Legislative mandates, plunging costs, but also consumer demand push shift
The rapid shift to renewables has three, and perhaps four powerful guiding forces. First were the legislative mandates to decarbonize electrical supplies. Colorado in 2019 set targets of 50% reduction economy wide by 2030 and 90% by 2040. New Mexico, a second state where Tri-State operates, has comparable goals.
A second and now more powerful driver pushing renewables have been plunging prices.
“It’s no longer just a green movement, it’s an economic movement,” said Duane Highley, chief executive of Tri-State Generation and Transmission, which delivers electricity to 43 member cooperatives in Colorado and three other states.
Tri-State recently signed contracts for 1,000 megawatts of wind and solar energy that will be coming online by 2024 at average price of 1.7 cents per kilowatt-hour.
“That’s an amazing price. That’s lower than anything we can generate with fossil fuels. It automatically gives us the head room, because of the savings just on energy, to accelerate the retirement of coal and do that affordably with no increases in rates,” said Highley. “We see downward rate pressure for the next 10 years, and beyond 2030, we see increases below the rate of inflation.”
The economics prevail in states that have not adopted mandates designed to reduce emissions.
“We see a green energy dividend that allows us to accelerate the closure of coal without raising rates. That’s a key and it’s a key for Tri-State to getting support from our board, which covers four states. Nebraska and Wyoming don’t have the same intensity of passion behind the renewable energy movement that New Mexico and Colorado do. But one thing all of our members can agree upon is low rates and low costs.”
At Holy Cross Energy, an electrical cooperative that is not supplied by Tri-State, chief executive Bryan Hannegan sees the same downward price pressures.
“The price of new power supply from the bulk grid is coming in below where we are today in the marketplace. That is actually putting downward pressure on rates,” he said. At Holy Cross, the cost of electricity accounts for half of what consumers pay, with the other half going to the poles, wires, trucks and overhead.
“We at Holy Cross are saying we will get to 70% clean energy by 2030 with no increase in our power supply costs. If we can do it—which is a big if—we will try to do it in a way that keeps our rates predictable and stable.”
A third driver of the move to renewables has been bottom-up pressure from customers. Both Vail Resorts and the Aspen Skiing Co. have pushed Holy Cross Energy to deliver energy untainted by carbon emissions. So have individual communities. Six of the member communities in Colorado Communities for Climate Action are served by Holy Cross. “That is driving us forward. We are hearing it from our customer base,” said Hannegan.
Yet a fourth driver may be choice, as consumers can demand to pick and choose their energy sources as is proposed in a bill about community choice aggregation introduced in the Colorado Legislature this year. Holy Cross has to deliver that clean energy “frankly before somebody else does.”
All three utilities represented on the webinar retain ownership in coal plants. Holy Cross Energy, however, has consigned the production from its small ownership of Comanche 3, located in Pueblo, Colo., to Guzman Energy. Both Tri-State and Platte River have plans to be out of coal in Colorado by 2030, although Tri-State has no plans yet announced to end importing coal from a coal plant at Wheatland, Wyo.
The report by the International Energy Agency points out that South Africa’s lockdown initially disrupted 75% of the global output of platinum, which is used in many clean energy technologies and emissions control devices.
Copper mining in Peru — which accounts for 12% of global production — ground to a halt, according to the report. Indonesia, which is the world’s top supplier of nickel, banned nickel ore exports earlier this year.
The report also points out that when it comes to lithium, cobalt and various rare earth materials, the top three producers control well over three quarters of the global output.
There are also stark vulnerabilities in the geographic concentration of refining operations, with China alone accounting for 50% to 70% of global lithium and cobalt refining. China is also responsible for 85% to 90% of processing rare earth materials into metals and magnets.
“The COVID-19 pandemic is again reinforcing the importance of responsible U.S. mineral development. During trade negotiations in June 2019, China threatened to cut off our access to rare earth minerals. Now, the COVID-19 shines a bright light on China’s dominance of critical mineral and other supply chains,” said the caucus’ executive vice chairman, Rep. Scott Tipton, R-Colo. ”This report should serve as a reality check that supporting a true all-of-the-above energy future in the U.S. will require strong investments in domestic mining,”
The rising installation of clean energy technologies is set to “supercharge” the demand for critical minerals, the agency predicts, and the already rapid growth was putting strains on supply even before the global pandemic.
Clean energy technologies, the report said, generally require more minerals than their fossil fuel counterparts.
As an example, an electric car uses five times as many minerals as a conventional car and an offshore wind plant requires eight times as many minerals as a gas-fired plant of the same capacity…
The most efficient coal-fired power plants, too, require a lot more nickel than the less efficient ones to produce higher combustion temperatures.
