Xcel Energy is moving to close a gap in electricity supplies that, for the moment, leaves the region short on electric generation and reserves for the summers of 2023 and 2024.
In filings to the Colorado Public Utilities Commission the company said it is facing “resource adequacy challenges” and that a waiver to add more resources is “critical to serving the company’s customers.”
The key to meeting next peak electricity demands are two large solar projects in Pueblo County that will miss their end-of-year deadlines, but which the utility hopes will be online by the end of next summer.
“This new capacity is absolutely essential,” Colorado Public Utilities Commission Chairman Eric Blank said at a commission meeting Wednesday.
Xcel Energy got into this spot because solar generation for which it contracted as part of the company’s Clean Energy Plan ran aground or was delayed.
In other regions — notably Texas and California — such shortfalls have led to power outages, the threat of rolling blackouts and emergency warnings to reduce electricity consumption.
Some Xcel Energy customers got a taste of what a shortfall in electricity can mean on a broiling Aug. 30, when the Comanche 3 power plant failed, pinching supplies. The utility locked the thermostats of 22,000 customers participating in its AC Rewards program, limiting air conditioning in those households.
Threat of peak shortage common in the warming climate
Xcel Energy, Colorado’s largest electricity provider with 1.3 million customers, is not alone in wrestling with adequate resources in the transition from fossil fuels to clean generation.
In its 2021 reliability report, the New York State Independent System Operator, which runs the state’s grid, said reserve margins — the extra cushion of generating capacity — were shrinking across the state.
“Fossil-fueled resources are retiring, primarily due to emissions concerns, at a faster pace than clean-energy resources are entering,” the report said. “As we have seen in California and Texas, operating a reliable electric grid requires a flexible and well-planned transition to the grid of the future.”
The closures of at least six coal-fired plants around the country have been postponed over concerns about adequate generating capacity. Indiana’s NiSource, for example, cited an 18-month holdup in a new solar project as the reason for delaying the shutdown of a coal unit to 2025 from 2021.
Xcel Energy’s dilemma led Blank to ask whether the closure of the Comanche 1 power plant, slated for the end of this year, should be delayed. The company said that it was not considering such a step.
“The entire nation is going through a transition,” Robert Kenney, CEO of Xcel Energy’s subsidiary Public Service Co. of Colorado, said in an interview. “We do have to retire coal units, but our path has been deliberate and intentional. … We are bringing on new capacity.”
It is a complex balance, said Charles Teplin, a manager in the electricity practice at energy consultant RMI. “This is a transition that has to be carefully planned. It’s been complicated because a lot of projects have fallen behind or need to be renegotiated because of the supply chain shortages.”
Another element bedeviling adequacy goals is the changing climate. “We are actually seeing climate change show up, with the swings to hotter and colder temperatures,” Teplin said. Either way may test energy systems.
The PUC was so concerned about the role of climate change and extreme weather it required Xcel Energy to do an assessment and file a report on their impacts on resource adequacy.
“In the summer of 2023 we could have a couple of hours or a couple of days where it could get pretty grim,” Blank said, during a June hearing on Xcel Energy’s resource adequacy.
In the last few months Xcel Energy has been able to fill about two-thirds of its projected 2023 deficit, leaving it short 49 megawatts for the summer of 2023, according to a PUC filing. In 2024, the company is projecting a 270 MW shortfall. Xcel is projecting a peak load of 7,145 MW in 2024.
Those estimates, however, are based on two large solar projects that are under construction, but delayed, coming online next year.
In 2018, Xcel Energy adopted a $2.5 billion Clean Energy Plan that was designed to close all the utility’s coal-fired plants by 2040 and add 1,810 MW of wind and solar generation and 275 MW of battery storage.
The utility boosted the program in 2021 to $8 billion with 3,900 MW of wind and solar, and coal plant closures running between 2022 and 2030.
Bids for 11 new generation projects were selected in 2018, eight of them from independent power producers, who would build the facilities and sell the electricity to Xcel Energy.
