The lawsuit accuses Tri-State, a wholesale power provider, of breach of contract. The electric cooperative is among Colorado rural electric associations that have explored leaving Tri-State due to disputes over rates, the push for more renewable energy and the desire to generate more of their energy locally.

The La Plata Electric Association and Brighton-based United Power, Tri-State’s largest member, have gone to the Colorado Public Utilities Commission and the Federal Energy Regulatory Commission to get what they view as fair terms for ending their contracts. LPEA said in its lawsuit, filed in La Plata County District Court, that Tri-State has dealt in bad faith by failing to offer a fair and just exit plan and stringing it along in talks about an agreement to allow it to produce more of its own electricity.

The cooperative saw the ability to generate more of its own power from local projects as an alternative to ending its contract with Tri-State. The cooperative said the local projects would benefit the local economy.

“LPEA, out of options and without any active dialogue to modify its power supply, was left with the single option of filing this lawsuit to vindicate its rights,” the association said in the complaint.

The cooperative said it could show that Tri-State’s alleged breaches of contract “have caused LPEA to suffer millions of dollars in damages.”

Tri-State said in a statement Friday that LPEA’s lawsuit is an attack on its fellow Tri-State cooperative members, “which continue to work collaboratively to advance greater contract and power supply flexibility.”

Tri-State will vigorously defend itself and its members from the lawsuit, the company said.

The electric cooperative has tried for years to work collaboratively with Tri-State to provide its members more local control over their power supply and power costs, Ted Compton, LPEA board chairman, said in a statement.

“We regret having to take legal action to get the engagement and collaboration we are seeking,” Compton said.

Tri-State, based in Westminster, provides wholesale power to 42 electric associations in Colorado, Wyoming, Nebraska and Wyoming. The associations are members of Tri-State.

Some of Tri-State’s members have complained about the rates and what they considered over reliance on coal. They’ve chafed under the 5% cap on the amount of power individual cooperatives can generate or buy from other sources.

The Kit Carson Electric Cooperative in Taos, N.M., paid $37 million in 2016 to break its contract with Tri-State. The Delta-Montrose Electric Association in Montrose paid $62.5 million in 2020 to leave Tri-State.

Tri-State has told United Power that it will take $1.6 billion to break its contract, which won’t expire until 2050. United Power has asked FERC to reject that amount. In the meantime, United Power plans to leave Tri-State on May 1, 2024, and has signed an agreement to buy electricity from another company.

United Power filed a lawsuit in Adams County District Court in 2020 to challenge Tri-State’s addition of other types of members so the utility could be regulated by federal rather than Colorado regulators. The lawsuit by LPEA alleges Tri-State pursued “a sneaky and underhanded course of action to deprive the Colorado Public Utilities Commission of jurisdiction.”

United Power and Tri-State said in a news release Friday that they will file an agreement to settle the lawsuit in Adams County District Court.

Tri-State said that LPEA’s lawsuit comes as the power supplier has filed a new electric resource plan that accelerates its move to clean energy and bolsters its system’s reliability. The plan would increase Tri-State’s amount of renewable energy resources and close two coal plants, including one in Craig by Jan. 1, 2028.

“LPEA has positioned themselves far outside the interests of both our members that are working for greater contract flexibility, and all those advancing a reliable and affordable clean energy transition,” Tri-State CEO Duane Highley said.

The PUC weighed in during a meeting Wednesday on the second phase of Xcel’s energy resource plan, which will help chart the utility’s spending and mix of resources to generate electricity through the rest of the decade. The company’s preference out of the different scenarios proposed would add roughly 6,500 megawatts of wind and solar power and storage on Xcel’s system while cutting greenhouse gas emissions by an estimated 87% from 2005 levels by 2030.

“This is likely to be the most impactful decision I’ll make during my term,” Eric Blank, commission chairman, said in what he called the beginning of regulators’ conversation on the proposal.

PUC members will discuss the proposal in a meeting next week. The commission originally planned to make a decision before the end of the year, but it’s unclear if it will extend the time.

Blank and other PUC members called Xcel Energy’s plan to significantly increase renewable sources on the grid and reduce carbon emissions by closing coal plants “transformational,” and leading to “a profound transition” from fossil fuels.

However, commission members seemed almost as struck by the utility’s plan to spend $15 billion, nearly double from the first phase of the proposal. About $2.8 billion of that increase would pay for transmission upgrades in the Denver area.

“We’re seeing a nearly nine times multiplication of what was anticipated in phase 1 to be the cost of Denver-metro upgrades, a jarring almost $3 billion new transmission upgrades in total,” PUC member Megan Gilman said.

Transmission costs in the plan would be on top of the $1.7 billion for the Colorado Power Pathway, which will consist of loops of up to 650 miles of high-voltage transmission lines stretching from the northern Front Range to the southeastern plains. The PUC approved most of the project in 2022.

Spokesman Tyler Bryant said in an email that the company appreciates the commissioners’ discussion of its “transformative Clean Energy Plan.”

“Like many stakeholders, we support the full amount of renewable energy in our proposed plan which is intended to meet and exceed the state’s greenhouse gas policy goals.” Bryant said.

The Office of the Utility Consumer Advocate said in written comments to the PUC that Xcel Energy gave the impression that the Power Pathway was the solution to its transmission needs. The office said while some Denver-area upgrades would be required, Xcel didn’t indicate that “the additional transmission costs would be in the billions of dollars.”

Gilman and the other commissioners expressed frustration with “late-breaking issues” in the plan and questioned some of the modeling and assumptions related to the economics of proposed projects and financial impacts on customers.