Since 2015, the report points out, electric transport and grid storage have become the largest consumers of lithium, accounting for 35% of the demand. And likewise, those users have driven demand for cobalt from 5% to nearly 25% in that same period.
Those demands, however, come with costs.
Congo, which controls the majority of the world’s supply of cobalt, nearly tripled its royalty rate in 2018 and has come under harsh scrutiny for its extraction practices in harsh conditions amid reports it also relies on child labor.
In its report, the agency recommends government and companies take a number of steps to ensure a steady supply chain and greater independence in the arena of critical minerals, including timely investments in new mines, periodic assessments, promotion of recycling of end of life materials to capture valuable minerals, and stepping up research and development in substitution materials…
Utah is the only state in the country that produces magnesium metal and is one of two U.S. states that produces potash.
While lithium is not being mined in Utah at this point, there is potential for U.S. Magnesium to produce it as a byproduct.
In a paper she wrote for the survey on battery metals’ demand, Mills details the potential of some of these elements to be “mined” in Utah as a byproduct of other metals, such as copper or uranium deposits revealing cobalt.
Utah hosts the only operating uranium and vanadium mill in the United States, Mills points out, and while there is not any uranium mining going on, the mill began producing vanadium from stockpiles in 2019. Vanadium can be used in high-capacity batteries used for large-scale energy storage applications.
Finally, Rio Tinto’s Kennecott operations in Utah puts it as the nation’s second largest producer of copper, which is unmatched in its ability to conduct electric currents.
In addition to copper, Kennecott is one of the largest producers of gold, silver, platinum group metals and molybdenum in North America, and could be a potential source of critical minerals such as rhenium and tellurium.
Rio Tinto is a member of the U.S. Department of Energy’s Critical Materials Institute and is jointly investigating with its experts on ways to extract additional critical minerals from the existing refining and smelting process.
Rhenium, one of the rarest elements, has the third-highest melting point and its nickel-based alloys are used in exhaust nozzles of jet engines. Its alloys are also used in oven heating elements and X-ray machines.
Mills said the state is engaged in research related to the production of tungsten — another critical mineral — which is the only other metal element with a higher melting point than rhenium.
The electric cooperative serving the cities of Delta and Montrose has agreed to a $136.5 million fee to exit the Tri-State Generation and Transmission Association – showing that breaking up is not only hard to do, but expensive.
The Delta-Montrose Electric Association (DMEA) has since 2016 been sparring over renewable energy with Tri-State, a wholesale power production company serving 43 member electric cooperatives in Nebraska, Colorado, New Mexico and Wyoming.
Tri-State and DMEA reached an agreement in principle in July 2019, just days before the Colorado Public Utilities Commission was set to begin proceedings to set an exit fee for the cooperative.
Under the exit agreement, which would have DMEA leave Tri-State on June 30, the cooperative would pay a $62.5 million exit fee, $26 million for local Tri-State infrastructure and forgo the $48 million in equity the cooperative held as a member of Tri-State.
The DMEA-Tri-State agreement still must be submitted for final approval by the Federal Energy Regulatory Commission, which is now the regulator for Tri-State.
A number of Tri-State cooperatives have chafed under the association’s long-term contracts that limit local generation to 5% of demand, as they hoped to add more local renewable generation. DMEA’s contract ran to 2040. Tri-State was also criticized for still being heavily dependent on coal-fired generation.
The $88.5 million will be paid by DMEA or a third party, according to Tri-State. When the Kit Carson Electric Cooperative, in Taos, New Mexico, left Tri-State in 2016, its new electric wholesaler, Guzman Energy paid the $37 million exit fee, which it is recouping in the first few years of its contract with the co-op.
DMEA has about 28,000 members and Kit Carson has 29,000, but DMEA has more commercial and industrial members and about twice the electricity demand as Kit Carson, with an annual peak of 95 to 100 megawatts, according to Virginia Harman, a DMEA spokeswoman.
DMEA is in the final steps of completing a 12-year wholesale power purchase agreement with Guzman Energy, Harman said, adding that there would be no further comment until the agreement is completed…
Tri-State has also established a procedure for setting exit prices as several other members have asked for estimates, the association said. FERC must approve the methodology for future exit fees
“This will be the methodology going forward,” Boughey said. “Kit Carson and DMEA were one-offs.”
