Ceremonial shovels mark the location of the Innovation Center coal refinery field demonstration project north of Gillette on Sept. 2, 2022. It will be co-located with Atlas Carbon’s facility that produces activated carbon products. (Dustin Bleizeffer/WyoFile)
Biden administration’s suite of coal pollution rules a win for climate and health, advocates say, but a major blow to one of Wyoming’s bedrock economic drivers.
Gov. Mark Gordon has promised to sue over a new suite of federal rules that most observers agree will hasten the U.S. thermal coal industry’s trajectory toward extinction — an existential threat to many Wyoming communities and one of the state’s main economic drivers.
The U.S. Environmental Protection Agency on Thursday issued four “final” rules aimed at drastically cutting coal pollution, including a mandate that existing coal-fired power plants cut or capture 90% of their planet-warming carbon dioxide emissions by 2032 or convert to natural gas or close altogether. The agency’s other rules set timelines for significant cuts to smokestack emissions of mercury and other toxic metals, polluted wastewater from coal power plants and more stringent standards for coal ash disposal.
The “power plant” rules make good on President Joe Biden’s promise to address human-caused climate change, according to the EPA. The actions are also intended to help curtail illness and premature deaths from coal pollution while providing a clear regulatory framework for utilities to shift to renewable sources of energy.
The agency also noted that it consulted with coal-reliant utilities about their existing plans regarding coal facilities and crafted the implementation schedules to allow for planning that avoids electrical power supply issues.
Gov. Mark Gordon and U.S. Environmental Protection Agency Administrator Michael Regan held a joint press conference at the University of Wyoming on August 9, 2023. (Dustin Bleizeffer/WyoFile)
“By developing these standards in a clear, transparent, inclusive manner, EPA is cutting pollution while ensuring that power companies can make smart investments and continue to deliver reliable electricity for all Americans,” EPA Administrator Michael S. Regan said in a prepared statement.
Coal proponents in Wyoming are furious.
This graph shows the globally averaged monthly mean carbon dioxide abundance measured at the Global Monitoring Laboratory’s global network of air sampling sites since 1980. Data are still preliminary, pending recalibrations of reference gases and other quality control checks. Credit: NOAA GML
While the rules target coal-fueled power plants, they also put Wyoming coal mines on notice: Their already waning U.S. customer base has an expiration date.
“It is clear the only goal envisioned by these rules released by the Environmental Protection Agency today is the end of coal communities in Wyoming,” Gordon said in a prepared statement Thursday. “EPA has weaponized the fear of climate change into a crushing set of rules that will result in an unreliable electric grid, unaffordable electricity and thousands of lost jobs.”
The Wyoming Mining Association also discounted climate change as an excuse to attack the coal industry.
“Wyoming is once again the sacrificial lamb on the altar of the climate change cult,” the association’s Executive Director Travis Deti said.
The rules
The carbon dioxide emissions rule applies to coal-fired power plants as well as new natural gas-fired facilities, requiring them to prevent at least 90% of greenhouse gasses from entering the atmosphere.
“Existing coal-fired power plants are the largest source of [greenhouse gas] from the power sector,” the EPA stated in the rule. “New natural gas-fired combustion turbines are some of the largest new sources of [greenhouse gas] being built today, and these final standards will ensure that they are constructed to minimize their [greenhouse gas] emissions.”
The rule updating Mercury and Air Toxics Standards tightens emissions by about 70%, an especially significant reduction for plants that burn lignite — a lower-value coal than Wyoming’s subbituminous product — according to the agency.
Wyoming remains the nation’s largest coal producer, although production has plummeted by nearly half since 2008, with companies shipping some 237 million tons in 2023, according to the Wyoming State Geological Survey. More than 90% of coal mined in the state is sold to power plants in the U.S., which is why it’s often referred to as “thermal coal” — unlike “metallurgic coal” that is sold to steel manufacturers.
Wyoming coal production has decreased by nearly half since 2008. (University of Wyoming)
Coal mining contributed some $650 million in taxes, royalties and fees to the state in 2019 and employed more than 5,000 workers, according to the Wyoming Mining Association.
The vast majority of coal mining occurs in the Powder River Basin in the northeast corner of the state, while several communities host nearby coal-fired power plants: Gillette, Glenrock, Wheatland, Kemmerer and Rock Springs.
Although Wyoming has experienced declines in both coal production and coal-fired power, the industry still serves as a major economic backbone for the state — and a significant source of government revenue. The potential loss of coal-fired power facilities is an especially daunting prospect for nearby communities.
Those communities have wrestled with the knowledge of potential plant closures for a long time already, and the EPA’s new rules only serve to clarify that potential reality, said Robert Godby, associate professor at the University of Wyoming’s Economics Department.
“It really just kind of steepens the glide path to what we all knew was happening anyway,” he told WyoFile on Friday.
Explosive materials are loaded into a “blast hole” at a coal mine. (Dyno Nobel)
The new rules are likely to be challenged in court, not only by Wyoming, but also by other coal-reliant states, Godby said. Politics will also continue to play a role — particularly if a Republican wins the presidential election this year. He noted, however, that former President Donald Trump was not able to make good on a promise to turn around the coal industry’s decline.
Regardless, utilities are under increasing pressure to make long-term investment decisions in a quickly changing energy environment, and the EPA’s actions this week diminish the likelihood that they’ll find the regulatory certainty needed to invest in coal-fueled power.
“It makes it more likely they’re going to retire [coal plants] and announce firm dates,” Godby said. “That’s going to create more certainty for the communities that are affected.”
Meantime, Gordon, who has touted technologies to reduce carbon dioxide from coal power plants, has vowed to fight the rules.
“These rules are a travesty, and their effects are devastating,” Gordon said. “I have directed the Wyoming Attorney General to engage with and lead a coalition of states to challenge the power plant emissions rule, and we are prepared to apply our litigation strategy to the oncoming wave of federal regulatory actions that threaten Wyoming.”
The University of Wyoming’s School of Energy Resources, and its partners, are advancing multiple CO2 capture and sequestration demonstration projects at Basin Electric’s Dry Fork Station north of Gillette, seen here on Sept. 2, 2022. (Dustin Bleizeffer/WyoFile)
Now this is what I’m talking about: Last week, the Biden administration forked out $7 billion to states, tribal nations, and non-profits to carry out its Solar for All program aimed at expanding rooftop and residential solar and energy storage access to low-income folks and other underserved communities. About $1.7 billion of that cash will go to the West (see breakdown below). This is what I call a win-win-win-win situation:
Win 1 = It will add more solar power to the nation’s energy mix, hopefully displacing some fossil fuel generation, which will result in cleaner air and fewer greenhouse gas emissions.
Win 2 = This added solar will be on rooftops or vacant lots in or near towns or cities, reducing the need to blanket the desert with photovoltaics, which can be hugely destructive to ecosystems and wildlife habitat.
Win 3 = Rooftop and community-level solar installations will increase residents’ self-sufficiency and reduce dependency on the grid, which is becoming less and less reliable as more frequent and severe extreme weather events damage infrastructure and utilities are forced to shut off power to reduce wildfire hazard. Plus, many homes that lack access to electricity, especially on tribal lands, will now have power.
Win 4 = This program has the potential to radically transform the residential solar landscape, redistributing this exclusive amenity now reserved to homeowners who can afford to spend tens of thousands of dollars upfront on a solar system, to, well, all of us, including renters.
Recipients include:
Colorado Energy Office: $156 million for single-family and multifamily rooftop solar statewide.
New Mexico Energy, Minerals, & Natural Resources Department: $156 million to “help overcome existing barriers to widespread adoption of distributed solar generation” by expanding access to shared solar beyond the new community solar program.
Utah Office of Energy Development: $62 million to launch a new program to “strengthen the market for deploying residential-serving solar … for disadvantaged and low-income homes”
Montana and Wyoming and Idaho, Bonneville Environmental Foundation: $131 million to “expand economic and environmental benefits of solar to low-income, tribal, and disadvantaged communities.”
Colorado-based Oweesta Corporation: $156 million to “address adoption barriers to Native residential and community solar deployment” in tribal lands across the nation.
Executive Office of the State of Arizona: $156 million to “bring the benefits of the state’s abundant solar resources to the state’s low-income and disadvantaged communities.”
California Infrastructure Economic Development Bank: $250 million to reach “the homes and businesses statewide that are most in need of affordable, reliable clean energy.”
Nevada Clean Energy Fund: $156 million
Hopi Utilities Corporation: $25 million to deploy residential solar and storage systems on the Hopi Reservation, where 35% of households do not have electricity and those that do experience frequent and extended outages.
GRID Alternatives (Western Indigenous Network Solar for All) $62 million. Provides grants and incentives and technical assistance to deploy tribal residential solar, prioritizing communities in Arizona, Colorado, Nevada, New Mexico, and Utah.
Alaska Energy Authority, $62 million, to partner with Alaska Housing Finance Corporation to deploy solar photovoltaic infrastructure statewide.
Oregon Department of Energy, $87 million
Washington State Department of Commerce, $156 million
Alaska, Tanana Chiefs Conference $62 million to provide tribal residents with residential and community solar.
***
And the good news keeps a coming: Wind, solar, hydropower, and geothermal generation supplied more than 100% of California’s energy demand on 39 of 47 days this spring. It wasn’t all day, by any means, but anywhere from about 15 minutes on some days to just over nine hours on April 20.
That is to say that a state of 39 million people, with one of the world’s largest economies, ran on non-fossil-fuel energy sources for more than nine hours. That’s a big deal.
Sure, it was on a Saturday in spring, when power demand tends to be lower, and on 4/20, when I guess a lot of people might have been outside smoking dope, which may or may not have affected electricity use. And a small percentage of that power came from large hydropower dams, which have their own problems and which California does not apply toward its renewable portfolio standards. Still, it’s a milestone that wasn’t imaginable a couple of decades ago, when coal generation dominated the power grid and utility-scale solar and wind power barely registered.
Most of the power came from utility-scale solar installations (California grid operators don’t track rooftop solar output, but it contributed by reducing overall demand). In fact, the state’s collective solar systems not only met demand, but exceeded it enough to charge grid-scale batteries and still have enough left over to export to other states. On some days there was so much solar they had to curtail generation — or basically throw it away.
Here’s what it looked like:
Graphic credit: Jonathan P. Thompson/The Land Desk
The green line represents electricity demand for the day. Part of the reason it dips during the middle of the afternoon is because that’s when rooftop solar output is at its peak, and rooftop solar reduces grid demand since folks are using power from their own panels rather than taking it from the grid. Source: CAISO.
And then there’s the dreaded solar duck curve to deal with. This refers to the shape of the electricity net-demand graph on sunny days (net-demand is determined by subtracting solar and wind supply from demand since they aren’t “dispatchable” power sources). On a number of days this spring, solar output was so high that it pushed the net-demand curve down into negative territory in the middle of the day. The real problem’s start when the sun sets and solar output suddenly diminishes. The net-demand curve shoots back up, forcing grid operators to fire up natural gas generation to “follow the load,” or meet demand.
But even that dynamic is changing as an ever-increasing amount of that late afternoon load spike is being met with power from grid-scale batteries that had been charging all day. On the evening of April 16, for example, another milestone was reached when battery storage discharge became the largest energy source on California’s grid, contributing nearly as much power as natural gas and nuclear generation combined for about an hour. Just this week, California announced it had surpassed 10,000 megawatts of battery storage capacity — a 1,250% increase from just five years ago.
Batteries alone, however, won’t get California or the West to 100% clean energy. The region will also need more of what’s known as “geographic smoothing,” or moving power around the region to fill gaps left when wind and solar generation drop off. This might include sending Wyoming wind power to California when the sun stops shining, or shipping California solar to Colorado during the middle of the day. Achieving this will require better regional integration of the grid and power markets. Just yesterday the Biden administration announced a plan to spend $331 million to help build out transmission lines, an important step in realizing this goal.
A pronghorn hangs out among Wyoming wind turbines. Better integration of the Western grid would allow California and Arizona to draw on Wyoming wind to back up solar when the sun goes down. Jonathan P. Thompson photo.
NEWS: Another proposed pumped hydropower storage project on the Navajo Nation bites the dust.
CONTEXT: One way to store energy is in batteries. Another way is with pumped hydropower facilities, usually consisting of two reservoirs, one above the other. Surplus power from the grid, usually generated by solar or wind during the day, is used to pump water from the lower to the upper reservoir. When the power is needed, such as when the sun sets and solar drops off, water is released from the upper reservoir and gravity propels it through a turbine that feeds electricity into the grid before emptying into the lower reservoir to begin the cycle anew.
It’s smart technology, capable of providing massive amounts of energy just when it’s needed. The problem is, these things require water, dams, reservoirs, pumping plants, and pipelines, all of which can have an impact. That means properly siting these facilities — and working with stakeholders before finalizing plans or applying for permits — is important. And, well, so far, a lot of developers haven’t done a great job with that, and now it’s biting them in the butt.
Confluence of the Little Colorado River and Colorado River; Credit: EcoFlight
A few months ago the Land Desk reported on federal regulators’ rejection of seven proposed pumped hydropower storage projects on the Navajo Nation, while also establishing a policy of denying any project on tribal land if the tribe opposes it. The regulators deferred a decision on one additional proposal — the massive, three-reservoir Big Canyon project that would be on Navajo Nation land along a tributary of the Little Colorado River. The Navajo Nation initially had expressed concerns about the proposal without explicitly opposing it. After the new policy was put in place, the tribe clarified its opposition. This week, the Federal Energy Regulatory Commission followed its new policy and rejected the permit.
It’s a bummer to see so many clean energy proposals go down in flames. Had they been built, the projects would have contributed mightily to the Western energy transition. Their failure, however, is not on the tribal nation or advocates who opposed the projects. The developers are to blame for faulty siting decisions and for failing to adequately consult with stakeholders at the very beginning of the process. That would save everyone a lot of headaches, and it might even result in some good projects getting built in the right places.
For more on the proposals and their problems, check out this excellent piece — complete with great maps — by the Grand Canyon Trust’s Daryn Akei Melvyn.
📸 Parting Shot 🎞️
Ute Mountain in the spring. Jonathan P. Thompson photo.
The U.S. Environmental Protection Agency on Thursday released a sweeping set of rules aimed at cutting air, water and land pollution from fossil fuel-fired power plants.
Environmental and clean energy groups celebrated the announcement as long overdue, particularly for coal-burning power plants, which have saddled hundreds of communities across the country with dirty air and hundreds of millions of tons of toxic coal ash waste. The ash has leached a host of toxins – including arsenic, mercury, lead, cadmium, radium and other pollutants – into ground and surface water.
“Today is the culmination of years of advocacy for common-sense safeguards that will have a direct impact on communities long forced to suffer in the shadow of the dirtiest power plants in the country,” said Ben Jealous, executive director of the Sierra Club, one of the nation’s oldest and largest environmental organizations. “It is also a major step forward in our movement’s fight to decarbonize the electric sector and help avoid the worst impacts of climate change.”
But some electric industry and pro-coal organizations blasted the rules as a threat to jobs and electric reliability at a time when power demands are surging. They also criticized the rule’s reliance on largely unproven carbon capture technologies.
America’s Power, a trade organization for the nation’s fleet of about 400 coal power plants across 42 states, called the number of new rules “unprecedented,” singling out the new emissions standards that will force existing coal plants to cut their carbon emissions by 90% by the 2032 if they intend to keep running past 2039. Michelle Bloodworth, the group’s president and CEO, called the rule “an extreme and unlawful overreach that endangers America’s supply of dependable and affordable electricity.”
The Pennsylvania Coal Alliance, a nonprofit organization representing Pennsylvania coal mining companies, called the new rule “a haphazard and dangerous threat to our grid’s electricity supply, national security and our economy,” in a news release.
‘This forces that’
Many experts expect the regulations to be litigated, particularly the carbon rule, since the last time the EPA tried to restrict carbon emissions from power plants, a group of states led by West Virginia mounted a successful legal challenge that went to the U.S. Supreme Court.
But Julie McNamara, deputy policy director with the Union of Concerned Scientists, said the agency took great pains to conform the rule to the legal constraints outlined by the court.
“This rule is specifically responsive to that Supreme Court decision,” she said. “Which doesn’t mean that it won’t go to the courts but this is so carefully hewn to that decision that it should be robust.”
The four rules EPA released Thursday mainly target coal-fired power plants.
“By developing these standards in a clear, transparent, inclusive manner, EPA is cutting pollution while ensuring that power companies can make smart investments and continue to deliver reliable electricity for all Americans,” EPA Administrator Michael S. Regan said.
In some ways, they attach a framework to a sea change in electric generation that is already well under way, McNamara said.
Coal accounted for just 16% of U.S. electric generation in 2023, according to the U.S. Energy Information Administration. In 1990, by comparison, it comprised more than 54% of power generation. However, some states are more reliant on coal power than others.
In 2021, the most coal-dependent states were West Virginia, Missouri, Wyoming and Kentucky, per a 2022 report by the EIA.
“This rulemaking adds structure to that transition,” McNamara said. “For those who have chosen not to assess the future use of their coal plants, this forces that.”
The same EIA report found that Ohio and Pennsylvania had the largest declines in coal-fired capacity over the past two decades. Both states shifted from coal to natural gas as their largest source of electricity over that period.
Heather O’Neill, president and CEO of the clean energy trade group Advanced Energy United, said the new regulations are a chance for utilities to embrace cheaper, cleaner and more reliable options for the electric grid.
“Instead of looking to build new gas plants or prolong the life of old coal plants, utilities should be taking advantage of the cheaper, cleaner, and more trusty tools in the toolbox,” she said.
The carbon rule
In 2009, the EPA concluded that greenhouse gas emissions “endanger our nation’s public health and welfare,” the agency wrote, adding that since that time, “the evidence of the harms posed by GHG emissions has only grown and Americans experience the destructive and worsening effects of climate change every day.”
The new carbon emissions regulation will apply to existing coal plants and new natural gas plants. Coal plants that plan to operate beyond 2039 will have to capture 90% of their carbon emissions by 2032. New gas plants are split into three categories based on their capacity factor, a measure of how much electricity is generated over a period of time relative to the maximum amount it could have produced.
The plants that run the most (more than 40% capacity factor) will have to capture 90% of their carbon emissions by 2032. Existing gas plants will be regulated under a forthcoming rule that “more comprehensively addresses GHG emissions from this portion of the fleet,” the agency said.
Michelle Solomon, a senior policy analyst for Energy Innovation, an energy and climate policy think tank, predicts that most coal plants will close rather than install the costly technology to capture carbon emissions.
“Climate goals aside, the public health impacts of the rules in securing the retirement of coal fired power plants is so important,” she said. Coal power in the U.S. has been increasingly pressured by cheaper gas and renewable generation and mounting environmental restrictions, but some grid operators have still been caught flat-footed by the pace of coal plant closures.
“I think the role of this rule, to provide that certainty about where we’re going, is so crucial to get the entities that have control over the rate of the transition to start to take action here,” she said. But the National Rural Electric Cooperative Association’s CEO, Jim Matheson, called the rules “unlawful, unrealistic and unachievable” noting that it relies on technology “that is not ready for prime time.”
And Todd Snitchler, president and CEO of the Electric Power Supply Association, a trade group for competitive power suppliers, called the rule “a painful example of aspirational policy outpacing physical and operational realities” because of its reliance on unproven carbon capture and hydrogen blending technologies to cut emissions.
A beefed up Mercury and Air Toxic Standards rule
The EPA called the revision to the Mercury and Air Toxic Standards “the most significant update since MATS was first issued in February 2012.” It predicted the rule would cut emissions of mercury and other air pollutants like nickel, arsenic, lead, soot, sulfur dioxide, nitrogen oxide and others. It cuts the mercury limit by 70% for power plants fired by lignite coal, which is the lowest grade of coal and one of the dirtiest to burn for power generation.
For all coal plants, the emissions limit for toxic metals is reduced by 67%. The EPA says the rule will result in major cuts in releases of mercury and other hazardous metals, fine particulate matter, nitrogen oxides and carbon dioxide. The agency projects “$300 million in health benefits,” including reducing risks of heart attacks, cancer and developmental delays in children and $130 million in climate benefits.
Stronger wastewater discharge limits for power plants
Coal fired power plants use huge volumes of water, and when the wastewater is returned to lakes, rivers and streams it can be laden with mercury, arsenic and other metals as well as bromide, chloride and other pollution and contaminate drinking water and harm aquatic life.
The new rule is projected to cut about 670 million pounds of pollutants discharged in wastewater from coal plants per year. Plants that will cease coal combustion over the next decade can abide by less stringent rules.
“Power plants for far too long have been able to get away with treating our waterways like an open sewer,” said Thomas Cmar, a senior attorney at Earthjustice, a nonprofit environmental law organization, during a briefing on the new rules earlier this week.
Closing a coal ash loophole
Coal ash, what’s left after coal has been burned for power generation, is one the nation’s largest waste streams. The 2015 EPA Coal Combustion Residuals rule were the first federal regulations for coal ash. But that rule left about half of the ash sitting at power plant sites and other locations – much of it in unlined disposal pits – unregulated because it did not apply to so-called “legacy impoundments” that were not being used to accept new ash.
“We’re going to see a long-awaited crackdown on coal ash pollution from America’s coal plants, and it’ll be a huge win for America’s health and water resources,” said Lisa Evans, a senior attorney with Earthjustice. “They are all likely leaking toxic chemicals like arsenic into groundwater and most contain levels of radioactivity that can be dangerous to human health.”
Groundwater monitoring data shows that the vast majority of ash ponds at coal plants are contaminating groundwater, said Abel Russ, a senior attorney with the Environmental Integrity Project. Butunder the old rule, Russ said, facilities could dodge cleanup requirements by blaming contamination on older ash dumps not covered by the regulation.
“This is a huge loophole,” Russ said. “You can’t restore groundwater quality if you’re only addressing half of the coal ash sources on site.”
However, several attorneys on the Earthjustice briefing said the new rules, which will require monitoring at clean up and hundreds of more ash sites, will only be as good as the enforcement.
“It’s meaningful only if these utilities obey the law. Unfortunately to date, many of them have not,” said Frank Holleman, a senior attorney with the Southern Environmental Law Center.
Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence. Contact Editor McKenzie Romero for questions: info@utahnewsdispatch.com. Follow Utah News Dispatch on Facebook and Twitter.
Embracing the state’s decades of collaboration, federal officials have found more agreement than outrage in response to a pending plan to protect the iconic western bird.
As home to about 38% of the planet’s remaining greater sage grouse — far more than any other state or province — and the architect of key conservation measures, Wyoming has a lot to gain or lose from upcoming changes to the complex, multi-agency matrix of rules and regulations governing management of the imperiled bird and its habitat.
Those stakes were top of mind Wednesday evening for Natrona County rancher Doug Cooper and others who attended a BLM information session on the agency’s recently released draft management plan for sage grouse habitat.
“When you say ‘conservation,’ it sounds wonderful,” Cooper said. “But I’m not sure ‘conservation’ is going to mean just that when we get down on the ground.”
Similar questions bubbled up for the dozen residents trying to make sense of the latest developments in what has been a whipsaw of approaches between Republican and Democratic administrations. Does the pending plan account for sage grouse predation from ravens and magpies? Is livestock grazing considered a harmful practice that might come under new restrictions in sage grouse habitats? And how might restrictions on federal lands impact grazing and oil and gas development on adjacent private property?
Natrona County rancher Doug Cooper poses a question to Bureau of Land Management officials April 24, 2024 in Casper. (Dustin Bleizeffer/WyoFile)
Not only is the bird’s future at stake, but it serves as an indicator for 350 other species that rely on a sprawling sage-steppe ecosystem that also supports rural economies in Wyoming and throughout much of the West. If the sage grouse is in peril, so are myriad other species and rural economies, according to proponents. The future of the species and its habitat also has major implications for the oil and gas industry, which frequently targets minerals underlying the sage grouse’s habitat in Wyoming.
The agency is soliciting public comments through June 13 on its draft environmental impact statement. After weighing that input, the BLM will issue a final rule for how it will manage sage grouse habitat in 10 western states, including the species’ stronghold in Wyoming.
“It is extremely important to get your guys’ feedback and ideas on how this plan can be improved,” BLM Wyoming Sage Grouse Coordinator Matt Holloran said.
Holloran, a wildlife biologist who has led myriad sage grouse studies, explained that the draft plan includes several aspects of the agency’s 2015 and 2019 plans while incorporating new scientific data and accounting for mounting pressures on the bird’s habitat from climate change, invasive plant species and wildfire.
The draft plan includes six alternative approaches, ranging from very stringent conservation measures to no change in current management. The BLM’s “preferred” option is Alternative 5, which mostly aligns with Wyoming’s own evolving management strategies implemented by executive order under recent governors.
Bureau of Land Management Wyoming Sage Grouse Coordinator Matt Holloran (right) visits with a Natrona County resident April 24, 2024 in Casper. (Dustin Bleizeffer/WyoFile)
That alignment with state policy has likely contributed to stakeholders across the spectrum in Wyoming expressing cautious, but caveated, optimism since the BLM published the draft plan in March.
Sage grouse conservation in Wyoming
The BLM manages 18 million surface acres and about 43 million acres of subsurface minerals in Wyoming. Although the agency does not manage wildlife, it does manage wildlife habitats, giving it an outsized influence on the state’s bedrock energy, recreation, wildlife and agriculture industries.
When conservation groups in the early 2000s sounded alarms about declining sage grouse populations, state leaders sprung into action fearing economy-endangering federal action, including a potential listing under the Endangered Species Act. Wyoming has earned accolades since for being the first state to voluntarily take on greater sage grouse protections — both a proactive drive for conservation and in defense of ongoing agriculture and oil and gas development.
In some instances, the state’s protections go further than the federal government’s, including a maximum 5% disturbance threshold for industrial activity in sage grouse “core areas.” So far, Wyoming is the only western state with a disturbance threshold that also takes wildfire impacts into account.
How the 5% calculation is made, however, is important. Some critics have alleged that some core area boundaries are simply made larger to allow for more disturbance.
The gubernatorial-appointed Sage Grouse Implementation Team is considering adding tens of thousands of acres of protective “core area,” along with some retractions, to the state map. Proposed changes are outlined here. (Sage Grouse Implementation Team)
Following Wyoming’s lead, the BLM proposes to maintain livestock grazing within core areas — mostly considered an insignificant impact and, in some cases, beneficial to sage grouse, according to state and federal documents. Although the BLM’s preferred alternative doesn’t include major changes to grazing, it does further define poor grazing practices that would be restricted in sage grouse management areas, according to local BLM officials.
Stakeholder responses
Oil and gas industry officials in Wyoming have tentatively expressed hope for a workable federal approach to conserving sage grouse and its habitat. Notably, the BLM’s preferred alternative does not include new leasing restrictions for oil and gas.
Conservation groups, however, want the BLM to include the use of a special wildlife habitat designation — Areas of Critical Environmental Concern — which would prohibit industrial activities. They point to a 2021 U.S. Geological Survey study that shows sage grouse populations have declined 80% throughout the West since 1965, and that even with recent conservation measures the species’ population is still expected to decline.
Responding to a question Wednesday, the BLM’s Holloran said the agency takes the species’ cyclical population into account. “What you see is those lows keep getting lower and the highs are not as high,” he said.
The Petroleum Association of Wyoming says it will push back against calls to include stringent habitat designations such as Areas of Critical Environmental Concern.
“Alternative 5 is the best option presented, but there is still work to be done,” PAW Vice President Ryan McConnaughey told WyoFile via email. “We appreciate the BLM’s willingness to take a measured approach and will work through the comment process to share our concerns.”
Reached for comment, Gov. Mark Gordon’s office referred to earlier statements regarding the BLM’s draft plan.
“While more analysis of this is needed,” Gordon said in March, “the first pass shows the BLM picked a preferred alternative that will allow for detailed comments that specifically [address] Wyoming’s concerns, including that the preferred alternative does not propose Areas of Critical Environmental Concern (ACEC) on top of our state identified core areas.”
Visit this BLM website for more information regarding the draft plan and how to comment.
by Jonathan Thompson, High Country News April 25, 2024
Welcome to the Landline, a monthly newsletter from High Country News about land, water, wildlife, climate and conservation in the Western United States.Sign up to get it in your inbox.
On March 27, Interior Secretary Deb Haaland signed an order withdrawing nearly 222,000 acres of federal land in western Colorado’s Thompson Divide area from future mining claims and oil and gas leases. The protected area includes aspen forests, alpine ridges, piñon-juniper-dotted mesas and high-country meadows — diverse habitat that is home to an array of big game species and other wildlife. It stretches from Glenwood Springs to Crested Butte and over to Paonia, home of High Country News’ headquarters.
The move was a big deal for the eclectic ensemble of local ranchers, environmentalists and recreational users who had spent the last two decades fighting proposed mining and fossil fuel development in the area. It solidified a decade-old ban on new oil and gas leases while also driving a nail into the coffin of a thwarted bid to mine molybdenum on the “Red Lady,” a wildflower-strewn mountain outside Crested Butte.
The Thompson Divide protections cover just one-tenth of 1% of the land administered by the Bureau of Land Management. So a cynic might see this temporary withdrawal — it expires in 2044 — as little more than a mildly consequential attempt by President Joe Biden to further differentiate himself from his Republican rival and perhaps regain the support of voters disillusioned by his administration’s failure to end or significantly curtail fossil fuel development on public lands.
Zoom out a bit, though, and a much different picture reveals itself: The Thompson Divide withdrawal, like the Chaco region leasing ban, is merely one piece in a far larger policy puzzle. Taken alone, they’re not terribly significant. But the whole is far greater than the sum of the parts: It’s the most significant shift in public-land management since Congress passed the Federal Land Policy and Management Act of 1976, which mandated multiple use and sought to rid the BLM of its reputation as the “Bureau of Livestock and Mining,” in the process rocking the Western political landscape and sparking the Sagebrush Rebellion.