In written comments, the PUC staff and the consumer advocate’s office said the higher transmission costs could potentially result in large rate increases. Xcel, which provides electricity to 1.6 million customers in Colorado, has said its proposal would amount to an average annual rate increase of 2.3% for customers, or below inflation.

But Blank pointed out that PUC staff and others say the forecast doesn’t include all the projected costs, such as wildfire mitigation, the electrification of transportation, distributed solar projects and development of hydrogen technology.

The consumer advocate’s office said Xcel Energy’s preferred plan would cost customers an average of 6.1% per year.

The PUC questioned whether Xcel’s proposed power projects would be in place a few years ahead of the required transmission. Blank suggested some of the projects could be delayed to better understand the cost, need and the best timing of new transmission.

The utility intends to take advantage of $10 billion in renewable energy tax credits through the federal Inflation Reduction Act.

Parties to the proceedings have challenged the fact that under the plan, Xcel would own roughly 66% of the new facilities. Critics note that a 2019 law requiring utilities to write clean energy plans set a target of a utility owning about half the infrastructure and the other half being privately owned. The costs of Xcel-owned facilities are added to the rate base, or the basic rate that customers pay.

“Of the overall $15 billion of proposed investment, the company would own over $10 billion representing an approximate doubling of its current rate base,” the PUC staff said.

PUC member Tom Plant said he is concerned about the impact on ratepayers of Xcel’s plans to build three new natural gas plants. He believes the technology will be phased out over the next 25 years, leaving customers on the hook to pay for plants built to last much longer.

The company’s proposal calls for closing six older gas-fired units and building three new plants totaling 600 megawatts.

The economic impacts on customers of so-called “stranded assets,” plants or equipment no longer needed, and the effects on air quality and health worry community and environmental groups. People rallied Nov. 15 at the state Capitol against building new gas plants.

“The plants would cost ratepayers $1 billion. These gas plants are just a bad deal for Colorado’s ratepayers, for Colorado’s consumers, for Colorado’s working families. We need to get off this sauce,” said Wendy Howell of the working families party.

Other speakers at the rally said the PUC should reject the new gas plants due to the effects on people’s health, air quality and the warming climate.

“We are thrilled to see a significant amount of clean renewable energy as well as energy storage in Xcel’s plan,” Jen Clanahan of Mountain Mamas said. “However, building three new gas plants is not a mom-approved plan. Frankly, we can’t figure out why anyone would build new gas plants when scientists have warned us that we need to stop burning fossil fuels yesterday.”

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Tri-State filed the new electric resource plan with state regulators Friday. The wholesale power supplier is seeking up to $970 million in grants and loans through the U.S Department of Agriculture’s Empowering Rural America program, aimed at helping rural communities make the transition to renewable energy.

Tri-State serves more than 40 rural electric associations in Colorado, Wyoming, New Mexico and Nebraska.

The utility has proposed to move up retirement of Unit 3 of its Craig coal-fired power plant to Jan. 1, 2028, from the end of 2029. With the closure of the plant in Craig, Tri-State won’t have any coal resources in Colorado, spokesman Lee Boughey said.

The company has also proposed closing a unit of a coal plant near Springerville, Ariz., by 2031. Under the plan, Tri-State would add 1,250 megawatts of additional renewables and battery storage through 2031.

One megawatt of solar or wind energy can supply electricity to several hundred homes.

Boughey said in an email that Tri-State currently has 1,497 megawatts of renewable energy sources. In 2022, 34% of the electricity used by members was from renewable sources. The utility expects that to rise to 70% by 2030.

The Colorado Public Utilities Commission is expected to consider the first phase of Tri-State’s energy plan in 2024.The second phase will include seeking bids for projects and approval of a final portfolio of power resources.

Environmental groups and member electric associations have criticized Tri-State for not moving away from coal and to renewable energy quickly enough. A few of Tri-State’s members have bought out their contracts or explored leaving over disputes about rates and the desire to generate more of their electricity locally.

However, Tri-State’s newest energy plan is a win for people’s health, the environment and members’ wallets, the Sierra Club said. Tri-State estimates that its plan will cut members’ costs by more than $1.8 billion through 2043.

Sarah Clark, Colorado field manager for the Sierra Club, said in a statement that the organization is committed to working with Tri-State and others to support the communities in Moffat County and Arizona that will be affected by closing the coal plants.

Tri-State CEO Duane Highley said in a statement that the company will work with its local, state and federal partners and employees at the Craig coal plant during the transition.

Moffat County Commissioner Tony Bohrer told the Craig Press newspaper that the plant’s earlier closing would negatively affect the area’s jobs and tax base and that the county and city of Craig will voice their concerns during the regulatory hearings.

The other two units of the Craig coal plant will be closed in 2025 and 2028.

“Tri-State should be commended for proposing a transformational electric resource plan, which will reduce carbon pollution across the West and provide economic benefits for its member cooperatives,” said Stacy Tellinghuisen with Western Resource Advocates, a Colorado-based conservation group.

Tellinghuisen said WRA encourages other utilities to take advantage of the federal funding “to replace expensive, polluting plants with cleaner resources.”

Tri-State submitted a letter of interest in September to the USDA’s New ERA program, which is part of the federal Inflation Reduction Act. Tri-State said the next step is an invitation to apply for the program, which it anticipates in the coming months.

Boughey said the federal money would help Tri-State accelerate the addition of renewables and closure of the Springerville plant. In the case of lesser funding, “we would reoptimize our approach to best utilize available funding,” he said.

