Winds of Change

Use it or lose it. That’s a basic premise of Colorado water law. Those with water rights must put the water to beneficial use or risk losing the rights to somebody who can. It’s fundamentally anti-speculative.
But Colorado legislators this year created a major exception for two electric utilities that draw water from the Yampa River for coal-burning power plants. They did so through Senate Bill 24-197, which Gov. Jared Polis signed into law in Steamboat Springs in late May.

The two utilities, Xcel Energy and Tri-State Generation and Transmission Association, plan to retire the five coal-burning units — two at Hayden and three at Craig — they operate in the Yampa River Basin by late 2028. These units represent Colorado’s largest concentration of coal plants, 1,874 megawatts of generating capacity altogether. That’s 40% of Colorado’s total coal-fired electrical generation. Together, they use some 19,000 acre-feet of water each year.

What will become of those water rights when the turbines cease to spin? And what will replace that power? The short answer is that the utilities don’t know. That’s the point of the legislation. It gives the utilities until 2050 to figure out their future.

While the legislation is unique to the Yampa Valley, questions of future water use echo across Colorado as its coal plants — two units at Pueblo, one near Colorado Springs, one north of Fort Collins, and one at Brush — all will close or be converted to natural gas by the end of 2030.

Both Xcel and Tri-State expect that at least 70% of the electricity they deliver in 2030 will come from wind and solar. The final stretch to 100%? That’s the hard question facing utilities across Colorado — and the nation and world.

Natural gas is expected to play a continued role as backup to the intermittency of renewables. Moving completely beyond fossil fuels? No one technology or even a suite of technologies has yet emerged as cost-effective. At least some of the technologies that Xcel and Tri-State are looking at involve water.

Fossil fuel plants use less than 1% of all of Colorado’s water. Yet in a state with virtually no raw water resources left to develop, even relatively small uses have gained attention. Colorado’s power future will have implications for its communities and their water, but how exactly that will look remains unknown.

Emissions Goals

The year 2019 was pivotal in Colorado’s energy transition. State lawmakers adopted legislation that specified a 50% economy-wide reduction in greenhouse gas emissions by 2030 and 100% by 2050. A decade before, that bill would have been laughed out of the Colorado Capitol. Even in 2019, some thought it unrealistic. But proponents had the votes, and a governor who had run on a platform of renewable energy.

Something approaching consensus had been achieved regarding the risks posed by climate change. Costs of renewables had plummeted during the prior decade, 70% for wind and 89% for solar, according to the 2019 report by Lazard, a financial analyst. Utilities had learned how to integrate high levels of renewables into their power supplies without imperiling reliability. Lithium-ion batteries that can store up to four hours of energy were also dropping in price.

Tied at the legislative hip to the targets adopted in 2019 were mandates to Colorado’s two investor-owned electric utilities, Xcel Energy and Black Hills Energy. By 2030 they must reduce emissions by at least 80% compared to 2005 levels. Both aim to do even better.

Xcel, the largest electrical utility in Colorado, was already pivoting. In 2017, it received bids from wind and solar developers in response to an all-sources solicitation that caused jaws across the nation to drop. In December 2018 shortly after the election of Gov. Polis, Xcel officials gathered in Denver to boldly declare plans to reduce emissions by 80% by 2030. Platte River Power Authority, the provider for Fort Collins and three other cities in the northern Front Range, later that month adopted a highly conditioned 100% goal. In January 2020, Tri-State announced its plans to close coal plants and accelerate its shift to renewables — it plans to reduce emissions by 89% by 2030. In December 2021, Holy Cross Energy, the electrical cooperative serving the Vail and Aspen areas, adopted a 100% goal for 2030. It expects to get to 91% by 2025.

Colorado’s emissions-reduction goals are economy wide, not just for power production. In practice, this means replacing technologies in transportation, buildings and other sectors that produce greenhouse gas emissions with low- or no-emissions energy sources. As coal plants have closed, transportation has become the highest-emitting sector. Colorado had 126,000 registered electric vehicles and hybrids as of June but hopes to have 940,000 registered by 2030. Buildings pose a greater challenge because most of us don’t replace houses the way we do cars or cell phones. Solutions vary, but many involve increased use of electricity instead of natural gas.

A final twist that has some bearing on water is Colorado’s goal of a “just transition.” House Bill 19-1314 declared that coal-sector workers and communities were not to be cast aside. Efforts would be made to keep them economically and culturally whole.

Possible Water Dividends

Where does this leave water? That’s unclear and, as the 2024 legislation regarding the Yampa Valley spelled out, it is likely to remain unclear for some time. The law prohibits the Division 6 water judge — for the Yampa, White and North Platte river basins — from considering the decrease in use or nonuse of a water right owned by an electric utility in the Yampa Valley.