Marcelina Mountain in the Raggeds Wilderness is seen from Gunnison National Forest’s Horse Ranch Park trail, Colorado. A portion of the scene is part of a withdrawal of nearly 222,000 acres of federal lands in Colorado’s Thompson Divide area from future mining claims and oil and gas leases.
The administration has issued so many public-lands-related orders, rules and protections over the last several weeks that I’ve had a tough time keeping up. Tracking the environmentalists’ fluctuating responses — along with the growing outrage from Republican officials — has been downright exhausting, and at times exasperating. The recent acts include:
The BLM finalized its methane waste prevention rule on March 27, requiring operators on public lands to find and repair leaks and to reduce flaring and venting of the potent greenhouse gas. Each year, oil and gas facilities on federal land lose about 44.2 billion cubic feet of methane — i.e., natural gas — and other associated gases to venting and flaring alone. This equates to burning 2.7 million tons of coal, and it also robs American taxpayers of as much as $32 million per year in lost royalties. The rule will not only require drillers to capture or reuse methane when feasible, it will also charge royalties on wasted gas, bringing in tens of millions of dollars annually in additional revenue.
The administration blocked new oil and gas leases on 13 million acres — or just over half — of the National Petroleum Reserve-Alaska. The move is a bittersweet victory for environmentalists; it doesn’t affect the gargantuan Willow Project, which the Biden administration approved last year, or any other active leases in the reserve. Alaska Republicans slammed Biden nonetheless, calling his action an “illegal” blow and a “one-two punch” to the state’s economy.
The administration revoked a Trump-era approval for the proposed 211-mile Ambler industrial road through northwestern Alaska wilderness, saying it would violate environmental laws and harm wildlife and Indigenous subsistence hunters. The road would give mining companies access to a massive copper deposit buried beneath ecologically sensitive lands.
The Biden administration also blocked new mining claims and oil and gas leases on 4,200 acres of federal land near Placitas, New Mexico, for the next 50 years. The Pueblos of San Felipe and Santa Ana consider the land in question sacred.
The administration finalized rules raising royalty rates and reclamation bonding amounts for oil and gas drilling on federal land. Environmentalists welcomed the new rules, which mark one of the most significant changes to the Mineral Leasing Act since it became law in 1920. However, some argued that they did not go far enough to reduce hydrocarbon production — or reduce the resulting emissions — from public lands. And a ProPublica/Capital & Main investigation found that the new bonding amounts, which were based on flawed math, would not be nearly enough to cover the actual costs of cleaning up all the wells. Meanwhile, New Mexico’s oil and gas industry, which has enjoyed record-high profits in recent years, whined: “The new anti-oil and gas development policies will substantially handcuff production opportunities for small producers.”
The Biden administration just blocked new oil and gas leases on over half of Alaska’s National Petroleum Reserve.
Probably the most intense reactions — of both elation and anger — came in response to last week’s finalization of the public-lands rule, designed to put conservation on a par with oil and gas development, grazing and other extractive uses. The rule directs the agency to prioritize landscape health and creates a mechanism enabling outside entities to lease public land for restoration projects, much as a rancher or oil and gas company might lease BLM land. It also allows firms to lease land for mitigation work to offset impacts from development elsewhere on public lands, and it clarifies the process for designating areas of critical environmental concern, or ACECs, where land managers can add extra regulations to protect cultural or natural resources. And it directs the agency to incorporate Indigenous knowledge into decision-making, particularly when considering ACECs.
Environmentalists lauded the decision. In a written statement, Wilderness Society President Jamie Williams called it a “generation-defining shift in how we manage our shared resources.” It was met by an equally fervent but entirely opposite response from conservative lawmakers. Rep. Lauren Boebert, a Colorado Republican, denounced it as a “land grab” that would “end federal grazing” and block access to public lands — a misguided worry that was echoed by a variety of her GOP colleagues.
Both responses are likely to prove excessive. The rule doesn’t add any new restrictions or put any public land off-limits to development, nor does it give greens the power to expel a legitimate drilling, mining or grazing operation in order to do a restoration project. It simply provides new tools to help the BLM uphold the multiple-use charge that Congress mandated nearly 50 years ago, before the agency went astray during the Reagan and successive Bush administrations. And Boebert’s notion that it will hurt grazing is especially off-base: While Biden has occasionally stood up to the oil industry, he has done nothing to reform public-lands grazing policy, much to conservationists’ dismay.
Again, taken on its own, the new rule is hardly radical or revolutionary. But combined with the administration’s other actions — from significantly reducing the amount of land leased to oil and gas companies, to restricting energy development via resource management plans, to establishing new and restoring shrunken national monuments — it begins to amount to something important. At long last, a coherent — if imperfect — public-lands climate policy has begun to take shape.
This article first appeared on High Country News and is republished here under a Creative Commons license.
The wave at Glenwood Whitewater Park has become a destination for kayaking and paddling enthusiasts. It’s also a nice spot for families looking to spend time on a sunny afternoon. Streamflow on the Colorado River near the park on April 12, 2023 was at 2,040 cubic feet per second. CREDIT: LAURINE LASSALLE/ASPEN JOURNALISM
On April 23, during the administrative public hearing of the Board of Mesa County Commissioners, they approved a million-dollar contribution toward the permanent protection of the most senior, non-consumptive water right on the Colorado River — the Shoshone water rights.
“Mesa County’s $1 million investment in the Shoshone water rights is not just a financial commitment, but a pledge to our community’s future,” said Bobbie Daniel, Chair of the Board of Mesa County Commissioners. “By safeguarding these rights, Mesa County ensures that the West Slope’s lifeblood — our beloved Colorado River — continues to sustain our families, farms, and natural habitats. We stand united with our fellow counties and stakeholders in protecting and preserving our most precious resource for future generations.”
For more information about the Shoshone Water Right Preservation Campaign & Coalition, visit KeepShoshoneFlowing.org.
Watch the video below to learn why the signing of the Shoshone Water Rights Agreement is vital to Mesa County.
Adult Yellow-billed Cuckoo. Photo: Andy Reago and Chrissy McClarren/Flickr (CC-BY-2.0)
Click the link to read the release on the Audubon website (Jennifer Pitt):
March 29, 2024
Audubon has joined partner conservation organizations to propose “Cooperative Conservation” as an alternative for the federal Bureau of Reclamation (Reclamation) to study as they consider how to manage the Colorado River after 2026, when current management rules expire. Reclamation has initiated a process expected to assess multiple alternatives before they establish new operational rules.
In recent weeks the Upper Basin (Colorado, New Mexico, Utah and Wyoming) and Lower Basin (Arizona, California and Nevada) have each submitted proposals of their own. They appear to be in broad agreement that Colorado River water uses need to be reduced, not only because the Colorado River’s water is over-allocated, but also because climate change is shrinking the river. But alignment between the Upper Basin and Lower Basin ends there, with significant dispute over whose water uses should be reduced.
Cooperative Conservation has a different focus. It prioritizes stabilizing the Colorado River water supply, provides opportunities to make management more equitable, and creates mechanisms to improve environmental outcomes [ed. emphasis mine]:
Water supply reliability would be improved by consideration of recent trends as well as assessing the health of the entire system, departing from the current operations that have not kept up with changing conditions such that in 2022 federal managers were worried about the continued ability release water through the dams.
Ecosystem health would be addressed with stewardship and mitigation provisions. Today’s operations are based on a policy framework that has not prioritized Colorado River habitats, leaving many used by birds such as Yuma Ridgeway’s Rails and Yellow-billed cuckoos degraded and vulnerable.
Colorado River Delta habitats and flows have been restored in recent United – States Mexico agreements, and the opportunity for future binational agreements to extend and expand commitments to these resources would be preserved. Most of Colorado’s Delta was desiccated as the river was developed through the 20th century, and these agreements have developed a path towards restoring some of what was lost.
A Conservation Reserve program to incentivize water conservation, that improves on the current system of “Intentionally Created Surplus” by adding to the stability of water supplies, offering an opportunity for state and federal governments to forge an agreement with Colorado River Basin Tribes looking to realize greater benefits from their water rights, and create ecological benefits through flexible management that puts water where it is needed in the Colorado River.
These innovations could help the diversity of birds and wildlife and more than 35 million people who depend on the Colorado River. But Reclamation will not be able to move forward with them if the states cannot answer important questions about who should reduce water uses to bring demands into balance with supplies. Without consensus, Colorado River management could be headed to the courts, and opportunities for improved management will be lost. We remain optimistic that over the coming months the states will negotiate a solution, and urge them to recognize that reaching agreement on how to share water shortages is essential.
In the meantime, Audubon will be promoting Cooperative Conservation and all that it offers. Reclamation is expected to publish their analysis of Colorado River management alternatives by the end of 2024.
The public lands beat has been rather busy, to put it mildly, as the Biden administration rushes to finalize rules, orders, and protections as soon as possible to make them less vulnerable to being rolled back if Biden were to lose in November to, ummm, a more hostile candidate. Maybe Biden’s also working to more clearly distinguish himself on environmental issues from Trump in advance of the election — as if the stark contrast isn’t abundantly clear already.
So much has happened that I’ve fallen behind. So forget the pre-amble, let’s get to it:
In late March, the Bureau of Land Management finalized its methane waste prevention rule, which requires oil and gas operators on federal lands to find and repair leaks in their infrastructure and to phase out flaring and venting of methane — a.k.a. natural gas. The rules complement the EPA’s similar regulations finalized earlier this year.
Methane is a potent greenhouse gas, having about 86 times the warming potential of carbon dioxide over the near-term (methane in the atmosphere breaks down into carbon dioxide and water over the long-term). While methane — which occurs alongside oil in underground reservoirs — can be captured and marketed as natural gas, oil drillers tend to vent or flare it and other associated gases, since it isn’t as profitable as oil.
Flaring and venting of methane and other gases shot up after horizontal drilling-multistage hydraulic fracturing opened up vast new stores of oil. Source: Bureau of Land Management.
Between 2010 and 2020, after the “fracking”-enabled shale revolution got underway, oil and gas operations on federal and tribal land vented and flared an average of 44.2 billion cubic feet of methane annually. That’s as bad for the climate as burning around 9 million tons of coal. And since operators don’t pay royalties on gas they throw away, that cost American taxpayers some $166 million in lost revenue over a decade.
The rules look to rein that in by gradually decreasing the maximum amount of methane that can be flared or vented and charging royalties on the gases that are wasted. It is expected to slash greenhouse gas emissions and result in about $50 million annually in added royalty revenue.
A few days later, the administration finalized its ban on new oil and gas leases and mining claims on about 220,000 acres along Western Colorado’s Thompson Divide. The protections cover a stretch of high-country BLM and USFS land between Glenwood Springs, Crested Butte, and Somerset. It does not affect valid, existing leases or claims.
In the early 2000s an eclectic group of environmentalists, ranchers, and recreational users banded together to protect the Divide from the growing threat of oil and gas development. Their efforts goaded the feds to halt new development and cancel existing leases on much of the acreage, long before this spring’s move. Meanwhile, a similar uprising in the Crested Butte area blocked a proposed molybdenum mine on Mt. Emmons, or the Red Lady.
The administration’s withdrawal bolsters these efforts and blocks new development for the next 20 years. By then, one would hope, the administration’s demand-side efforts to reduce fossil fuel consumption — including encouraging clean energy development and pushing zero-emission cars — will have kicked in.
***
And Biden and Interior Secretary Deb Haaland raised royalty rates and reclamation bonding amounts for oil and gas drilling on federal land. This one was a long-time coming. The previous 12.5% royalty rate has remained unchanged since Congress passed the Mineral Leasing Act in 1920. And oil and gas drillers have been getting away with posting bonds for all of their wells in a state that don’t get anywhere near covering the cost of cleaning up a single well.
Environmentalists welcomed the reforms, but also criticized them for failing to address climate impacts of oil and gas development on public lands. Oh, and then there’s the thing about the faulty math: Mark Olalde and Nick Bowlin, for ProPublica and Capital & Main, found that even the new bonding amounts wouldn’t cover clean up. The problem? A BLM staffer miscalculated the cost to plug and reclaim a single well, and the inaccurate figure got incorporated into the analysis and final rule. Whoops.
***
The administration blocked new oil and gas leases on 13 million acres of the National Petroleum Reserve-Alaska. That’s a huge amount of land and especially remarkable given that it’s in a petroleum reserve and it’s likely to result in some 50% less greenhouse gas emissions than Trump’s plan for the same area. Still, it may not be enough for the climate hawks who remain livid over the administration’s approval of a scaled-back, but still gargantuan, Willow (a.k.a. “carbon bomb”) drilling project in the reserve. Meanwhile, Biden’s Willow approval is not enough to soothe the anger of Alaska’s congressional delegation — including Democrat Rep. Mary Peltola — who blasted Biden for ignoring Alaska’s love for fossil fuels and called it an “illegal” move that dealt a “one-two punch” to the state’s economy. You just can’t win for losing, can you?
***
Light and texture. Big Gypsum Valley, Colorado. Jonathan P. Thompson photo.
And last, but certainly not least: The Bureau of Land Management finalized its public lands rule, designed to put conservation on a par with oil and gas development, grazing, and other extractive uses.
The rule’s main provisions include:
It directs the agency to prioritize landscape health in all decision making, which is what it’s already supposed to do when assessing grazing allotments. It hasn’t done a very good job at that, so far.
It creates a mechanism for outside entities — states, tribes, or nonprofits — to lease public land for restoration projects — much as a rancher or oil and gas company might lease BLM land.
It allows firms to lease land for mitigation work to offset impacts from development elsewhere.
It clarifies the process for designating areas of critical environmental concern, or ACECs, where land managers can add extra regulations to protect cultural or natural resources.
And it directs the agency to incorporate Indigenous knowledge into decision-making, particularly when considering ACECs.
The rule is being hailed by conservationists as a “generation-defining shift” in public land management, and lambasted by Sagebrush Rebel-wannabes as a “misguided land grab meant to prevent oil and gas production … <and> … an attack on our ranchers and farmers that will end grazing on federal lands and will also prevent Coloradans from accessing their public lands.” (A gold star to whoever guesses which MAGA-loving congress member made the latter grossly misinformed quote!).
Honestly, I’m not sure either side’s hoohas are warranted. It’s hard to see how a couple new leasing categories will be generation defining, I kinda doubt the rules will affect oil and gas production, and I’m absolutely certain they won’t end grazing or otherwise block access to public lands.
The rule doesn’t add any new restrictions or put any land off-limits to development. It doesn’t give greens the power to kick a legitimate drilling, mining or grazing operation off public land to do a restoration or mitigation project. The mitigation leases could actually facilitate energy development. As for grazing, the Biden administration has indicated it considers ranching to be a type of land conservation, a theory that is manifested in the BLM’s policy of veering away from public lands grazing reform. Grazing is allowed in most ACECs. And the agency just set the 2024 grazing fee at $1.35 per animal unit month, the minimum Congress allows. I think the cows and their ranchers will be just fine under this new rule.
It seems to me that this rule’s provisions are fairly open to interpretation. That means the actual implementation — and how it plays out on the ground — will depend largely on BLM state, regional, and field-office managers. And those local-level bureaucrats can be swayed by the prevailing attitudes of the communities where they live and work, and by pressure from local or state officials.
In the end, the rule is essentially a reminder to the BLM that their job is not just to bend over for corporate and extractive interests, but to actually care for the land that belongs to all Americans. It is simply reinforcing the multiple-use charge Congress set forth when it passed the Federal Lands Policy and Management Act back in 1976. It’s not that big of a deal. But then again, FLPMA helped spark the Sagebrush Rebellion in the late 1970s. So who knows what this rule might inspire now…
📸 Parting Shot 🎞️
Eagles in a tree near Norwood, Colorado. Jonathan P. Thompson photo.
Corn in Baca County. Photo credit: Allen Best/Big Pivots
Click the link to read the article on the Big Pivots website (Allen Best):
Unanimous votes in the Colorado Legislature are rare, but they do happen. Consider HB24-1435, the funding for the Colorado Water Conservation Board projects.
The big duffle bag of funding for various projects was approved 13-0 by the Senate Water and Agriculture Resources Committee. It had bipartisan sponsors, including Rep. Marc Catlin, a former water district official from Montrose.
“Colorado has been a leader in water for a long, long time, and this is bill is an opportunity for us to stay in that leadership position,” said Catlin, a Republican and a co-sponsor.
“This is one of my favorite bills,” said Rep. Karen McCormick, a Democrat from Longmont and former veterinarian. She is also a co-sponsor.
This historical photo shows the penstocks of the Shoshone power plant above the Colorado River. A coalition led by the Colorado River District is seeking to purchase the water rights associated with the plant. Credit: Library of Congress photo
The bill has some very big-ticket items, including $20 million for the Shoshone power plant agreement between Western Slope interests and Public Service Co. of Colorado, better known by its parent company, Xcel Energy. Andy Mueller, the general manager of the Glenwood Springs-based Colorado River District, called the effort to keep the water in the river “incredibly important” to those who make a living in the Colorado River Basin.
This map shows the 15-mile reach of the Colorado River near Grand Junction, home to four species of endangered fish. Map credit: CWCB
Mueller also pointed out that keeping water in the river will benefit of four endangered species of fish that inhabit what is called the 15-mile stretch of the Colorado River near Grand Junction.
Another $2 million was appropriated for the turf-replacement program in cities, a program first funded in 2022. Another mid-range item is telemetry for Snotel sites, to keep track of snow depths, the better to predict runoff. It is to get $1.8 million.
Among the smallest items in the budget is a big one for Baca County, in Colorado’s southeast corner. The bill, if adopted, would provide the Colorado Water Conservation Board with $250,000 to be used to evaluate the remaining water in aquifers underlying southeastern Colorado. There, near the communities of Springfield and Walsh, some wells long ago exhausted the Ogallala aquifer and have gone deeper into lower aquifers, in a few cases exhausting those, too. Farmers in other areas continue to pump with only modest declines.
What exactly is the status of the underground water there? How many more decades can the agricultural economy dependent upon water from the aquifers continue? The area is well aside from the Arkansas River or other sources of snowmelt.
A study by the McLaughlin Group in 2002 delivered numbers that are sobering. Wes McKinley, a former state legislator from Walsh, at a meeting in February covered by the Plainsman Herald of Springfield, said the McLaughlin study numbers show that 84% of the water has been extracted. That study suggested 50-some years of water remaining. If correct, that leaves 34 years of water today.
Tim Hume, the area’s representation on the Colorado Groundwater Commission, has emphasized that he believes this new study will be needed to accurately determine how water should be managed.
How soon will this study proceed? asked Rep. Ty Winter, a Republican from Trinidad who represents southeastern Colorado. Tracy Kosloff, the deputy director of the Colorado Division of Water Resources, answered that the technical analysis should begin sometime after July. “I would think it is reasonable to finish it up by the end of 2025, but that is just an educated guess.”
She said the state would work with the Baca County community to come up with a common goal and direction “about how they want to manage their resources.”
Unlike the Republican River area of northeastern Colorado, where farmers also have been plunging wells into the Ogallala and other aquifers, this area of southeastern Colorado has no native river. In the Republican Basin, Colorado is trying to remove 25,000 acres from irrigation by the end of 2029 in order to leave more water to move into the Republican River. See story. A similar proposition is underway in the San Luis Valley, where farmers have also extensively tapped the underground aquifers that are tributary to the Rio Grande. See story.
San Luis Valley Groundwater
The closest to critical questioning of the bill came from Rep. Richard Holtorf, a Republican who represents many of the farming counties of northeastern Colorado. He questioned the $2 million allocated to the Office of the Attorney General.
He was told that $1 million of that constantly replenishing fund is allocated to the Colorado River, $110,000 for the Republican River, $459,000 for the Rio Grande, $35,000 for the Arkansas and $200,000 for the South Platte.
Then there’s the litigation with Nebraska about the proposed ditch that would begin in Colorado near Julesburg but deliver water to Nebraska’s Perkins County. Colorado hotly disputes that plan.
Lauren Ris, the director of the Colorado Water Conservation Board, said Colorado is “very confident in our legal strategy.”
Holtorf also noted that the severance tax provides 25% of the funding for the water operations. The severance tax comes from fossil fuel development. As Colorado moves to renewable energy, “what happens to this Colorado water if we kill the goose that lays the golden egg?”
Ris replied said future declines in the severance tax is a conversation underway among many agencies in Colorado state government.
The South Platte Hotel building that sits at the Two Forks site, where the North and South forks of the South Platte River come together. Photo: Brent Gardner-Smith/Aspen Journalism
“I am proud to see the collaborative work of the newly developed Colorado Produced Water Consortium begin to bear fruit with the development of the Initial Guidance Documents and Case Studies to Promote Best Practices for In-Field Recycling and Reuse of Produced Water Report. The engagement, diversity of views, and expertise of the whole of the Consortium was utilized in the development of this report, which will continue to evolve as more technology, case studies, and research are incorporated in the future as we continue to implement HB23-1242 and explore ways to reduce the amount of freshwater used and increase the amount of reuse and recycling of produced water used in oil and gas operations across the state,” said Consortium Chair John Messner.
The Consortium collaboratively developed this synthesis report by identifying and reviewing over 130 research journal articles, best practices, and case studies. Key themes that promote best practices for in-field recycling and reuse of produced water throughout the state emerged from the review and will be used to inform the Consortium’s future recommendations. Given the ongoing and evolving nature of produced water research, the library of references is expected to grow over time.
“I congratulate the Consortium in submitting their first deliverable to the Colorado legislature and for working hard to bring together the expertise of a diverse set of stakeholders,” said Dan Gibbs, Executive Director, Colorado Department of Natural Resources. “This first report builds the expertise of Colorado’s policy makers and the public on produced water. I look forward to the Consortium’s continued work to inform produced water policy.”
The Colorado Produced Water Consortium was established in the Department of Natural Resources by HB23-1242 to help reduce the consumption of freshwater within oil and gas operations. The Consortium’s responsibilities also include making recommendations towards developing an informed path for reuse and recycling of produced water inside and potentially outside of oil and gas operations within the state and identifying measures to address barriers associated with the use of produced water.
The Consortium consists of 31 members representing state and federal agencies, research institutions, environmental groups, industry, local governments, environmental justice groups, and disproportionately impacted communities.
The Crossing Trails Wind Farm between Kit Carson and Seibert, about 150 miles east of Denver, has an installed capacity of 104 megawatts, which goes to Tri-State Generation and Transmission. Photo/Allen Best
Click the link to read the article on the KUNC website (Rae Solomon). Here’s an excerpt:
…the six counties that comprise Colorado’s Northeast Plains – namely, Morgan, Logan, Washington, Yuma, Phillips and Sedgwick Counties – seem to be lagging behind the rest of the state when it comes to mobilizing for climate change preparedness. Those communities do not have any plans for climate action and resiliency and a regional hazard mitigation plan for Northeast Colorado makes no mention of climate change.
“That region is among the lowest in the state,” said Karam Ahmad, director of the climate team at the Colorado Health Institute. “Cities and counties in that region don’t really have climate related plans, or strong commitments to climate adaptation.”
[…]
In a recent statewide survey, The Colorado Health Institute asked Coloradans if their communities were prepared for climate disaster. In all of Colorado, the Northeast Plains stood out for its lack of confidence in local climate change preparedness. More than 60% of respondents in Northeast Colorado reported they did not think their community was prepared for climate change. That’s compared to about 47% statewide.
Yet as I’ve traversed the American West over the last two years with my L.A. Times colleagues, exploring how the transition from fossil fuels to cleaner energy is reshaping sensitive ecosystems and rural communities, one lesson has risen above the rest: If we don’t embrace change now, while we still have a choice, far worse changes will eviscerate us later. That lesson crystallized for me over the last few months, as I wrote about a Montana coal town struggling to accept that its West Coast customer base no longer wants coal power — you can read my full story here — and as I struggled personally to figure out what kinds of stories I want to tell going forward, after a decade of reporting on challenges facing the energy transition…
Folks in Colstrip [Montana] and similar towns are justifiably worried that if big cities replace fossil fuels with renewable energy, their lives will change for the worse. They’re not totally opposed to wind and solar, but they’re skeptical those technologies will ever fully replace fossil fuels, in terms of the bountiful jobs, tax revenues and other economic benefits that coal, oil and gas have provided.
Power distribution lines in the Yampa River Valley October 2020. Photo credit: Allen Best/Big Pivots
Click the link to read the article on the Big Pivots website (Allen Best):
April 18, 2024
Bill moving through Colorado Capitol that would allow Xcel Energy and Tri-State G&T to keep water rights for 20 years after last coal plant closes
Colorado’s Yampa River Valley has five coal-burning units that will cease operations from 2025 to 2030. Two are at Hayden and three are at Craig. All require water for cooling.
What will become of that water once the coal plants close?
SB24-197, a bill that is rapidly moving through the Colorado Legislature, would allow Xcel Energy and Tri-State Power and Generation to hold onto their water rights, even if they are not using them, until 2050. That is a precedent-setting exception to Colorado’s famous use-it-or-lose-it provision in water law.
The utilities say they may very likely need the water once they figure out how they will replace the coal generation. Neither utility has announced specific plans, but in response to a question at the bill’s first hearing in a Senate committee last week, Xcel Energy’s Richard Belt identified pumped-storage hydro and hydrogen as leading candidates. The federal government has devoted considerable funding and support for development of both technologies, he said.
“Those are the two leaders,” said Belt. “There aren’t many on the horizon that would fill the niche in that decree.”
Both technologies would provide storage. Xcel and other utilities are on their way to having massive amounts of cheap renewable energy. Still to be solved is how to ensure reliability when winds quiet for long periods. And the sun, of course, always goes down.
Storage will be essential and perhaps some kind of baseload generation. Xcel’s current plans call for an increase in natural gas capacity to ensure reliability even if the natural gas plants are used only infrequently, say 1% or 2% of the time. Xcel Energy is also adding literally tons of four-hour lithium-ion battery storage.
Cabin Creek pumped hydro reservoir. Photo credit: EE Online
The company’s biggest storage device is still its oldest, the 324-megawatt Cabin Creek pumped storage unit. Water from the upper reservoir is released to generate electricity when it is needed most, then pumped back uphill when power is relatively plentiful.
A developer has secured rights from landowners at a site between Hayden and Craig. See story. Another pumped-storage hydro possibility has been identified in the area between Penrose and Colorado Springs.
Hydrogen has less of a track record, at least in Colorado. However, it is part of Colorado’s all-of-the-above approach. See story. Hydrogen can be created from natural gas, but to meet Colorado’s needs it must be created from water. It would then be stored. Like pumped-storage hydro, it would be created when renewables are producing excess electricity, and the hydrogen could then be tapped to create electricity when needed most. That electrical generation would also use water for cooling, Belt said.
The bill, said Belt, proposes to allow Xcel the time for the economic and feasibility details of these emerging technologies to be resolved “instead of forcing a near-term decision driven by the processes of current water law.”
Normally, utilities would be required to demonstrate purpose of water, which can take several years, or risk abandonment. Because they will not have to, some see this as allowing the utilities to speculate. The utilities insist that it’s too soon to know exactly what their future water needs will be. But in addition to owning land in the Yampa Valley and water, they have expensive transmission linked to the rest of Colorado.
State Sen. Cleave Simpson, a Republican from Alamosa — and a former lignite coal-mining engineer, made note of that infrastructure on the floor of the Senate on Monday morning when he spoke in favor.
The bill will allow the utilities to hold onto the water in Western Colorado “so the region can have a true just transition and so hopefully it can continue to be an energy producing
region using existing infrastructure.” Upon advice of the Colorado Attorney General’s Office, the bill was amended by the Senate to specify that the water must remain in the Yampa River Basin.
Coyote Gulch near the confluence of the Little Snake and Yampa Rivers July 2021.
Since Colorado adopted carbon reduction targets in 2019, there have been questions about what might happen to the water in the Yampa Valley. It’s not a huge amount of water, but it can matter in a basin that since 2018 has had several calls on the river after having none for the previous 150 years.
The issue was hashed out by the legislatively-created Drought Task Force in 2023. The task force called attention to the idea of allowing utilities to preserve their water rights until 2050, but the idea failed to get a full endorsement.
Sen. Dylan Roberts, a prime sponsor, explained at the Senate Agriculture and Natural Resources Committee meeting that additional work in recent months has produced legislation that has ended objections. Indeed, Western Resource Advocates supported the full bill, as did others.
Jackie Brown, who represented Tri-State on the task force, told the Senate committee members that the measures in SB24-197 “provide Tri-State certainty that our water resources remain intact and available for future dispatchable carbon-free generation as needed and is projected in our electric resource plan. While we continue our planning process, keeping this utility water in the Yampa River helps all water users, creating a win-win situation.”
The Glenwood Springs-based Colorado River District in 2021 conducted a study of what happens to water when released from the Elkhead Reservoir, which is located near Hayden. The study found that 14% of the water was picked up by irrigators, 10% was lost to transit – and the rest of it flowed downstream. That suggests what will become of this water while it is not used.
Downstream lie segments of the Yampa where endangered fish species live. Those stretches have become nearly non-existent during the hot and dry summers of recent years.
Routt County Commissioner Tim Corrigan said his county supports the bill. He said hebelieved that Moffat County did also. He emphasized that the solution will help the environment as well as other users. The energy transition in northwest Colorado, he said “will take place over a very long time.”
The bill also has provisions applicable across Colorado. It allows the owner of a decreed storage water right to loan water to the Colorado Water Conservation Board for a reach of river for which the board does not hold a decreed instream flow water right. It also requires the CWCB to establish an agricultural water protection program in each of the state’s water divisions.
Simpson, on the Senate floor, also explained that the bill would create what he called a much-needed program, crafting a pathway to loan water from water storage for a reservoir to benefit an instream flow program “without going through the whole CWCB process with getting an adjudicated flow.”