The $9.7 billion program is the country’s largest investment in rural electrification since the Rural Electrification Act of 1936, according to the USDA. The funding, which prioritizes cutting greenhouse-gas emissions, can be used for renewable energy and zero-emission systems and manage so-called stranded assets, such as coal plants closed ahead of schedule.

“Federal funding in support of our preferred plan would be transformational for Tri-State and our members,” Highley said in a statement.

The vapor was released from a pump that was not functional and had not been used or properly inspected in seven years, according to the report detailing the U.S. Occupational Safety and Health Administration‘s investigation into the accident. The fire burned for six hours.

The report, obtained by The Denver Post through a federal Freedom of Information Act request, said the likelihood of injury had been higher because “employees were exposed to the hazards for nearly 7 years without the equipment being inspected properly.”

Suncor was fined $15,625 — the maximum allowed — in June for a serious violation of federal safety standards in connection with the fire at Colorado’s only oil refinery.

Most of the 1,090-page report was redacted, but it still revealed some new information about the circumstances surrounding the Dec. 24 fire that burned one person’s face so badly that he was hospitalized. A second worker was injured but did not need hospitalization, according to the report.

OSHA officials could not be reached to explain why so much of the investigative report was withheld from the public.

In response to a Denver Post inquiry about the investigation, Leithan Slade, a Suncor spokesman, wrote in an email, “Suncor has repaired and replaced the equipment related to the fire and is identifying, inspecting and testing all dead legs in the unit where the December 24, 2022 fire occurred. That work will be complete by the end of the year.”

The OSHA investigation raises questions about how Suncor manages its inspection of “dead legs,” an industry term for pipes that are no longer used and are shut off from liquids and vapors.

The explosion took place after a cold front rolled into the region, causing an extreme and fast temperature drop, on the afternoon of Dec. 21. The deep freeze caused extensive problems, and Suncor officials over the course of about a week shut down the refinery.

The Commerce City facility remained closed until early April while it was being repaired, fueling a more than 50% jump in gas prices in Colorado.

The cause of the shutdown was shrouded in secrecy with Suncor revealing little information about what had happened. Since then, details have been emerging in bits and pieces.

At a Nov. 16 meeting of the Air Quality Control Commission, state air regulators gave a briefing on Suncor’s operations and their efforts to enforce environmental regulations at the refinery. That briefing included an update on the December shutdown, which remains under investigation by the state’s Air Pollution Control Division.

The extreme weather caused instruments to freeze and the refinery was unable to make steam, said Shannon McMillan, who manages the air division’s compliance and enforcement program. Other equipment also needed to be shut off because of freezing and thawing issues.

“There were also two people that were injured during the initial days of the shutdown, which obviously further elevated the concerns about what was going on,” McMillan said.

However, her division does not investigate injury accidents. Instead, the air division is looking into air pollution violations that occurred during the shutdown. The refinery exceeded the amount of hydrogen sulfide, sulfur dioxide and visible emissions allowed under its air permits and exceeded the benzene limits allowed in its water permit. That investigation is ongoing, McMillan said.

The Suncor refinery has more than 200,000 flanges and valves that require inspection, according to the air division’s briefing.

Suncor gave OSHA a copy of its dead leg inspection program but it was redacted in the copy of the report provided to The Post.

John Jechura, a Colorado School of Mines professor in the chemical and biological engineering department, described a dead leg as being like a garden hose that is turned off at the spigot and has the valve closed on the nozzle.

“If it gets water in it and there’s a deep freeze, it freezes and expands,” Jechura said. “You don’t really know it until it thaws out.”

The report shows the pump that exploded was a backup and rarely used, Jechura said. It would make sense for the refinery to have a system of backups in place so that operations would not be interrupted if one failed.

Jechura, who reviewed the OSHA report for The Post, said too much information was blacked out to determine whether there were oversights that led to the explosion or what Suncor could have done to prevent the accident.

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An attorney and solar advocate who wrote an amendment to a law on HOAs and solar systems said the board at the Villas at Cherry Creek is flouting the state law designed to protect people’s right to use solar energy to power their homes.

The attorney for the HOA said the board’s position has been misrepresented and that the board’s policy is in line with state law.

Meanwhile, Cunningham and Rozycki say they’ve been waiting for a resolution. Both are former presidents of the HOA board and both submitted their initial applications more than a year ago to put solar panels on their roofs.

Both were turned down.

“I want to do this for the good of the environment, not so much to save money. The saving of the money is down the road,” Rozycki said.

Rozycki, like Cunningham, wanted to lease rather than buy the solar panels and equipment. The HOA board’s policy on solar, written in 2021 after Rozycki and others brought up the subject, includes several requirements that Rozycki and Cunningham said are “over the top.”

The policy also prohibits homeowners from leasing solar panels. The reason? The HOA said its policies don’t allow owners to lease a portion of their homes to third parties for commercial activity.

“We’re not the lessor, we’re the lessee,” Cunningham said. “This is no different than Xcel Energy putting a meter on your house. The board’s interpretation would be you’re leasing a portion of your wall.”

The subdivision’s 100 homes are duplexes where solar panels have been approved on a couple of homes. The HOA maintains the rooftops, but the residents own them. Rozycki sought advice from attorney Roger Freeman, who specializes in environmental and energy matters, after running into obstacles.

Rozycki said he recently capitulated on the leasing controversy. After his first application was rejected, he submitted another one, this time saying he’ll buy the solar-energy equipment. The board approved the new plan.