In other words, they can sit on these water rights through 2050 while they try to figure what technologies will emerge as cost competitive. Xcel Energy and Tri-State will not lose their water rights simply because they’re not using them during this time as would, at least theoretically, be the case with other water users in Colorado.

Conversion of the Cherokee power plant north of downtown Denver from coal to natural gas provides one case study of how energy shifts can affect water resources. Xcel converted the plant to natural gas between 2010 and 2015. Its capacity is now 928 megawatts.

Richard Belt, a water resources consultant for Xcel, says that when Cherokee still burned coal, it used 7,000 to 8,000 acre-feet of water per year; since 2017, when natural gas replaced coal, it uses 3,000 to 3,500 acre-feet per year.

Does that saved water now flow downstream to farmers in northeastern Colorado?

“If the wind is really blowing, there could be some water heading downstream on certain days,” Belt answered. In other words, there’s so much renewable energy in the grid that production from the gas plant at times
is not needed. A more concrete way to look at this conversion, Belt says, is to step back and look at Xcel’s water use more broadly across its system. It also has the Rocky Mountain Energy Center, a 685-megawatt combined-cycle natural gas plant along Interstate 76 near Keenesburg that it bought in 2009 and began operating in 2012. With the plant came a water contract from Aurora Water.

Xcel has been renegotiating that contract, which it projects will be effective in early 2025. The new contract will allow Xcel to take water saved at Cherokee and instead use it at the Rocky Mountain Energy Center. That will allow it to use 2,000 acre-feet less of the water it has been leasing from Aurora each year. Belt says it will save Xcel customers around $1 million a year in water costs.

“Another way to look at this dividend is that we’re going to hand [Aurora] two-thirds of this contract volume, around 2,000 acre-feet a year, and they can use that water within their system,” Belt explains.
Other coal-burning power plants have also closed in recent years, with water dividends of their own. One small coal plant in southwestern Colorado at Nucla, operated by Tri-State, was closed in 2019. In 2022, Xcel shut down one of its three coal units at the Comanche Generating Station in Pueblo.

Colorado Springs Utilities stopped burning coal at its Martin Drake coal-fired plant in 2021, which is located near the city’s center, and replaced it with natural gas. It used some 2,000 acre-feet of water per year in the early 2000s, and was down to only 14 acre-feet per year in 2023. Colorado Springs Utilities — a provider of both electricity and water — delivers 70,000 to 75,000 acre-feet of water annually to its customers. Whatever water savings were achieved in that transition will be folded into the broader operations. The city’s remaining coal plant, Ray Nixon, burns both coal and natural gas. The city delivers about 2,000 acre-feet per year to Nixon to augment groundwater use there.

The 280-megawatt Rawhide coal-fired power plant north of Fort Collins is to be shut down by 2030. Platte River Power Authority, which owns and operates the plant, had not yet chosen a replacement power source as of June 2024. Platte River delivers electricity to Estes Park, Fort Collins, Longmont and Loveland.

That leaves just the 505-megawatt Pawnee among Colorado’s existing coal plants. The plant near Brush is to be retrofitted to burn natural gas by 2026. The water dividend? Xcel is trying to keep its options open.
The one commonality among all the possible power-generating technologies that Xcel may use to achieve its goal of emissions-free energy by 2050 is that, with the exception of some battery technologies, they all require water, says Belt. And that, he says, means it would be unwise to relinquish water without first making decisions about the future.

That’s why this year’s bill was needed. Colorado’s two biggest electrical providers, Xcel and Tri-State, both with coal plants retiring in the Yampa Valley, have questions unanswered.

The Future of Energy

What comes next? Obviously, lots more wind and solar. Lots. The graph of projected solar power in Colorado through this decade looks like the Great Plains rising up to Longs Peak. Construction of Xcel’s Colorado Power Pathway, a 450-mile transmission line looping around the Eastern Plains, will expedite renewables coming online. Tri-State is also constructing new transmission lines in eastern Colorado. The plains landscape, San Luis Valley, and other locations could look very different by the end of the decade.

Very little water is needed for renewables, at least once the towers and panels are put into place.

You may well point out that the sun goes down, and the wind doesn’t always blow. Storage is one holy grail in this energy transition. Lithium-ion batteries can store energy for four hours. That works very effectively until it doesn’t. Needed are new cost-effective technologies or far more application of known technologies.

One possible storage method, called iron-rust, will likely be tested at Pueblo in 2025 by a collaboration between Xcel and Form Energy, a company that proclaims it will transform the grid. It could provide 100 hours of storage. Tri-State’s electric resource plan identifies the same technology.