Yampa/White/Green/North Platte river basins via the Colorado Geological Survey
All this worry about warming when it’s just a natural cycle. The climate is always changing and today’s no different — right? Global Weirding is produced by KTTZ Texas Tech Public Media and distributed by PBS Digital Studios. New episodes every other Wednesday at 10 am central. Brought to you in part by: Bob and Linda Herscher, Freese and Nichols, Inc, and the Texas Tech Climate Science Center.
Click the link to read the article on the NOAA website (Theo Stein):
Levels of the three most important human-caused greenhouse gases – carbon dioxide (CO2), methane and nitrous oxide – continued their steady climb during 2023, according to NOAA scientists.
While the rise in the three heat-trapping gases recorded in the air samples collected by NOAA’s Global Monitoring Laboratory (GML) in 2023 was not quite as high as the record jumps observed in recent years, they were in line with the steep increases observed during the past decade.
“NOAA’s long-term air sampling program is essential for tracking causes of climate change and for supporting the U.S. efforts to establish an integrated national greenhouse gas measuring, monitoring and information system,” said GML Director Vanda Grubišić. “As these numbers show, we still have a lot of work to do to make meaningful progress in reducing the amount of greenhouse gases accumulating in the atmosphere.”
The global surface concentration of CO2, averaged across all 12 months of 2023, was 419.3 parts per million (ppm), an increase of 2.8 ppm during the year. This was the 12th consecutive year CO2 increased by more than 2 ppm, extending the highest sustained rate of CO2 increases during the 65-year monitoring record. Three consecutive years of CO2 growth of 2 ppm or more had not been seen in NOAA’s monitoring records prior to 2014. Atmospheric CO2 is now more than 50% higher than pre-industrial levels.
This graph shows the globally averaged monthly mean carbon dioxide abundance measured at the Global Monitoring Laboratory’s global network of air sampling sites since 1980. Data are still preliminary, pending recalibrations of reference gases and other quality control checks. Credit: NOAA GML
“The 2023 increase is the third-largest in the past decade, likely a result of an ongoing increase of fossil fuel CO2 emissions, coupled with increased fire emissions possibly as a result of the transition from La Nina to El Nino,” said Xin Lan, a CIRES scientist who leads GML’s effort to synthesize data from the NOAA Global Greenhouse Gas Reference Network for tracking global greenhouse gas trends.
Atmospheric methane, less abundant than CO2 but more potent at trapping heat in the atmosphere, rose to an average of 1922.6 parts per billion (ppb). The 2023 methane increase over 2022 was 10.9 ppb, lower than the record growth rates seen in 2020 (15.2 ppb), 2021(18 ppb) and 2022 (13.2 ppb), but still the 5th highest since renewed methane growth started in 2007. Methane levels in the atmosphere are now more than 160% higher than their pre-industrial level.
This graph shows globally-averaged, monthly mean atmospheric methane abundance determined from marine surface sites for the full NOAA time-series starting in 1983. Values for the last year are preliminary, pending recalibrations of standard gases and other quality control steps. Credit: NOAA GM
In 2023, levels of nitrous oxide, the third-most significant human-caused greenhouse gas, climbed by 1 ppb to 336.7 ppb. The two years of highest growth since 2000 occurred in 2020 (1.3 ppb) and 2021 (1.3 ppb). Increases in atmospheric nitrous oxide during recent decades are mainly from use of nitrogen fertilizer and manure from the expansion and intensification of agriculture. Nitrous oxide concentrations are 25% higher than the pre-industrial level of 270 ppb.
Taking the pulse of the planet one sample at a time NOAA’s Global Monitoring Laboratory collected more than 15,000 air samples from monitoring stations around the world in 2023 and analyzed them in its state-of-the-art laboratory in Boulder,
Colorado. Each spring, NOAA scientists release preliminary calculations of the global average levels of these three primary long-lived greenhouse gases observed during the previous year to track their abundance, determine emissions and sinks, and understand carbon cycle feedbacks.
Measurements are obtained from air samples collected from sites in NOAA’s Global Greenhouse Gas Reference Network, which includes about 53 cooperative sampling sites around the world, 20 tall tower sites, and routine aircraft operation sites from North America.
Carbon dioxide emissions remain the biggest problem
By far the most important contributor to climate change is CO2 , which is primarily emitted by burning of fossil fuels. Human-caused CO2 pollution increased from 10.9 billion tons per year in the 1960s – which is when the measurements at the Mauna Loa Observatory in Hawaii began – to about 36.8 billion tons per year in 2023. This sets a new record, according to the Global Carbon Project, which uses NOAA’s Global Greenhouse Gas Reference Network measurements to define the net impact of global carbon emissions and sinks.
This graph shows annual mean growth rates of carbon dioxide based on globally averaged marine surface data. Decadal averages of the growth rate are plotted as horizontal lines. Credit: NOAA GML
The amount of CO2 in the atmosphere today is comparable to where it was around 4.3 million years ago during the mid-Pliocene epoch, when sea level was about 75 feet higher than today, the average temperature was 7 degrees Fahrenheit higher than in pre-industrial times, and large forests occupied areas of the Arctic that are now tundra.
About half of the CO2 emissions from fossil fuels to date have been absorbed at the Earth’s surface, divided roughly equally between oceans and land ecosystems, including grasslands and forests. The CO2absorbed by the world’s oceans contributes to ocean acidification, which is causing a fundamental change in the chemistry of the ocean, with impacts to marine life and the people who depend on them. The oceans have also absorbed an estimated 90% of the excess heat trapped in the atmosphere by greenhouse gases.
Research continues to point to microbial sources for rising methane
NOAA’s measurements show that atmospheric methane increased rapidly during the 1980s, nearly stabilized in the late-1990s and early 2000s, then resumed a rapid rise in 2007.
A 2022 study by NOAA and NASA scientists and additional NOAA research in 2023 suggests that more than 85% of the increase from 2006 to 2021 was due to increased microbial emissions generated by livestock, agriculture, human and agricultural waste, wetlands and other aquatic sources. The rest of the increase was attributed to increased fossil fuel emissions.
“In addition to the record high methane growth in 2020-2022, we also observed sharp changes in the isotope composition of the methane that indicates an even more dominant role of microbial emission increase,” said Lan. The exact causes of the recent increase in methane are not yet fully known.
NOAA scientists are investigating the possibility that climate change is causing wetlands to give off increasing methane emissions in a feedback loop.
The coal-fired Tri-State Generation and Transmission plant in Craig is scheduled to close in 2028. Senate bill SB24-197 would allow the water rights associated with the plant to be protected from abandonment until 2050. Photo credit: Brent Gardner-Smith/Aspen Journalism
State lawmakers are considering a bill that would let two energy companies with coal-fired power plants in northwest Colorado hang on to their water rights even after the plants’ planned closures in 2028.
Senate Bill SB24-197 says that industrial water rights held by Xcel Energy and Tri-State Generation and Transmission Association Inc. will be protected from abandonment through 2050. Under Colorado law, a water right that is not being used could end up on an abandonment list, which is compiled every 10 years.
Abandonment is the official term for one of Colorado’s best-known water adages: Use it or lose it. It means that the right to use the water is essentially canceled and ceases to exist. The water goes back into the stream where another water user can claim it.
Supporters of the bill say this protection from abandonment would give the companies a grace period to transition to clean-energy sources and eventually use the water again in new methods of energy production. In the meantime, the water will remain in the stream for the benefit of the environment, recreation and downstream irrigators.
State Sen. Dylan Roberts, D-Frisco, is one of the bill’s sponsors, and represents Clear Creek, Eagle, Garfield, Gilpin, Grand, Jackson, Moffat, Rio Blanco, Routt and Summit counties.
“The idea is if we can find a way to ensure that the water rights of the power companies are protected over the next couple of decades, this will give them a stronger incentive to find a new way to produce energy in the region,” Roberts said.
Tri-State plans to shut down its coal-fired power plant in Craig in 2028, the same year that Xcel Energy plans to close the Hayden Generating Station, which has prompted questions about what will happen to the water currently being used by the facilities.
Jackie Brown is a senior water and natural resource advisor at Tri-State. She said the bill preserves future opportunities for economic development by energy utilities in Moffat and Routt counties.
“The measures in this bill provide Tri-State with certainty that our water resources remain intact and available for future dispatchable, carbon-free generation as needed and projected in our Electric Resource Plan,” Brown said in a statement. “While we continue our planning process, keeping the utility water in the Yampa River helps all water users, creating a win-win situation.”
According to Brown, the water used from the Yampa River by both energy companies is estimated to be about 44 cubic feet per second of flow. But, if the bill passes, engineers will officially quantify by 2030 the amount of water that the industries have historically used, and that is the amount that will be protected from abandonment. Any portion of the water rights that the energy companies lease to a third party would not be protected from abandonment.
The Yampa River begins in the Flat Tops Wilderness, flows through the city of Steamboat Springs and west through Routt and Moffat counties to Dinosaur National Monument, and eventually joins with the Green River. The Yampa River basin was one of the last to be developed in the state and in recent years has begun experiencing some of the issues long present in other areas such as shortages, calls, an overappropriation designation and stricter enforcement of state measurement rules.
In 2018, irrigators placed the first call on the river, triggering cutbacks from junior water users. When an irrigator is not receiving the entire amount of water to which they are legally entitled, they can place a call, which requires water-rights holders with younger water rights to stop irrigating so the senior water user can get their share. The Colorado River Water Conservation District, the Colorado Water Trust and others have made releases out of Elkhead Reservoir to get extra water to these senior downstream irrigators and keep the call off the river.
The Lefevre family prepares to put their rafts in at Pebble Beach for a float down the Yampa River to Loudy Simpson Park in Craig in June 2021. When the coal-fired power plants shut down in 2028, the water they currently use will be left in the water to the benefit of the environment, recreation and downstream irrigators. From left, Marcie Lefevre, Nathan Lefevre, Travis Lefevre and Sue Eschen. CREDIT: HEATHER SACKETT/ASPEN JOURNALISM
Support from environmental groups
SB 197 has gained support from environmental groups, including Conservation Colorado, The Nature Conservancy and Western Resource Advocates. Josh Kuhn, senior water campaign manager with Conservation Colorado, said leaving the water in the river will have environmental benefits such as lowering the often-too-high temperature of the Yampa, boost flows for recreation and the environment, and prevent calls on the river.
But the benefit to the river and water users from SB 197 may only be temporary. The energy companies will still own the water rights and may begin using them again whenever they want.
“It has been made clear that there’s no assurances that the water will be there on a permanent basis because Tri-State wants the ability to use that water to generate additional renewable clean-energy supplies in the future,” Kuhn said. “So there is a shared understanding that this is being done on a temporary basis.”
With the impending closure of the coal mines and power plants that by one estimate will result in 800 lost jobs, some see the Yampa River as an underutilized amenity that could supply recreation jobs and enhance quality of life. Supporters of the bill say keeping the energy companies’ water in the river and protected from abandonment will ensure that the water is not diverted out of the basin.
“The Yampa is already a river that suffers the impacts of climate-driven drought,” Kuhn said. “And so, in order to help protect that river and the economy that’s dependent upon it, they were looking for solutions to make sure that none of that water was exported to another basin.”
The protection of the energy companies’ water rights is just one facet of SB 197, which would also implement recommendations from last year’s Colorado River Drought Task Force. These include expanding the state’s instream-flow temporary loan program to let owners of water stored in reservoirs to loan it for the benefit of the environment in stream reaches where the state does not hold an instream-flow water right; expanding the state’s agricultural water rights protection program; and waiving the matching funds requirement for water project grants to the Southern Ute and Ute Mountain Ute tribal nations.
Roberts was the sponsor of 2023’s SB 295, which created the drought task force. Although the 17-member task force did not advance protections for industrial water rights from abandonment as an official recommendation (it failed on a 9-7 vote), it was included in the narrative section of the report that it provided to lawmakers.
“I’ve been working on this for months with the energy companies, with the state, with environmental groups and with local stakeholders in Routt and Moffat counties,” Roberts said. “And we narrowed the proposal significantly, and now almost everybody who was opposed on the task force is supportive of this idea moving forward.”
SB 197 passed unanimously in the Senate on Wednesday [April 17, 2024] and will now be up for approval by the House.
The U.S. has a long record of extracting resources on Native lands and ignoring tribal opposition, but a decision by federal energy regulators to deny permits for seven proposed hydropower projects suggests that tide may be turning.
As the U.S. shifts from fossil fuels to clean energy, developers are looking for sites to generate electricity from renewable sources. But in an unexpected move, the Federal Energy Regulatory Commission denied permits on Feb. 15, 2024, for seven proposed hydropower projects in Arizona and New Mexico.
The reason: These projects were located within the Navajo Nation and were proposed without first consulting with the tribe. FERC said it was “establishing a new policy that the Commission will not issue preliminary permits for projects proposing to use Tribal lands if the Tribe on whose lands the project is to be located opposes the permit.”
We are a cultural anthropologist and a water resource geographer who have studied tensions between Indigenous rights, climate governance and water management in the U.S. and globally for over 20 years. In our view, the commission’s decision could mark a historic turning point for government-to-government relations between the U.S. government and tribal nations.
How might this new approach shape future energy development on tribal lands throughout the U.S.? Given the federal government’s long history of exploiting Native American resources without tribal consent, we’re following FERC’s actions for further evidence before assuming that a new era has begun.
Extraction on tribal lands
Around the world, many Indigenous communities argue that their lands have been treated as sacrifice zones for development. This includes the U.S., where the federal government holds 56.2 million acres in trust for various tribes and individuals, mostly in western states.
The trust responsibility requires the U.S. government to protect Indigenous lands, resources and rights and to respect tribal sovereignty. Consulting with tribes about decisions that affect them is fundamental to this relationship.
The seven permits FERC denied in February 2024 were requested by private companies seeking to build pumped hydropower storage projects. These systems pump water uphill to a reservoir for storage. When power is needed, water is released to flow downhill through turbines, generating electricity as it returns to a lower reservoir or river.
Currently there are over 60 pumped storage proposals pending across the U.S. Pumped storage typically requires constructing massive concrete-lined tunnels, powerhouses, pipelines and transmission systems that can damage surrounding lands.
Withdrawing water for hydropower could disrupt rivers and sacred sites that are culturally and spiritually important for many tribes. These projects also threaten water security – a critical issue in arid western states.
Colorado River water is already over-allocated among western states, which hold legal rights to withdraw more water than is in the river. As a result, many pumped storage projects would require groundwater to fill their reservoirs. The proposed Big Canyon project in Arizona, for example, would require up to 19 billion gallons of groundwater, taken from aquifers that support local springs and streams.
Pumped storage hydropower transfers water between two reservoirs to generate electricity. It requires a local water source to fill the reservoirs. Joan Carstensen, Grand Canyon Trust, CC BY-ND
FERC’s trust responsibility
The Federal Energy Regulatory Commission is an independent agency that licenses and oversees interstate transmission of electricity, natural gas and oil; natural gas pipelines and terminals; and hydropower projects. Under a 1986 law, the agency is required to consider factors including environmental quality, biodiversity, recreational activities and tribal input in making licensing decisions.
In 2000, President Bill Clinton issued Executive Order 13175, directing federal agencies to engage in “regular and meaningful consultation and collaboration with tribal officials” in developing federal policies that affect tribes. Each agency interprets how to do this.
In his first week in office in 2021, President Joe Biden reaffirmed this responsibility and nominated U.S. Rep. Deb Haaland as Secretary of the Interior – the first Native American to head the agency that administers the U.S. trust responsibility to Native Americans and Alaska Natives.
FERC’s new direction
Tribes have called FERC’s record of consultation with Native Americans “abysmal.” Recently, however, the agency has started to make its operations more inclusive.
In canceling the projects in February, FERC cited concerns raised by the Navajo Nation, including negative impacts on water, cultural and natural resources and biological diversity. It also stated that “To avoid permit denials, potential applicants should work closely with Tribal stakeholders prior to filing applications to ensure that Tribes are fully informed about proposed projects on their lands and to determine whether they are willing to consider the project development.”
Aligning clean energy and environmental justice
Many more energy projects are proposed or envisioned on or near tribal lands, including a dozen pumped storage hydropower projects on the Colorado Plateau. All 12 are opposed by tribes based on lack of consultation and because tribes are still fighting to secure their own legal access to water in this contested basin under the 1922 Colorado River Compact.
We recently analyzed FERC’s handling of the Big Canyon pumped hydropower storage project, which would be located on Navajo land in Arizona, and concluded that the agency had not adequately consulted with the tribe in its preliminary permitting. In the wake of its February ruling, the agency reopened the public comment period on Big Canyon for an additional 30 days, with a decision likely later in 2024.
The Biden administration has set ambitious targets for halting climate change and accelerating the shift to clean energy while promoting environmental justice. In our view, meeting those goals will require the federal government to more earnestly and consistently live up to its trust responsibilities.
Great Sage-Grouse. Photo: Evan Barrientos/Audubon Rockies
Click the link to read the release on the Audubon website (Jason Howe):
(Washington, DC-April 12, 2024) – The U.S. Bureau of Land Management (BLM) today announced a rule updating the cost of doing business on public lands and helping to balance the extraction of natural resources with the conservation of wildlife habitat and the preservation of landscapes sacred to Indigenous peoples.
In addition to siting oil and gas development away from wildlife habitat and cultural resources, the new regulations increase fees – including royalty and rental rates, and minimum bids associated with oil and gas development – bringing them in line with what many states require; and reduce so-called “speculative leasing”, where companies hold leases on land with little potential for development.
The BLM manages 245 million acres, nearly 40 percent of U.S. public lands. The agency is charged with balancing the protection of America’s natural legacy with managing the 30 percent of the nation’s mineral wealth that lies beneath the surface. But over the past 50 years, the agency has mainly focused on extractive uses (coal, and oil and gas), applying rules governing that extraction that have been unchanged for decades. An estimated 300 bird species spend at least part of their lives there, including Burrowing Owls and the Greater Sage-Grouse, which is already under stress across much of its range.
“When BLM oil and gas leasing policy was last updated, Gerald Ford was in the White House, the Bee Gees were on the radio and a gallon of gas cost an average of 59 cents,” said Christopher Simmons, senior manager of public lands policy for the National Audubon Society. “The BLM’s approach to oil and gas leasing has been the equivalent of a polyester leisure suit – painfully outdated. This is a big step forward towards the BLM fulfilling its mission, delivering common-sense policies that balance responsible development with land and wildlife conservation.”
For decades, oil and gas policies prioritized development on public lands over activities like hunting, fishing, birding, hiking, grazing and restoration. When oil and gas companies left behind a mess on public lands, American taxpayers were previously forced to foot the bill. Before today’s update, taxpayers could have been responsible for as much as $15 billion in clean-up costs.
Shoshone Hydroelectric plant. Photo credit: The Colorado River District
Click the link to read the article on the Summit Daily website (Robert Tann). Here’s an excerpt:
April 9, 2024
During a Tuesday, April 9, Summit Board of County Commissioners meeting, river district General Manager Andy Mueller told officials that his organization’s efforts to acquire water rights along a segment of the Colorado River “is vital to the health of all of our rivers in the Western Slope.”
Western Slope communities aren’t the only beneficiaries of the current system, with the [Shoshone Hydroelectric] plant’s water rights strengthening flows in Grand, Summit and Eagle counties, providing security to areas that depend on the Colorado River for a host of economic and environmental reasons. If the current water rights were not in place, the main beneficiaries would be Denver Water and other trans-mountain diverters which would experience increased yield through their respective collection systems, according to the river district…
In order to keep the same volume of downstream flow under new ownership, the river district will need to secure a water right for an instream flow, which can only be operated by the Colorado Water Conservation Board. The river district is currently in talks with the board to create a contract to do just that. But the crux of the river district’s deal is the water right’s $99-million price tag.
“The idea that we would allow this archaic little water right to disappear and watch it get siphoned off to benefit someone else’s future is really hard to take if you live and thrive here in Western Colorado.” — Colorado River District General Manager Andy Mueller
The city of Grand Junction became the latest entity to contribute to an effort to preserve a senior water right on the Colorado River Wednesday after City Council voted unanimously to pledge $1 million to the cause. The water right is from the Shoshone power plant in Glenwood Canyon, and provides 1,250 cubic feet per second under the senior right, and 158 cubic feet per second under the junior water right.
“It’s one of the oldest, largest rights on the Colorado River within our state,” said Colorado River District General Manager Andy Mueller said at Wednesday’s meeting. “It’s very unique in that it’s a non-consumptive water right built and first decreed in 1902 to generate hydroelectic power.”
In December, Xcel Energy and the river district agreed on a sale of the water rights for $99 million…Mueller said communities have relied on this water right for recreation, agriculture and development.
Click the link to read the article on the Big Pivots website (Allen Best):
April 4, 2023
Mike Kruger of the Colorado Solar and Storage Association explains why the big jump now and how storage has become an important component of the trade organization’s agenda.
First, a question for you: What is your first reaction to seeing the chart below. Is it wow! Or had you already realized that this was coming, this break-out year for solar in Colorado?
When I talked with Mike Kruger, who directs Colorado Solar and Storage Association, he assured me that most readers of Big Pivots will not be surprised. Most saw it coming – and, in fact, had it not been for Covid and the supply disruptions, Colorado might have had its big leap during 2021.
The chart comes from the Solar Energy Industries Association report of March 2024. The report — which brims with interesting data — says nearly 40% of Colorado’s 4,112 megawatts of installed solar capacity was installed in 2023. And that Colorado is projected to gain another 2,835 megawatts of capacity in the next five years.
Credit: Solar Energy Industries Association report of March 2024
A full admission: I said wow, and I had been tracking this story since roughly 2016 – which is one place where this story starts. Xcel Energy that year began its electric resource planning cycle. It got bids late in 2017 and announced them just after Christmas. I remember seeing the e-mail distributed by Leslie Glustrom, an Xcel shareholder and watchdog. Wind, especially, but solar, too, had delivered jaw-dropping offers. In that instant it became apparent to me that coal would soon to be in our rear-view mirror.
The Colorado Public Utilities Commission approved Xcel’s plans for a deep investment in renewables in September 2018.
That November Jared Polis was elected Colorado governor after having campaigned on a platform of 100% renewables.
In early December, Xcel Energy announced it planned to achieve an 80% reduction in carbon emissions by 2030 as compared to 2005 levels. Platte River Power Authority announced an even more ambitious goal in December but one festooned with conditions. And by the next May, Colorado had a law that required Xcel and Black Hills Energy to attain 80% decarbonization by 2030.
Kruger had arrived in the midst of this sudden pivot to take the reins of what was then called the Colorado Solar Energy Industries Association. At the time, the staff consisted of Kruger and one other individual. The organization now has six staff members, suggestive of the growth of the solar industry in Colorado.
On a recent Friday, between an emergency discussion about legislative affairs and his next appointment, Kruger talked with Big Pivots for about 25 minutes about the context for this graph and the story that lies beyond.
Big Pivots: What explains this big jump in solar during 2023 in Colorado?
Mike Kruger: We’re finally seeing the fruits of some of our labors here to decarbonize stuff. The big jump is explained largely by Thunder Wolf and Neptune, Xcel’s two big solar projects in Pueblo County. Nearly 500 MWs of new solar and 125 megawatts of battery as well. All are for Xcel Energy. And then we have the projects of the electrical cooperatives, including the 80-megawatt project out by Bennett (east of Denver). Hunter. That power goes to CORE Electric Cooperative and …
Holy Cross Energy.
Yeah. The Hunter project came on in 2023. Multiple other smaller projects entered service in 2023, too.
We’re just seeing the fruits of the labor by COSSA and other advocacy groups to decarbonize. Neptune and Thunder Wolf were a result of the solicitation in 2017 that came online in 2023. So it takes time to build these things. Obviously, we have a pandemic between them, which pushed the timeline even further.
Now that they’ve been set up, these dominoes are going to start falling. We’re going to really see hundreds, if not thousands, of megawatts of solar added to the grid every year through the rest of the decade.
In 2019, when we passed our first decarbonization bill, we had a 15-gigawatt system in Colorado. That was our peak demand. 80% of that is around 12 gigawatts of demand. Through 2019, we had installed about 2 gigawatts of renewables, mostly wind.
So, to meet those decarbonization goals, you have to build a lot of solar farms. You have to put up a lot of wind turbines. For the first time we’re seeing that legislative and policy work finally coming together.
We can only expect it to get bigger. The future now is 25 gigawatts by 2034, according to modeling by the Colorado Energy Office. To hit that we now have to add a gigawatt (of generation) every year for all the 2020s and then need to add two gigawatts a year for the first five years of the 2030s.
It’s a good time to be a solar installer, to be a solar developer. There’s a “gignormous” market in Colorado. It’s heavily competitive, but it‘s a big market.
Mike Kruger, right, and Will Toor, director of the Colorado Energy Office, after a panel discussion about net-metering at the Colorado Solar and Storage Association annual conference in February. Credit: Allen Best/Big Pivots
How deeply is this understood within your industry. And how well do you think the general public understands this?
I suspect the world’s energy geeks recognize where solar is and where it’s going to be. I don’t think they would be surprised. In fact, I think most would be frustrated that the jump didn’t happen in 2021 rather than in 2023.
And I don’t think any Big Pivots readers would be surprised. They might be surprised by the size of the jump, but we are starting from a pretty small base.
As for people writ large, they have no idea that renewables were responsible last year for 30% of Colorado’s electric grid. I think most people would be shocked. If you were an Xcel customer, it was even higher, I think close to 50%.
And you didn’t experience outages, or at least any more outrages than you have experienced previously. You lost power for four hours in 2023, like you did in 2022, like you did in 2021, right? That speaks to how well the utilities are quickly figuring this stuff out. Kudos to them. They have one job, keep the lights on, and they’re doing it with now a much higher carbon-free mix and more intermittent generation.
OK, what we see here was basically an outcome of decisions made in 2017. If memory serves me, for much of that decade prices for solar had come down 10% a year. Although I think the costs have now leveled off.
Some of the best prices we had were in that Xcel RFP from 2017. The prices are up now. They’ve elevated, but they’re still tons cheaper than the alternatives. Go back to Xcel Energy’s most recent 120-day report. Even solar-plus-storage came in cheaper than gas. Nobody bid coal, but solar would come in cheaper than coal, even from the existing coal plants.
Is it as cheap as it ever was? No. But it’s still really cheap. And I think that whether you’re a homeowner or a utility — and increasingly we’re seeing corporate buyers, such as Amazon and Google — it’s a very viable option.
That’s combined with really strong (state) policy support. Our neighbors to the west gutted their efforts on solar support and generally climate friendly policies. And now they don’t have anywhere near the decarbonized electricity system that we do.
The neighbors to the west being Utah?
Yes, specifically Utah. They have one big city, like we do. No offense to our good folks in Colorado Springs and Pueblo. And they have similar geography: lots of mountains and high desert.
Hunter Solar, located east of Denver and south of Bennett, came online in late 2023. CORE Electrical Cooperative has 45 megawatts of the generating capacity and Holy Cross Energy has 30. Photo credit: Allen Best/Big Pivots
So your members are not surprised by this. They knew it was coming. They might’ve wished that it had happened earlier, if not for Covid. Is that surge then reflected in your organization? By that, I mean the number of members you have. And I’ve been noticing that you have added staff.
It’s a “virtuous cycle.” When I started, it was me and one other individual, and we had, I think it was, 83 to 85 members. We didn’t exactly know how many we had. This week we crossed 300 members. Now, we’re at almost four times the size. And I’ve gone from me and a single individual to now me and five others. We have six on our staff.
My membership has invested in me and the organization, and we have won a bunch of policy victories, which then opens the market even further. And then that allows those folks to invest further in the policy and advocacy work that we do.
We are getting pretty close to the top. An annual survey of companies doing work in each market shows about 350 in Colorado, and I have 300 of them. Using the kind-of-standard 80-20 rule. I think we’re probably pretty close to the top as far as membership numbers go.
That doesn’t mean those members won’t continue to grow. Part of the point of our work is to ensure that members who are currently doing two rooftop systems a week can, if their customer demand is there, expand to five a week.
Or consider Sandbox Solar in Fort Collins, which started in 2015. They were exclusively a rooftop company. All they did was residential rooftop. Now they’ve expanded into the commercial-industrial market and can be successful with multiple footprints. They’re a different company now than when they started.
If memory serves me, you came on in 2018, right?
Correct. I think my first day was Oct. 1. Then we (his family) moved here right around Halloween.
Then in the spring of 2019, my board said, we’re rebranding. We’re adding storage, so rename us, rebrand us, build a new website.
How important is that storage as a component of what you do? Do you have companies that are storage exclusive?
We have some companies that are exclusively developers of storage on a large scale.
Increasingly, we have solar folks expanding (into storage) Photon Brothers is a really good example. The company has been doing rooftop systems for maybe 10 years, and they are now the leading installer of (Tesla) Powerwalls in the state because they’ve really leaned into that. They have a group of customers for which they know so this makes good sense.
For solar of 20 megawatts or more to be bid into a utility RFP without the option to have batteries is almost unheard of.
In places that have price signals, like time-of-use rates, we see batteries being used there and also in places that are prone to outages. So we’re definitely seeing that as an expanded business opportunity, but almost always by a solar company that’s moving into that space. The exception, like I said, we have a few large-scale companies that do only battery storage.
Mike Kruger, right, chats with Kevin Smith, then chief executive of Lightsource bp, upon the near completion of the Bighorn solar project in October 2021. The 300 megawatt solar project was built for Evraz, the owner of the steel mill in Pueblo. Since then Target, Walmart and Amazon have all installed solar projects associated with their operations in Colorado. Amazon has a 6-megawatt solar project in Aurora. Credit: Allen Best/Big Pivots
Looking back to before you arrived in Colorado, your predecessors spent a fair amount of time at the PUC and in meetings, trying to work toward policies. But it’s my sense that you now have two attorneys that can be engaged in the PUC process. Are there signal accomplishments that you think you’ve been able to achieve in the policy realm?
Some of the stuff I’m proudest of is still working its way through.