However, the board voted in early November against Cunningham’s plan to buy a solar system, citing engineering and insurance issues.

The board’s solar rules are “so outside the bounds of the HOA Solar Law that they are clearly illegal and unenforceable under the law,” Freeman wrote in March to the homeowners association.

In 2021, Freeman helped write an amendment to state laws referred to as the “Solar Bill of Rights.” A provision he wrote provides narrow exceptions to a broad prohibition against HOAs interfering with installation of solar energy systems.

One exception allows “reasonable restrictions” on the dimension, placement or external appearance of equipment as long as they don’t increase the cost or decrease performance by more than 10% and the review is capped at 60 days. Another allows “bona fide safety requirements” related to a building code or a recognized safety standard.

In the case of the Villas at Cherry Creek, the rules are “cumbersome, overreaching, illegal and unenforceable,” said Freeman.

Cunningham and Rozycki said they had to provide a record of a year’s worth of their electricity use and insurance information. The board even suggested design changes, said Cunningham, who got permits from the city but was turned down by the HOA board.

The HOA’s rules go beyond aesthetics to intrude into the technology, construction and design, Freeman said. The board doesn’t have the authority to impose a rule that residents use “the most recent technology available,” he said.

Freeman said the board also lacks the authority to mandate that residents buy rather than lease a solar system. That’s a personal decision that has nothing to do with aesthetics or safety, he said.

And a ban on leasing the equipment leaves out people who don’t have the upfront money, Freeman said. The leasing model “broadens the tent for solar,” he added.

“These are folks who want to power their homes and eventually their electric cars with the sun. It’s their roof, which is their property,” Freeman said. “The bigger issue is that the state and so many other governments and other entities have decided and told us that we need to make a conversion to renewable energy sources.”

And the state has specified the limits of HOAs’ authority, Freeman added. Recent laws have provided more protections for homeowners when HOAs move to foreclose on properties. A 2021 law prevents the associations from restricting residents’ use of xeriscaping.

Freeman said it’s common for questions to come up about HOAs’ oversight of solar-system installations.

“They will often say they don’t want to see it from the street. Great, but the sun’s shining on both sides of my house. If I put it just on the back of my house, it’s 50% less efficient. You can’t make me do that,” Freeman said.

Freeman said the Stoney Brook Homeowners Association in Denver revised its rules after the state law was updated. Stoney Brook’s policy was promoted as a template for the Villas, but Freeman said the suggestion went nowhere.

“Frankly, I think it’s a case where there are folks on the board who have been doing this for a long time, are used to a certain level of oversight and control and have their own views about solar,” Freeman said.

The HOA board members didn’t return requests for comment. The board’s attorney, Lynn Jordan, said in an interview that critics have misrepresented the board’s position.

“Applications have been approved, tweaked or withdrawn,” Jordan said of residents’ solar plans. “If we can make it work, we do.”

Jordan believes the HOA’s policy follows state law. “When the law changed we realized we needed to do a policy and obviously it had to be lawful.”

As for whether residents can lease the solar equipment, Jordan said, “We don’t care at all how they acquire it.”

But in an April letter to Rozycki, Jordan wrote that residents can’t host any third-party business “whereby a third party installs, owns and operates an energy system on any portion of the Residence.”

As a result, Rozycki said he has gone to Plan B. “I’ve given up the lease approach and I’m buying it because they won’t budge.”

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The commission is expected to make a decision by year’s end on the second phase of Xcel Energy-Colorado’s clean energy plan, which maps out the utility’s strategies for meeting a state mandate of reducing its emissions by at least 80% by 2030 in a cost-effective manner.

Xcel Energy frequently bumps heads with other parties in proceedings before the PUC, but its proposal to add a total of 6,500 megawatts of renewable energy resources and battery storage to its system has drawn praise.

One megawatt of solar or wind energy can supply electricity to several hundred homes.

“Overall, the amount of solar, wind and storage that’s being added is something to be celebrated and something we really want to trumpet to our neighboring states, that you can get to a resilient, stable, high renewables grid,” said Mike Kruger,president and CEO of the trade group Colorado Solar and Storage Association.

Gwen Farnsworth, deputy director of state advocacy with environmental group Western Resource Advocates, lauded the company’s expectations that it will reduce emissions 87% by 2030 and produce 83% of its power from clean sources by 2028. The utility also intends to take advantage of $10 billion in tax credits through the federal Inflation Reduction Act.

But Xcel faces headwinds from critics who say the utility’s proposal to own most of the new power generation will keep costs high for customers for years to come because the infrastructure costs will be added to the rates. They worry that new natural gas plants could end up being the financial albatross coal plants have become as renewable technology continues to advance.

And Eastern Plains residents whose land could be a corridor for new transmission lines to accommodate new power want their local elected officials to make Xcel build elsewhere.

“It hurts my heart to even think about this because where we live is beautiful and so many people have put their heart and soul and dreams into living out here,” said Kerry Jiblits, who lives near Kiowa.

Jiblits and other Elbert County residents want Xcel to build the transmission lines farther to the east in the county where fewer people live. The segment would be part of the company’s Colorado Power Pathway, 610 miles of transmission lines approved by the state utilities commission. The project also needs the approval of the counties it runs through.

“We continue to work with the community to find out what the best path forward is,” said Robert Kenney, president of Xcel Energy-Colorado. “Without getting into the specifics of Elbert County, our goal is to continue working with our community to find a mutually agreeable route.”

