include Critical Peak Pricing, Interruptible Service Option Credit, Peak Day Partners, Peak Partner Responses, Saver’s Switch, Integrated Volt-Var Optimization, and Electric Vehicle Critical Peak Pricing.
The plan presented by Xcel will add an incremental cost of $77 million to be applied against the bills of its 1.6 million customers in Colorado.
This is in addition to the cost at Comanche 3. The company now reports it expects to have Comanche 3 burning coal again by mid-August. Repairs will run somewhere between $15 million and $26 million. After insurance, Xcel expects the cost to come in at $4.6 million. Also on the hook are the co-owners of Comanche 3, CORE Electric Cooperative (25% ownership share) and Holy Cross Energy (8% share).
The cost of coal, of course, is more, as is the cost of coal for Comanche 2. The company projects the cost of operating Comanche 2 this year at $28 million to $33 million.
What happened?
How did Xcel get into this pinch? After all, it spends lots and lots of money on resource planning.
Pascucci, the vice president for planning, cited four reasons for the resource adequacy concerns.
First, the company’s planning had previously assumed the “dispatchable resources provided 100% peak contribution.” That assumption did not contemplate outages. He did not mention Comanche 3, but that would seem to be the obvious case, although he specifically mentions it elsewhere in his list.
Second, some projects that had been planned “have outright failed due to increased costs or other constraints.”
Third, load growth has grown from both electrification and customer growth. “To be clear, large-load customers are not driving these short-term needs,” said Pascucci.
Fourth, the Comanche 3 outage and problems with the Cabin Creek pumped-storage hydro project near Georgetown have “exacerbated the company’s near-term resource adequacy need.” Cabin Creek’s Unit B is assumed to resume service by December 2027.
Another background reason may be the increasing heat and risk of wildfires in the West. That comes from the testimony of John T. Welch, the company’s vice president of commercial operations.
Welch cites a report from the Western Electricity Coordinating Council that finds reliability concerns during the summer of summer 2026 about resource adequacy during “periods of extreme heat, and drought, which exacerbates the wildfire threat and can lead to diminished hydro output.”
The same organization said that “wide-area heat events or wildfires that affect resource and transmission availability across the Western Interconnection are a concern. The ability to import energy may be limited during these events.”
Welch also noted that constraints of existing transmission to other power providers west of Colorado is capped at approximately 188 megawatts. That is, incidentally, one of the problems that the Colorado Electric Transmission Agency, or CETA, wants to address.
Xcel says it conferred extensively with the staff of the PUC, the Colorado Energy Office, the Office of the Utility Consumer Advocate, Western Resource Advocates and the Sierra Club prior to making the filing.
“This is not to say that the filing is a consensus filing or that there is support from any particular stakeholders for the Company’s Preferred Portfolio,” wrote Zeryai Hagos, the company’s regional vice president for integrated system planning.
The scenarios examined ranged from no extension for use of Comanche 2 beyond 2026 to an even broader agenda of items. For example, it examined adding 50 megawatts of batteries, reciprocating internal combustion engines, and fuel cells.
Responses
How will the PUC respond? Hard to say, although it should be noted that Eric Blank, the chair, has cited concerns about resource adequacy. The PUC commissioners have also expressed worries about whether the electric grid in Colorado could stand up to demands if a heat dome such as hit the Pacific Northwest in June 2021 were to hit Colorado. In that heat dome, many people lacking air conditioning died.
As for others, the reaction from the Western Clean Energy Campaign’s Eric Frankowski was immediate — and highly skeptical.
“Until its last resource plan, Xcel viewed its coal assets as providing a 100% contribution to peak demand,” he said in a written statement. “Seriously? Its flagship coal plant is broken down as often as it’s running and the company modeled that as a reliable resource? They’ve known for a decade that Comanche 3 is a lemon and they still viewed it as a guaranteed resource. Unbelievable.”
Xcel, he added, “should be the one bearing all of the costs for digging its way out of the hole it made, not its customers.”
Also of note:
• The U.S. Department of Energy recently requested data from Xcel regarding any retirement plans for coal and natural gas units in its systems.
Will the Department of Energy tell Xcel it must keep the fossil fuel plants operating even if Xcel (and the PUC) do not want to? It has at Craig.
• The company says it expects to spend $54,000 for purchase of transcripts of the hearing associated with this proposal and other hearing costs. It wants to be able to charge its customers for this cost. It also wants to hire attorneys not already working for the company to assist in the case. For this, it expects to spend $300,000, a cost that again it wants customers to pay.
• Arrival of a regional transmission organization to Colorado was supposed to provide a more efficient way for utilities to share electricity. Arrival of the RTO created by the Southwest Power Pool on April 1 has had the opposite effect, according to Welch, Xcel’s vice president of commercial operations.
Price volatility in the market has occurred, and SPP has issued several resource advisories. These repercussions are not uncommon after the arrival of new market formations, said Welch, but will diminish over time. In the short term, though, it makes it harder for Xcel to be comfortable that it can secure electricity it needs for resource adequacy from other suppliers.
Editor’s note; An earlier version of this story said that the federal court had ruled that the U.S. Department of Energy had overstepped its authority in ordering a coal plant in Michigan continue operations. The court has not issued a written decision.