First, I want to be clear that I stand on the shoulders of the folks that came before me. I didn’t come into an organization that I created from scratch. We’re actually celebrating our 35th anniversary this year.
One item I’m very proud of is that we just got a tariff from Xcel and Black Hills about multi-unit net-metering so that for apartment dwellers you can put a large solar array on-site somewhere in the apartment or on the roof and the individual apartment occupants and renters can get solar credits. That’s a huge market that has not been tapped. That was a single issue that we pushed. There really wasn’t a lot of other folks pushing it. Once we got it to the Legislature and brought it to people’s attention, we picked up some allies. That’s one I’m proud of.
The most recent Xcel electric resource plan had a lot of small details, but those details add up. We’re getting 5,300 megawatts of new renewables being procured.
One of our big wins was in Xcel’s initial filing, they only wanted 400 megawatts of batteries. We forced them back to the drawing board. They are ending up buying 1,848 megawatts of batteries. So, more than four times what was originally planned.
Once you get all those batteries on the grid, we will better be able to integrate renewables. We’ll decarbonize faster. We’ll have less need for gas-peakers. And we’ll have an increasingly stable grid, right?
Batteries solve a lot of the intermittency issues that had had many utilities concerned. They don’t solve everything. I get that lithium-ion batteries have four-hour windows or six-hour windows. But four hours is better than nothing. And energy geeks like the Big Pivots readers will know that we really are only worried about four hours or thereabouts most days. Except for—
When you’re worried about a hundred hours when the wind isn’t blowing, right?
Yeah, exactly. There will be some point in the future when we have 10 days of no sun, no wind, and it will be dastardly cold or whatever. And we’ll need something bigger than that.
That’s why COSSA is involved in some of the conversations about regional markets and expanded transmissions, because it may be brutally cold here with no wind and no solar, but it won’t be in New Mexico or it won’t be in Idaho.
Hopefully we’re smart enough to grab a big geographic footprint to offset those few occasions.
Allen, there’s plenty more to do. The state is far from decarbonized. We have some policies in place, but not enough. And then we’re adding a boatload of new load (demand), right? New electrification of vehicle and fleets and industrialization and buildings. We’ve haven’t solved any of that. It’s a huge opportunity for my membership. It’s millions and millions of dollars of new private investment in mitigating climate change that we haven’t even tapped into yet.
Any workforce issues? As we talk about decarbonizing buildings, it’s brought up again and again that we don’t have the workforce familiar with heat pumps, for example.
Yes and no. Right now, solar is kind of in a steady state where we’re not hiring but we’re not firing. If you’ve been a student of this for a long time, we’ve had the “solar coaster” where we’ve ramped up and hired a bunch of folks and then the bottom dropped out and we let a bunch of folks go. Right now I think things are pretty steady state.
However, like other trades, we struggle to attract new individuals. You can make a lot of money being a crew lead or being a sales lead or a chief designer, but maybe it’s on us to do a better of communicating that. It’s not as sexy as say, going to Harvard or getting your master’s degree from CU or whatever.
All the trades have this problem. That includes plumbers and electricians. I applaud a bipartisan effort to draw attention to that through education. Honestly, though, if you wanted to become an electrician today, if you know where to look, you can do it for free. The grants are available, the training is available, and you can end up with a $150,000 job and have no debt.
Percentage of State’s Electricity from Solar: 9.03%.
Solar Companies in State: 394 (38 Manufacturers, 182 Installers/Developers, 174 Others).
Total Solar Investment in State: $7.7 billion.
Prices have fallen 47% over the last 10 years.
Growth Projection: 2,836 MW over the next 5 years (ranks 19th).
OK, and you have to go in a minute, but let’s talk land use.
I am not totally convinced that we have a problem to solve yet. I think there is potential for conflict, whether that’s on the local community with NIMBys or the environmentalists who are worried about specific species or ecosystems. However, we don’t have them yet.
For us to be solving a problem at the Legislature that we don’t have yet feels a little premature. I know there are folks on the other side who say, well, we should solve them before they become a problem. I get a little worried about solving a problem that doesn’t exist because we might solve it in the incorrect way and create all kinds of unintended consequences. Coming up on seven weeks left in the session, we don’t have a bill yet. To my knowledge, there’s still not an agreement about what a bill should contain.
But things could move quickly – as always.
And then Kruger was off to his next meeting. The land use in question was a non-bill that has been getting a lot of attention – including from Big Pivots. See: “Should Colorado tell counties how to review renewable projects?” It would set a statewide standard for evaluating renewable energy projects by towns, cities and county governments. In late February, Sen. Chris Hansen told Big Pivots he planned to introduce it during March. As of early April, it has not.
What will have to wait are my questions about hail and solar panels. My in-house editor wants to know whether Colorado’s proclivity for hail made it somewhat less attractive to solar developers.
And then there’s the question about all those acres and acres of warehouse roofs that are proliferating along I-70 and I-76 on the eastern and northeaster edges of metropolitan Denver. What role might they place in the future? Will they be covered with solar panels some day?
Colorado lawmakers on Wednesday hailed the announcement by federal officials that 220,000 acres of national forest land on Colorado’s Western Slope will be protected from oil and gas development and mining for at least the next 20 years.
The U.S. Interior Department confirmed that it would withdraw the Thompson Divide area near Crested Butte from federal mineral leasing, following an 18-month review process and more than a decade of advocacy by local conservationists and Colorado officials.
“This announcement is a testament to the persistence of Colorado’s farmers, ranchers, hunters, anglers, recreationists, wildlife enthusiasts, and conservation groups, who were unrelenting in their work to protect the landscape we all love,” Bennet, a Democrat who has long championed the move, said in a press release.
“The Thompson Divide area is a treasured landscape, valued for its wildlife habitat, clean air and water, and abundant recreation, ecological and scenic values,” said U.S. Interior Secretary Deb Haaland. “The Biden-Harris administration is committed to ensuring that special places like these are protected for future generations.”
Prohibiting mineral leasing in the Thompson Divide area is one component of the Colorado Outdoor Recreation and Economy Act, a public lands package championed by Democrats in the state’s congressional delegation since 2019. With the bill stalled by Republican opposition, President Joe Biden in 2022 moved to implement several CORE Act provisions through executive action, including the designation of the Camp Hale–Continental Divide National Monument near Leadville.
While oil and gas trade groups opposed the move, a U.S. Forest Service assessment last year found the impact on the industry would be negligible, while “the proposed action would protect the agricultural, ranching, wildlife, air quality, recreation, ecological, and scenic values of the Thompson Divide area for both intrinsic and economic value to local communities.”
The withdrawal order applies to nearly 200,000 acres of in the White River and Grand Mesa, Uncompahgre, and Gunnison national forests, in addition to 20,000 acres of public land administered by the Bureau of Land Management. The Federal Land Policy and Management Act authorizes the Interior Department to order such withdrawals for a maximum of 20 years.
The CORE Act, which Colorado Democrats have reintroduced for a third time in Congress, still aims to make the withdrawal permanent. The bill stands little chance of being passed by the Republican-controlled House, where GOP lawmakers including Rep. Lauren Boebert of Windsor have called it a “400,000-acre land grab.”
But a long list of local elected officials and conservation advocates say Wednesday’s announcement has been a long time coming.
“We have worked for almost two decades to secure meaningful protection for the Divide, with ranchers, hunters, anglers, mountain bikers, off road vehicle users, and environmentalists coming together in an unlikely alliance to preserve the current uses of these lands,” Jason Sewell, a rancher and president of the Thompson Divide Coalition, said in a statement. “While we will continue to advocate for permanent protections for the Thompson Divide as afforded in the CORE Act, we could not be more thrilled to know that this landscape will continue for the next 20 years to provide the recreational opportunities, jobs, and wildlife habitat that it has for generations.”
Interested in methane and other greenhouse gas emissions near you? Check out http://climatetrace.org, which allows you to see emissions from oil and gas fields, large individual facilities, and more. You can also break it down by industry.
Final rule established after Hickenlooper and Bennet pushed federal government to follow Colorado’s lead
WASHINGTON – Today, U.S. Senators John Hickenlooper and Michael Bennet applauded the announcement of a final rule from the Bureau of Land Management (BLM) that will reduce methane emissions from the production of oil and gas on federal and Tribal lands, conserving billions of cubic feet of gas that might otherwise have been vented, flared, or leaked.
“Colorado has led the way in reducing methane emissions. Taking basic steps to cut harmful emissions will go a long way to slowing climate change and keep pollutants out of our atmosphere. Now, the rest of the country will follow Colorado’s lead so we can meet our climate goals,” said Hickenlooper.
“Colorado has led the nation in limiting methane emissions from the oil and gas industry, and has long recognized the harm caused by routine venting and flaring. These practices waste valuable natural resources, risk the health of surrounding communities, and pollute the environment,” said Bennet. “I’m glad BLM followed our state’s example and is taking steps to cut down on these wasteful practices on our public and Tribal lands.”
The final rule comes after Hickenlooper and Bennet urged the agency last year to follow Colorado’s lead by eliminating routine venting and flaring from oil and gas operations on public and Tribal lands. This final rule will conserve billions of cubic feet of gas and keep harmful methane emissions from entering our atmosphere, while generating more than $50 million in additional natural gas royalty payments each year. This conserved gas will be available to power American homes and industries.
Routine flaring is the practice of regularly burning off excess gas during oil and gas production and processing as a waste product; venting allows excess gas to escape directly into the atmosphere without burning it. Methane, a harmful climate pollutant many more times more potent than carbon dioxide, can be released into the atmosphere in pollution from flaring and venting. Human-caused methane emissions are responsible for at least 25 percent of the climate warming we are experiencing today.
As governor, Hickenlooper brought together environmentalists and the oil industry to create the world’s first methane regulations. Those regulations were used by President Obama as a model for national standards which in turn were used as a basis for the international methane pledge in 2021.
Hickenlooper and Bennet have consistently worked to cut methane emissions and strengthen federal oil and gas methane rules, modeled on Colorado’s. In 2021, Hickenlooper and Bennet led members of the Colorado congressional delegation to push the EPA for stronger methane regulations for the oil and gas sector. Last year, the senators urged the EPA to use data from innovative monitoring technologies like satellite imaging, and tighten restrictions on routine flaring to strengthen methane emission standards. In November, the senators urged the EPA to more accurately track methane emissions. In January, Hickenlooper celebrated the announcement of a conditional commitment from the Department of Energy for up to $189 million in loan guarantees from the Inflation Reduction Act to support the fabrication and installation of a real time methane emissions monitoring network across Texas, Oklahoma, Kansas, Colorado, North Dakota, and New Mexico.
…China’s overwhelming dominance has alarmed officials in the United States and in Europe, who say they are worried that a flood ofcheap Chinese products will undercut their efforts to grow their own renewable energy industries — especially if the Chinese companies have what they consider an unfair advantage. Treasury Secretary Janet L. Yellen, who is expected to soon make her second visit to Beijing in less than a year, said in a speech Wednesdaythat she will press China to address “excess capacity” — including in solar, electric cars and batteries — that “distorts global prices” and “hurts American firms and workers.” Combined, this raises the specter of another trade war, one that activists say could pit protectionism against planet…
China’s metamorphosis into clean tech giant was ordered from the very top. Leader Xi Jinping made supporting “essentially green” industries a priority last month as he tries to stop the world’s second-largest economy from slowing…Clean energy is a bright spot in an otherwise gloomy economic outlook: China’s exports of electric vehicles, lithium-ion batteries and solar products soared 30 percent to $146 billion last year. BYD overtook Tesla in 2023 to become the world’s top-selling electric-car maker. This helped make the renewable energy industry the biggest contributor to the country’s economy, ahead of every other sector, according tothe Center for Research on Energy and Clean Air, a think tank. That shift has come about thanks in no small part to state support. For over a decade, Beijing has used measures including subsidies and tax breaks to create dozens of huge conglomerates that dominate sustainable energy industries. The Tongwei facility, toured by The Washington Post, is 15 percent owned by two of Chengdu city’s state-run investment companies. In the first nine months of last year, the company reported being subsidized with $125 million by the state, a 240 percent rise from 2022.
Downtown Durango on a Sunday morning. Photo credit: Allen Best/Big Pivots
Click the link to read the article on the Big Pivots website (Allen Best):
March 26, 2024
Directors say they see less risk going solo than staying tethered to their long-time wholesale provider
In putting together their annual meetings for members, Tri-State Generation and Transmission tries to put on a happy face of good health, team spirit, and forward movement. That’s what associations do, of course.
A happy face will be harder to muster when Tri-State holds its annual meeting next week at the Westminster Westin hotel. On May 1 it will lose its single largest member, United Power, which alone is responsible for more than 20% of the electricity supplied by Tri-State.
And on Monday morning [March 22, 2024], directors of another cooperative, Durango-based La Plata Electric Association, voted to serve notice of the coop’s plans to exit in two years. La Plata is the fifth largest of Tri-State’s 42 members, responsible for 5.7% of the total demand over a three-year period.
“We have kicked the tires,” said one of the directors, Rachel Landis, moments before the 9-to-3 vote. “We have been staying up late at night.”
“It’s a big day, a monumental day,” said Ted Compton, the chair of the board of directors, in a later interview with Big Pivots. “Nobody thinks that this decision will make our lives in this coop easy at all, but we have self-determination to make the choice that we want and our members want.”
La Plata has been studying its options for the last five years. At one point, in 2021, it chose a partial-requirements contract with Tri-State. The co-op even had an alternative supplier for 50% of the generation. But that approach went nowhere as the formula got balled up in the review by the Federal Energy Regulatory Commission, or FERC. Still, it left a sour taste still evident on the tongues of some directors.
Smaller tent needed
In 2026, when La Plata leaves, Tri-State will be left with 38 members. Also leaving in the interim will be Granby-based Mountain Parks Electric in Colorado and Nebraska’s Northwest Rural Public Power District.
For many years Tri-State had 44 members. The exodus began in 2016 when Kit Carson Electric of Taos, N.M., left Tri-State to pursue a different vision. Some wondered about the disaster ahead. Kit Carson had to pay $37 million to break its all-requirements contract to 2040. It hooked up with a new company, Denver-based Guzman Energy, which had no power generation of its own — although it now does.
Instead of a disaster, Kit Carson has triumphed. In June 2023 it made the final payment to Tri-State while also completing enough new solar to meet 100% of daytime needs in its service territory in northern New Mexico. It has also been building microgrids and pursuing hydrogen as a storage solution.
A retired Tri-State employee who lives in the Durango area urged the directors to stick with Tri-State. The utility can do renewables at scale, he said.
“Please do not try to get out of this contract with Tri-State,” said one woman, who said she was from rural La Plata County.
Another speculated that La Plata will have to pay $200 million or more to break its contract with Tri-State. Even if La Plata saves money, he added, “My kids will have grown up by the time we recoup $200 million.”
Compton, in his interview with Big Pivots, declined to give a figure. Tri-State, in a statement posted after the La Plata decision, said that the estimated value of La Plata’s contract termination payment to Tri-State is estimated at $209.7 million, with a final amount to be calculated prior to withdrawal.
Mark Pearson, a Durango resident, pointed to Kit Carson’s success. “It’s not like we’re the first one out of the gate,” he said. He cited a number of solar projects west and south of Durango. “There are an abundance of local energy sources that would be cheaper than our current contract with Tri-State.”
Directors supporting the exit emphasized their views that Tri-State has failed to be a viable partner. The contract to 2050 – agreed to in 2006 — does not meet La Plata’s needs now, they said.
“We need the ability to make decisions, be nimble, have flexibility, to have local generation,” said Tim Wheeler. “And the contract with Tri-State to 2050 does not present that at all. It represents something from 20 years ago.”
Decision to seek FERC regulation
Wheeler also cited the decision by Tri-State to seek regulation under FERC, which is far more complex, expensive and time consuming than regulation under the state PUC. To do so, Tri-State had to create a new class of members in 2019 who are not electrical cooperatives. For example, it added a greenhouse near Fort Lupton and a hunting guide from near Craig.
Joe Lewandowski, a director from Durango, urged La Plata members to take the long view of 5, 10 to 20 years when viewing costs. He also suggested that there was more risk to staying with Tri-State.
Asked about risk, Compton offered a couple of analogies.
“A lot of people simplistically see this as a decision to stay on a stable ship and get what need or jump off and swim on your own. That is not the way that La Plata has evaluated this. We currently do not see Tri-State as a stable ship. There are a lot of chinks in their armor, and it makes us nervous to be attached to that.”
La Plata, he added, feels more comfortable charting its own course. Tri-State, he said, got off course by seeking federal regulaton.
Tri-State went into the energy transition carrying heavy debt. It has pinned much hope on federal aid through the inflation Reduction Act to cover the cost of retiring stranded assets even as it builds lower cost renewables and natural gas.
But Wall Street analysts in the last couple of years have taken an increasingly dim view of Tri-State’s financials. For several years they have downgraded Tri-State’s credit-worthiness in a series of financial appraisals.
And Compton observed that Tri-State has encountered many problems at FERC.
In its statement, Tri-State made its case for why it should be seen as a viable wholesale provider going forward. In 2030, when 70% of its energy comes from renewables, Tri-State is forecast to achieve an 89% reduction in greenhouse gas emissions in Colorado from a 2005 baseline.
Tri-State has not raised its wholesale rates since 2017 – with an average 6.36% wholesale rate increase proposed to go into effect in 2024. That is being held up at FERC.
“Tri-State’s members have created tremendous momentum toward an energy transition that will provide long-term reliability and rate competitiveness, while reducing emissions and increasing flexibility to provide industry-leading optionality for members,” said Duane Highley, Tri-State’s CEO. La Plata’s “board has chosen not to be part of this future and go it alone on a different path, even as the region faces increasing reliability challenges.”
Why now for this decision?
Why a special meeting for the decision? And why just 10 days after Jessica Matlock, the general manager for the five previous years, left for a job at a larger organization in the Pacific Northwest?
Compton said the timing of the decision had nothing to do with Matlock’s departure.
But why not wait until April and the regularly scheduled board meeting? Because, he said, the board had decided the time was right to make the decision. It had all the information it needed.
He dismissed an observation made by the chief executive of another Colorado co-op that the timing allows La Plata to use its 2023 financials in its application to FERC. That will make La Plata exempt from any capital investments going forward such as new generation and transmission planned by Tri-State — and hence might lower the amount that La Plata will have to pay Tri-State to exit.
Compton repeatedly characterized that observation as speculative. “It was just one of one of many factors that we saw coming in the April 1 timeline,” he said.
La Plata has been a member of Tri-State since 1992 when it and other electrical cooperatives from Western Colorado joined in the wake of the bankruptcy by their former wholesale supplier, Colorado Ute.
Colorado Ute had over-extended itself to build three coal-burning units at Craig for an oil-shale industry that never arrived. Tri-State took over Colorado Ute’s members and its coal plants at Craig. Now, Tri-State is struggling in part because of the cost burden of those coal plants that will be closed between 2025 and 2030.
Craig Station in northwest Colorado is a coal-fired power plant operated by Tri-State Generation & Transmission. Photo credit: Allen Best
Interested in methane and other greenhouse gas emissions near you? Check out http://climatetrace.org, which allows you to see emissions from oil and gas fields, large individual facilities, and more. You can also break it down by industry.
Click the link to read the article on the Colorado Politics website (Scott Weiser). Here’s an excerpt:
Battle lines have been drawn in a fight between oil-producing red states and environmentally-driven blue states over a new regulation by the Environmental Protection Agency…Led by the attorneys general of Texas and Oklahoma, 26 states are suing the EPA over a final rule published March 8 that, in part, sets new regulations for existing methane infrastructure. Twenty other states, including Colorado and the District of Columbia, filed a motion to intervene in the case in support of the new federal regulation Tuesday…
Colorado Attorney General Phil Weiser said the new rule must be defended in a Monday news release announcing the state’s intervention in the Texas case.
“These protections must remain in place at the federal level for effective oversight of methane emissions from surrounding states; that’s why we are committed to defending the federal methane rule,” Weiser said in the release…
The new rule from the EPA regulates methane emissions from both new sources and existing infrastructure, something the EPA has never done before. This raises the question of whether the EPA has legal authority to expand its statutory mandate without asking Congress for permission. The “major questions” doctrine states that federal agencies must have explicit permission to newly regulate politically and economically significant issues, rather than assuming they have unbridled regulatory authority.
Heat pumps are an alternative to gas boilers and wood stoves for indoor heating.
They now feature in most proposals for cutting greenhouse gas emissions to net-zero by mid-century in order to meet the globally agreed aim of avoiding dangerous climate change.
For example, the Intergovernmental Panel on Climate Change (IPCC) says with high confidencethat net-zero energy systems will include the electrification of heating “rely[ing] substantially on heat pumps” – with a possible exception only for extreme climates.
Heat pumps significantly cut greenhouse gas emissions from building heat and are the “central technology in the global transition to secure and sustainable heating”, according to the International Energy Agency (IEA).
Heat pumps are also a mature technology and are very popular in countries such as Norway, Sweden and Finland, where they are the dominant heating technology. For the first time in 2022, heat pumps outsold gas boilers in the US – and they continued to do so in 2023.
Yet, in major economies such as the UK and Germany, heat pumps are the subject of hostile and misleading reporting across many mainstream media outlets. [ed. emphasis mine]
Here, Carbon Brief factchecks 18 of the most common and persistent myths about heat pumps.
1. FALSE: ‘Heat pumps don’t work in existing buildings.’
In a recent survey in the UK, 20% of respondents said they believed that heat pumps only work in newer homes. In 2023, the Daily Telegraph even published an article with the headline: “Heat pumps won’t work in old homes, warns Bosch.”
In reality, millions of buildings of all ages have been fitted with heat pumps around the world. In fact, the UK government’s boiler upgrade scheme, which offers grants to households replacing boilers with heat pumps, only funds work in existing homes.
After conducting several case studies of old homes with “air-source” heat pumps – those that draw energy from the outside air – public body Historic England concluded in a report last year that these “work well in a range of different historic building types and uses”.
The UK government-funded “electrification of heat” project took this a step further, stating that “there is no property type or architectural era that is unsuitable for a heat pump”.
Results from the project also indicate that there is no significant variation in performance based on house age.
These findings are not exclusive to the UK. Research organisation the Fraunhofer Institute in Germany carried out extensive field testing and monitoring of heat pumps in existing buildings and concluded that they worked reliably and without problems.
2. FALSE: ‘Heat pumps only work in highly insulated buildings.’
A common – but false – claim is that heat pumps require extremely well insulated buildings to perform properly. For example, Mattie Brignal, senior money reporter at the Daily Telegraph, wrote in October 2023 that good insulation was “crucial” for heat pumps to work:
“Effective insulation is crucial for heat pumps to function optimally because the devices operate at lower temperatures than gas boilers.”
“Heat pumps will never work in Britain,” he claimed, partly because of the UK’s poorly insulated housing. It is indeed true that the UK has one of the worst housing stocks in Europe when it comes to insulation, as data from smart thermostat company tado shows.
Heat pumps can work in any building if sized, designed and installed correctly. Many uninsulated homes and buildings are already heated to comfortable temperatures with heat pumps, as shown across multiple case studies, including an uninsulated stone church.
A building loses heat through the walls, the windows and the roof when it is colder outside than inside, as shown by the stylised arrows in the figure below. The upper panels show an outdoor temperature of 10C, coloured purple, and an indoor temperature of 20C, coloured red.
Without insulation, shown in the left-hand panels, heat loss is higher – indicated by the larger arrows – and the heat input must similarly be increased, in order to maintain a steady indoor temperature.
At lower outside temperatures – shown in the lower panels – more heat is being lost, for a given level of home insulation. Yet as long as the heat input from a heating system is equal to the heat loss, the building will still retain its indoor temperature.
This means that for a poorly insulated home, a larger heat pump is needed, just as a larger gas boiler would be needed to reach the required heat input. For any home, the system is usually designed for the coldest day of the year.
Four graphics showing heat loss without insulation (left panels) and with insulation (right). Stylised heat loss, from a house heated to 20C with an outdoor temperature of 10C (upper panels) or -10C (lower panels), is shown by the red arrows. Source: Based on an earlier figure by Stefan Holzheu.
Field research from Germany confirms this stylised representation. One of the longest running field studies of heat pumps in renovated properties shows that extensive renovations and insulation upgrades are not necessary to install a heat pump. Good fabric efficiency will keep running costs down, but this is also true for homes heated by gas and oil boilers.
Heat pumps do usually operate at lower “flow temperatures” to maximise efficiency, which means the water pumped to the radiators in a house will have a temperature closer to 50C or below. Although gas boilers also operate more efficiently at lower flow temperatures, they are typically set to provide water at much higher temperatures of 70C or more.
This means the radiators connected to a heat pump system will be cooler, potentially requiring larger radiators or underfloor heating to achieve the same indoor temperature. Research shows, however, that radiators are often oversized to begin with – and that, as a result, not all radiators may need to be replaced.
Moreover, the market already offers high-temperature heat pumps that can reach flow temperatures of 65C and higher. These can be operated with existing radiators.
Furthermore, the UK government’s electrification of heat UK demonstration project showed that the efficiency of high-temperature heat pumps nears that of standard heat pumps, because they only need to run at higher flow temperatures on the coldest days.
3. FALSE: ‘Heat pumps only work with underfloor heating.’
In a recent survey commissioned by the energy supplier Good Energy, 15% of respondents said they believed heat pumps would require underfloor heating.
This is incorrect. Heat pumps work very well with radiators, too, although the lower flow temperature required by underfloor heating means this radiant heating can make heat pumps work more efficiently.
In some cases, the radiators may need upgrading. However, it has been common practice in recent years for heating installers to oversize radiators to apply large safety margins for providing sufficient heat.
If insulation is installed at a later date, the original radiators will also be larger than required. Some radiators may, therefore, need to be replaced to install a heat pump, but this will depend on the property.
Plenty of properties listed on open-source platform Heat Pump Monitor, which allows individuals to upload key information about their own installations, have heat pumps and old radiators, but no underfloor heating.
The Daily Telegraph reported in October 2023 that “many flats are unsuitable for heat pumps”.
Similarly, in August 2023, the Daily Mail reported the comments of Climate Change Committeechief executive Chris Stark saying it is “very difficult” to install heat pumps in flats.
Finding space for the outside units of air-source heat pumps can indeed be a challenge, when it comes to multi-apartment buildings. Solutions for this problem exist, however, as documented in case studies of blocks of flats using a variety of heat pump technologies including ground, air- and water-source heat pumps.
In the UK, Kensa Contracting has successfully installed ground-source heat pumps in high-rise buildings with hundreds of flats, for example. In this case, a shared “ground loop” circulates water to gather warmth from beneath the ground and this is piped into individual flats via a small, in-home unit, which brings the water up to temperature.
Air-to-air heat pumps – similar to air conditioning units – are also an option for flats.
Cllr Gledhill pushes the button to start works at the Thurrock Council flats having the heat pumps installed. Credit: thurrock.gov.uk
A common criticism of heat pumps is that they purportedly do not work in cold weather. For example, Scottish businessman and Labour peer Lord Haughey was quoted last year in the Timessaying that heat pumps cannot cope with the cold climate in Scotland. This story was also widely reported in the Daily Telegraph and the Daily Express.
In all three countries, there are now more than 40 heat pumps per 100 households, more than in any other country in the world. Heat pump installations started to pick up 20 years ago and have significantly reduced carbon emissions in those countries.
Indeed, European countries with the coldest winters have the highest rates of heat pump sales, as shown in the figure below.
Number of heat pumps sold per 1,000 households in 2022 versus average January temperatures. Source: EHPA.
Some also raise questions about how well heat pumps perform when temperatures drop below freezing. For example, climate-sceptic commentator Ross Clark claimed in the Daily Telegraph in January 2024 that “heat pumps seem destined to make us freeze” and that “there is no point in telling us we’ve got to get to net-zero if you can’t tell us how we cope when we reach sub-zero”.
Real-world evidence contradicts such claims. Various field studies have collected performance data of heat pumps, for example on air-source heat pumps in Switzerland, Germany, the UK, the US, Canada and China.
The analysis found that while the coefficient of performance (COP), which is a measure of how efficiently a heat pump operates, declines as outside temperature falls, it remains high.
The COP compares the amount of energy put into a heating system with the amount that it puts out as useful heat, to warm the home. A COP of 1 means that each unit of energy used to run the system returns 1 unit of heat – corresponding to 100% efficiency.
Fossil fuel boilers are never 100% efficient because some of the heat is lost with flue gases. Instead, gas boilers typically operate at around 85% efficiency, equivalent to a COP of 0.85.
In contrast, heat pumps use electricity to gather extra heat from the outside air or ground, meaning they typically generate at least 2 units of heat for each unit of input. This means they can have a COP of 2 or above, meaning they are 200%, 300% or even more efficient.
As the graph below shows, even on the coldest winter days when temperatures drop to as low as -20C, a standard air-source heat pump can still operate with a COP of around 2. This is significantly higher than fossil fuel and electric boilers, which operate at COPs of less than or equal to 1, respectively.
Air-source heat pump performance gathered in field testing studies from “mild” cold climates in five countries: Canada, China, Germany, Switzerland, the US and the UK. Source: Duncan Gibb et al. (2023).
For locations with regular frigid temperatures, cold-climate heat pumps are available on the market today. These heat pumps use refrigerants that have a lower boiling point than standard models and are suitable for winters down to -26C.
However, for very cold temperatures far below freezing (-20C or below), systems with some form of backup may be needed. In the Nordic countries this is common.
Ground-source heat pumps may also be useful in colder climates, because the ground retains heat over winter and very rarely reaches such low temperatures as the air.
6. FALSE: ‘Heat pumps will always need a backup heating system to keep you warm.‘
It is often claimed that heat pumps require a secondary heating system to provide backup.