The 184-page clean energy plan details Xcel Energy’s preferred blueprint for meeting goals to cut heat-trapping emissions and expand renewable energy. The company has its own goal of producing carbon-free electricity by 2050.

“There are multiple benefits that make this plan exciting,” Kenney said. “It’s the size and amount of renewables we’re able to bring onboard, the additional transmission investment.”

Xcel has said it received more than 1,000 competitive bids for the projects proposed.

Kenney knows there’s opposition to building new natural gas plants. He said they will be used less frequently than Xcel uses the existing plants, but the utility still needs “dispatchable” energy, which can be turned on and off as needed, to “fill in the gaps when renewables aren’t able to perform.”

Dan Haley, CEO and president of the trade group Colorado Oil and Gas Association, said it’s important that consumers can continue to rely on reliable and affordable energy as Xcel works toward the state mandates.

“Natural gas will remain a key part of this effort and serves as a potentially life-saving energy source during periods when renewables are not capable of meeting the demands of the grid,” Haley said in an email.

Fear of stranded assets

Others aren’t convinced that Xcel Energy’s clean energy future should include new natural gas plants. The company’s proposal calls for closing six older gas-fired units and building three new plants totaling 600 megawatts.

“They’re retiring some (plants) but then they’re going to build more. It doesn’t make any sense,” said KK DuVivier, a professor at the University of Denver’s Sturm College of Law and an expert on national resources and energy law.

The new gas plants could end up as “stranded assets,” DuVivier added, meaning they’ll be closed earlier than planned when they were designed, financed and built. Xcel Energy, like other regulated utilities, can seek approval to tap ratepayers to cover the costs of those assets.

The company has about $1 billion in stranded coal plants that have to be paid off, said Leslie Glustrom, a Boulder resident with the nonprofit Clean Energy Action. “It is important to not now make the same mistakes on the gas side.”

Xcel expects to close all its coal plants in Colorado by the start of 2031, but customers will shell out for years to close the books on them.

Farnsworth of Western Resource Advocates said Xcel’s proposal relies much less on new natural gas generation than originally projected. She said it might be possible to further reduce that reliance “both for lower emissions and to avoid high fuel costs.”

Even with the new gas plants, there will be a net reduction of 700 megawatts of natural gas, Kenney said. Xcel is looking at shortening the depreciation time for the plants so it can cover costs more quickly. Xcel also wants to explore blending hydrogen with natural gas in the plants to decrease emissions and potentially burn 100% hydrogen.

So-called “green” hydrogen fuel is produced only by renewable energy, but more than 90% of the hydrogen currently produced in the country uses natural gas. Sierra Club spokesman Noah Rott said despite “many positive elements” in Xcel’s plan, the company is asking customers to bet on speculative hydrogen technology.

“If technologies like hydrogen that could reduce emissions from gas plants don’t end up being cheap or reliable, then we can still be on the hook paying for the company’s failure to find real solutions to the climate crisis, and that only benefits the company’s shareholders, not our communities,” Rott said in an email.

Another sticking point is that under Xcel Energy’s preferred plan, the utility would own about 66% of the new facilities. Kruger, with the statewide solar and storage trade group, noted that a 2019 law requiring utilities to write clean energy plans established a target of a utility owning about half the infrastructure and the other half being privately owned. In the case of cost overruns or malfunctioning plants, a private company would bear the costs, not customers, Kruger said.

Xcel Energy has been criticized by customers, legislators and consumer advocates for seeking frequent rate increases while its parent company, based in Minneapolis, reported $1.74 billion in profits for 2022, up 8.75% from 2021. The company’s net profits in Colorado were $727 million, up from $660 million in 2021.

Xcel, which provides electricity to 1.6 million customers in Colorado, said its proposal would amount to an average annual rate increase of 2.3% for customers.

Kenney said an advantage of Xcel owning the facilities is that it can use the tax credits available to utilities under the Inflation Reduction Act and the savings can be passed onto customers. “We do make profits. We don’t make outsized profits and we’re making substantial investments back in our community.”

Colorado Power Pathway

The Colorado Power Pathway, planned in several counties on the Eastern Plains and the Front Range, will be a conduit for tapping solar and wind resources detailed in Xcel’s clean energy plan. The plan pegs transmission costs at roughly $4.5 billion, not including $123 million in interconnection costs.

Construction has started on some of the transmission project’s segments and counties have approved some of the land-use permits Xcel will need. The utility is expected to submit a formal application this spring for a permit to Elbert County, where the project is proving to be a hard sell for residents.

“I have not met one person in this area who is in favor of this route,” said Jiblits, who lives 10 miles northeast of Kiowa.

Jiblits is a member of the Elbert County Environmental Alliance Board, which opposes a route that would cut through the middle third of the county. The group has suggested routing the more than 50 miles of lines farther east where it is less populated and people’s property is measured in thousands of acres.

“Whereas here we have several landowners who are on just 5 acres of land so it’s impacting many more landowners,” said Jiblits, who has attended open houses hosted by Xcel on the project.

The eastern part of the county doesn’t have the forest and the variety of wildlife the middle part does, Jiblitz added. “We’re just saying build it in a place that makes more sense, in a place that’s not going to negatively impact so many people.”

Chris Richardson, chairman of the Elbert County Board of Commissioners, said Xcel Energy had proposed “a multitude of routes,” including one farther east that would parallel existing transmission lines serving its Rush Creek Wind Project.

“To us it seemed like the logical route to take, but it appears Xcel feels otherwise. Until we actually have an application before us, we’re kind of in a holding pattern,” Richardson said.