- Colorado’s energy milestone (elevator-ride version) - July 4, 2026
- Colorado’s milestone of 53% renewables (cup of coffee version) - July 4, 2026
- What if next year looks like this one? - June 25, 2026
Since Xcel’s “resource adequacy” is mostly for air-conditioning peaks on late summer afternoons, they might have avoided this at least partially by building or contracting more solar and batteries or pumped hydro, or at least fixing the PHES they have. But they can’t be totally blamed, I think the PUC stopping them from “overbuilding” and the ability of counties to slow/stop solar farms can’t be discounted.
As far as “volatility” or “resource advisories” from SPP; in the rest of the country and the world this has been or is being solved by batteries and solar. It seems pretty clear that “volatility” will be higher in smaller markets, and it seems absurd that CO utilities are in two different “markets,” and maybe some still haven’t joined any.
It seems that all players work in their own vaccuum? At what point in human history did we know about climate change, related temperature increases, water shortages etc. A comprehensive plan in my mind would start with imprisoning Trump and his cabinet, convert Xcel to a utility company that works for the folks of Colorado not a number of investors. The millions spend on a group of presidents and vice-presidents are clearly misplaced. Taking about resources adequacy.
This is a symptom of a wider political problem. That is that politicians are too wary of big and needed investment into the 21st century electric economy or are simply in the pockets of the fossil fuel/nuclear industry.
We can build big and fast if the political will can be mustered. We can do it with existing technology solar, wind, battery storage (home scale and utility scale), and geothermal (not the nuclear SMR fantasy). Will it be expensive? Sure, but so are a lot of things that provide nearly benefits of a clean electric economy.
All that is to say that this is a political problem not a technological one.
Solar is alright but Nukes do it all night!!
https://www.realclearenergy.org/articles/2026/06/18/solar_wind_and_the_cost_of_pretending_1189268.html
AI will continue to consume power at a scale the current renewables-only framework can’t support. Nuclear is the obvious answer, and the market is beginning to act accordingly. Americans can support cleaner energy without surrendering arithmetic. Anything less is just a very expensive way to feel virtuous for a while.
Joining SPP changed nothing physically. It may have highlighted the Resource Adequacy (RA) concerns, though. SPP has stout requirements for both summer and winter. When they say that there have been problems in recent years around RA; one possible thing that they are saying is that how they functioned as a vertically-integrated, locally regulated utility was not up to the regional standards required by SPP.
Although in Xcel’s defense, SPP runs a tight ship and is an industry leader in RA requirements. They recognized several years ago that RA was going to be a year-round, 34/7/365 concern and not just related to air conditioning. Renewables drive this change. This is especially true in winter, when solar output is significantly diminished and wind output is a bit lower as well. SPP upped the summer RA requirements substantially and added a winter RA requirement. All of their members that I work with have been scrambling to meet those requirements.
This excellent essay made me take a spot check of the wildfire outlook for today. The TL;DR is that fuels are in the 80-90% percentile of historical “energy content available for release” (the ERC percentile below) in Utah and Colorado, and we are still in June.
The National Weather Service has fire forecasts and discussions at https://www.spc.noaa.gov/products/fire_wx/overview.html
Today’s (June 26) shows an area of Critical Risk extends roughly from the US border near Imperial, California; up to south of Lake Tahoe; northeast all the way across Nevada and Idaho to south of the Grand Tetons; southeast to Carbon County, Wyoming; and due south across Colorado and the western edge of New Mexico to the US border. The Extreme Risk extends for several hundred miles on either side of the Colorado. It forms an oval from Provo on the North; to Arches NP on the east; the the Grand Canyon in the south; to eastern Nevada on the west.
It says about the Extreme Risk fire region and the Critical Risk fire region closer to us.
“…With very dry and receptive fuels across this region
(ERCs in the 80-90+ percentiles) and ongoing large wildfire
activity, these conditions will yield an extremely critical fire
weather threat across this region. Deep boundary layer mixing
coupled with the aforementioned mid-level jet will also promote wind
gusts to 45 mph. A more expansive area of elevated to critical fire
weather concerns is expected across adjacent areas of the Great
Basin where modestly weaker sustained surface winds (generally 15-25
mph) are forecast to overlap very low RH values of 5-20%. An
extended period of critical wind/RH conditions (perhaps 10+ hours
for some locations), poor overnight humidity recoveries, and
residual gusty winds are forecast.
…Colorado Plateau…
Increasing mid-level flow and ascent ahead of the approaching
mid-level trough (coupled with dry boundary layer profiles and PWAT
values of 0.5-0.8”) will support the potential for isolated dry
thunderstorms this afternoon from northwestern New Mexico into much
of western Colorado. While storm motions are anticipated to be
generally 20-30+ kts, pockets of heavier rainfall totals are
possible, especially across northwestern New Mexico and southwestern
Colorado where the latest guidance suggests PWAT contents and storm
coverage may be locally greater. Thus, a mix of wet/dry
thunderstorms is likely. Pockets of lingering receptive fuels (ERCs
in the 80-90+ percentile) will continue to be receptive to lightning
ignitions, however, and concerns regarding any lightning ignitions
increase as multiple days of critical fire weather conditions are
expected this weekend.
Excellent points.