For example, a 2023 Daily Mail article reported the experience of one homeowner who had installed backup oil-fired heating to “kick in during winter when the [heat] pumps don’t work efficiently”, while another said they needed backup to make their home “cosy again”.
Yet some 79% of the homes monitored under the UK’s electrification of heat project have no backup heating system and use a heat pump to provide all of their hot water and space heating needs.
(Some homes involved in the project trialled “hybrid” heating systems, with heat pumps providing heating and a gas boiler providing hot water and extra heating capacity.)
As explained above, a complementary heat source might be needed in very cold climates where winter temperatures routinely fall below -20C. But, generally, this does not apply to the UK and other temperate countries.
A variation on the false claim that heat pumps are unable to operate in cold climates is the similarly inaccurate idea that they will not be able to keep homes sufficiently warm.
“You can’t find an engineer prepared to install one of the devices in your home because, in all honesty, they know it wouldn’t actually keep you warm,” claimed Ross Clark in the Daily Telegraph last year.
There is no evidence to support the claim that heat pumps will not keep homes warm. If designed and installed correctly, heat pumps can provide the same levels of comfort as a fossil fuel heating system, or more.
In a survey carried out in the UK on behalf of charity Nesta, more than 80% of people stated that they are satisfied with the ability of their heat pump to provide space and hot water heating. This is a satisfaction level similar to households with gas boilers, Nesta said.
Shares of survey respondents, showing the percentage that were very satisfied (dark blue), fairly satisfied (light blue), not very satisfied (light red), not at all satisfied (red), and those that don’t know (dark grey) or for whom the question was not applicable (light grey). Source: Nesta.
Evidence from other countries provides further support. Some 81% of respondents to a pan-European survey in 2022 indicated that their level of comfort had improved after getting a heat pump.
8. INCOMPLETE: ‘You will freeze during a power cut and be better off with a gas boiler.’
In another article attacking heat pumps, published in January 2024, climate-sceptic columnist Ross Clark warned in the Daily Telegraph that “a power cut lasting more than a few hours will be a very serious matter for communities, which face being totally cut off, shivering”.
Similarly, the Daily Express states heat pump owners have been issued a “horror warning over blackouts”. It quotes Erica Malkin from the Stove Industry Alliance who instead suggests “having a wood-burning stove would certainly mean that people have the ability to heat their homes in the event of a blackout”.
The shiny new cold-weather air source heat pump installed during summer 2023 at Coyote Gulch Manor.
It is correct that a heat pump will not work during a power cut. But the same is the case for gas boilers, which require electricity for controls and to pump hot water through your radiators.
Boiler Central, an online boiler sales company, states on its website that “most” boilers are unable to function without power, such that power cuts render them “temporarily useless”:
“Most modern boilers are reliant on electricity to function, so when the power goes out, your boiler will not be able to heat your home. Without electricity, most of the main components like the thermostat, central heating pumps, and valves will have no power therefore causing your boiler not working properly, rendering your boiler temporarily useless.”
It is also worth noting that the UK’s power grid is very reliable. Most customers only experience a few minutes of outages each year, as data by the energy regulator Ofgem indicates. The same is true in Germany and most other developed countries.
(In the US, power outages are significantly longer – lasting a total of 5 hours on average in 2022 – mainly caused by falling trees.)
Another of the false arguments frequently thrown at heat pumps is the idea that they are “too loud” to be installed in many homes – or that the noise they create is a nuisance.
For example, the Daily Telegraph reported – inaccurately – in November 2023 that “heat pumps are too loud to be installed in millions of homes in England under the government’s noise guidelines”.
This headline was contradicted by the experts cited in the article. Consultants Apex Acoustics, who led the research, released a statement saying that the headline claim was “an exaggeration” and that, contrary to the article, noise issues were not “insurmountable”. It said:
“The headline claims heat pumps are ‘too noisy’ for millions of British homes. This is an exaggeration. While noise is a valid concern with heat pumps that needs to be addressed, technology improvements and proper installation can mitigate noise issues in most homes. The article presents noise as an insurmountable problem, which is not the case.”
The Daily Telegraph article also claims there will be a “rise in noise complaints” as more heat pumps are installed.
In reality, UK data shows noise complaints about heat pumps are very low. There are only around 100 noise complaints for every 300,000 installations – a rate of 0.03% – according to a survey by noise experts cited in a research paper by Apex Acoustics.
Government-commissioned research confirms this. It says there is a “low incidence of ASHP [air-source heat pump] noise complaints” and adds: “These arose due to poor quality installations, including location and proximity factors.”
Concluding its response to the Daily Telegraph, Apex Acoustics states that “the article spins isolated concerns and worst-case scenarios into an exaggerated narrative against heat pumps”.
It is true that air-source heat pumps generate a certain degree of noise, due to the fan that circulates ambient air around the outdoor unit. But they can be very quiet and “sound emissions from heat pumps were not reported as noticeable” by the majority of respondents in the studycommissioned by the UK government.
In the UK there are strict noise limits on heat pumps. The legal noise limit for heat pumps in the UK is 42 decibels. It is measured from the nearest neighbouring property and means the noise limit at the boundary to a neighbour’s property is 42 decibels. This is a similar volume to a refrigerator.
Noise scale showing different sounds and where they rank in terms of decibels, including a heat pump sitting in the moderate (40-60dB) range. Source: RNID, Zhang (2016).
Ground-source heat pumps create no noise outside of the home, given that there is no fan unit required. Inside a home, ground-source heat pumps do not make more noise than a standard fridge or freezer, says a review by the Federation of Master Builders.
10. INCOMPLETE: ‘Heat pumps cost more to run and will increase heating bills.’
One of the most widespread lines of attack against heat pumps is that they are expensive to run. On the contrary, thanks to their high efficiency, well-designed systems can save UK households hundreds of pounds a year, even though electricity is more expensive than gas.
They offer even greater relative savings in other countries, where electricity prices compared to gas prices are lower.
In a YouTube video from the “Skill Builder” channel, watched more than 2.2m times, presenter Roger Bisby claims “when you look at people’s fuel bills, running a heat pump is roughly three times more expensive than running a gas boiler”. This statement is false.
The running costs of heat pumps relative to gas boilers depend on energy prices and the efficiency of the heat pump installation.
It is a fact that electricity prices are higher than gas prices. Under the UK energy price cap as of March 2024, each unit of electricity is four times more expensive than gas.
However, heat pumps use about 3-5 times less energy compared to a gas boiler. This is because a heat pump turns one unit of electricity into 2.5-5 units of heat.
This efficiency is measured by the seasonal coefficient of performance (SCoP). The SCoP provides a metric to measure the efficiency of a heat pump over the course of a year, rather than the COP which relates to a single moment in time. It measures the total amount of heat produced in a year, compared with the total amount of electricity consumed.
For example, a SCoP of three indicates that for every unit of electricity consumed in a year, the heat pump provides three units of heat. A SCoP of 4 means that the heat pump delivers four times more heat than the electricity input.
In addition, if the heat pump is also used to produce hot water, households can save £110 per year by disconnecting from the gas grid and no longer paying the gas “standing charge”.
In a household paying standard unit prices under the March 2024 UK energy price cap, a heat pump with a SCoP of more than 3 will achieve cost parity with the running costs of an 85% efficient gas boiler.
Under the electrification of heat project, the central estimate (median) SCoP was 2.9. At this level of efficiency, the yearly heating costs to run a heat pump on the current standard tariff would be £25 higher than an 85% gas boiler. Yet much higher heat pump efficiencies can and have been achieved.
HeatGeek, an organisation that trains heat pump installers, reports that installations by those it has trained achieve SCoPs of 4. With a SCoP of 4, households on a standard tariff would save 25% on their heating bills compared to an average gas boiler.
This may change depending on how prices develop in the future, but government estimatessuggest that unit prices for electricity will fall relative to those for gas. In other words, the relative running costs of heat pumps will improve versus gas boilers, if those projections are broadly correct.
In the meantime, heat pump users can lower their operating costs through using dedicated tariffs. Some energy companies offer time-varying prices. For example, Octopus Energy’s “Agile” tariff averaged 17 pence per kilowatt hour (p/kWh) over December 2023 to February 2024. This was significantly below the price cap of 27p/kWh from January to March and 25 p/kWh from April to June 2024.
Octopus also offers a special heat pump tariff called “Octopus Cosy”. From 1 April 2024, this will cost 19.6p/kWh, according to Octopus Energy.
Energy supplier OVO also offers a new heat pump tariff of 15p/kWh, called “Heat Pump Plus”, which reduces the unit price by 44% compared to the price cap. (Note that the OVO offering is contingent on working with heat pump accreditation scheme Heat Geek that only covers part of the market.)
OVO also states that, currently, the offering is limited to the first 100 customers who sign up. Whether or not the OVO offering will be available in the future and, if so, in what form is uncertain.
For a UK home on a given energy tariff, the running costs for a heat pump fall as the system gets more efficient (higher SCoP). This is illustrated in the figure below, showing that a home with a heat pump on the standard tariff for April to June 2024 would have lower running costs than for an 85% gas boiler if the SCoP is 3 or above.
The equivalent figures under a range of different energy tariffs are shown by the curved lines. While the figure includes a line for a 92% efficient gas boiler – the rating given on the label of many modern condensing boilers – data from real homes suggests 85% is more typical.
Annual running cost of heat pumps and gas boilers, £, as a function of system efficiency, SCoP. Gas boilers and heat pump standard tariff use the April-June 2024 price cap. Figure based on an earlier methodology updated with the latest energy price data. Source: RAP.
This analysis shows that homes heated with gas boilers could cut their heating bills in half with a heat pump, if they use the Octopus Agile or OVO tariffs, and if their heat pumps have SCoPs of 4.0 and 3.7, respectively.
11. FALSE. ‘Turning gas to electricity to heat via a heat pump is less efficient than burning gas in a boiler.’
A common misunderstanding is that it would be more efficient to burn gas in a domestic gas boiler, rather than converting it into electricity at a power station and using the electricity to run a heat pump instead.
For example, Conservative MP John Redwood tweeted in March 2024 that this would mean “we end up burning more gas in a power station instead of in gas boilers”.
This is false. A standard 300% efficient heat pump (SCoP of 3) would be able to deliver the same amount of warmth as an average gas boiler while cutting gas demand by two-fifths, even if running on 100% gas-fired electricity.
In a more realistic scenario taking into account the way the UK actually generates electricity, the same heat pump would cut gas demand – and the resulting carbon dioxide (CO2) emissions – by at least three-quarters over the next 15 years.
The late Prof Sir David MacKay, former chief scientific adviser to the then-Department of Energy and Climate Change, explained this clearly back in 2008, in his celebrated book “Sustainable Energy Without the Hot Air”:
“Heat pumps are superior in efficiency to condensing boilers, even if the heat pumps are powered by electricity from a power station burning natural gas.”
This is because a heat pump with a SCoP of 3 uses one unit of electricity to make three of heat. As a result, burning one unit of gas in a power plant at 48.3% average efficiency and taking into account the 8% of electricity lost during transmission results in 1.3 units of heat from a heat pump.
In comparison, a gas boiler in the UK typically operates at 85% efficiency, as shown by the grey area in the left-hand bars in the chart below. This means one unit of gas for heating (left column) results in 0.85 units of heat (second from left).
As a result, a 300% efficient heat pump (second column from right, SCoP 3), even if running 100% on gas-generated electricity (rightmost column), needs about two-fifths less gas to make the same amount of heat (“saving”, yellow hatching).
Gas demand, kWh, for home heating using an 85% efficient gas boiler (left-hand bars) versus an electric heat pump system (right hand bars) with an efficiency of 300% (SCoP 3) using electricity generated at a 48% efficient gas-fired power station, after 8% line losses. “Wasted” energy refers to waste heat during combustion. “Ambient” energy is taken from the outside air. The overall gas saving is hatched yellow. Source: Carbon Brief analysis.
In reality, instead of running on 100% gas-fired electricity, heat pumps would run on the current electricity mix. In the UK, the share of fossil fuels (black) in total electricity generation was 33% in 2023, as shown in the figure below.
Share of UK electricity generation by source, %, 1920-2023. Source: Carbon Brief analysis.
It is also important to note that the share of gas generation in the electricity mix will decline over the coming years. This means that a heat pump would cut CO2 emissions by 77-86% over 15 years compared with a gas boiler, based on UK government guidance.
12. FALSE: ‘Heat pumps will never offset the carbon emissions resulting from making them.’
As with electric vehicles, solar panels or wind turbines, the factories making heat pumps need raw materials and energy, which lead to CO2 emissions.
This results in another common misunderstanding that the CO2 saved by the heat pump during operation will be cancelled out by the emissions created during manufacturing.
A typical response on Twitter when posting about heat pumps is along these lines: “Ripping out a perfectly well functioning gas boiler before the end of its natural life and replacing it with a heat pump is misguided. It won’t reduce much carbon.”
The perception that it makes sense to use a gas boiler until the end of its life before installing a heat pump is widespread. It is based on the belief that the “embodied” carbon emissions of a heat pump are higher than any carbon savings during operation.
Despite the intuitive appeal of this belief, detailed analysis shows it is incorrect. In fact, replacing a gas boiler with a heat pump would save 25-28 tonnes of CO2 equivalent (tCO2e) over a 15-year period, a reduction of more than three-quarters.
According to one peer-reviewed study, it takes 1,563kg of CO2 equivalent (kgCO2e) to manufacture a domestic heat pump. This figure – 1.6tCO2e – can be compared with annual per capita emissions in the UK of 5.6tCO2e in 2023.
The Chartered Institution of Building Services Engineers (CIBSE) has provided new guidance on embodied carbon, which gives a similar result. Using the CIBSE figures, for a heat pump with a capacity of 7 kilowatts (kW), we can assume embodied carbon of around 1,500kgCO2e – slightly more than 200kgCO2e per kW of capacity.
Now let us compare this to a typical gas boiler. Embodied emissions of the boiler are ignored in the calculation of gas boiler emissions, as we assume the gas boiler is already in place. What we are interested in is how quickly a heat pump install will offset its embodied carbon.
The central estimate for annual gas consumption per household is 12,100 kilowatt hours (kWh), excluding the 2.4% of gas used for cooking. Per kWh of gas used, the boiler emits 183gCO2 based on the UK government’s green book guidance. That is 2,209kgCO2e per year. If we assume the gas boiler runs for another 15 years, it will result in total operational emissions of 33,134kgCO2e.
For comparison, a heat pump has significantly lower operational emissions. Using the more conservative “marginal” emission factors from green book guidance and a SCoP of three, the total operational emissions over 15 years from 2023-2037 are expected to be 6,153kgCO2e.
(Using marginal emission factors assume the heat pump is powered by the marginal source of electricity, which is the last power plant that needs to be switched on to meet overall demand. At present, this is usually a gas plant.)
For average green book emission factors, the heat pump would emit 3,242kgCO2e. Using CIBSE figures for the embodied carbon in its manufacture, the total emissions associated with the new heat pump over 15 years would reach 7,653kgCO2e for marginal and 4,742kgCO2e for average emission factors.
This is a saving of 25,481-28,392kgCO2e compared with the gas boiler (25-28tCO2e).
Overall then, replacing a gas boiler with a heat pump would cut emissions by 77-86%, including the embodied emissions from manufacturing the heat pump. This means the heat pump would offset its embodied carbon after 13 months.
Cumulative emissions from heating a home in the UK with an existing gas boiler or a new heat pump, 2023-2037, tonnes of CO2 equivalent (tCO2e) including emissions embodied in the manufacturing of the heat pump. Source: Author calculations.
Even under the unrealistic and extreme assumption that manufacturing a heat pump entails 10 times more embodied carbon than thought, it would still generate emissions savings of 36-45% over 15 years when replacing a gas boiler.
Additionally, the emissions estimate for gas excludes upstream emissions associated with gas extraction, processing and transport. Applying a higher estimate of 210kgCO2e/kWh to account for the upstream emissions results in higher carbon savings of 80-87% for a heat pump, compared to an existing gas boiler.
In conclusion: the embodied emissions from a heat pump are offset after a few months. Over the lifetime of the appliance, heat pumps save considerable amounts of carbon emissions compared to a gas boiler.
A common myth suggests that installing a heat pump will devalue your property. For example, an article in the Daily Express from 2022 suggested that “homeowners who are forced to rip out their gas boiler and replace it with eco-friendly heat pumps will see the value of the home collapse”.
The evidence suggests the opposite: heat pumps increase the value of properties. Research from the US found that “residences with an air source heat pump enjoy a 4.3–7.1% (or $10,400–17,000) price premium on average”.
UK research has shown that a heat pump could add between 1.7% and 3.0% to the value of an average home. Estate agent Savills also reports that buyers pay a premium for homes with heat pumps.
Based on the average UK house price in December 2023, some £285,000, this implies a price premium of £4,800-£8,600, which amounts to a significant proportion of the cost of installing a heat pump in the first place.
The upfront cost of heat pumps is a frequently cited issue with the technology.
For example, the Daily Telegraph said in a September 2023 article:
“The main barrier to installing these devices for most homes is the disproportionately large upfront cost when compared to traditional heating systems.”
Similarly, yet another Ross Clark comment for the Daily Telegraph – under the headline “The great heat pump hype is almost dead” – said they were “horrendously expensive to install”.
It is true that heat pumps are more expensive to buy than gas boilers.
In 2023, the average installation cost of an air source heat pump in the UK was £12,368, according to MCS data. This compares with £2,500-3,000 for a gas boiler, according to the UK government. A recent report by the National Audit Office concluded that heat pumps have seen a 6% real-terms cost reduction compared to 2021.
The UK government offers subsidies for heat pumps of £7,500 per installation under the boiler upgrade scheme. This is an increase from the previous level of £5,000, leading to a surge in interest, as shown in the figure below.
(The number of applications for heat pump vouchers in January 2024 was 39% higher than a year earlier, the government says.)
The number of boiler upgrade scheme voucher applications received from May 2022 through to January 2024. Source: Department for Energy Security and Net Zero.
Some companies now offer heat pumps for less than £3,000 after the grant, a cost similar to a new gas boiler.
Most forecasts are for heat pump installation costs to decline in the future, according to a systematic review of the evidence by the UK Energy Research Centre. The majority of forecasts suggest a reduction in total installed costs of around 20-25% by 2030, it found.
Crucially, while heat pumps currently have relatively high upfront costs, they are expected to be the most cost-effective way to decarbonise heating.
15. INCOMPLETE: ‘The grid cannot cope with heat pumps.’
Another common myth about heat pumps – as for electric vehicles – is that their widespread adoption would be catastrophic for the electricity grid.
For example, the Daily Express published an article in 2022 titled: “Heat pump hell: Owners sent horror warning over boiler alternatives amid blackout threat.”
The article cites Erica Malkin from the Stove Industry Alliance, the trade association for UK stove manufacturers, installers and retailers. She claimed that the grid may not be able to cope with heat pumps and there could be power outages if they are widely rolled out.
Similarly, a February 2024 comment for the Sunday Telegraph by omnipresent climate-sceptic columnist Ross Clark asked “at a time when politicians want millions more of us to be driving electric cars and heating our homes with heat pumps…how will we keep the lights on?”
Clark also claimed that the plan to electrify heating and transport will “put us all in the dark” and that “the UK is much closer to blackouts than anyone dares to admit”.
In an unrealistic scenario where all UK homes switched to heat pumps overnight, in many areas the electricity grid would indeed struggle. Yet the transition to heat pumps will take decades, not just a couple of years.
This gives the electricity network companies, the future system operator, the energy suppliers and the energy regulator Ofgem time to adjust.
In its latest assessment of UK infrastructure needs, official government advisor the National Infrastructure Commission points to the rapid transformation of the power system in the past. This suggests the UK can build the infrastructure needed to electrify heating within the timescales required, it says.
Moreover, although not widely known, UK electricity demand has fallen by 18% over the last two decades. This has created some space on the grid for demand growth.
The factors driving the drop include product energy efficiency regulations, energy-efficient lighting – which has cut peak demand by the equivalent of roughly two nuclear plants alone – environmentally conscious consumers and economic restructuring, including offshoring energy-intensive industries.
National Grid is well aware of the needed investment in the grid and is planning for heat pumps (and electric vehicles) to be connected. It says it is confident that electrification of home heating can be delivered in the UK.
Distribution network operators, who manage local grids and transmit electricity to individual customers, started to develop heat pump strategies a few years ago.
The amount of unused grid capacity in the distribution grid varies by area. In some parts of the country, there is no need for grid upgrades.
Research carried out on behalf of the UK government found that in rural areas of Scotland, 36-59% of the grid would require upgrades if all heating was electrified.
More recent research predicts that peak heat demand from heat pumps will be 8% lower than for gas heating, because heat pumps are designed to deliver heat consistently over longer periods rather than in short bursts.
In addition, it found that the maximum “heat ramp rate” – the speed at which heating loads increase prior to peak periods – will be 67% lower compared to gas heating.
An important solution for minimising the required grid investments and consumer costs is demand flexibility, or the ability to shift demand to periods when electricity is cheap and the pressure on the grid is lower.
It has been demonstrated that heat pumps can provide demand flexibility to support the grid. This can mean heating buildings slightly before peak periods and ramping down heat pump output during the peak, without a noticeable loss in comfort. It can also mean using “heat batteries” and thermal storage to absorb cheaper electricity when available.
The question of energy system reliability under a net-zero pathway has been looked at extensively by the Committee on Climate Change and the Royal Society. Those assessments found that with an appropriate technology mix, it is possible to electrify much of the UK’s heating at the same time as ensuring reliability of supply.
16. INCOMPLETE: ‘Heat pumps don’t work with microbore piping.’
The Daily Express reported in 2021 that “any homes with microbore pipework looking to install a heat pump…could result in huge costs and major disruption to installing additional equipment. All pipework throughout the properties might also need replacing.”
All pipework throughout the properties might also need replacing.”
Microbore pipework is a smaller type of pipework often used in homes to transport hot water to radiators. It is a generic term for pipes which measure under 15mm in diameter and are usually made of either plastic or copper.
The lower diameter means it is harder to run hot water around the system quickly.
Heat pump heating systems typically use higher flow rates, in combination with lower flow temperatures, in order to maximise efficiency.
As a result, microbore piping is not ideal for heat pumps. Yet it can still be possible to keep some microbore pipes and still install a heat pump, as explained by Heat Geek.
There are even examples of homes with microbore piping that have had heat pumps installed successfully. Heat pump installer Airaexplains how a home with microbore can still benefit from a heat pump, with the right adjustments.
In conclusion, it is correct that microbore pipes are not always ideal for heat pumps. But it is incorrect to say that heat pumps will not work with microbore piping.
Despite persistent claims to the contrary on social media, heat pumps can last a couple decades or even longer. The UK government assumes a lifetime of 20 years in its official impact assessment for heat pump subsidies.
Analysis of field data from the US, collected between 2001 and 2007 by Lawrence Berkeley National Laboratory, concluded that air-to-air heat pumps last on average 15 years – and since then, the quality of the technology has improved.
18. INCOMPLETE: ‘Heat pumps are new and untested technology.’
In a February 2024 article about Scotland’s plans to roll out heat pumps, the Herald reported that the GMB trade union had tabled a motion at the Scottish Labour Party conference against “forcing onto households untested systems such as heat pumps”.
(The “b” in GMB historically stood for “boilermakers”.)
Heat pumps are, however, a very mature technology and have been around for more than 100 years. The first heat pump as we know it today was built by Austrian engineer Peter von Rittingerin 1856. Heat pumps were installed in peoples’ homes many decades ago.
A heat pump was installed in the City Hall of Zurich in 1938 and was not replaced until 2001. The first heat pump in the UK was installed in Norwich in 1945 by John Sumner, the city electrical engineer for Norwich.
Across the world, there are close to 200m heat pumps in operation today.
2M3PD53 Diagram illustrating how heat in the earth and water can provide heating for homes and factories. City Electrical Engineer of Norwich, where using pipes containing a liquid chemical with a low boiling point, such as sulphur dioxide, placing them underground, the chemical would collect heat from the earth and eventually vaporise. In 1947 britain had a harsh winter, with several cold spells, bringing large drifts of snow to the country, which caused roads and railways to be blocked. Coal supplies, already low following the Second World War, struggled to get through to power stations and many st
Click the link to read the article on the Grist website (Tristan Ahtone, Robert Lee, Amanda Tachine, An Garagiola, and Audrianna Goodwin):
February 7, 2024
This project was supported by the Pulitzer Center, the Data-Driven Reporting Project, and the Bay & Paul Foundation.
Alina Sierra needs $6,405. In 2022, the 19-year-old Tohono O’odham student was accepted to the University of Arizona, her dream school. She would be the first in her family to go to college.
Her godfather used to take her to the university’s campus when she was a child, and their excursions could include a stop at the turtle pond or lunch at the student union. Her grandfather also encouraged her, saying: “You’re going to be here one day.”
“Ever since then,” said Sierra. “I wanted to go.”
Then the financial reality set in. Unable to afford housing either on or off campus, she couch-surfed her first semester. Barely able to pay for meals, she turned to the campus food pantry for hygiene products. “One week I would get soap; another week, get shampoo,” she said. Without reliable access to the internet, and with health issues and a long bus commute, her grades began to slip. She was soon on academic probation.
“I always knew it would be expensive,” said Sierra. “I just didn’t know it would be this expensive.”
Alina Sierra poses for a photo while wearing a locket containing the ashes of her godfather. “He would tell me, like, ‘Further your education, education is power,’” she said. “Before he passed away, I promised him that I was going to go to college and graduate from U of A.” Bean Yazzie / Grist
She was also confused. The university, known as UArizona, or more colloquially as U of A by local residents and alumni, expressed a lot of support for Indigenous students. It wasn’t just that the Tohono O’odham flag hung in the bookstore or that the university had a land acknowledgment reminding the community that the Tucson campus was on O’odham and Yaqui homelands. The same year she was accepted, UArizona launched a program to cover tuition and mandatory fees for undergraduates from all 22 Indigenous nations in the state. President Robert C. Robbins described the new Arizona Native Scholars Grant as a step toward fulfilling the school’s land-grant mission.
Sierra was eligible for the grant, but it didn’t cover everything. After all the application forms and paperwork, she was still left with a balance of thousands of dollars. She had no choice but to take out a loan, which she kept a secret from her family, especially her mom. “That’s the number one thing she told me: ‘Don’t get a loan,’ but I kind of had to.”
Cacti grow behind a sign for the University of Arizona. Bean Yazzie / Grist
Established in 1885, almost 30 years before Arizona was a state, UArizona was one of 52 land-grant universities supported by the Morrill Act. Signed into law by President Abraham Lincoln, the act used land taken from Indigenous nations to fund a network of colleges across the fledgling United States.
By the early 20th century, grants issued under the Morrill Act had produced the modern equivalent of a half a billion dollars for land-grant institutions from the redistribution of nearly 11 million acres of Indigenous lands. While most land-grant universities ignore this colonial legacy, UArizona’s Native scholars program appeared to be an effort to exorcise it.
But the Morrill Act is only one piece of legislation that connects land expropriated from Indigenous communities to these universities.
In combination with other land-grant laws, UArizona still retains rights to nearly 689,000 acres of land — an area more than twice the size of Los Angeles. The university also has rights to another 705,000 subsurface acres, a term pertaining to oil, gas, minerals, and other resources underground. Known as trust lands, these expropriated Indigenous territories are held and managed by the state for the school’s continued benefit.
A parcel of land in Willcox, Arizona, granted to the University of Arizona. Eliseu Cavalcante / Grist
State trust lands just might be one of the best-kept public secrets in America: They exist in 21 Western and Midwestern states, totaling more than 500 million surface and subsurface acres. Those two categories, surface and subsurface, have to be kept separate because they don’t always overlap. What few have bothered to ask is just how many of those acres are funding higher education.
The parcels themselves are scattered and rural, typically uninhabited and seldom marked. Most appear undeveloped and blend in seamlessly with surrounding landscapes. That is, when they don’t have something like logging underway or a frack pad in sight.
In 2022, the year Sierra enrolled, UArizona’s state trust lands provided the institution $7.7 million — enough to have paid the full cost of attendance for more than half of every Native undergraduate at the Tucson campus that same year. But providing free attendance to anyone is an unlikely scenario, as the school works to rein in a budget shortfall of nearly $240 million.
UArizona’s reliance on state trust land for revenue not only contradicts its commitment to recognize past injustices regarding stolen Indigenous lands, but also threatens its climate commitments. The school has pledged to reach net-zero emissions by 2040.
The parcels are managed by the Arizona State Land Department, a separate government agency that has leased portions of them to agriculture, grazing, and commercial activities. But extractive industries make up a major portion of the trust land portfolio. Of the 705,000 subsurface acres that benefit UArizona, almost 645,000 are earmarked for oil and gas production. The lands were taken from at least 10 Indigenous nations, almost all of which were seized by executive order or congressional action in the wake of warfare.
Over the past year, Grist has examined publicly available data to locate trust lands associated with land-grant universities seeded by the Morrill Act. We found 14 universities that matched this criteria. In the process, we identified their original sources and analyzed their ongoing uses. In all, we located and mapped more than 8.36 million surface and subsurface acres taken from 123 Indigenous nations. This land currently produces income for those institutions.
“Universities continue to benefit from colonization,” said Sharon Stein, an assistant professor of higher education at the University of British Columbia and a climate researcher. “It’s not just a historical fact; the actual income of the institution is subsidized by this ongoing dispossession.”
Indigenous landgranted to universities
The amount of acreage under management for land-grant universities varies widely, from as little as 15,000 acres aboveground in North Dakota to more than 2.1 million belowground in Texas. Combined, Indigenous nations were paid approximately $4.7 million in today’s dollars for these lands, but in many cases, nothing was paid at all. In 2022 alone, these trust lands generated more than $2.2 billion for their schools. Between 2018 and 2022, the lands produced almost $6.7 billion. However, those figures are likely an undercount as multiple state agencies did not return requests to confirm amounts.