The county staff and commissioners will review the application. Richardson stressed the county will wait until it has the all information it needs before making any decisions. He just thinks the process could have been smoother if Xcel Energy had engaged with the community earlier.

“Probably the last six months, I don’t think we’ve had a public meeting where we didn’t hear concerns about the route,” Richardson said. “I think there was a way to approach us that would have been a lot more collaborative.”

Updated Nov. 13, 2023, to clarify the plan’s expected impact on customers’ rates.

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NovoHydrogen in Golden has secured a $20 million equity commitment from Modern Energy, which invests in and partners with businesses working to transition from fossil fuels.

The U.S. Department of Energy also selected the company to participate in one of seven regional hubs for the development of hydrogen as an energy source. NovoHydrogen will participate in the hub to be established in the Pacific Northwest.

Colorado joined Utah, New Mexico and Wyoming in a bid for one of the regional hubs and a share of the roughly $8 billion included in the federal infrastructure bill, but wasn’t chosen.

After working for years with renewable energy and battery storage, Matt McMonagle founded NovoHydrogen in October 2021. The company works only on so-called “green hydrogen,” which uses renewable energy to power electrolysis. The process splits water into hydrogen and oxygen, emitting no greenhouse gas.

The Inflation Reduction Act contains tax credits for green hydrogen projects.

NovoHydrogen has at least 15 projects in the works in nine states, including Colorado. The company has 11 employees and expects to add two more people in the next month or two.

“From a climate perspective, current hydrogen production is a major problem. It accounts for 2 to 3% of global greenhouse gas emissions,” McMonagle said.

Approximately 95% of the hydrogen produced today comes from fossil fuels, according to RMI, a Colorado-based research and consulting organization. Hydrogen is used in petroleum refining, to make fertilizer, in rocket fuel and to power vehicles.

The various ways of producing hydrogen as a fuel are referred to by colors to distinguish the processes. High-temperature steam is used to produce hydrogen from natural gas to make what’s called “gray” hydrogen, the majority of what’s generated in the U.S.

What’s called “blue” hydrogen also uses methane with the added step of capturing and storing the carbon dioxide emissions. TJ Kirk, a manager in RMI’s climate-aligned industries program, said methane emissions from producing the natural gas have to be factored in when considering the impacts. And most large-scale projects typically don’t manage to capture more than 60% of the carbon dioxide emissions, he said.

Operators are looking at using hydrogen to supplement or replace natural gas in power plants, the U.S. Energy Information Administration said. As part of its clean energy plan, Xcel Energy-Colorado is proposing to blend hydrogen with natural gas in new plants it wants to build.

Blending hydrogen with natural gas can lower carbon emissions. “But it’s not a linear relationship. A 10% blend would result in somewhere near a 5 to 7% reduction,” Kirk said.

RMI believes hydrogen can be used to decarbonize many sectors, but should be prioritized for areas where direct electrification isn’t feasible or is difficult. Those include heavy industry, shipping fuels and long-distance transportation.

Those banking on hydrogen to help stem the impact of climate change believe hydrogen produced by renewable energy could cut greenhouse gas emissions from steel production, which is highly dependent on coal and accounted for about 7% of global emissions in 2020.

Hydrogen can be stored as a gas or liquid to be used later in electricity generation, supplementing renewable energy sources. But the development of hydrogen as an energy source is still a work in progress.

“There are  a lot of projects being planned, but there are very few projects in existence,” Kirk said.

However, the economic incentives in the Inflation Reduction Act and the infrastructure bill will help  grow the industry, McMonagle of NovoHydrogen said. The incentives mean hydrogen produced by wind, solar and other renewable sources will become cost competitive with hydrogen made from fossil fuels, he added.

“There’s a clear pathway for green hydrogen to be cheaper than fossil-fuel-based hydrogen and not subject to the volatility of commodity prices,” McMonagle said.

The company, Green Mountain Power, proposed buying batteries, burying power lines and strengthening overhead cables in a filing with state regulators on Monday. It said its plan would be cheaper than building a lot of new lines and power plants.

The plan is a big departure from how U.S. utilities normally do business. Most of them make money by building and operating power lines that deliver electricity from natural gas power plants or wind and solar farms to homes and businesses. Green Mountain — a relatively small utility serving 270,000 homes and businesses — would still use that infrastructure but build less of it by investing in television-size batteries that homeowners usually buy on their own.

“Call us the un-utility,” Mari McClure, Green Mountain’s CEO, said in an interview before the company’s filing. “We’re completely flipping the model, decentralizing it.”

Like many places, Vermont has been hit hard this year by extreme weather linked to climate change. Half a dozen severe storms, including major floods in July, have caused power outages and damaged homes and other buildings.

Those calamities and concerns about the rising cost of electricity helped shape Green Mountain’s proposal, McClure said. As the company ran the numbers, it realized that paying recovery costs and building more power lines to improve its system would cost a lot more and take a lot longer than equipping homes with batteries.

Green Mountain’s plan builds on a program it has run since 2015 to lease Tesla home batteries to customers. Its filing asks the Vermont Public Utility Commission to authorize it to initially spend $280 million to strengthen its grid and buy batteries, which will come from various manufacturers.

The company expects to invest an estimated $1.5 billion over the next seven years — money that it would recoup through electricity rates. The utility said the investment was justified by the growing sum it had to spend on storm recovery and to trim and remove trees around its power lines.