The coronavirus pandemic has mostly yielded bad news for renewable energy. Disruptions to supply chains and slowdowns in permitting and construction have delayed solar and wind projects, endangering their eligibility for the soon-to-expire investment tax credits they rely on. There’s another form of renewable energy, however, that might see a benefit from the recent global economic upheaval and emerge in a better position to help the United States decarbonize its electricity system: geothermal…
Unlike wind and the sun, subsurface heat is available 24/7, perpetually replenished by the radioactive decay of minerals deeper down. But compared to wind and solar farms, geothermal power plants are expensive to build. The cost can range from $2,000 to $5,000 per installed kilowatt, and even the least expensive geothermal plant in the U.S. costs more than double that of a utility-scale solar farm. Engineers have to drill thousands of feet into the ground to reach reservoirs of water and rock hotter than 300 degrees F in order for the plants to be economical. Plants generate electricity by pumping steam or hot water up from those reservoirs to spin a turbine which powers a generator.
Experts told Grist that drilling can account for anywhere between 25 to 70 percent of the cost of a project, depending on where it is, the method of drilling, and the equipment required. But now, the companies that supply the machinery and services for drilling are starting to slash rates.
That’s because they are the same suppliers the oil industry uses, but oil companies are idling drilling rigs and cutting contracts left and right. They’re getting pummeled by the largest oil price crash in decades, the result of plunging demand due to the pandemic and a glut in supply because of a price war between Saudi Arabia and Russia. On Tuesday, the U.S. Energy Information Administration revised its short-term outlook for crude oil production, predicting a steep decline through 2021. All of the suppliers who are normally digging for oil are now eager for new business.
Tim Latimer, a former drilling engineer for the oil and gas industry and now the cofounder and CEO of Fervo Energy, a geothermal energy company (and a 2020 Grist 50 Fixer) said suppliers have already been willing to knock 10 percent off quotes they gave him a few weeks ago. In a recent Twitter thread, Latimer predicted that drilling costs could drop by as much as 20 to 40 percent. On top of that, interest rates are down, and recovery bills with new funding for clean energy are potentially around the corner.
Lowering the up-front cost of building a geothermal power plant would allow plant operators to bring down electricity prices, which could attract new interest in geothermal from utilities. “If you can bring that price down even a little bit,” Latimer said, utility buyers “get a lot more excited about it because they want to have something in their portfolio that can produce electricity at night.”
In California, which has set a target of 100 percent clean electricity by 2045, energy providers are starting to recognize the benefits of geothermal’s round-the-clock power and have agreed to purchase power from two new plants being built in the state. But in states where there isn’t as much pressure to decarbonize, it’s a tough sell: The cost of electrons from a geothermal plant can be more than three times as high as those from solar and wind.
Part of the problem, according to Susan Petty, the chief technology officer, president, and co-founder of geothermal company AltaRock Energy, is that utilities don’t place extra value on geothermal’s ability to generate electricity all the time. She said bringing drilling costs down will help, but it would help even more if there were parity in the tax incentives for renewables: This year, geothermal electricity projects were eligible for a 10 percent investment tax credit, compared to a 26 percent credit for solar and wind.
Geothermal faces other hurdles, like a lengthy permitting process that stretches out project timelines. It can be challenging to find investors during the early, risky stages of a project, before the viability of developing a given site has been proven. Geothermal also suffers from a PR problem — people just aren’t as familiar with it as they are with wind and solar. The technology has been around in the U.S. since the 1960s, but for these reasons and others, geothermal still only makes up 0.4 percent of the U.S. electricity mix.
Large electricity generators use lots of water to cool their coal-fired plants. As those units shut down, expect to see battles heat up over how the massive amounts of water can be repurposed.
Any newfound source of water is a blessing in a state routinely stricken by drought and wildfire, where rural residents can be kept from washing a car or watering a garden in summer, and where farm fields dry up after cities buy their water rights.
State water planners long assumed that the amount of water needed to cool major power plants would increase with the booming population. Planners in 2010 predicted that, within 25 years, major power plants would be consuming 104,000 acre-feet per year of their own water. The Colorado Sun found that their annual consumption will end up closer to 10% of that figure.
The 94,000 acre-feet of water that major power plants won’t be consuming is enough to cover the needs of 1.25 million people, according to figures included in the Colorado Water Plan of 2015. (That’s counting water permanently consumed in cities, and not counting water consumed by agriculture and certain giant industries, or water returned to rivers through runoff and wastewater treatment plants.)