This work builds upon previous investigations that examined how land grabs capitalized and transformed the U.S. university system. The new data reveals how state trust lands continue to transfer wealth from Indigenous nations to land-grant universities more than a century after the original Morrill Act.
It also provides insight into the relationship between colonialism, higher education, and climate change in the Western United States.
Nearly 25 percent of land-grant university trust lands are designated for either fossil fuel production or the mining of minerals, like coal and iron-rich taconite. Grazing is permitted on about a third of the land, or approximately 2.8 million surface acres. Those parcels are often coupled with subsurface rights, which means oil and gas extraction can occur underneath cattle operations, themselves often a major source of methane emissions. Timber, agriculture, and infrastructure leases — for roads or pipelines, for instance — make up much of the remaining acreage.
By contrast, renewable energy production is permitted on roughly one-quarter of 1 percent of the land in our dataset. Conservation covers an even more meager 0.15 percent.
However, those land use statistics are likely undercounts due to the different ways states record activities. Many state agencies we contacted for this story had incomplete public information on how land was used.
“People generally are not eager to confront their own complicity in colonialism and climate change,” said Stein. “But we also have to recognize, for instance, myself as a white settler, that we are part of that system, that we are benefiting from that system, that we are actively reproducing that system every day.”
Students like Alina Sierra struggle to pay for education at a university built on her peoples’ lands and supported with their natural resources. But both current and future generations will have to live with the way trust lands are used to subsidize land-grant universities.
In December 2023, Sierra decided the cost to attend UArizona was too high and dropped out.
UArizona did not respond to a request for comment on this story.
Acreage now held in trust by states for land-grant universities is part of America’s sweeping history of real estate creation, a history rooted in Indigenous dispossession.
Trust lands in most states were clipped from the more than 1.8 billion acres that were once part of the United States’ public domain — territory claimed, colonized, and redistributed in a process that began in the 18th century and continues today.
The making of the public domain is the stuff of textbook lessons on U.S. expansion. After consolidating states’ western land claims in the aftermath of the American Revolution, federal officials obtained a series of massive territorial acquisitions from rival imperial powers. No doubt you’ve heard of a few of these deals: They ranged from the Louisiana Purchase of 1803 to the Alaska Purchase of 1867.
Backed by the doctrine of discovery, a legal principle with religious roots that justified the seizure of lands around the world by Europeans, U.S. claims to Indigenous territories were initially little more than projections of jurisdiction. They asserted an exclusive right to steal from Indigenous nations, divide the territory into new states, and carve it up into private property. Although Pope Francis repudiated the Catholic Church’s association with the doctrine in 2023, it remains a bedrock principle of U.S. law.
Native land loss 1776 to 1930. Credit: Alvin Chang/Ranjani Chakraborty
Starting in the 1780s, federal authorities began aggressively taking Native land before surveying and selling parcels to new owners. Treaties were the preferred instrument, accompanied by a range of executive orders and congressional acts. Behind their tidy legal language and token payments lay actual or threatened violence, or the use of debts or dire conditions, such as starvation, to coerce signatures from Indigenous peoples and compel relocation.
By the 1930s, tribal landholdings in the form of reservations covered less than 2 percent of the United States. Most were located in places with few natural resources and more sensitive to climate change than their original homelands. When reservations proved more valuable than expected, due to the discovery of oil, for instance, outcomes could be even worse, as viewers of Killers of the Flower Moon learned last year.
The public domain once covered three-fourths of what is today the United States. Federal authorities still retain about 30 percent of this reservoir of plundered land, most conspicuously as national parks, but also as military bases, national forests, grazing land, and more. The rest, nearly 1.3 billion acres, has been redistributed to new owners through myriad laws.
A waste pond on a land-grant parcel in Carlsbad, New Mexico. Eliseu Cavalcante / Grist
When it came to redistribution, grants of various stripes were more common than land sales. Individuals and corporate grantees — think homesteaders or railroads — were prominent recipients, but in terms of sheer acreage given, they trailed a third group: state governments.
Federal-to-state grants were immense. Cram them all together and they would comfortably cover all of Western Europe. Despite their size and ongoing financial significance, they have never attracted much attention outside of state offices and agencies responsible for managing them.
The Morrill Act, one of the best known examples of federal-to-state grants, followed a well-established path for funding state institutions. This involved handing Indigenous land to state legislatures so agencies could then manage those lands on behalf of specifically chosen beneficiaries.
Many other laws subsidized higher education by issuing grants to state or territorial governments in a similar way. The biggest of those bounties came through so-called “enabling acts” that authorized U.S. territories to graduate to statehood.
Every new state carved out of the public domain in the contiguous United States received land grants for public institutions through their enabling acts. These grants functioned like dowries for joining the Union and funded a variety of public works and state services ranging from penitentiaries to fish hatcheries. Their main function, however, was subsidizing education.
Since time immemorial, Indigenous peoples have lived with, and cared for, the lands they call home. But as settlers moved west, U.S. government and military officials forced those communities from their lands, sometimes through the signing of treaties, sometimes through military action. Once ceded, those lands became territories and then states. With statehood, those lands became part of America’s real estate system.
Lands inside newly formed states were overlaid with the Public Land Survey System — a rectangular survey system designed by early colonists to map newly acquired Indigenous lands. One 6-by-6 mile square on the grid is known as a township. Inside each township are 36 more 1-by-1 mile squares called sections.
In most states, sections 16 and 36 of every township were automatically set aside to fund K-12 schools, known as common schools at the time. From the remaining 34 sections, states could choose which lands would benefit other public institutions, like hospitals, penitentiaries, and universities.
In the years since statehood, some of these lands have been sold or swapped, but most Western states have held onto their trust lands. Spread across the Western U.S. land grid, trust lands are often unseen, landlocked, and anonymous on the landscape.
Primary and secondary schools, or K-12 schools, were the greatest beneficiaries by far, followed by institutions of higher education. What remains of them today are referred to as trust lands. “A perpetual, multigenerational land trust for the support of the Beneficiaries and future generations” is how the Arizona State Land Department describes them.
Higher education grants were earmarked for universities, teachers colleges, mining schools, scientific schools, and agricultural colleges, the latter being the means through which states that joined the Union after 1862 got their Morrill Act shares. States could separate or consolidate their benefits as they saw fit, which resulted in many grants becoming attached to Morrill Act colleges.
Originally, the land was intended to be sold to raise capital for trust funds. By the late 19th century, however, stricter requirements on sales and a more conscientious pursuit of long-term gains reduced sales in favor of short-term leasing.
The change in management strategy paid off. Many state land trusts have been operating for more than a century. In that time, they have generated rents from agriculture, grazing, and recreation. As soon as they were able, managers moved into natural resource extraction, permitting oil wells, logging, mining, and fracking.
Land use decisions are typically made by state land agencies or lawmakers. Of the six land-grant institutions that responded to requests for comment on this investigation, those that referenced their trust lands deferred to state agencies, making clear that they had no control over permitted activities.
Credit: Grist
State agencies likewise receive and distribute the income. As money comes in, it is either delivered directly to beneficiaries or, more commonly, diverted to permanent state trust funds, which invest the proceeds and make scheduled payouts to support select public services and institutions.
These trusts have a fiduciary obligation to generate profit for institutions, not minimize environmental damage. Although some of the permitted activities are renewable and low-impact, others are quietly stripping the land. All of them fill public coffers with proceeds derived from ill-gotten resources.
For a $10 fee last December, anyone in New Mexico could chop down a Christmas tree in a pine stand on a patch of state trust land just off Highway 120 near Black Lake, southeast of Taos. The rules: Pay your fee, bring your permit, choose a tree, and leave nothing behind but a stump less than 6 inches high.
“The holidays are a time we should be enjoying our loved ones, not worrying about the cost of providing a memorable experience for our kids,” said Commissioner of Public Lands Stephanie Garcia Richard, adding that “the nominal fee it costs for a permit will directly benefit New Mexico public schools, so it supports a good cause too.” The offer has been popular enough to keep the program running for several years.
The New Mexico State Land Office, sometimes described by state legislators as “the most powerful office you’ve never heard of,” has been a successful operation for a very long time. Since it started reporting revenue in 1900, it’s generated well over $42 billion in 2023 dollars.
All that money isn’t from Christmas trees.
For generations, oil and gas royalties have fueled the state’s trust land revenue, with a portion of the funds designated for New Mexico State University, or NMSU, a land-grant school founded in 1888 when New Mexico was still a territory.
New Mexico State University, as seen in an aerial view, is a land-grant school founded in 1888. Eliseu Cavalcante / Grist
The oil comes from drilling in the northwestern fringe of the Permian Basin, one of the oldest targets of large-scale oil production in the United States. Corporate descendants of Standard Oil, the infamous monopoly controlled by John D. Rockefeller, were operating in the Permian as early as the 1920s. Despite being a consistent source of oil, prospects for exploitation dimmed by the late 20th century, before surging again in the 21st. Today, it’s more profitable than ever.
In recent decades, more sophisticated exploration techniques have revealed more “recoverable” fossil fuel in the Permian than previously believed. A 2018 report by the United States Geological Survey pegged the volume at 46.3 billion barrels of oil and 281 trillion cubic feet of natural gas, which made the Permian the largest oil and gas deposit in the nation. Analysts, shocked at the sheer volume, and the money to be made, have taken to crowningthe Permian the “King of Shale Oil.” Critics concerned with the climate impact of the expanding operations call it a “carbon bomb.”
As oil and gas extraction spiked, so did New Mexico’s trust land receipts. In the last 20 years, oil and gas has generated between 91 and 97 percent of annual trust land revenue. It broke annual all-time highs in half of those years, topping $1 billion for the first time in 2019 and reaching $2.75 billion last year. Adjusted for inflation, more than 20 percent of New Mexico’s trust land income since 1900 has arrived in just the last five years.
“Every dollar earned by the Land Office,” Commissioner Richard said when revenues broke the billion-dollar barrier, “is a dollar taxpayers do not have to pay to support public institutions.”
Credit: Grist
Trust land as a cost-free source of subsidies for citizens is a common framing. In 2023, Richard declared that her office had saved every New Mexico taxpayer $1,500 that year. The press release did not mention oil or gas, or Apache bands in the state.
Virtually all of the trust land in New Mexico, including 186,000 surface acres and 253,000 subsurface acres now benefiting NMSU, was seized from various Apache bands during the so-called Apache Wars. Often reduced to the iconic photograph of Geronimo on one knee, rifle in hand, hostilities began in 1849, and they remain the longest-running military conflict in U.S. history, continuing until 1924.
In 2019, newly elected New Mexico Governor Michelle Lujan Grisham began aligning state policy with “scientific consensus around climate change.” According to the state’s climate action website, New Mexico is working to tackle climate change by transitioning to clean electricity, reducing greenhouse gas emissions, supporting an economic transition from coal to clean energy, and shoring up natural resource resilience.
“New Mexico is serious about climate change — and we have to be. We are already seeing drier weather and rising temperatures,” the governor wrote on the state’s website. “This administration is committed not only to preventing global warming, but also preparing for its effects today and into the future.”
No mention was made of increasingly profitable oil and gas extraction on trust lands or their production in the Permian. In 2023, just one 240-acre parcel of land benefiting NMSU was leased for five years for $6 million.
NMSU did not respond to a request for comment on this story.
More than half of the acreage uncovered in our investigation appears in oil-rich West Texas, the equivalent of more than 3 million football fields. It benefits Texas A&M.
Take the long drive west along I-10 between San Antonio and El Paso, in the southwest region of the Permian Basin, and you’ll pass straight through several of those densely packed parcels without ever knowing it — they’re hidden in plain sight on the arid landscape. These tracts, and others not far from the highway, were Mescalero Apache territory. Kiowas and Comanches relinquished more parcels farther north.
A flare glows on a land-grant parcel in Pyote, Texas, associated with Texas A&M. Eliseu Cavalcante / Grist
In the years after the Civil War, a “peace commission” pressured Comanche and Kiowa leaders for an agreement that would secure land for tribes in northern Texas and Oklahoma. Within two years, federal agents dramatically reduced the size of the resulting reservation with another treaty, triggering a decade of conflict.
The consequences were disastrous. Kiowas and Comanches lost their land to Texas and their populations collapsed. Between the 1850s and 1890s, Kiowas lost more than 60 percent of their people to disease and war, while Comanches lost nearly 90 percent.
If this general pattern of colonization and genocide was a common one, the trajectory that resulted in Texas A&M’s enormous state land trust was not.
Texas was never part of the U.S. public domain. Its brief stint as an independent nation enabled it to enter the Union as a state, skipping territorial status completely. As a result, like the original 13 states, it claimed rights to sell or otherwise distribute all the not-yet-privatized land within its borders.
Following the broader national model, but ratcheting up the scale, Texas would allocate over 2 million acres to subsidize higher education.
Texas A&M was established to take advantage of a Morrill Act allocation of 180,000 acres, and opened its doors in 1876. The same year, Texas allocated a million acres of trust lands, followed by another million in 1883, nearly all of it on land relinquished in treaties from the mid-1860s.
Today, the Permanent University Fund derived from that land is worth nearly $34 billion. That’s thanks to oil, of course, which has been flowing from the university’s trust lands since 1923. In 2022 alone, Texas trust lands produced $2.2 billion in revenue.
The Kiowa and Comanche were ultimately paid about 2 cents per acre for their land. The Mescalero Apache received nothing.
Texas A&M did not respond to a request for comment on this story.
For more than a century, logging has been the main driver of Washington State University’s trust land income, on land taken from 21 Indigenous nations, especially the Confederated Tribes and Bands of the Yakama Nation. About 86,000 acres, more than half of the surface trust lands allocated to Washington State University, or WSU, are located inside Yakama land cessions, which started in 1855. Between 2018 and 2022, trust lands produced nearly $78.5 million in revenue almost entirely from timber.
But it isn’t a straight line to the university’s bank account.
“The university does not receive the proceeds from timber sales directly,” said Phil Weiler, a spokesperson for WSU. “Lands held in trust for the university are managed by the Washington State Department of Natural Resources, not WSU.”
In 2022, WSU’s trust lands produced about $19.5 million in revenue, which was deposited into a fund managed by the State Investment Board. In other words, the state takes on the management responsibility of turning timber into investments, while WSU reaps the rewards by drawing income from the resulting trust funds.
“The Washington legislature decides how much of the investment earnings will be paid out to Washington State University each biennium,” said Weiler. “By law, those payouts can only be used to fund capital projects and debt service.”
This arrangement yielded nearly $97 million dollars for WSU from its two main trust funds between 2018 and 2022, and has generally been on the rise since the Great Recession. In recent decades, the money has gone to construction and maintenance of the institution’s infrastructure, like its Biomedical and Health Sciences building, and the PACCAR Clean Technology Building — a research center focused on innovating wood products and sustainable design.
That revenue may look small in comparison to WSU’s $1.2 billion dollar endowment, but it has added up over time. From statehood in 1889 to 2022, timber sales on trust lands provided Washington State University with roughly $1 billion in revenue when Grist adjusted for inflation. But those figures are likely higher: Between 1971 and 1983, the State of Washington did not produce detailed records on trust land revenue as a cost-cutting measure.
Meanwhile, WSU students have demanded that the university divest from fossil fuel companies held in the endowment. But even if the board of regents agreed, any changes would likely not apply to the school’s state-controlled trust fund, which currently contains shares in ExxonMobil, Shell, Chevron, and at least two dozen other corporations in the oil and gas sector.
“Washington State University (WSU) is aware that our campuses are located on the homelands of Native peoples and that the institution receives financial benefit from trust lands,” said Weiler.
In states with trust lands, a reasonably comfortable buffer exists between beneficiaries, legislators, land managers, and investment boards, but that hasn’t always been the case. In Minnesota’s early days, state leaders founded the University of Minnesota while also making policy that would benefit the school, binding the state’s history of genocide with the institution.
Those actions still impact Indigenous peoples in the state today while providing steady revenue streams to the University.
Henry Sibley began to amass his fortune around 1834 after only a few years in the fur trade in the territory of what would become Minnesota, rising to the role of regional manager of the American Fur Company at just 23. But even then, the industry was on the decline — wild game had been over-hunted and competition was fierce. Sibley responded by diversifying his activities. He moved into timber, making exclusive agreements with the Ojibwe to log along the Snake and Upper St. Croix rivers.
His years in “wild Indian country” were paying off: Sibley knew the land, waterways, and resources of the Great Lakes region, and he knew the people, even marrying Tahshinaohindaway, also known as Red Blanket Woman, in 1840 — a Mdewakanton Dakota woman from Black Dog Village in what is now southern Minneapolis.
Sibley was a major figure in a number of treaty negotiations, aiding the U.S. in its western expansion, opening what is now Minnesota to settlement by removing tribes. In 1848, he became the first congressional delegate for the Wisconsin Territory, which covered much of present-day Minnesota, and eventually, Minnesota’s first governor.
But he was also a founding regent of the University of Minnesota — using his personal, political, and industry knowledge of the region to choose federal, state, and private lands for the university. Sibley and other regents used the institution as a shel corporation to speculate and move money between companies they held shares in.
n 1851, Sibley helped introduce land-grant legislation for the purpose of a territorial university, and just three days after Congress passed the bill, Minnesota’s territorial leaders established the University of Minnesota. With an eye on statehood, leaders knew more land would be granted for higher education, but first the land had to be made available.
That same year, with the help of then-territorial governor and fellow university regent Alexander Ramsey, the Dakota signed the Treaty of Traverse De Sioux, a land cession that created almost half of the state of Minnesota, and, taken with other cessions, would later net the University nearly 187,000 acres of land — an area roughly the size of Tucson.
Among the many clauses in the treaty was payment: $1.4 million would be given to the Dakota, but only after expenses. Ramsey deducted $35,000 for a handling fee, about $1.4 million in today’s dollars. After agencies and politicians had taken their cuts, the Dakota were promised only $350,000, but ultimately, only a few thousand arrived after federal agents delayed and withheld payments or substituted them for supplies that were never delivered.
The betrayal led to the Dakota War of 1862. “The Sioux Indians of Minnesota must be exterminated or driven forever beyond the borders of the state,” said Governor Ramsey. Sibley joined in the slaughter, leading an army of volunteers dedicated to the genocide of the Dakota people. At the end of the conflict, Ramsey ordered the mass execution of more than 300 Dakota men in December of 1862 — a number later reduced by then-president Abraham Lincoln to 39, and still the largest mass execution in U.S. history.
That grisly punctuation mark at the end of the war meant a windfall for the University of Minnesota, with new lands being opened through the state’s enabling act and another federal grant that had just been passed: the Morrill Act. Within weeks of the mass execution, the university was reaping benefits thanks to the political, and military, power of Sibley and the board of regents.
Between 2018 and 2022, those lands produced more than $17 million in revenue, primarily through leases for the mining of iron and taconite, a low-grade iron ore used by the steel industry. But like other states that rely on investment funds and trusts to generate additional income, those royalties are only the first step in the institution’s financial investments.
Today, Sibley, Ramsey, and other regents are still honored. Their names adorn parks, counties, and streets, their homes memorialized for future generations. While there have been efforts to remove their names from schools and parks, Minnesota, its institutions, and many of its citizens continue to benefit from their actions.
Less than half of the universities featured in this story responded to requests for comment, and the National Association of State Trust Lands, the nonprofit consortium that represents trust land agencies and administrators, declined to comment. Those that did, however, highlighted the steps they were making to engage with Indigenous students and communities.
Still, investments in Indigenous communities are slow coming. Of the universities that responded to our requests, those that directly referenced how trust lands were used maintained they had no control over how they profited from the land.
And they’re correct, to some degree: States managing assets for land-grants have fiduciary, and legal, obligations to act in the institution’s best interests.
But that could give land-grant universities a right to ask why maximizing returns doesn’t factor in the value of righting past wrongs or the costs of climate change.
“We can know very well that these things are happening and that we’re part of the problem, but our desire for continuity and certainty and security override that knowledge,” said Sharon Stein of the University of British Columbia.
That knowledge, Stein added, is easily eclipsed by investments in colonialism that obscure university complicity and dismiss that change is possible.
Though it’s a complicated and arduous process changing laws and working with state agencies, universities regularly do it. In 2022, the 14 land-grant universities profiled in this story spent a combined $4.6 million on lobbying on issues ranging from agriculture to defense. All lobbied to influence the federal budget and appropriations.
But even if those high-level actions are taken, it’s not clear how it will make a difference to people like Alina Sierra in Tucson, who faces a rocky financial future after her departure from the University of Arizona.
In 2022, a national study on college affordability found that nearly 40 percent of Native students accrued more than $10,000 in college debt, with some accumulating more than $100,000 in loans. Sierra is still in debt to UArizona for more than $6,000.
“I think that being on O’odham land, they should give back, because it’s stolen land,” said Sierra. “They should put more into helping us.”
In January, Sierra enrolled as a full-time student at Tohono O’odham Community College in Sells, Arizona — a tribal university on her homelands. The full cost of attendance, from tuition to fees to books, is free.
The college receives no benefits from state trust lands.
CREDITS
This story was reported and written by Tristan Ahtone, Robert Lee, Amanda Tachine, An Garagiola, and Audrianna Goodwin. Data reporting was done by Maria Parazo Rose and Clayton Aldern, with additional data analysis and visualization by Marcelle Bonterre and Parker Ziegler. Margaret Pearce provided guidance and oversight.
Original photography for this project was done by Eliseu Cavalcante and Bean Yazzie. Parker Ziegler handled design and development. Teresa Chin supervised art direction. Marty Two Bulls Jr. and Mia Torres provided illustration. Megan Merrigan, Justin Ray, and Mignon Khargie handled promotion. Rachel Glickhouse coordinated partnerships.
This project was edited by Katherine Lanpher and Katherine Bagley. Jaime Buerger managed production. Angely Mercado did fact-checking, and Annie Fu fact-checked the project’s data.
Special thanks to Teresa Miguel-Stearns, Jon Parmenter, Susan Shain, and Tushar Khurana for their additional research contributions. We would also like to thank the many state officials who helped to ensure we acquired the most recent and accurate information for this story. This story was made possible in part by the Pulitzer Center, the Data-Driven Reporting Project, and the Bay & Paul Foundation.
The Misplaced Trust team acknowledges the Tohono O’odham, Pascua Yaqui, dxʷdəwʔabš, Suquamish, Muckleshoot, puyaləpabš, Tulalip, Muwekma Ohlone, Lisjan, Tongva, Kizh, Dakota, Bodwéwadmi, Quinnipiac, Monongahela, Shawnee, Lenape, Erie, Osage, Akimel O’odham, Piipaash, Očhéthi Šakówiŋ, Diné, Kanienʼkehá:ka, Muh-he-con-ne-ok, Pαnawάhpskewi, and Mvskoke peoples, on whose homelands this story was created.
The amount of acreage under management for land-grant universities varies widely, from as little as 15,000 acres aboveground in North Dakota to more than 2.1 million belowground in Texas. Combined, Indigenous nations were paid approximately $4.7 million in today’s dollars for these lands, but in many cases, nothing was paid at all. In 2022 alone, these trust lands generated more than $2.2 billion for their schools. Between 2018 and 2022, the lands produced almost $6.7 billion. However, those figures are likely an undercount as multiple state agencies did not return requests to confirm amounts.
Representatives from the U.S. Environmental Protection Agency met with Cove community members last week to discuss the agency’s decision to place the Lukachukai Mountains Mining District on the National Priorities List. Although the meeting was intended to be informational, tribal, Navajo EPA and community leaders expressed their uncertainty about whether the federal government will actually start addressing the cleanup of the abandoned uranium mines that landed the site on the EPA list, also known as the Superfund program. The mining district encompasses Navajo Nation communities of Cove, Round Rock and Lukachukai in the far northeastern corner of Arizona.
“We are looking at what happened in the past and how the federal government could have prevented a lot of this contamination,” said Council Delegate Amber Kanazbah Crotty, “could’ve prevented our community from getting sick. What I don’t want them (children) to have to deal with is another three or four decades before actual action happens.”
[…]
Phil Harrison remembers when his childhood community of Cove was alive with family gatherings, ceremonies, rodeos, farming and ranching, but after decades of uranium contamination, those days are a thing of the past…Harrison’s father was a miner in the uranium mines of Cove, which was where uranium was first discovered on the Navajo Nation. Uranium production in the northern and western Carrizo Mountains of the Navajo Nation began in 1948, peaked in 1955 and 1956 and declined to zero again by 1967.
For 84 sinuous miles, the Green River of eastern Utah carves its way through one of the largest roadless areas in the lower 48 states, forming the remote and rugged country of Desolation and Gray canyons as it cuts through the Tavaputs Plateau. Desolation Canyon was so named when, in 1869, John Wesley Powell first chronicled the river’s nearly 60 side canyons, describing the journey as one through “a region of wildest desolation.”
Green River Basin
DESOLATION CANYON
Remote and spectacular, Desolation Canyon has been home to Fremont People, their stories left behind in the pictographs, petroglyphs, and ancient dwellings, towers and granaries that still decorate the canyon’s walls. Since time immemorial, the Desolation Canyon region has also been home to the Ute Indian Tribe, whose Uintah and Ouray Reservation borders the east side of the river from above Sand Wash to Coal Creek Canyon, or 70 miles of Desolation/Gray Canyons.
Now, boaters of all persuasions relish multi-day river trips through relatively easy riffles and rapids, where sandy beaches with massive Fremont cottonwoods provide shade and cover from wind. The piñon, juniper and douglas fir-covered slopes of the canyon harbor wintering deer and elk, nesting waterfowl, bison, mountain lions, migrating birds and the occasional sun-bleached blackbear. Of the 84 river miles, 66 miles are within the Desolation Canyon Wilderness Study Area, the largest WSA in the lower 48 states. Looking up from the river, the edge of the canyon is nearly 5,000 feet overhead , and anywhere from 2-150 million years old. Of the canyon’s unique and exposed geologic history, celebrated southwest writer Ellen Meloy wrote: “You launch in mammals and end up in sharks and oysters.”
Map of oil shale and tar sands in Colorado, Utah and Wyoming — via the BLM
THREATS
While it’s true that Desolation Canyon remains one of the most remote places in the contiguous United States, the threats it faces are not so remote. And ironically, the canyon’s deep and layered history and geology in some ways, threaten the river most. The Green River Formation, formed between 33-56 million years ago, is a much sought after petroleum resource. A recent report by the USGS posited that the formation could hold as much as 1.3 trillion barrels of oil. In order to convert tar sands and oil shale into usable oil (1.55 million barrels/day), producers would require about 378,000 acre feet of water per/year, likely from the Green. While the inner gorge of Desolation Canyon is a designated wilderness study area, on the state, tribal, and federal lands surrounding it, oil rigs march right to the canyon’s edge.
Wyoming Department of Environmental Quality acknowledges years of built-up pollution from Moneta Divide field but has no plan to remove black sludge 6 feet deep
Two creeks tainted by decades of dumping from Moneta Divide oilfield drillers are officially “impaired” and unable to sustain aquatic life, state regulators say in a new report.
Parts of Alkali and Badwater creeks in Fremont County are polluted to the point they don’t meet standards for drinking, consumption of resident fish or sustaining aquatic life, a report by the Wyoming Department of Environmental Quality states. The agency listed 40.8 miles of the creeks as impaired in a biannual report required by the U.S. Environmental Protection Agency.
The project is being developed by Aethon Energy Management and Burlington Resources Oil and Gas Company. Aethon Energy Management and its partner RedBird Capital Partners acquired the Moneta Divide assets from Encana Oil and Gas in May 2015. The environment impact assessment (EIA) process of the Moneta Divide field was commenced in 2011, while the final environmental impact statement (EIS) and resource management plan (RMP) for the project were released in February 2020. Photo credit: NS Energy
Parts of the creeks are polluted by oilfield discharges, including hydrogen sulfide, ammonia and chloride. The industrial activity is responsible for low levels of oxygen in the water, turbidity and a black sludge that critics say is up to 6 feet deep.
Arsenic also is present, but state monitoring couldn’t determine its origin.
The report catalogs pollution downstream of discharge points where produced water — effluent from natural gas and oil production — flows from the 327,645-acre energy field operated mainly by Aethon Energy Operating in Fremont and Natrona counties.
The “impaired” listings are a good thing that set the table for action, said Jill Morrison, who works on the pollution issue for the conservation group Powder River Basin Resource Council. But the listing comes only after years of badgering an agency that now should look to clean up the creeks.
“What we are saying is ‘thank you’ for stepping up to address these issues,” Morrison said. “We wish it was done sooner. You’ve got enforcement power; what steps are you taking to make Aethon clean this up?”
Wyoming rivers map via Geology.com
Environmental stewards
The DEQ issued a revised permit to the private Dallas company in 2020 allowing it to discharge oilfield waste into Alkali Creek, which flows into Badwater Creek and the Boysen Reservoir, a source of drinking water for the town of Thermopolis. The permit calls for monitoring and testing, among other things.
About a year ago, however, the DEQ sent the company a letter of violation for “reoccurring exceedances” of water quality standards for sulfide, barium, radium and temperature. That’s a violation of the Wyoming Environmental Quality Act, state rules and regulations, and the permit itself.
The April 28 letter states that the DEQ hopes to resolve the violation through “conference and conciliation.” DEQ wants Aethon “to show good faith efforts toward resolving the problem and to prevent the need for more formal enforcement action by this office.”
The alleged kid-glove treatment rankles Powder River’s Morrison. “They trade, back and forth, nice conversations and nothing happens,” she said.
An Aethon pump jack in the Moneta Divide oil and gas field east of Shoshoni. (Angus M. Thuermer Jr./WyoFile)
DEQ asked Aethon for a response within 30 days. WyoFile requested on March 6 that the agency provide a copy of Aethon’s response but had not received it by publication time. Aethon typically does not respond to media questions regarding regulatory enforcement and did not answer a recent request for comment.