Other potential storage technologies involve water. Pumped-storage hydropower is an old and proven technology. It requires vertical differences in elevation, and Colorado has that. In practice, finding the right spots for the two reservoirs, higher and lower, is difficult.

Xcel Energy’s Cabin Creek project between Georgetown and Guanella Pass began electrical production in 1967. In this closed-loop system, water from the higher reservoir is released through a three-quarter-mile tunnel to the second reservoir 1,192 feet lower in elevation. This generates a maximum 324 megawatts to help meet peak demands or to provide power when it’s dark or the wind stops blowing. When electricity is more freely available, the water can be pumped back to the higher reservoir. Very little water is lost.

Near Leadville, the U.S. Bureau of Reclamation has a pumped-storage hydropower project at Twin Lakes, the Mt. Elbert Power Plant, with a more modest elevation difference. The plant can generate up to 200 megawatts of electricity.

A private developer with something similar in mind has reported reaching agreements with private landowners along the Yampa River between Hayden and Craig. With private landowners, the approval process would be far easier than if this were located on federal lands. Cost is estimated at $1.5 billion.

Belt points out that the Federal Energy Regulatory Commission has streamlined the permitting process for pumped-storage hydro but that technology remains expensive and projects will take probably 10 to 12 years to develop if everything goes well.

“During that 10 to 12 years, does something new come along? And if you’re committed to pumped storage, then you can’t pivot to this new thing without a financial impact,” he says, explaining a hesitancy around pumped storage.

Green hydrogen is another leading candidate in the Yampa Valley and elsewhere. It uses electrolysis to separate the hydrogen and oxygen in water. Renewable energy can be used to fuel the electrolysis. That’s why it is called green hydrogen as distinct from blue hydrogen, which uses natural gas as a catalyst. A news story in 2023 called it a “distant proposition.” Costs remain high but are falling. Tax incentives seek to spur that innovation.

Gov. Polis’ administration remains optimistic about hydrogen. It participated in a proposal for federal funding that would have created underground hydrogen storage near Brush. That proposal was rejected, but Will Toor, the chief executive of the Colorado Energy Office, has made it clear that green hydrogen and other emerging technologies remain on the table. Xcel says the same thing. “It’s not something we are going to give up on quite yet,” says Belt. The water savings from the conversion of coal to natural gas could possibly play into those plans.

Polis is bullish on geothermal, both kinds. The easier geothermal uses the relatively constant 55 degree temperatures found 8 to 10 feet below ground to heat and cool buildings. The Colorado Capitol has geothermal heating, but the most famous example is Colorado Mesa University, where geothermal heats and cools about 80% of the campus. This technology may come on strong in Colorado, especially in new construction.

Can heat found at greater depths, say 10,000 feet or from particularly hot spots near the surface, be mined to produce electricity? California generates 10.1% from enhanced geothermal, Nevada 5.1%, and Utah 1.5%. Colorado generates zero. At a June conference, Polis said he thought geothermal could produce 4% to even 8% of the state’s electricity by 2040. Geothermal for electric production would require modest water resources.

Nuclear? Those plants, like coal, require water. Many smart people believe it may be the only way that civilization can reduce emissions as rapidly as climate scientists say is necessary to avoid catastrophic repercussions. Others see it as a way to accomplish just transition as coal plants retire.

Costs of traditional nuclear remain daunting. Critics point to projects in other states. In Georgia, for example, a pair of reactors called Vogtle have been completed but seven years late and at a cost of $35 billion, more than double the project’s initially estimated $14 billion price tag. The two reactors have a combined generating capacity of 2,430 megawatts.

New reactor designs may lower costs. The Nuclear Regulatory Commission in 2023 certified design of a small-modular reactor by NuScale. It was heralded as a breakthrough, but NuScale cancelled a contract later that year for a plant in Idaho, citing escalating costs.

Greater optimism has buoyed plans in Wyoming by the Bill Gates-backed TerraPower for a 345-megawatt nuclear plant near the site of a coal plant at Kemmerer. It has several innovations, including molten salt for energy storage and a design that allows more flexible generation, creating a better fit with renewables. Ground was broken in June for one building. An application for the design is pending with the U.S. Nuclear Regulatory Commission. Gates has invested $1 billion and expects to invest many billions more in what he estimates will be a $10 billion final cost. He also hopes to see about 100 similar plants and reduced costs. Other companies with still other designs and ideas say they can also reduce costs. All these lower-cost nuclear solutions exist in models, not on the ground. Uranium supply remains problematic, at least for now, but more difficult yet is the question of radioactive waste disposal.