Already, water once used by now-defunct power plants is flowing to households, shops and factories in Denver, Colorado Springs, Boulder and Palisade, because the local water utilities owned the water and supplied the plants. When the plants closed, the cities just put their own water back into municipal supplies, officials in those cities said…
In Pueblo, Black Hills Energy shut down a 100-year-old, coal-then-gas-fired power plant downtown. After decommissioning stations 5 and 6 near the Arkansas River in 2012, Black Hills donated the water to public use. Water that once cooled the plant now flows in the Arkansas through the city’s Historic Riverwalk, where gondoliers paddle and picnickers gather in the sun for art and music. Renowned Denver historic preservationist Dana Crawford has partnered with a local developer on plans to revive the art deco power plant as an anchor for an expansion of the Riverwalk, with shops and restaurants.
In Cañon City, water that cooled the closed W.N. Clark power plant is going down the Arkansas River as well, Black Hills Energy spokeswoman Julie Rodriguez said. It is likely being picked up by the user with the next legal right in line.
The San Miguel River on the Western Slope is gaining some water from closure of the coal power plant in Nucla — at least temporarily until Tri-State Generation and Transmission Association, which owns the plant, finishes the tear down and reclamation, which requires some water. Spokesman Mark Stutz said Tri-State has made no decision on what to do with the water rights after that, but “we will listen to the input of interested stakeholders.”
Major power plants’ water consumption peaked in 2012 at about 60,000 to 70,000 acre-feet. It has dropped to about 47,000 acre-feet now and will fall further to about 27,000 acre-feet over the next 15 years, just from closures already announced. By the time the last coal plant closes, major power plant water consumption will have plummeted to about 10,000 acre-feet…
In the past 10 years, 13 coal power plant units in Colorado have shut down. Another 10 will close by 2036 or much earlier. The remaining four units are under review by their owners.
The last gas power plant built in Colorado was in 2015, according to the U.S. Energy Information Administration. All new power generation in Colorado since then has been renewable…
In the past 10 years, 13 coal power plant units in Colorado have shut down. Another 10 will close by 2036 or much earlier. The remaining four units are under review by their owners.
The last gas power plant built in Colorado was in 2015, according to the U.S. Energy Information Administration. All new power generation in Colorado since then has been renewable.
Technology has driven down the cost of wind and solar, and they now can provide power at a lower price per kilowatt-hour than coal-fired power in Colorado. Even accounting for the need to store electricity, bids to provide renewable energy have come in lower than the cost of coal-fired power.
Closure dates have been accelerating. Utilities are running scenarios on how they could shut down the last four coal-burning units in Colorado not already set for closure. They are Xcel Energy’s Pawnee in Brush and Comanche 3 in Pueblo, Platte River Power Authority’s Rawhide 1 near Wellington, and Colorado Springs Utilities’ Ray D. Nixon unit 1 south of the city.
Emissions controls and customers’ climate concerns are also driving the change, utility officials said.
For example, Platte River Power Authority already expects to be 60% wind, solar and hydro by 2023, and its board said it wants to reach 100% by 2030, spokesman Steve Roalstad said. A public review process started March 4 to discuss how best to achieve that. Closing the coal plant at Rawhide and even the adjacent gas plants by 2030 are options, but not certain, he said.
Early closing dates set for other coal plants could move up. PacifiCorp, a partial owner of three coal power units in Craig and Hayden in northwest Colorado, is pushing its partners, Tri-State and Xcel, for faster shut-downs. It wants to move more quickly to cheaper renewables…
As more power plants close in coming years, much of the water no longer needed will be water owned by the power companies themselves. Many were reluctant to talk about their water rights in detail.
Water court records show Xcel owns water from wells all over the metro area, and draws from Clear Creek. Xcel also owns 5,000 to 10,000 acre-feet in the Colorado River. That water is diverted to northern Colorado through the Colorado-Big Thompson tunnel under the mountains.
Xcel did say it is holding onto its water rights for now. It has been cutting its water purchases from cities, switching to its own water as power plants close.
On a smaller scale, Tri-State is now switching its J.M. Shafer power plant in Fort Lupton from city well water to its own water rights, city administrator Chris Cross said.
Water court records show another example of what can happen to utility-owned water: Xcel wants to use some of its Clear Creek water rights at a hydroelectric plant above Georgetown that is being renovated to produce more megawatts.
Some water might become available for other uses as more Xcel coal plants close, spokeswoman Michelle Aguayo said…
Closure of the power plants could open up arguments over where that water should go instead, explained Erin Light, state water engineer for the northwestern district.
“Every water right is decreed for an amount, a use and a place of use,” Light said. With the power plant gone, utilities can try to sell their rights, but other water users may dispute that in court.