The utility said it would continue offering battery leases to customers who want them sooner. It will take until 2030 for the company to install batteries at most homes under its new plan if regulators approve it. Green Mountain says its goal to do away with power outages will be realized by that year, meaning customers would always have enough electricity to use lights, refrigerators and other essentials.

“We don’t want the power to be off for our customers ever,” McClure said. “People’s lives are on the line. That is ultimately at the heart of why we’re doing what we’re trying to do.”

Green Mountain would control the batteries, allowing it to program them to soak up energy when wind turbines and solar panels were producing a lot of it. Then, when demand peaked on a hot summer day, say, the batteries could release electricity.

Under the proposal, the company would initially focus on delivering batteries to its most vulnerable customers, putting some power lines underground and installing stronger cables to prevent falling trees from causing outages.

Hurricanes, winter storms and wildfires have highlighted the growing vulnerability of electric grids in recent years. To many people they have also reinforced the importance of quickly shifting away from fossil fuels, the primary cause of climate change.

Utilities are spending tens of billions of dollars on strengthening grids and switching to cleaner forms of energy, often with the help of federal and state incentives.

But critics of the industry say utilities are not being particularly innovative in investing in their systems. Utilities are spending a lot on new long-distance power lines that can take years or even decades to build because of environmental reviews and local opposition.

A May report by the Brattle Group, a research firm based in Boston, concluded that utilities could save up to $35 billion a year if they invested in smaller-scale energy projects such as home batteries and rooftop solar panels that can be built more easily and quickly.

Green Mountain’s proposal seems to recognize that reality, said Leah Stokes, an associate professor of environmental politics at the University of California, Santa Barbara. “It really is the model, especially if you’re worried about power outages,” she said. “It really could become the example for the rest of the country.”

McClure said the high cost of large-scale power projects threatened to raise electricity rates so much that many customers might struggle to pay for energy.

Electricity customers in New England pay about $270 a month, on average, for a home that uses 1,000 kilowatt-hours of electricity, compared with the national average of about $160, according to the Energy Information Administration. That’s the third-highest rate in the country, behind Hawaii and California. Vermont’s rates are the lowest in New England but still about 29% above the national average.

Electricity rates nationwide increased about 25% in the past five years and are expected to continue to rise sharply as utilities seek to strengthen the grid and build renewable energy projects.

Emily Fisher, executive vice president for clean energy and general counsel at the Edison Electric Institute, a utility trade organization, said Green Mountain’s proposal aligns with discussions throughout the industry about ways to respond to climate change and the results of extreme weather.

“I think it’s innovative,” Fisher said. “I don’t see it as a change in the business model but a way to harness the business model. You’re going to have to show that it has systemwide benefit.”

Power outages cost utilities in the United States about $150 billion a year, according to analysts at Sprott, an investment firm. And modernizing U.S. electric grids could cost “well into the trillions of dollars,” according to Sprott’s estimates.

In addition to the roughly $20 million to $25 million that Green Mountain spends each year on managing trees and other vegetation around its power lines, the utility said, it spent about $55 million on storm recovery this year. It spent an average of less than $10 million a year after storms between 2015 and 2022.

Those kinds of storm recovery costs can increase rates by as much as 7% over time because the utility is allowed to recoup that spending from ratepayers.

“If you are leading a utility anywhere in the country you have to get on a path to stop the madness, relative to rates,” McClure said.

This article originally appeared in The New York Times.

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Xcel is expanding its work with Pano AI, a San Francisco-based company that will install 21 camera systems by the end of the year on more than 1.5 million acres across the utility’s territory. The objective is to quickly alert Xcel and first responders when smoke is detected.

Pano uses artificial intelligence, or AI, to interpret images from its high-definition cameras that capture 360-degree views, adding data from satellite feeds and other sources to assess the weather and conditions on the ground. The company staffs a center 24/7 where people review information.

“By the end of 2023 we will have installed 21 cameras across the state, both on the Front Range and the Western Slope,” Xcel Energy Colorado President Robert Kenney said Tuesday.

“We understand that wildfires in particular pose a significant and evolving risk to our customers and our communities. Climate conditions continue to change rapidly throughout the western United States,” Kenney added.

Facing larger and more catastrophic wildfires driven by warmer temperatures and drier weather, firefighting agencies and governments around the world are looking to AI to help squelch fires early and reduce fire risks. Pano AI is working with local agencies in western Colorado and has deployed its technology in seven other states as well as in Canada and Australia.

Xcel is expanding its pilot project with Pano that started in Boulder. The two made the announcement at an Arvada Fire Protection District station.

Pano works with fire agencies in areas where its technology is in use, said Arvind Satyam, the company’s co-founder and chief commercial officer.

“It’s a real new tool for us. We’ve been working with Pano for just a few weeks now, but one thing we’re really making strides on is connecting to our dispatch center,” said Steven Parker, fire marshal for the Arvada agency.

The site of the news conference, a suburban fire station, underscored that wildfire threats aren’t limited to the region’s foothills and mountains. Colorado’s most destructive wildfire tore through Louisville, Superior and parts of unincorporated Boulder County on Dec. 30, 2021. The Marshall fire killed two people, destroyed more than 1,000 homes and did more than $2 billion in property damage in an area about 8 miles northeast of the fire station.

Winds of up to 90 mph and parched vegetation fueled the flames.

“For many years we have thought that wildfire was just a threat in forested areas, but that perspective has changed,” Parker said. “Now, we are seeing wildfires burn near and into highly populated areas.”