Into The Future

The potential for nuclear is balled up in the issue of just transition. Legislators in 2019 said that coal communities would not be left on their own to figure out their futures. What this means in practice remains fuzzy.

Consider Pueblo. Xcel Energy on August 1 is scheduled to submit to the Colorado Public Utilities Commission what is being called the Pueblo Just Transition Electric Resource Plan. Through that plan, Xcel must determine to what extent it can, through new generating sources, leave Pueblo economically whole after it closes the coal plants. Existing jobs will be lost, although others in post-closure remediation of the site will be gained. What, then, constitutes a just transition for Pueblo?

A task force assembled by Xcel Energy in January delivered its conclusions after nearly a year of study: “Of all of the technologies that we studied, only advanced nuclear generation will make Pueblo whole and also provide a path to prosperity,” concluded the task force. They advised that a natural gas plant with carbon capture would be a distinctly secondary choice.

What will happen with the water in Pueblo? Xcel Energy has a take-or-pay water contract with Pueblo Water for 12,783 acre-feet per year for the Comanche Generating Station. It must pay for the water even if it does not take it. Pueblo Water has a similar take-or-pay contract for 1,000 acre-feet annually for the 440-megawatt natural gas plant operated by Black Hills Energy near the Pueblo airport.

The draw of these water leases from the Arkansas River isn’t that notable, says Chris Woodka, president of the Pueblo Water board, even in what he describes as a “small year,” with low flows in the river. These water leases constitute some 5% or less of the river’s water, Woodka says. Xcel could tap that same lease for whatever it plans at Pueblo. And if it has no use? “We haven’t had many conversations around what we would do if that lease goes away, because it is so far out in the future.”

Xcel and Tri-State both own considerable water rights in the lower Arkansas Valley, near Las Animas and Lamar. Neither utility has shared plans for using the water, as the ideas of coal or nuclear power plants that initially inspired the water purchases never moved forward. Water in both cases has been leased since its acquisition to Arkansas Basin agricultural producers in order to maintain an ongoing beneficial use.

Why don’t Tri-State and Xcel lease their water in the Yampa River as they do in the Arkansas? Jackie Brown, the senior water and natural resources advisor for Tri-State, explains that there is no demand for additional agricultural water in the Yampa Basin. About 99% of all lands capable of supporting irrigated agriculture already get water. This is almost exclusively for animal forage. This is a valley of hay.

However, the Yampa River itself needs more water. The lower portion in recent years has routinely suffered from low flows during the rising heat of summer. Some summers, flows at Deerlodge, near the entrance to Dinosaur National Monument, have drooped to 20 cubic feet per second. Even in Steamboat, upstream from the power plants, fishing and other forms of recreation, such as tubing, have at times been restricted.

One question asked in drafting the legislation this year was whether to seek protection with a temporary instream flow right for some of the 45 cfs that Tri-State and Xcel together use at the plants at Craig and Hayden. The intent would have been to protect the delivery of some portion of that water to Dinosaur National Monument through 2050. That idea met resistance
from stakeholders.

Instead, a do-nothing approach was adopted. Those framing the bill expect that most of the time, most of the water will flow downstream to Dinosaur anyway. In most years, no demands are placed on the river from November through the end of June. The challenge comes from July through October. The amount of water, used formerly by coal plants, that reaches Dinosaur will
depend upon conditions at any particular time. Have the soils been drying out? Has the summer monsoon arrived?

“Even if you’re adding even half of that [45 cfs], it is a big deal,” says Brown. “If you can double the flow of a river when it’s in dire circumstances it’s a big deal.”

A study conducted by the Colorado River Water Conservation District several years ago examined how much water released from Elkhead Reservoir, located near Hayden, would reach Dinosaur. The result: 88% to 90% did.

Brown says river managers will be closely studying whether the extra water can assist with recovery of endangered fish species and other issues. “There’s a lot of learning to be done. My key takeaway is that that’s really going to contribute to the volume of knowledge that we have and the future management decisions that are made.”

A larger takeaway about this new law is that it gives Colorado’s two biggest electrical providers time. Xcel and Tri-State don’t know all the answers as we stretch to eradicate emissions from our energy by mid-century. Many balls are in the air, some interconnected, each representing a technology that may be useful or necessary to complement the enormous potential of wind and solar generation now being created. All of these new technologies will require water. Some water in the conversion from coal is being saved now, but it’s possible it will be needed in the future.

No wonder Xcel’s Belt says its “imprudent in a very water-constrained region to let go of a water asset that you may not get back, until you know how some of these balls are going to land.”

Allen Best is a frequent contributor to Headwaters magazine. He publishes Big Pivots, an e-journal that chronicles the energy and water nexus.