Two of the developers then told Xcel Energy they could not deliver the projects as bid and a third was unsuccessful in getting permits from Park County.
Those three projects — Owl Canyon, Piccadilly and Hartsel — were supposed to supply 257 MW of generation and 50 MW of battery storage.
Xcel Energy awarded new contracts for two new installations — the 293 MW Sun Mountain solar farm in Pueblo and the 110 MW Front Range-Midway in El Paso County — to replace the failed projects.
In 2019, Xcel Energy also took over the $745-million Cheyenne Ridge wind farm project when its developer TradeWind Energy indicated that it could not meet its 2020 deadline.The 500 MW wind farm, which straddles Cheyenne and Kit Carson counties, was completed in September 2020.
Shortage projected even with coal-fired generation online
The pace for replacing Xcel’s coal-fired units— all six are still operating — and meeting growing electricity demand was further upended by the COVID-19 pandemic and a U.S. Commerce Department antidumping investigation to see if Chinese manufacturers were circumventing solar panel tariffs.
Xcel Energy owns and operates coal-fired plants in Hayden, Pueblo and Brush.
The pandemic disrupted global supply chains and the federal investigation cut the flow of solar panels into the U.S. The tariff investigation led to the postponement or cancellation of 318 projects nationwide, according to an analysis by the Solar Energy Industries Association, an industry trade group.
In 2021, Front Range-Midway, which also includes 50 MW of storage, told Xcel Energy that due to material and equipment procurement problems its completion would be delayed 15 months to March 2024.
Two other solar projects, Neptune and Thunder Wolf, east of Pueblo, were also behind schedule.
“The failure or delay of these projects has created planning challenges for the company in ensuring the timely and cost-effective supply of resources to serve the needs of our customers … and has exacerbated the capacity constraints facing the company in 2023 and 2024,” Xcel Energy said in a PUC filing.
When Xcel Energy executives briefed the PUC this past June, generation looked tight for the summers of 2022, 2023 and 2024. Summer, with its heavy use of air conditioning, traditionally has the greatest peak demand.
Electricity supplies for this past summer also grew tighter because demand increased by 210 MW over initial projections. This was the result of a rise in residential and commercial demand.
The additional residential demand came from the “lingering” pandemic stay-at-home effect, said John Welch, Xcel Energy vice president for commercial operation.
PUC Commissioner Megan Gilman questioned whether there was a more fundamental shift at work. “We may have a more permanent change on our hands rather than a blip.”
As for the increase in commercial demand, part of that came from companies hitting the same problems as utilities in adding solar to their facilities. “Commercial customers scaled back on how much electricity they could generate,” said Jack Ihle, Xcel Energy’s director of regulatory and strategic analysis.
In June, the shortfalls looked to be even larger with the utility forecasting a 27 MW shortfall for the summer of 2022 and 137 MW in 2023 and 384 MW in 2024.
The company extended contracts to buy electricity from a natural gas-fired power plant and in July Comanche 3, the 750 MW coal-fired plant in Pueblo that had been offline for repairs for most of the year, returned to service.
“We are OK in 2022, but with extreme weather or unit derates (lower output) we could be in trouble in 2023,” Welch told the commission.
New contracts required to complete Pueblo County projects
Xcel Energy has made moves to fill the gap renegotiating contracts for large-scale solar plants with NextEra Energy Resources. In September, the utility filed a request for a waiver on its original contract and expedited approval of the changes.
NextEra, the world’s largest generator of wind and solar electricity, had been awarded a contract for two projects in Pueblo County: Thunder Wolf, a 200 MW solar farm with 100 MW of battery storage, and Neptune, a 250 MW solar farm with 125 MW of battery storage.
Both were supposed to be completed by the end of this year, but the projects are behind schedule. Xcel Energy and NextEra renegotiated their purchase power agreements, or PPAs, giving more time for completion of the projects and increasing their generation capacity.
Under the new agreement,Thunder Wolf will grow to 248 MW of capacity and Neptune will rise to 325 MW. Thunder Wolf would come online in June and Neptune by the end of August.