Kenney wouldn’t speculate about what kind of help Pano’s technology might have been during the Marshall fire. A 17-month investigation by Boulder County authorities said the fire started in two places: on the Twelve Tribes religious cult’s property when embers from an earlier fire reignited; and near part of Xcel’s electrical distribution system, where a power line became loose.

Investigators said they found no evidence that Twelve Tribes members intended to start a fire or that Xcel Energy was negligent.

The utility has disputed that its equipment started one of the fires that merged into one massive wildfire. Nearly 250 area residents, property owners and businesses, as well as more than 150 insurance companies, are suing Xcel Energy for damages and to recover money paid in settlements.

“It’s impossible to speculate on a hypothetical,” Kenney said about whether Pano AI’s system would have made a difference during the Marshall fire.

Going forward, Xcel expects the technology to help spot fires earlier and “direct the right resources with a level of precision much more quickly,” Kenney said.

Other tools in the utility’s firefighting toolbox are inspections of power lines and equipment using drones and helicopters, Kenney said. Inspectors use technology that creates three-dimensional maps of equipment to aid assessments.

Xcel’s wildfire mitigation program includes replacing equipment and clearing vegetation away from lines.

The 21 cameras being installed by Pano AI will be placed in areas considered to be at high risk for wildfires. They are placed at high vantage points about 10 miles apart. Satyam said the cameras continuously rotate 360 degrees, creating a full panorama.

Xcel has a five-year contract with Pano AI. The utility is paying $50,000 per year per camera. Kenney said Xcel will recover the costs as it does with other infrastructure through electric rates, but is also pursuing federal funding.

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The ECMC unanimously voted against the plan by K.P. Kauffman Co. Thursday after several hours of testimony stretching over three days. The company originally proposed putting up $10.3 million to ensure it will take care of all its wells. ECMC members voted to require the company to provide roughly $133 million over 10 years.

A so-called financial assurance plan is required of all oil and gas companies under new rules approved in 2022 and are intended to ensure that operators have enough money to cover the cost of closing wells and reclaiming well sites.

Previous required bonds were seen as too low, making it easier for some companies to walk away rather than pay to plug a well, clean up the site and restore surrounding land.

“In order for us to make a statement that we have some of the strongest financial assurance requirements in the country, it is our responsibility to apply the rules in the way they were intended to be applied,” said John Messner, a commission member.

Opponents of the plan by K.P. Kauffman, or KPK, saw the commission’s decision as a test of how the rules, part of a sweeping revamp of state regulations, would be implemented. Critics, including the communities of Frederick and Dacono, argued KPK’s plan didn’t meet the requirements and was grossly underfinanced.

The ECMC staff accepted KPK’s financial plan but the commission said the company needed to post a bigger bond to clean up leaks and contamination at several sites. KPK proposed upping the bond by $2.9 million, but the staff said an additional $24 million was necessary.

In the end, the ECMC rejected both approaches after finding the analyses failed to show the proposed bonds would be enough. The commission required KPK to pay a standard per-well cost: $30,000 to close each well and $100,000 to reclaim each well site. The bond will cover a little over 1,000 wells. The company will have 90 days after an order is issued to post 10% of the overall bond.

As of Sept. 26, the ECMC had approved 151 financial assurance plans, covering nearly 38,000 wells and providing $570 million. The industry has paid fees for several years into an orphan well fund to help pay to close wells when the owner can’t or won’t or isn’t known.

K.P. Kauffman said it’s disappointed by the commission’s decision and is exploring all administrative and judicial options for relief.

“Yesterday’s decision by the commissioners is the latest in a series of rulings in which KPK has been treated differently and more harshly than other operators,” the company said in a statement. “If the commissioners’ order were to stand, KPK would be the highest-bonded oil and gas operator in the U.S.”

The ECMC has approved financial plans similar to KPK’s for other operators, the company said.

However, Jeff Robbins, commission chairman, said the decision was not influenced by the state’s enforcement actions against KPK or any legal disputes. “This is its own ball of wax.”

The company has been under state scrutiny for a while because of complaints that it has violated state regulations and not cleaned up spills  and contamination.  After finding KPK out of compliance with a plan to resolve the complaints, the ECMC gave the company until Aug. 1 to comply with state rules or face losing its license.

A June 30 ruling in Denver District Court put the ECMC’s order on hold until KPK’s appeal is decided. A trial is scheduled for 2024.

Municipal officials in Dacono and Frederick urged the commission to require KPK to post a much larger bond or order the company to close its low-producing, older wells in their communities. There have been spills and leaks at several well sites, they said. The wells have hindered development and posed hazards to public health and the environment, city officials told the ECMC.

“I do appreciate the relevant local governments taking the time to hire counsel and be involved in this,” Robbins said. “It’s important because they are the boots on the ground that are dealing with some of these things.”

Dacono was proud to have participated in the process and believes it helped ensure continued protection of residents of the city and the state, said Steven Louis-Prescott, an attorney representing the city. He said questions remain about KPK’s plans to close its aging wells and its ability to pay the required bond

Frederick town officials said 95 of KPK’s wells in the town are low-producing, which means they generate fewer than two barrels of oil a day. They have said the company has 17 open remediation sites in the town.

“The Town of Frederick was involved in this issue because it is uniquely impacted by legacy oil and gas wells that are now owned by KPK,” Mayor Tracie Crites said in an email. “These wells have had numerous issues, including leaks causing contamination of both soil and water.

“We hope the decision in this case will lead operators to commit to stronger financial assurance planning and fewer orphaned wells throughout the state of Colorado,” she added.

Updated Oct. 29, 2003, with information on the number of financial assurance plans approved.

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