The 2020 permit also requires Aethon to dramatically reduce the amount of chloride — salty water — it pumps onto the landscape. DEQ said the company is preparing to meet a late-summer deadline for that standard.
“Aethon continues to diligently work toward resuming treatment of effluent using the Neptune reverse osmosis treatment plant,” DEQ said in an email, “in accordance with the established chloride compliance schedule.”
Aethon’s website says the company has a “commitment to protect the environment and our people [and] operate responsibly.” The company is a “steward of the environment,” the website states.
Black sludge
The DEQ’s “impaired” listing addresses surface water in the two creeks through what’s known as a draft Integrated 305 (b) report. It is open for comments through March 25.
But there’s another issue that rankles critics, including the Wyoming Outdoor Council and the Powder River group — black sludge.
DEQ surveys of the creeks revealed “bottom deposits” containing mineral deposits, iron sulfides and dissolved solids, all contributing to low oxygen levels that kill aquatic life. After a phone conference with DEQ in February, Powder River’s Morrison said she learned that the bottom deposit of black sludge extends for about three miles and is from 6 inches to 6 feet deep.
A retired University of Wyoming professor who worked with the Powder River group analyzing Aethon’s permit called the sediments “totally loaded.” Harold Bergman said “that contaminated sediment will be leaching out contaminants into Boysen Reservoir for decades to come.”
He and Joe Meyer, a retired chemist who also worked with the conservation group, wrote that DEQ’s Aethon permit did not require enough testing for deleterious substances, did not consider what impact the mix of substances together has on aquatic life, and allowed as much as five times the proper amount of dissolved solids to flow out of the oilfield.
“You would not have that black gunk sediment if it weren’t for the Aethon discharge,” Meyer said.
A report of monitoring between 2019-’22 shows that aluminum exceeded discharge standards up to 17% of the time. Other than that, there’s still a question of what else is in the sludge.
This image of Alkali Creek shows flows downstream of the Frenchie Draw oil and gas field discharge point in October 2021, according to the image title. The Powder River Basin Resource Council obtained this and other public records through a request to Wyoming DEQ. (DEQ)
“We don’t know about individual organic chemicals,” Meyer said. Reports only mention “the gross measures of organic compounds,” he said.
“That doesn’t tell us about individual chemicals,” Meyer said. How much, if any, BTEX chemicals — Benzene, Toluene, Ethylbenzene and Xylenes that are harmful to humans — are in the sludge “we have no way of knowing.”
He stopped short of accusing DEQ of avoiding the question. For now, “they just wanted to get an overview analysis,” he said.
DEQ said it has a plan for the sludge. “DEQ’s Water Quality Division is monitoring any sediment flow in lower Badwater Creek to determine if there are any sediments that may mobilize towards Boysen Lake,” an agency official said in an email.
For Morrison, “the big question is what DEQ is going to require Aethon to do to clean up this mess,” she wrote in an email. Meyer and Bergman say simply dredging up the sludge is likely too dangerous because such an operation would dislodge substances and send them downstream. A more complex plan would be needed, they said.
Morrison criticized what she sees as the DEQ’s priorities. “They’re not putting the health and safety of these streams’ water quality, fish and downstream water users above the interests and profits of Aethon.”
The shiny new cold-weather air source heat pump installed during summer 2023 at Coyote Gulch Manor.
Click the link to read the article on the Grist website (Alison F. Takemura):
Installing a heat pump now is better for the climate, even if it’s run on U.S. electricity generated mostly by fossil fuels. Here’s why.
March 17, 2024
This story was originally published by Canary Media.
You might consider heat pumps to be a tantalizing climate solution (they are) and one you could adopt yourself (plenty have). But perhaps you’ve held off on getting one, wondering how much of a difference they really make if a dirty grid is supplying the electricity you’re using to power them — that is, a grid whose electricity is generated at least in part by fossil gas, coal, or oil.
That’s certainly the case for most U.S. households: While the grid mix is improving, it’s still far from clean. In 2023, renewable energy sources provided just 21 percent of U.S. electricity generation, with carbon-free nuclear energy coming in at 19 percent. The other 60 percent of power came from burning fossil fuels.
So do electric heat pumps really lower emissions if they run on dirty grid power?
The answer is an emphatic yes. Even on a carbon-heavy diet, heat pumps eliminate tons of emissions annually compared to other heating systems.
The latest study to hammer this point home was published in Joule last month by the National Renewable Energy Laboratory. The team modeled the entire U.S. housing stock and found that, over the appliance’s expected lifetime of 16 years, switching to a heat-pump heater/AC slashes emissions in every one of the contiguous 48 states.
In fact, heat pumps reduce carbon pollution even if the process of cleaning up the U.S. grid moves slower than experts expect. The NREL team used six different future scenarios for the grid, from aggressive decarbonization (95 percent carbon-free electricity by 2035) to sluggish (only 50 percent carbon-free electricity by 2035, in the event that renewables wind up costing more than their current trajectories forecast). They found that depending on the scenario and level of efficiency, heat pumps lower household annual energy emissions on average by 36 percent to 64 percent — or 2.5 to 4.4 metric tons of CO2 equivalent per year per housing unit.
That’s a staggering amount of emissions. For context, preventing 2.5 metric tons of CO2 emissions is equivalent to not burning 2,800 pounds of coal. Or not driving for half a year. Or switching to a vegan diet for 14 months. And at the high end of the study’s range, 4.4 metric tons of CO2 is almost equivalent to the emissions from a roundtrip flight from New York City to Tokyo (4.6 metric tons).
Eric Wilson, senior research engineer at NREL and lead author of the study, told me, “I often hear people saying, ‘Oh, you should wait to put in a heat pump because the grid is still dirty.’” But that’s faulty logic. “It’s better to switch now rather than later — and not lock in another 20 years of a gas furnace or boiler.”
Emissions savings tend to be higher in states with colder winters and heaters that run on fuel oil, such as Maine, according to the study. (Maine seems to be one step ahead of the researchers: Heat pumps have proven so popular there that the state already blew past its heat-pump adoption goal two years ahead of schedule.)
A dirty grid, then, doesn’t cancel out a heat pump’s climate benefits. But heat pumps can generate emissions in the same way standard ACs do: by leaking refrigerant, the chemicals that enable these appliances to move around heat. Though it’s being phased down, the HVAC standard refrigerant R-410A is 2,088 times more potent a greenhouse gas than CO2, so even small leaks have an outsize impact.
Added emissions from heat-pump refrigerant leaks barely make a dent, however, given the emissions heat pumps avoid, the NREL team found. Typical leakage rates of R-410A increase emissions on average by only 0.07 metric tons of CO2 equivalent per year, shaving the overall savings of 2.5 metric tons by just 3 percent, Wilson said.
A 2023 analysis from climate think tank RMI further backs up heat pumps’ climate bona fides. Across the 48 continental states, RMI found that replacing a gas furnace with an efficient heat pump saves emissions not only cumulatively across the appliance’s lifetime, but also in the very first year it’s installed. RMI estimated that emissions prevented in that first year were 13 percent to 72 percent relative to gas-furnace emissions, depending on the state. (Canary Media is an independent affiliate of RMI.)
Both the RMI and NREL studies focused on air-source heat pumps, which, in cold weather, pull heat from the outdoor air and can be three to four times as efficient as gas furnaces. But ground-source heat pumps can be more than five times as efficient compared to gas furnaces — and thus unlock even greater greenhouse-gas reductions, according to RMI.
How much could switching to a heat pump lower your home’s carbon emissions? For a high-level estimate, NREL put out an interactive dashboard. In the “states” tab, you can filter down to your state, building type and heating fuel. For instance, based on a scenario of moderate grid decarbonization in my state of Colorado, a single-family home that swaps out a gas furnace for a heat pump could slash emissions by a whopping 6 metric tons of CO2.
One final takeaway Wilson shared: If every American home with gas, oil, or inefficient electric-resistance heating were to swap it right now for heat-pump heating, the emissions of the entire U.S. economy would shrink by 5 percent to 9 percent. That’s how powerful a decarbonizing tool heat pumps are.
Natural gas flares near a community in Colorado. Colorado health officials and some legislators agree that better monitoring is necessary. Photo credit the Environmental Defense Fund.
Click the link to access the article on the Nature website (Evan D. Sherwin, Jeffrey S. Rutherford, Zhan Zhang, Yuanlei Chen, Erin B. Wetherley, Petr V. Yakovlev, Elena S. F. Berman, Brian B. Jones, Daniel H. Cusworth, Andrew K. Thorpe, Alana K. Ayasse, Riley M. Duren, & Adam R. Brandt). Here’s an excerpt:
As airborne methane surveys of oil and gas systems continue to discover large emissions that are missing from official estimates, the true scope of methane emissions from energy production has yet to be quantified. We integrate approximately one million aerial site measurements into regional emissions inventories for six regions in the USA, comprising 52% of onshore oil and 29% of gas production over 15 aerial campaigns. We construct complete emissions distributions for each, employing empirically grounded simulations to estimate small emissions. Total estimated emissions range from 0.75% (95% confidence interval (CI) 0.65%, 0.84%) of covered natural gas production in a high-productivity, gas-rich region to 9.63% (95% CI 9.04%, 10.39%) in a rapidly expanding, oil-focused region. The six-region weighted average is 2.95% (95 % CI 2.79%, 3.14%), or roughly three times the national government inventory estimate. Only 0.05–1.66% of well sites contribute the majority (50–79%) of well site emissions in 11 out of 15 surveys. Ancillary midstream facilities, including pipelines, contribute 18–57% of estimated regional emissions, similarly concentrated in a small number of point sources. Together, the emissions quantified here represent an annual loss of roughly US$1 billion in commercial gas value and a US$9.3 billion annual social cost. Repeated, comprehensive, regional remote-sensing surveys offer a path to detect these low-frequency, high-consequence emissions for rapid mitigation, incorporation into official emissions inventories and a clear-eyed assessment of the most effective emission-finding technologies for a given region.
The Rifle City Council listened to a funding request from a Colorado River District representative during their Wednesday regular session.
“We are asking that the City of Rifle consider a funding request for $100,000,” Amy Moyer said, Director of Strategic Partnerships for the Colorado River District…
The City Council authorized staff to sign a letter committing $100,000 to the purchase of the Shoshone Water Rights. This would be in the budget for 2025.
“I just want everyone to realize how historic this Shoshone Water Rights Purchase is and how it can totally save the western slope in case something ever happened to Xcel or that power plant. So I’m glad they came in and I’m glad we’re partnering with them,” Councilor Clint Hostettler said in their closing comments for the meeting.
After years of dealing with contaminated groundwater and an unreliable water supply, officials in Fort Lupton say a single solar project could solve both issues for the foreseeable future.
The city has an aging diesel-powered generator that has a habit of going offline at times of high demand and power outages. Officials have also been working to reduce algae blooms in their 300-acre-foot reservoir that the water treatment plant turns into drinking water.
To address both these issues, the city partnered with Brighton-based power provider United Power and contractor Schneider Electric to replace the old generator with an 850-kilowatt solar array and a 1,147-kilowatt battery storage system that floats in the city’s water treatment plant.
The project could receive up to $6.1 million in federal funds from the U.S. Department of Energy as part of its $1 billion Energy Improvements in Rural or Remote Areas Program, which was created under the Bipartisan Infrastructure Law in 2021. However, the funding is not yet guaranteed, according to U.S. Rep. Yadira Caraveo (D-CO), who represents Fort Lupton and is pushing the project.
Fort Lupton City Administrator Chris Cross said he expects the project to increase power redundancy for the city, meaning it will have more than one power source to draw from. Cross also expects Fort Lupton residents to see roughly 9% savings on their average power bill.
Residents of Fort Lupton pay an average of $0.12 per kilowatt hour for residential power, which is about 5% greater than the statewide average, according to data from Electricity Local.
“Coupled with the floating panel benefits to the water storage, we are excited to see how high our overall savings will be from the project,” Cross said.
Fort Lupton, like many rural communities in Colorado, has faced challenges providing clean drinking water for decades. Data from the Colorado Department of Public Health and Environment shows the city has recorded 268 water quality incidents since 1995. That total is comparable to much larger cities that are fed by waters from Carter Lake like Superior, Louisville, and Broomfield even though Fort Lupton has the smallest population at just 8,500 residents.
One of the most memorable water quality incidents in Fort Lupton happened in March 2009 when residents reported that their tap water had become flammable. An investigation found that nearby natural gas wells were leaking into the city’s groundwater supply, the Greeley Tribune reported.
In November 2023, a water main break at the intersection of 9th St. and Lancaster Ave. in Fort Lupton caused a high concentration of chlorine to enter the water supply for the nearby neighborhoods. Officials with CDPHE’s water quality division told Fort Lupton staff that “there will be water quality complaints” resulting from the break and that residents should flush their ice makers and sinks, although “a mandatory advisory would not be necessary at this time,” according to emails contained in a November 2023 CDPHE water quality incident report.
The city’s most recent water quality report also shows that the city’s water treatment plant reported one health-based violation in 2023 for having an inadequate backflow prevention and cross-connection control program. This program, “Uncontrolled cross connections can lead to inadvertent contamination of the drinking water,” the report says. Fort Lupton has hired a contracting firm called Aqua Backflow to help improve its backflow issues, according to the city’s website.
Schneider Electric North America Microgrid President Jana Gerber said these are just a few of the issues that the project team wanted to address when they pitched the microgrid idea to Fort Lupton officials. Gerber added that the project could serve as a model for other microgrid partnerships in rural communities.
As part of the agreement, Schneider Electric is responsible for designing and building the microgrid. United Power would then become the owner and operator of the grid while Fort Lupton pays for maintenance. United Power also plans to partner with Aims Community College and the BUENO Center for Multicultural Education to provide contracting outreach, according to United Power CEO Mark Gabriel.
John Tracy, director of the Colorado Water Center at Colorado State University in Fort Collins, said the issues with Fort Lupton’s drinking water system are indicative of the city’s age. Fort Lupton was incorporated in 1889, and Tracy said the city’s existing water system likely dates back to the 1970s when the Clean Water Act provided billions in federal subsidies for water improvement projects.
But maintaining that infrastructure is a delicate dance that is difficult for rural communities to perform, Tracy added. Many rural towns like Fort Lupton collect enough water fees to operate their system, not improve it, Tracy said. Fort Lupton’s 2024 budget projects a 10.7% decrease in water sales tax collections and a more than 5% increase in expenditures from its water sales tax fund. The city also plans to spend more than $18 million on capital improvements for its water system over the next six years.
With all of the planned expenditures, Fort Lupton needs to find a place to cut its operating costs. That’s where the floating solar array comes in. Tracy said Other cities like San Antonio, Texas have come to the same conclusion that green technology can reduce their operating costs by reducing their dependence on fossil fuels, which are more expensive to acquire than electricity.
“Fossil fuel energy prices have been too variable and it’s difficult to blend that into a municipal budget and project what those costs are going to be two years from now,” Tracy said. “If you’re doing something like either wind or solar, you have much more predictability in the cost.”
The Shoshone hydro plant in Glenwood Canyon, captured here in June 2018, uses water diverted from the Colorado River to make power, and it controls a key water right on the Western Slope and that right is in the process of being acquired by the Colorado River Water Conservation District. Photo credit: Brent Gardner-Smith/Aspen Journalism
In their board meetings this month, the Clifton Water District and Grand Valley Water Users Association kicked in $250,000 and $100,000, respectively, toward the Colorado River District’s proposed purchase of the rights. The Orchard Mesa Irrigation District and Grand Valley Irrigation Co. have also informally agreed to financially support the effort and are awaiting final action in upcoming board meetings, according to a new release from the river district…
Clifton Water serves nearly 13,000 domestic taps. On the Western Slope De Beque, Silt, Parachute, Battlement Mesa and Rifle also rely on the river as their primary supply of drinking water. Grand Valley Water Users Association delivers irrigation water to more than 22,000 acres within its boundaries and more than 42,000 acres in the Grand Valley…
The river district also hopes to secure about half of the money for the purchase from the U.S. Bureau of Reclamation in the form of Inflation Reduction Act funds. Sealing the deal also is contingent on negotiating an instream flow agreement between the Xcel, the river district and the Colorado Water Conservation Board, and Xcel receiving approval from the state Public Utilities Commission for the dispersal of profits from the sale.
Oak Flat, Arizona features groves of Emory oak trees, canyons, and springs. This is sacred land for the San Carlos Apache tribe. Resolution Copper (Rio Tinto subsidiary) lobbied politicians to deliver this National Forest land to the company with the intent to build a destructive copper mine. By SinaguaWiki – Own work, CC BY-SA 4.0, https://commons.wikimedia.org/w/index.php?curid=98967960
“This is our land,” said [Verlon] Jose, whose tribe [Tohono O’odham Nation] includesroughly 38,000 members across southern Arizona and northern Mexico. “It should all be protected.”
[…]
Jose is one of several tribal leaders nationwide who are growing frustrated with the Biden administration and its ambitious plans for clean-energy projects that could affect their ancestral lands. While the White House has worked to repair the federal government’s relationships with Indigenous peoples, that effort is conflicting with another Biden priority: expediting projects essential for the energy transition…The SunZia transmission line is one of those projects. Once complete, the power line would carry clean electricity from massive wind farms in New Mexico to more-populated areas as far away as California. The Biden administration has championed SunZia as a key pillar of its plans for fighting climate change and boosting green energy, and has defended its engagement with area tribes…
“We do not disagree with renewable energy,” Jose said. “We are for renewable energy. You know what the fix to this issue is? They could have rerouted it. But they didn’t listen.”
[…]
About 70 miles east of Phoenix, one of the tribes fighting SunZia — the San Carlos Apache — is also working to stop a proposed copper mine on land that it considers sacred. In Nevada, some tribal activists are opposing one of the world’s largest mines for lithium, a mineral crucial to the development of batteries for electric vehicles.And in Oklahoma, a federal judge recently took the rare step of ordering the removal of a wind farm on Osage Nation land.
On the coast, the Yurok Tribe’s ancestral territory stretches from the Little River in Humboldt County to Damnation Creek in Del Norte County. The tribe’s territory extends for 44 miles up the Klamath River to its confluence with the Trinity River. The Klamath and Trinity rivers are the lifeline of Yurok people, as the rivers provide the majority of the food supply including ney-puy (salmon), Kaa-ka (sturgeon), and kwor-ror (candlefish). Today, the tribe is the largest in California with more than 6,400 enrolled members. The Yurok Tribe was a signatory to the Amended Klamath Hydroelectric Settlement Agreement, which ultimately led to dam removal. The Yurok Tribe has played a pivotal role in every single aspect of Klamath River Dam Removal and restoration efforts.
The Yurok Fisheries Department and Yurok Tribe Construction Corporation are all at the forefront of these projects. The Yurok Fisheries Department collected a substantial volume of the approximately 20 billion native seeds that will be used to restore the 2,000-acre reservoir reach in between the four dams. Yurok Fisheries crews, RES and many project partners are now hand-sowing the seeds throughout the empty reservoirs. The Yurok Tribe is working on large-scale river restoration projects in other parts of California too. Informed by Traditional Ecological Knowledge and western science, the Yurok Fisheries Department and Yurok Tribe Construction Corporation transform severely degraded aquatic ecosystems into highly productive habitat for salmon as well as many other native fish and wildlife species. The Yurok Tribe has completed numerous projects on the Klamath and Sacramento Rivers and many smaller streams.
The Karuk Tribe lives in its ancestral homelands along the middle part of the Klamath River, between Weitchpec and Seiad, California. The Karuk Tribe was a signatory to the Klamath Hydroelectric Settlement Agreement, which ultimately led to dam removal.
As Karuk Tribal Chairman Russell “Buster” Attebery stated in a video shared by KRRC, “Having the dams come out and having the almost 400 miles of salmon spawning grounds, and better water quality, is going to be imperative to life along the Klamath River. I was born and raised along the Klamath River and the fish, the river, and the clean water provides a perfect way of life. We are looking forward to the opportunity to have clean water again, and spawning grounds so our children can again experience the opportunities to fish and provide a food source for their families. It will be a great benefit to everyone who lives along the Klamath River.
The Klamath Justice Coalition was founded by grassroots Indigenous leaders more than two decades ago. They created what is now known as the “Un-dam the Klamath Campaign”. The refrain “Undam the Klamath, bring the salmon home” was heard from fishing boats on the river all the way to Berkshire Hathaway’s shareholder meeting in Omaha, Nebraska. As one of the co-founders Molli Myers (Karuk) states, “this was a movement of the people”.
Berkshire Hathaway is the parent company of PacifiCorp, which owned and operated the four Klamath River dams. In 2020, Berkshire Hathaway played a pivotal role in securing the final dam removal accord: the company agreed to transfer operating licenses of the dams to the states of Oregon and California, and the Klamath River Renewal Corporation. Berkshire also agreed to share the burden of any cost overruns.
Ridges to Riffles is advancing Indigenous-led restoration efforts on the Klamath and other rivers. R2R works in partnership with Indigenous Peoples to advance their cultural and natural resource interests through legal and policy advocacy. In partnership with the Yurok Tribe, R2R is working on Klamath dam removal, habitat restoration, instream flows, and personhood rights for the Klamath River.
The Klamath River Renewal Corporation (KRRC) is a nonprofit organization formed by signatories of the amended Klamath Hydroelectric Settlement Agreement, to take ownership and oversee removal of the four hydroelectric dams on the river. Managing the biggest dam removal and river restoration project in history is no small feat. KRRC’s team has prioritized safety, community engagement, and helping the people of the basin take steps toward a shared, sustainable future.
Klamath River Basin. Map credit: American Rivers
States of Oregon and California
Bipartisan support was key to success on the Klamath: elected leaders from both parties saw the value of a restored Klamath River, with California Governor Schwarzenegger and Oregon Governor Kulongoski signing the original agreement to remove the dams in 2010. A decade later, California Governor Newsom and Oregon Governor Brown took a vital step, joining the Klamath River Renewal Corporation as a co-licensee, allowing PacifiCorp to relinquish the operating license for the dams. California Proposition 1 water bond funds combined with PacifiCorp ratepayer funds to make the project possible. Never before has a state contributed this much funding to a dam removal project.
With a unanimous decision during a regular board meeting on February 14th, Ute Water’s Board of Directors pledged a financial contribution of two million dollars to the Colorado River District in securing the Shoshone water rights. The largest domestic water provider between Denver, Colorado, and Salt Lake City, Utah, is committing funding for the historic and monumental acquisition of the state’s largest and most senior non-consumptive water right on the Colorado River. This landmark purchase aims to finalize the Shoshone permanence efforts that Ute Water has been committed to for over 20 years.
Summary: View of a packtrain used for President Theodore Roosevelt’s hunting party in Glenwood Canyon (Garfield County), Colorado. The Colorado River is nearby.. Date: 1905. Buckwalter, Harry H.. Photo credit: Denver Public Library Digital Collections
What are the Shoshone water rights?
The senior Shoshone water right was established in 1902, before the Shoshone Hydroelectric Facility was constructed in the Glenwood Canyon east of Glenwood Springs, Colorado. The rights have commanded supreme control over the Colorado River for over a century to ensure the hydroelectric plant’s “first in time, first in right” allocation to run water through the power-generating turbines and back into the river below. The Colorado River water that exits the Xcel Energy-owned facility after power generation flows downstream has contributed to the life force of the Grand Valley for generations.
On December 19th, 2023, Xcel Energy signed a momentous Purchase Sale Agreement (PSA) with the Colorado River District, which will transfer the senior water rights to the multi-county conservation organization for 98.5 million dollars. The sale will provide a permanent solution to an agreement made in 2016–the Shoshone Outage Protocol (SHOP), a standing acknowledgment between major water users across the state to operate the Shoshone Call, thereby sending historic flows westerly even when the hydroelectric facility is not in operation. The facility does not have any plans to close to date, but isolated outages related to the age of infrastructure and a host of natural disasters that the Glenwood Canyon has inflicted, from rockslides to wildfires, have tested the SHOP agreement.
According to the Colorado Division of Water Resources, water rights can be abandoned or dissolved when not put to beneficial use. When called, rights as influential as Shoshone can command as much as 86,000 acre-feet of westerly flow in a dry year.
With the Shoshone water rights purchase, the Colorado River District, in collaboration with the Colorado Water Conservation Board, aim to arrange an instream flow agreement to secure the historic flows to the Western Slope.
Photo: 1950 “Public Service Dam” (Shoshone Dam) in Colorado River near Glenwood Springs Colorado.
Why are the Shoshone Water Rights important to Ute Water and its 90,000 customers?
With strategically redundant infrastructure and source waters, Ute Water can overcome the difficulties of dry years by activating secondary water sources from Ruedi Reservoir and the Colorado River to supplement primary Plateau Creek water sources. Additional flows in the Colorado River from the Shoshone call improve water quality characteristics, such as the dilution of salinity levels. Irrigation entities also rely on Colorado River flows that fill canals and allow for robust and bountiful agriculture. Continued flows from Shoshone aid in maintaining the natural heritage of four endangered and threatened fish species that utilize the 15-mile reach (Bonytail, Colorado Pikeminnow, Humpback Chub, and Razorback Sucker), and persist alongside continued water security and sustainability for the Grand Valley community.
On a statewide level, maintaining higher recreational flows fuels the river recreation economy in Colorado, where the Colorado River basin on the Western Slope contributes around four billion dollars annually to the state’s GDP, according to the Colorado River District. The flows from Shoshone that reach Lake Powell also contribute to Colorado River interstate compact compliance.
How will the purchase be funded?
The Colorado River District presented the plan and progress for funding the Shoshone permanency effort during Ute Water’s regular board meeting on February 14th. Colorado River District General Manager Andy Mueller outlined two major milestones that have gotten the project’s funding off the ground.
On December 19th, 2023, in conjunction with signing the PSA with Xcel Energy, the Colorado River District’s 15-county board unanimously approved a 20-million-dollar contribution.
Then on January 29th, during the regular Colorado Water Conservation Board meeting, a hearing took place regarding Shoshone water rights funding. Ute Water staff testified in support of the Shoshone permanency effort at the hearing, and the Colorado Water Conservation Board unanimously backed the effort with an additional 20 million dollars in state funds through the Non-Reimbursable Investment Grant.
Moving forward, the Colorado River District hopes to leverage at least ten million dollars committed by various water users and providers of the Western Slope who will continue to benefit from the flows of Shoshone. Once local funds are secured alongside Ute Water’s two-million-dollar contribution, the Colorado River District plans to request the remaining balance of 49 million dollars from the Bureau of Reclamation’s Inflation Reduction Act funding sources, which is slated to support drought mitigation funding projects like these efforts on Shoshone permanency.
What’s next?
More information about the effort can be found through the Shoshone Water Right Preservation Coalition and Campaign, of which Ute Water is a member, at keepshoshoneflowing.org. The Colorado River District plans to meet the four closing conditions of the PSA by December 31st, 2027. These closing conditions are as follows:
Negotiation of an instream flow agreement with the Colorado Water Conservation Board
A change of water rights decree through the water court process
Secure Funding
Approval by the Colorado Public Utilities Commission
Once these conditions are met and the acquisition is completed, Ute Water, the Grand Valley, and the Western Slope at large will realize the water security and sustainability benefits of Shoshone permanency.
Ute Water is proud to stand with our Western Slope community in preserving the lifeblood of our region – the Colorado River. Shoshone permanency has been generations in the making, and it will provide Western Slope water resources and prosperity for generations to come.
This historical photo shows the penstocks of the Shoshone power plant above the Colorado River. A coalition led by the Colorado River District is seeking to purchase the water rights associated with the plant. Credit: Library of Congress photo
Click the link to read the article on The Denver Post website (Elise Schmelzer). Here’s an excerpt:
February 26, 2024
A small hydroelectric power plant on the banks of the Colorado River has inspired a unique coalition in a state where water scarcity and politics often pit environmentalists, growers and recreationists against each other. Yet those groups recently set aside their competing interests in western Colorado, banding together to safeguard the water rights tied to the squat brown building tucked just off Interstate 70 in Glenwood Canyon. It still generates power, but its true value has been in the water that flows through it — which just might be the key to the river’s future…
Peter Fleming, the general counsel for the district, said of the interests along the river, from agricultural producers to the recreation industry: “Uniformly, across the board, they are in support of protecting the Shoshone flows. It’s pretty unique. People don’t always see eye to eye on water issues.”
[…]
Environmental protection plans exist based on the assumption that the water will be in the river. If the plant’s right were to disappear, those plans likely would need to be rewritten. The flows also keep water temperatures down for endangered fish and keep salinity low in drinking water for towns on the river…For agricultural producers in the Grand Valley, the water is crucial for growing Palisade peaches, wine grapes, wheat, corn, hay and alfalfa, said Tina Bergonzini, the general manager of the Grand Valley Water Users Association…The consistent flows provided by the Shoshone right also are critical for the $4 billion recreation industry centered on the Colorado River on the Western Slope, according to the river district.
Happy Agricultural Census time! Last week, the USDA released the 2022 Census of Agriculture — a once-every-five-year event — and, as always, it’s chock full of data on the state of the nation’s farming. I like to peruse the numbers and compare them to those from previous censuses to try to get a sense of how the West’s agricultural landscape is changing, and to get answers to questions like: How are farmers responding to aridification? Is residential development really gobbling up all the farmland?
The report only offers numbers, without a lot of context. So drawing firm conclusions isn’t possible. But the data are interesting, and sometimes enlightening, nonetheless. Let’s start with an overview:
Credit: Jonathan P. Thompson/The Land Desk
I gotta say, I had to double- then triple-check the numbers on this one. New Mexico has way more farmed acres than California — Say what!? But yeah, they do. Keep in mind that this is not cropland, but farm land, which can include sprawling ranches and just land that someone is calling agricultural for tax reasons. So take it with a grain of salt. Farm acreage is decreasing in all the states, which is hardly surprising.
But before you freak out about the death of American farming, consider this: The total number of farms has increased everywhere since 1997 except in California.
