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Study finds that existing technology can get Colorado to near-zero electricity without need for breakthroughs in geothermal, nuclear or other realms. It will require a bit of natural gas.


by Allen Best

Colorado can decarbonize its electricity very deeply by 2040 without busting the bank. But there’s a catch.

To hit this 98.5% decarbonization level will require accepting natural gas as 1% of the mix along with a small percentage of carbon-based electricity imported into Colorado. And getting there will not require still-costly emerging technologies.

That’s the take-away from a modeling study commissioned by the Colorado Energy Office.

How about 100% emissions-free electricity? That can be achieved, and in several different ways — all of them at a higher price, according to the modeling conducted by Ascend Analytics, a Boulder-based company.

The company modeled two other scenarios deploying deep levels of geothermal, hydrogen, and advanced nuclear reactors as well as other emerging technologies. Still another scenario examined the cost of using simply wind, solar, and existing battery technology. And one scenario emphasized local generation.

These five other scenarios came in at prices of $47.1 billion to $56.2 billion in net-present value — all substantially higher than the $37.5 billion of the less-than-perfect scenario using some natural gas.

Burning natural gas on an as-needed basis to ensure reliability will produce 565,000 metric tons of emissions in 2040. That compares with 40 million tons in 2005, according to the modeling study. This scenario also envisions a higher share of electricity , about 17%, being imported into Colorado.

All the scenarios in the modeling assume substantial amounts of improved energy efficiency, in effect partially eliminating the need for new generation. All models also assume that Colorado utilities will, as required by a state law, be participating in some sort of regional market for electricity by 2030.

Will Toor, director of the Colorado Energy Office, called the study results “huge.”

“The biggest takeaway of the study is understanding that we can get very deep emissions reductions, nearly zero emissions by 2040 while minimizing costs to utility customers. That is not something that we understood going into this study,” he said in an interview.

“As we look at developing the policy framework for 2040, it will be very much informed by that understanding,” he added.

The modeling study will likely deliver the justification for a bill in the legislative session beginning in January that would propose a new emissions-reduction target for Colorado’s electrical utilities. Laws adopted in 2019 and in subsequent years tasked those utilities with reducing emissions 80% by 2030. Most and perhaps all seem to be on track to get there with relative ease.


Some moving higher more quickly

Some utilities expect to get far higher—and soon. Notable is Holy Cross Energy, the electrical cooperative based in Glenwood Springs. It expects to achieve 92% emissions-free electricity by early in 2024 and has a goal of 100% by 2030.

Bryan Hannegan, chief executive of Holy Cross, has long said that the path to 90% was reasonably clear. The hard part, with answers still unknown, he has said, will be that final 10%. And unlike the path to 90%, that final leg will likely be more expensive.

The modeling has any number of assumptions. Some likely are further out on the limb than others.

All the scenarios assume a 40% increase in electrical demand across Colorado during the next 17 years. Population growth will drive some of this new demand. Increased demand will also result from electricity replacing fossil fuels in both transportation and building and water heating.

To satisfy this increased demand will require new generation. Just how much new generation will depend upon the type. Wind and solar exclusively from generators within Colorado coupled with battery storage would require 74,492 megawatts of installed capacity. Having natural gas available will require far less, 44,474 megawatts.

On a more micro level and with a concrete challenge, Platte River Power Authority — the supplier to Fort Collins, Loveland, Estes Park and Longmont — is putting together its resource plan looking out to 2030. Directors in 2018 identified a goal of 100% renewables by 2030 but also attached a handful of conditions to that goal. Five years later, Platte River’s planners don’t see a way to 100% by 2030, at least not without risking reliability or absorbing considerable costs. One scenario calls for 85% renewables. The plan, however, is not scheduled to be completed until June.

For an explanation of the reasoning for a unanimous resolution by Platte River’s board of directors, see a blog by Fort Collins Mayor Jeni Arndt, her city’s board representative.


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. Top: downtown Denver from the Denver Art Museum. Photos/Allen Best

Transmission, seen by many as critical to deep levels of emissions reductions, gets relatively little mention in the modeling report. Arguably, an entire scenario could be built around potential for transmission upgrades, such as greater ease of moving electricity between the Western Interconnection grid, of which Colorado is a part, and the Eastern Interconnection, which starts at Kansas and Nebraska.

Ascend Analytics had conducted similar modeling about deep, deep decarbonization of electricity for Los Angeles Water and Power. The question in that study was what would it take for Los Angeles to achieve zero-emissions electricity?

Twenty years ago Colorado and its electrical utilities almost entirely embraced coal generation as the cheapest energy source far into the future. By 15 years ago, that resolve had weakened. Voters had adopted the state’s first renewable energy mandate and legislators had upped it. Wind prices were swooping down. Not least utilities had become confident of keeping lights on while deploying wind and solar.