The changes require the PUC to grant a variance on the original PPA. In seeking that adjustment, Xcel Energy said in its application that the changes would “assist in addressing the company’s capacity shortage in the near term.”
With the addition of the two projects the gap for generation and reserve will be 49 MW in 2022 and 270 MW in 2024, a sharp drop from the June projections. Without the two NextEra solar projects, Xcel Energy said the 2023 gap will be almost nine times bigger.
Xcel Energy said in a PUC filing that it is also “in the process of evaluating” another 494 MW of capacity from additional natural gas and renewable resources for the summers of 2023 and 2024.
The utility asked ther PUC to limit the time for other parties to intervene to a week and make a decision by December.
“Given the urgency of what we are seeing in the summer of 2023 and the potential importance of these resources and the need, let’s keep this moving,” Blank said.
The commission decided to give parties two weeks, until Sept. 21, to intervene, about half the standard time.
“This is a big question and it is hard to gauge how controversial this will be,” Ron Davis, the commission’s principal energy advisor, said at the Sept. 7 hearing on the variance.
The PUC trial staff and Colorado Utility Consumer Advocate have filed to participate in the case.
“UCA has potential concerns regarding the cost of the additional solar capacity being added in the amended PPAs, and shares Trial Staff’s concerns regarding rate impacts and reserve margin requirement,” the office said in its filing.
The planning for adequate generation is based on the maximum, normal demand a utility faces. PUC commissioners, however, say they are concerned about what happens during extreme weather or if key generation fails, like Comanche 3 did last month.
The PUC Wednesday set a hearing for Nov. 18 on the waiver with the goal of issuing a decision by Dec. 1.
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“Under traditional planning we are OK in 2023,” Blank said during the June hearing. “With extreme weather extremes or unit derates we could be in trouble in 2023.”
In February 2021, for example, Winter Storm Uri brought snow, ice and subzero temperatures to Texas. All forms of generation struggled with the frigid temperatures leading to widespread blackouts. At its peak 4.5 million homes and businesses were without power.
Strategies for coping with extremes include purchasing extra power
California faced the risk of rolling blackouts in early September as temperatures pushed above 100 degrees, forcing the state’s grid operator to issue seven days of emergency alerts for voluntary electricity conservation.
On Sept. 21, Xcel Energy filed its report on extreme weather and resource adequacy concluding “the various stress tests conducted show that Public Service’s system can be prepared for increased demand caused by high temperatures and other issues.”
Xcel Energy model scenarios with extreme weather leading to high electricity loads and outages and a combination of the two.
One strategy the utility used in its modeling to ensure the lights stayed on was the purchase of power from the regional grid.
“Often during periods of challenging reliability the company is able to obtain energy and capacity from outside entities at higher prices that would not be considered ‘economic,’ but is needed to enhance reliability,” Xcel Energy said.
Such purchases, however, may be harder to come by as declining hydropower in the West linked to drought and high demand in markets like California make electricity transfers more difficult, according to the North American Electric Reliability Corp. NERC oversees reliability issues for the nation’s grid.
In its 2022 summer assessment NERC said, “the growing reliance on transfers within the Western Interconnection and falling resource capacity in many adjacent areas increases the risk that extreme events will lead to load interruption.”
That places all the more pressure on the utility’s own generating assets. “You never know when you have extreme events like wildfires and extreme temperatures,” Blank said. “If it lasts three days, five days a week, do we start to see equipment failures?”
Within its generating portfolio, Comanche 3, the largest generating unit on Xcel Energy’s system, has been plagued by operational and equipment failures and has been out of service for more than 825 days since it went online in 2010.
It was a Comanche 3 shutdown due to leaking pipes that locked the thermostats and air conditioning units of customers Aug. 30.
Still, in its assessment of climate change and extreme weather impacts, Xcel Energy said the commission “should be confident that Public Service has the tools at its disposal to mitigate these potential risks and will maintain a reliable system.”
“The company believes there is a low risk of serious reliability concerns for its customers,” the assessment said.