Xcel, for example, owns 35,000 acre-feet of conditional water rights in reservoirs in the Yampa Valley that have never been built, she said. But “conditional” means the company gets the water only if it is actually needed, she explained. So when the Hayden power plant closes in the 2030s, Xcel would have to go back to water court to change the use or sell the rights, she said.
“Those conditional water rights become a lot more speculative if they are not operating a power plant,” she said. “Arguably, they would lose their conditional rights.”
Legislators are sufficiently concerned about speculators making money on Colorado’s water shortage that in March they passed Senate Bill 48 asking water officials to give them suggestions on how to strengthen current law against it.
Steve Lowe gazed into a gaping pit in the heart of the California desert, careful not to let the blistering wind send him toppling over the edge.
The pit was a bustling iron mine once, churning out ore that was shipped by rail to a nearby Kaiser Steel plant. When steel manufacturing declined, Los Angeles County tried to turn the abandoned mine into a massive landfill. Conservationists hope the area will someday become part of Joshua Tree National Park, which surrounds it on three sides.
Lowe has a radically different vision.
With backing from NextEra Energy — the world’s largest operator of solar and wind farms — he’s working to fill two mining pits with billions of gallons of water, creating a gigantic “pumped storage” plant that he says would help California get more of its power from renewable sources, and less from fossil fuels…
At Eagle Mountain, one of several abandoned mining pits would be filled with water, pumped from beneath the ground. When nearby solar farms flood the power grid with cheap electricity, Lowe’s company would use that energy — which might otherwise go to waste — to pump water uphill, to a higher pit.
When there’s not enough solar power on the grid — after sundown, or perhaps after several days of cloudy weather — the water would be allowed to flow back down to the lower pit by gravity, passing through an underground powerhouse and generating electricity…
The Eagle Mountain plant wouldn’t interrupt any rivers or destroy a pristine landscape. But environmentalists say the $2.5-billion facility would pull too much water from the ground in one of the driest parts of California, and prolong a history of industrialization just a few miles from one of America’s most visited national parks.
Lowe rejects those arguments, saying his proposal has survived round after round of environmental review and would only drain a tiny fraction of the underground aquifer.
The project’s fate may hinge on a question with no easy answer: How much environmental sacrifice is acceptable — or even necessary — in the fight against climate change?
FromThe Guardian (Patrick Greenfield and Jonathan Watts):
The world’s largest financier of fossil fuels has warned clients that the climate crisis threatens the survival of humanity and that the planet is on an unsustainable trajectory, according to a leaked document.
The JP Morgan report on the economic risks of human-caused global heating said climate policy had to change or else the world faced irreversible consequences.
The study implicitly condemns the US bank’s own investment strategy and highlights growing concerns among major Wall Street institutions about the financial and reputational risks of continued funding of carbon-intensive industries, such as oil and gas.
JP Morgan has provided $75bn (£61bn) in financial services to the companies most aggressively expanding in sectors such as fracking and Arctic oil and gas exploration since the Paris agreement, according to analysis compiled for the Guardian last year.
Its report was obtained by Rupert Read, an Extinction Rebellion spokesperson and philosophy academic at the University of East Anglia, and has been seen by the Guardian.
The research by JP Morgan economists David Mackie and Jessica Murray says the climate crisis will impact the world economy, human health, water stress, migration and the survival of other species on Earth.
“We cannot rule out catastrophic outcomes where human life as we know it is threatened,” notes the paper, which is dated 14 January.
Drawing on extensive academic literature and forecasts by the International Monetary Fund and the UN Intergovernmental Panel on Climate Change (IPCC), the paper notes that global heating is on course to hit 3.5C above pre-industrial levels by the end of the century. It says most estimates of the likely economic and health costs are far too small because they fail to account for the loss of wealth, the discount rate and the possibility of increased natural disasters.
The authors say policymakers need to change direction because a business-as-usual climate policy “would likely push the earth to a place that we haven’t seen for many millions of years”, with outcomes that might be impossible to reverse.
“Although precise predictions are not possible, it is clear that the Earth is on an unsustainable trajectory. Something will have to change at some point if the human race is going to survive.”
The investment bank says climate change “reflects a global market failure in the sense that producers and consumers of CO2 emissions do not pay for the climate damage that results.” To reverse this, it highlights the need for a global carbon tax but cautions that it is “not going to happen anytime soon” because of concerns about jobs and competitiveness.
The authors say it is “likely the [climate] situation will continue to deteriorate, possibly more so than in any of the IPCC’s scenarios”.
Without naming any organisation, the authors say changes are occurring at the micro level, involving shifts in behaviour by individuals, companies and investors, but this is unlikely to be enough without the involvement of the fiscal and financial authorities.