Credit: Jonathan P. Thompson/The Land Desk
Other data suggest that small farms are making a big comeback, especially in Colorado (though there was a slight dip in farm numbers between 2017 and 2022).
Now let’s look at alfalfa, since hay is not only fodder for horses but also for fighting over these days, especially in the Colorado River Basin. We hear a lot about how much water alfalfa uses and about how the federal government is paying farmers in the Lower Colorado River Basin not to grow the stuff. And so, one might expect to see a big drop in alfalfa production in those places.
That didn’t happen. In fact, several places produced significantly more alfalfa in 2022 than in 2017. It seems weird, but there are a few things to consider. First, even though the Colorado River Crisis was well under way by 2022, most of the programs paying farmers to stop farming hadn’t yet kicked in in 2022. Also, farmers aren’t really being paid to stop farming or plow up their crops. They’re being paid to use less water. Or, another way to look at it: The feds are leasing the farmers’ water from them in order to keep it in the reservoirs. Which means farmers can keep growing if they want; they just can’t irrigate as much. And alfalfa, it turns out, is fairly drought tolerant, unlike, say, almonds or lettuce or broccoli. So it makes some sense to see alfalfa production hold steady or even climb during a drought.
Credit: Jonathan P. Thompson/The Land Desk
Once again, Imperial County, California, is the West’s biggest alfalfa producer. And the Imperial Irrigation District remains the largest single water user on the Colorado River. Maricopa County, Arizona, is in second place for alfalfa tonnage, which just goes to show that Phoenix sprawl may be gobbling up farm- and desert-land, but the hayfields endure (and Maricopa County is ginormous). And alfalfa production increased substantially between 2017 and 2022 in those places, though it fell in most of the other counties surveyed.
And here’s something else that doesn’t show up on the graph: Eddy County, New Mexico’s alfalfa acreage and production fell by more than 50% between 1997 and 2022. I don’t know the reason, but I wouldn’t be surprised if it had to do with the Permian Basin oil and gas drilling boom, some of which surely is taking place on farmland. Just a guess. It also might have to do with ongoing drought, I suppose.
Of course, most of that alfalfa is going to feed livestock, either in the U.S. or elsewhere. And a surprisingly (for me, at least) large percentage of that livestock in the West are dairy cattle. So eschewing beef, alone, in order to save water ain’t gonna be enough. You gotta ditch the whole enchilada, cheese and all! (Ain’t happening).
Credit: Jonathan P. Thompson/The Land Desk
California, especially Tulare and Merced Counties, is dairy country. The state is home to nearly 1.7 million dairy cattle. Idaho runs a distant second for the West, with a mere 664,000. Nearly a half-million dairy cattle call New Mexico home, while Maricopa County has about 103,000 dairy cows. Montana is the West’s beef-cow leader, with California, Wyoming, Colorado, and New Mexico rounding out the top five, in that order. Weld County, Colorado, (home of the Greeley stench) is the beefiest county in the West, with Fresno, Kern, and Tulare in California up there, too.
$36 million; $14 million; $45 million: Amount spent in 2018 on energy for on-farm irrigation-pumping in the Rio Grande; Upper Colorado; and Lower Colorado watersheds, respectively.
626,000; 1.4 million Acres of almond orchards in California in 2002 and 2022, respectively. (Aridification ain’t keeping these water hogs at bay, apparently!)
546; 1176 Number of farms in Colorado harvesting vegetables for sale in 1997; 2022, respectively. (A small-farm/farmers market revolution?)
$671,000; $2 million Average value of a Colorado farm’s land and buildings in 1997; 2022, respectively (That amounts to $618/acre then vs. $2,401/acre now, meaning it’s a lot more expensive to get into farming these days if you don’t already have any land).
37; 105 Number of farms in Nevada harvesting vegetables for sale in 1997; 2022, respectively.
85,446; 58,831 Acres of potatoes harvested in Colorado in 1997; 2022, respectively. (That’s a big drop. I plan to look into this one a bit more in a future dispatch).
2,038,456; 606,105cwt (approx. 100 lbs) of dry beans harvested in Colorado in 1997; 2022, respectively (Ack! What’s going on?!)
6.8 million; 9.4 million Bushels of corn produced in Arizona in 1997; 2022, respectively. (Another counterintuitive one. Warrants further investigation!)
860,000; 313,000 Bales of cotton harvested in Arizona in 1997; 2022, respectively.
73,603; 58,492 Acres of land in orchards in Arizona in 1997; 2022, respectively. (Those citrus groves have been displaced by subdivisions, I’m afraid).
2.7 million; 4.1 million Acres of land in orchards in California in 1997; 2022, respectively. (Wow! A lot of these acres are planted with almonds, surely.)
2.6 million; 1.8 million Number of hogs and pigs sold by Utah operations in 2012; 2022, respectively. (Yes, Utah is hog-farm central. Smithfield Foods contracts with a bunch of factory hog farming operations in Beaver County. They are cutting back operations, however.)
And the most heartbreaking data point? Dove Creek isn’t even close to being the Pinto Bean Capital of the World anymore. Hell, it’s not even the bean capital of Colorado. Dolores and Montezuma Counties together produced about 25,000 cwt of dried beans in 2022. Yuma County, Colorado, harvested 270,000 cwt. Okay, granted, that’s for alldry beans, not just pintos (the census doesn’t break them out by variety). Still … How the mighty have fallen!
Are you curious about specific ag stats for your county or state? Drop the Land Desk a line or put your question in the comments below and we’ll try to track down an answer.
Golf course at Page, Arizona, with Glen Canyon Dam and the diminished Lake Powell in the background. Jonathan P. Thompson photo.
In recent weeks I’ve written a piece or Two about Alfalfa. My thesis: As the biggest single water user in the Colorado River Basin, the crop must plan an equally large role in contributing two the cuts necessary to keep the river from drying out. I know, it doesn’t seem like a hot-button topic. I mean, it’s just hay, after all.
This cool map by the Grand Canyon Trust’s Stephanie Smith shows how these projects usually work and gives a sense of scale and impacts. Source: Grand Canyon Trust.
When I wrote earlier this week that federal regulators had nixed all of the still active proposals for pumped hydropower energy storage facilities on the Navajo Nation, I overlooked one: the proposed Big Canyon Pumped Storage Project on a tributary of the Little Colorado River. Seems that when the Phoenix-based company surrendered permits for two other Little Colorado projects back in 2021, it kept a third proposal alive. Since I hadn’t heard anything about it, I had assumed it had simply faded away. Not quite.
Confluence of the Little Colorado River and the Colorado River. Climate change is affecting western streams by diminishing snowpack and accelerating evaporation. The Colorado River’s flows and reservoirs are being impacted by climate change, and environmental groups are concerned about the status of the native fish in the river. Photo credit: DMY at Hebrew Wikipedia [Public domain]
This week FERC issued a notice seeking public input on the Pumped Hydro Storage’s application for a preliminary permit for the project, which would be located on Navajo Nation lands.
So why didn’t FERC reject this project like it did the other proposals? Because back in 2020, when the application was initially submitted, the tribe intervened in the case, but didn’t express outright opposition. Now they have the chance to do so, which presumably would result in the permit’s rejection per FERC’s new policy. The Hopi Tribe has also weighed in on FERC policy and these projects.
The Crossing Trails Wind Farm between Kit Carson and Seibert, about 150 miles east of Denver, has an installed capacity of 104 megawatts, which goes to Tri-State Generation and Transmission. Photo/Allen Best
Click the link to read the article on the Big Pivots website (Allen Best):
February 23, 2024
A bill being readied for introduction in March would create a state standard for review of renewable energy projects by Colorado jurisdictions. Is this really needed?
A bill creating statewide standards for local governments in Colorado evaluating renewable energy projects is likely to be introduced in coming days or weeks. Is this a solution in search of a problem?
Very few local governments in Colorado have adopted regulations seen as onerous by energy developers. Pueblo County several years ago rejected a solar farm based on neighborhood opposition. They feared loss of views. Mesa County in January adopted a six-month moratorium on new utility-scale solar projects with the active support of at least one local solar company. Delta County commissioners at first rejected a solar farm on Garnett Mesa but the proponents made changes more acceptable to neighbors.
Colorado’s counties have not been hard-nosed about renewable energy. That point was made by State Sen. Byron Pelton, a former Logan County commissioner who represents much of northeastern Colorado and has a small cow-calf operation near Sterling.
In an op-ed published in the print edition of The Denver Post on Feb. 4 (not available online), he took a swing at the “Democrat majority and radical environmentalists” who would usurp local control in regulating renewable energy siting.
“Most proposed renewable energy projects are approved, and when proposals are denied, it’s for good reason,” wrote Pelton. “Those reasons range from environmental impact concerns and impact on agriculture and wildlife to inadequate benefits for the host community.”
Boulder County, he pointed out, led the way in using moratoriums to address local concerns.
“They imposed a five-year moratorium on oil and gas, giving them time to contemplate the best path forward for their community. None of the moratoriums imposed on renewable energy development have come anywhere close to approaching five years.”
“At least 15% of counties in the US have effectively halted new utility-scale wind, solar or both,” the newspaper reported. The limits come in the form of outright bans, moratoriums, construction impediments and other conditions that make green energy difficult to build.”
The newspaper reported that 375 counties blocked new wind developments in the past decade compared to 183 counties who got them. Many were in Tennessee, North Carolina, and Kentucky, but also in Vermont. Maps published with the story show a couple of counties with wind restrictions on Colorado’s eastern plains, and several on the Western Slope, which have far less wind value. The chart also shows solar restrictions in several Colorado counties but provides no detail.
One common requirement in zoning rules intended to block new wind farms specifies the height of a turbine relative to adjacent property lines. Most new wind turbines in the U.S. are 500 feet or taller. Some counties require setbacks of 1,320 feet, 1,500 feet, a mile or, in some cases, 3 miles.
Colorado Public Radio in a Feb. 8 story reported that State Sen. Chris Hansen, D-Denver, said he intended to introduce a bill that would create a standardized process for local governments considering renewable energy projects. CPR’s Sam Brasch reported that an early draft of the bill also identified rules to restrict development of wind and solar farms and also transmission lines.
Hansen yesterday confirmed that he intends to introduce the bill in March.
A flashpoint for this lies in Washington County, which is in Pelton’s district. While county commissioners in Akron have welcomed the Colorado Power Pathway that crosses the county’s southern section, the county in 2021 also approved some of the state’s toughest regulations on renewable energy projects. CPR says those regulations require one-mile spacing between structures and new wind turbines.
The CPR story also cites a study from the Sabin Center for Climate Change Law that found local governments across 34 states have approved at least 228 restrictions on renewable energy development.
New York, California, and Illinois adopted legislation similar to that being drafted by Hansen to limit local control over renewable energy projects.
Leaders of four Pacific Northwest tribal nations indigenous to the region on Friday inked a historic agreement with the U.S. that lays out the future of the operations of hydropower dams in the Columbia River Basin, including the dams on the Lower Snake River. At the White House on Friday, the Nez Perce, Umatilla, Warm Springs and Yakama tribes, and the states of Washington and Oregon, signed a memorandum of understanding, outlining a series of commitments from the federal government. It’s not an agreement for dam removal; in fact, removal of the Lower Snake dams, a long-running and controversial goal of tribes and other groups, is put off for years. But it’s the end of an era.
“We need a lot more clean energy, but we need to develop it in a way that’s socially just,” Yakama Nation Chair Gerald Lewis said at the White House. “The last time energy was developed in the Columbia Basin it was done on the backs of tribal communities and tribal resources.”
[…]
Tribal nations helped draw up a road map for the future of the region’s energy and salmon. Under the $1 billion-plus agreement announced in December and approved by a federal judge this month,tribes will help restore wild fish and lead in the construction of at least 1 to 3 gigawatts of clean-energy production. The agreement stems from years of mediated negotiations in a decadeslong court battle over dam operations. A stay of litigation is in place for up to five years and could continue for as long as 10. In a key compromise, the agreement also reduces water spilled over the dams for summer and fall run fish, including fall Chinook, one of the more robust salmon runs on the river, and a mainstay of tribal and sport fisheries. That allows the Bonneville Power Administration to sell more power from the dams into the lucrative California power market. However, spring spill would be boosted, to help spring Chinook by providing something more like a spring freshet for young fish migrating to the sea.
A regional effort to purchase major Colorado River water rights in Glenwood Canyon gained major Western Slope support this week when the Ute Water Conservancy District pitched in $2 million toward the cause. The Mesa County entity’s board unanimously approved the contribution on Wednesday. An effort being led by the Colorado River District is seeking to buy water rights associated with the Shoshone hydroelectric power plant in Glenwood Canyon from Xcel Energy for $98.5 million, plus $500,000 to cover Xcel’s transaction costs. The rights include a right to flows of 1,250 cubic feet per second that dates back to 1902, along with a second, 158-cfs right that was appropriated in 1929…
The purchase is intended to ensure the flows continue even if the plant ever closes, through reaching an agreement with the state and pursuing a water court decree that would change the rights so they are not just for hydropower production but are instream flow rights would also ensure the flows continue.
The river district has committed $20 million itself for the purchase, and the Colorado Water Conservation Board recently supported pitching in $20 million in state funds, contingent on approval by the state legislature. The river district also has said it hopes to secure $49 million in federal funding and $10 million from West Slope governments and water entities.
Senator Cheri Steinmetz (R-Lingle) chairs an official Senate Agriculture, State and Public Lands and Water Resources Committee hearing at the Wyoming Capitol in February 2024. (Mike Koshmrl/WyoFile)
Sen. Cheri Steinmetz was clear: The committee chairwoman did not want to hear prevailing viewpoints about carbon dioxide and climate change.
Those who accept what climate scientists have known for decades — that the planet is warming because of human-caused CO2emissions — need not speak up, the Lingle Republican said.
“If proponents of a different viewpoint wish to express that,” Steinmetz said, “they are free to have a hearing of their own.”
That left room for only alternative theories, those that deny or discount the world-changing effect carbon dioxide and other greenhouse gasses are having on human beings, other species and the climatic conditions of the planet.
Purported experts invited to testify, and other speakers, including each lawmaker who spoke, expressed either disbelief that climate change was happening, or a belief that it is inconsequential, even beneficial.
Speakers with the CO2 Coalition testify at a Senate Agriculture, State and Public Lands and Water Resources Committee hearing. The advocacy group is known for spreading disproven claims about climate change. (Ashton J. Hacke/WyoFile)
Flanking Steinmetz in the Wyoming Capitol extension building auditorium were four members of the Senate Agriculture, State and Public Lands and Water Resources Committee: Sens. Dan Laursen (R-Powell), John Kolb (R-Rock Springs), Tim French (R-Powell) and Bob Ide (R-Casper).
They nodded and smiled as they listened to presentations from speakers brought in from the CO2Coalition. The group touted its theory — discredited by the Intergovernmental Panel on Climate Change and other climate scientists — that loading more carbon dioxide into the atmosphere will not tip the planet’s climate into unlivable conditions.
William Happer, a physicist and co-founder of the CO2 Coalition, told lawmakers and attendees that those who believe climate science have been brainwashed.
“I don’t know how you deprogram people from a cult,” Happer said, “it’s really sort of a cult.”
Pamphlets distributed by an advocacy group, the CO2 Coalition, were distributed at a Wyoming Legislature hearing this week. On the front, the pamphlet declares: “CO2 should be celebrated, not captured.” (Ashton J. Hacke/WyoFile)
But the science is clear. In fact, human-caused climate change has pushed Wyoming’s annual mean temperature upward by 2.2 degrees Fahrenheit from 1920 to 2020, according to National Oceanic and Atmospheric Administration data. Wyoming’s highest elevations are warming even faster, already changing the seasonal pulse of water flows that the state’s economy is built around.
Climate change, which is already changing people’s lives in Wyoming, will have a dramatic effect on temperature regimes all across the state, according to University of Wyoming climate scientist Bryan Shuman. A place like Jackson, he said, will go from virtually never touching 90 degrees to getting that warm with regularity.
“On the track we’re on by 2050, [Jackson] will pretty easily start to have about two weeks of 90 degree weather,” said Shuman, one of the lead authors of the Greater Yellowstone Climate Assessment. “By 2100, depending on whether we mitigate carbon emissions or not, [Jackson] either ends up staying around that two-week level or it gets up to about two months of 90 degree weather.”
Deniers’ road trip
The CO2Coalition’s participation at the legislative hearing was part of a three-stop engagement in Wyoming. The Wyoming Republican Party teamed up with conservative group Turning Point USA to host speakers from the coalition for a series of events this week in Gillette, Cheyenne and at the University of Wyoming in Laramie.
Laramie resident Laurie Richmond attended the UW event and said she’s very concerned about Gov. Mark Gordon’s policy goal to capture and store more carbon than is emitted.
The governor, Richmond told WyoFile, won’t even give the CO2Coalition speakers “the time of day” — and she wasn’t happy about it.
Richmond worried about the economic burden of current state policies that attempt to force carbon capture retrofits at Wyoming coal-fired power plants. So far, Wyoming ratepayers are being forced to cover more than $3 million in costs for utilities to study the feasibility of adding carbon capture at five coal-burning units in the state — studies that were mandated by the Wyoming Legislature. If the utilities actually implement carbon capture at the coal plants, Black Hills Energy customers in Wyoming could be tapped for up to $1 billion, and Rocky Mountain Power’s Wyoming customers could pay more than $2 billion, according to preliminary filings with the state.
William Happer, co-founder and Chairman of the CO2 Coalition, in the red tie, arrives at the University of Wyoming in Laramie Feb. 14, 2024. (Dustin Bleizeffer)
“This is all about government grifting,” Richmond said. “Can we really afford $1,000 electrical bills every month? So Gov. Gordon’s got a problem coming.”
In the Capitol, Steinmetz said at the onset that the Senate Agriculture hearing wasn’t intended to be a personal attack on the governor. That didn’t stop speakers from taking shots at his policies.
“CO2 capture is unnecessarily costly and dangerous and therefore, it is not worth pursuing for the state of Wyoming — or anyone, for that matter,” Frits Byron Soepyan, a chemical engineer, told lawmakers.
“There are people that are going to say, ‘Climate is not changing.’ Or they’ll say, ‘It’s better to have more CO2.’ We can talk about all of that, but that doesn’t really matter,” Gordon said while speaking to business leaders in Casper on Tuesday.
More than 20 years of climate policy dictated from outside the state has moved markets toward lower-carbon energy sources, Gordon said. If Wyoming’s coal, oil and natural gas are going to remain viable, those industries must have technical solutions to reduce their carbon emissions, the governor has maintained.
Gov. Mark Gordon visits with City of Casper leaders during an Advance Casper event on Feb. 13, 2024. (Dustin Bleizeffer/WyoFile)
“The reason I say that it doesn’t really matter [where Wyomingites stand on climate change] is that what we are seeing is a regulatory environment that says, ‘We need to move away from fossil fuels because that’s the only way that we can save the planet, and we need to move to renewables because that’s the only way that we can save the climate,’” Gordon said.
“The most important thing is that Wyoming not stick its head in the sand,” he continued. “If [carbon capture] isn’t going to happen here, it’s going to happen — it is already happening in places like Texas and places like Louisiana. We really need to make sure that Wyoming is competitive, that it is a leader and that it is a place that people come to find the solutions.”
Gordon and his chief energy advisor, Randall Luthi, are working with Sen. Cale Case (R-Lander) and others on an idea that more equitably distributes both the cost of adding renewables and the cost of integrating fossil fuel carbon capture into the western electricity grid. All those capital costs — as well as long-term benefits — should be spread “system wide,” Luthi told WyoFile.
Wind turbines north of Medicine Bow, pictured Feb. 9, 2024. (Dustin Bleizeffer/WyoFile)
It will be a tough sell among Wyoming’s counterparts on the western grid, Gordon admitted. But it’s part of his signature “Decarbonizing the West” initiative as chairman of the Western Governors Association. Ultimately, Wyoming cannot impose such a system-wide “fee” on its own, Gordon told WyoFile. But the current electrical power regulatory regime doesn’t fairly distribute the cost of pursuing a net-zero electrical grid.
“We’re all in this together,” Gordon said. “Instead of being a victim, Wyoming can say, ‘If you’re really interested in doing something about CO2, we got the answer. We got the answer from the bottom to the top.’”
A state of climate denial
Steinmetz and other far-right lawmakers in the Legislature have tried to capitalize politically on Gordon’s carbon-capture advocacy. It’s fair to say their criticisms land with some residents of Wyoming, a state long financially dependent on revenue from carbon-producing industries and where fewer than half of residents believe humankind is driving climate change.
Approximately 38% of Wyoming residents believe “climate change is an extremely or very serious problem,” and 46% “have noticed significant effects from climate change over the past 10 years,” according to Colorado College’s annual Conservation in the West Poll, released earlier this month. Fifty-four percent “think that the low level of water in rivers is a serious problem,” according to the poll.
Still, Steinmetz’s and others’ efforts to make a spectacle of Gordon’s carbon policies haven’t gone over seamlessly. There was a fight, for example, over whether the Senate Agriculture Committee’s climate denier-led hearing should have been considered an official legislative event.
In late January Steinmetz spread word of the hearing on official Wyoming Legislature letterhead. She challenged the governor’s authority to pursue a carbon-negative policy: “The Legislature must have a true cost-benefit analysis in order to make an informed policy decision regarding the governor’s decarbonization plans for the state of Wyoming,” the Goshen County senator said in a press release.
CO2 Coalition Executive Director Gregory Whitestone spoke at the University of Wyoming on Feb. 14, 2024. (Dustin Bleizeffer/WyoFile)
The Legislature’s leadership didn’t appreciate it. Two days later the speaker of the House, Rep. Albert Sommers (R-Pinedale) and the Senate president, Sen. Ogden Driskill (R-Devils Tower) sent out another press release purportedly uncoupling the event from the Ag Committee.
The Legislative Service Office explained the decision in an email: “Under the Senate Rules a chairman can convene a meeting of their committee at any point during a legislative session to discuss items they deem to be relevant.”
House Majority Floor Leader, Rep. Chip Neiman (R-Hulett), thought that leaving the hearing sanctioned was “appropriate,” given how “deeply involved agriculture is in the whole issue of climate change.”
Parroting disproven claims
Shuman, the UW climate scientist, missed Turning Point USA’s event with the CO2 Coalition speakers due to a conflict, but afterward he looked into their resumes and a short report they produced about Wyoming and climate change.
“They are not climate scientists,” Shuman said.
The University of Wyoming professor took issue with some of the graphics the CO2 Coalition speakers presented. He was “shocked,” he said, by one graph purporting that annual average max temperatures have declined over the last 90 years in Wyoming, a “truly misleading” assertion.
“Basically, every single weather station across the state refutes that this is the trend,” Shuman said.
Sen. Cheri Steinmetz (R-Lingle) gives remarks at a press conference that followed a legislative hearing that promoted disproven claims about climate change. (Mike Koshmrl/WyoFile)
Nevertheless, the CO2 Coalition speakers had a receptive audience with the Senate Ag Committee. The next day, Steinmetz and other hardline Republican members of the Legislature gathered for a follow-up press conference.
“Our voters — the citizens of Wyoming — are rightly skeptical of this so-called crisis and permanent carbon capture and sequestration,” Steinmetz said.
Ten members of the Legislature, plus Secretary of State Chuck Gray, spoke after Steinmetz. Some doubted climate change was happening, while others challenged the need to act and take steps like sequestering carbon. Yet other legislators repeated the CO2 Coalition’s primary disproven message: that the primary gas accelerating the climate crisis is actually beneficial.
“We all know CO2is good,” said Sen. Dan Laursen (R-Powell), a hydrographer with the State Engineer’s Office. “Plants have to have it. The more there is there, the plants do better.”
Sen. Tim French (R-Powell) agreed.
Sen. Tim French (R-Powell) gives remarks at a press conference that followed a legislative hearing that promoted disproven claims about climate change. (Mike Koshmrl/WyoFile)
“As a farmer, I need a lot of CO2to grow my crops,” French said. “There’s a lot of hype out there from different individuals, but in my world, my business, I really need it.”
Climate scientists, however, came to consensus decades ago that the atmosphere needs less CO2 — at least if the goal is to inhabit a planet resembling the one we know today. In the middle of the 20th century the average annual temperature in Wyoming was about 40 degrees, Shuman said. Today, it’s approaching 43 degrees.
“While that doesn’t sound like a huge amount, it’s worth keeping in mind that the difference between the last ice age and today is only about 5 to 7 degrees,” Shuman said. “Even a few degrees makes a big difference.”
The Global Monitoring Division of NOAA/Earth System Research Laboratory has measured carbon dioxide and other greenhouse gases for several decades at a globally distributed network of air sampling sites. Credit: NOAA Global Monitoring Laboratory
Gov. Mark Gordon spoke with Advance Casper members Feb. 13 2024 in Casper. (Dustin Bleizeffer/WyoFile)
Click the link to read the article on the WyoFile website (Dustin Bleizeffer):
February 14, 2024
Governor Mark Gordon’s push for carbon capture at coal-fired power plants and for pumping planet-warming carbon dioxide underground to produce more oil isn’t a climate crusade, he told business leaders Tuesday in Casper. It’s an acknowledgment of where policies outside Wyoming have driven markets.
Wyoming, the nation’s top coal producer and among its top oil and natural gas producers, can help meet the goal — and the market reality — of reducing carbon emissions into the atmosphere, he said. But the state doesn’t have to abandon its fossil fuels to do it.
Instead, Gordon is on a mission to prove that integrating carbon capture with fossil fuel production and use is not only economically and technically viable, it’s necessary to fill in the energy-availability gaps that renewable energy introduces into the western electricity grid when the sun doesn’t shine and the wind doesn’t blow.
And if people are honest about the full cost and complete carbon life cycles of both renewables and fossil fuel energy, more states will get on board, he said.
Gov. Mark Gordon visits with Casper business leaders Feb. 13 2024 in Casper. (Dustin Bleizeffer/WyoFile)
“If we can extend the life of these coal plants [by retrofitting them to capture carbon] for a period of time, we can meet that gap,” Gordon told members of Advance Casper, the city’s business and economic development group.
Gordon has been aggressively sharing his energy vision of late. He spoke last fall at Harvard University, which drew a strong rebuke from Wyoming’s far right. He also appeared on “60 Minutes,” where the governor discussed making the state carbon-negative.
One challenge, Gordon explained to members of Advance Casper, is that states that are demanding low-carbon or carbon-free electricity are not fairly distributing those costs, which include the loss of viewsheds and wildlife habitat from wind and solar farms in Wyoming. At the same time, those states don’t want to help pay to capture carbon at Wyoming coal plants, despite their own carbon policies that push costs onto Wyoming ratepayers.
“We need to be able to have the grid pay for the desire to reduce carbon emissions — that’s consumers across” the West, Gordon said.
To that end, Gordon has been lobbying his counterparts in the Western Governors Association. Gordon was elected WGA president last summer, and he established “Decarbonizing the West” as his signature initiative during his one-year tenure.
A sticker at Nerd Gas Co. in Casper. (Dustin Bleizeffer/WyoFile)
The initiative spans an all-of-the-above energy strategy, from nuclear and geothermal power to smarter siting of wind and solar development. Bringing some of those western state leaders onboard with his ideas for adding carbon capture to fossil fuels is still a challenge, Gordon said.
Meantime, the Biden administration — although it’s onboard with Wyoming’s carbon capture research efforts — continues to present existential threats to the state’s struggling fossil fuel industries through restrictive rulemakings to cut carbon emissions, the governor maintains.
State of the state’s energy
In his State of the State address on Monday at the Capitol, Gordon said the Legislature’s task of crafting a state budget for the next two years is particularly challenging under the weight of federal policies that the Biden administration continues to pile on fossil fuels — an industry that has “anchored our economy for over a century,” Gordon said.
The weight of Wyoming’s fossil fuel economic anchor has varied greatly in recent years, and it’s the largest factor in setting the state’s budget — in boom times and in bust. Although revenue from Wyoming’s carbon-based energy industries rebounded after the economic shock of the pandemic, markets have begun to settle back into broader trends that point to a continued decline in Wyoming coal consumption and the potential for even more volatility for oil and natural gas.
Gov. Mark Gordon gives his State of the State address Feb. 12, 2024, at the Capitol in Cheyenne. (Ashton J. Hacke/WyoFile)
They also represent a federal policy agenda that is “misguided,” “warped” and “unwise” — and, borrowing from a phrase by Gulf War military leader Gen. Norman Schwarzkopf, they amount to “pure, unadulterated ‘bovine scatology,’” Gordon declared.
“Wyoming people know how these policies have left our nation more vulnerable to put our economy — our very way of life — at risk,” Gordon said.
Mauna Loa is WMO Global Atmosphere Watch benchmark station and monitors rising CO2 levels Week of 23 April 2023: 424.40 parts per million Weekly value one year ago: 420.19 ppm Weekly value 10 years ago: 399.32 ppm 📷 http://CO2.Earthhttps://co2.earth/daily-co2. Credit: World Meteorological Organization
Today the U.S. Fish and Wildlife Service (FWS) announced revisions to their incidental take permitting program under the Bald and Golden Eagle Protection Act. The final rule includes a general permit for wind energy projects that exhibit a demonstrably low risk to eagles. Audubon and partners submitted recommendations to make permitting more efficient in ways that support the buildout of wind energy while benefitting Bald and Golden Eagle conservation.
“Bald Eagles and Golden Eagles are deeply important to our nation, and this rule sets a new precedent for how the U.S. Fish and Wildlife Service will work with clean energy developers to avoid and minimize impacts to these iconic birds at wind energy sites as well as transmission,” said Marshall Johnson, chief conservation officer of the National Audubon Society. “We congratulate the Service and the Migratory Bird Program for their hard work in creating a pathway to a more efficient permit program where wind energy companies commit to conservation measures, monitor and share data on eagles at their project sites, and help manage Bald and Golden Eagle populations across the country.”