A watershed year was 2017. Xcel Energy, Colorado’s largest utility, which supplies roughly half of the electricity in the state, sought bids for new electrical generation. The low prices for wind and solar dramatically undercut those of fossil fuels. Proponents of renewables were elated. A year later, Xcel Energy announced its plans for 80% decarbonization by 2030. The paradigm had shifted.

Most of those wind, solar, and storage projects bid in 2017 have now or soon will go on line. Statistics for 2023 are not yet available. However, as of 2022, renewable energy accounted for 37% of the state’s electrical generation, with wind power accounting for four-fifths of that renewable generation, according to the U.S. Energy Information Administration.

Two coal plants have closed since 2017 and now eight more will be laid down before the end of 2031. One, Pawnee, located at Brush, is to be converted to natural gas.

Toor said his agency began having discussions in 2022 about the next steps beyond 2030. The questions guided creation of the modeling study. The state called in utilities, environmental groups, industrial sectors, and others for conversations about how to frame the study.


What some said

Ean Tafoya, the Colorado director for GreenLatinos, a national advocacy group, said he remembers the first meeting occurring in May. Based on the number of those interested in environmental justice invited to participate as stakeholders, he suspects dozens of stakeholders were involved.

The results of the modeling Tafoya described as “very promising.”

“It shows me that the emerging technologies that my community has been very concerned about, that we don’t need them,” he said, referring to hydrogen, carbon capture and sequestration and direct-air capture as well as deep-well geothermal.  “And if we can do this by 2040 without change of policy, that is very exciting.”

If Colorado can find ways to leverage capital through green infrastructure banking and address workforce training, Colorado “can truly be a leader nationally and globally,” he added.

Xcel Energy issued a statement that said the company was “encouraged by the Colorado Energy Office’s findings.”

“We agree there is a need for new 24/7 carbon-free technology to achieve deep carbon reductions. The state’s policies will enable us to reduce carbon emissions greater than 80% by 2030 and will inform our future investments into the local infrastructure necessary to move clean energy reliably into our customers’ homes – while keeping bills low.”

Do Colorado’s modeling results suggest a template for other states or regions of the United States, even other countries? Toor thinks so.

“It is saying that you can get to near-zero greenhouse gas emissions and pollution from electricity generation within the next 20 years —with no incremental cost to customers. That’s true with other states, and it doesn’t matter whether you’re a red state or blue state. “Regulators and utilities should be excited about the ability to minimize costs to customers while nearly entirely eliminating emissions. I think that is a really important conclusion.”

That said, added Toor, other states are starting at different places. “We have already had substantial progress.”

Colorado also is blessed with renewable resources. It has wind – not the best, but among the best. It also has strong solar. Again, not the best, but very good.

“I want to be careful about claiming insight into other states, but I do think it is a very striking result that you can achieve such deep pollution reductions simply by developing the lowest-cost resources,” said Toor.

In creating the documents, Ascent based its projected costs of various technologies on projections by the National Renewable Energy Laboratory but also Ascend’s Market Intelligence Team.


How fast will technology move?

Even with those presumably careful calculations based on strong information, how good are they? After all, 20 years ago, the cost numbers argued for coal. Incredibly, some people still try to make that argument.

Also 20 years ago, many smart people projected the imminent arrival of both peak oil and, by extension, peak natural gas. Those projections, based on rear-view mirror data, failed to anticipate the rapid incremental advances in hydrofracturing, horizontal drilling and other extraction technology. From $14.50 per million Btu in 2008, natural gas prices plummeted to $2.50 with the recession – but never returned to the stratospheric levels that justified poking very deep holes across the Piceance Basin southwest of Craig. Meantime, the U.S. became a net exporter of oil.

Of course, we have had similar cost curves with wind, then solar, and now storage prices.

Might the same thing occur with geothermal, using underground heat to produce electricity, as is already done in California and some other places? Sarah Jewett, vice president for strategy at Fervo Energy, suggested cause for similar optimism in her industry during her remarks at the Colorado Rural Electric Association conference on Monday. The cost curve in recent projects in Utah and Nevada has been bending downward, she said.

Earlier that same day, a panel of experts about nuclear energy reported cause for optimism about nuclear, while yet another panel predicted reason to believe hydrogen will play an important role in the future.

Toor acknowledged the unexpected cost declines for many technologies. “It’s quite possible that hydrogen and other technologies will be lower cost than now projected,” he said.

Regardless, he added, these near-zero or zero-emissions pathways should become the baseline.

“I think it would be important that utilities are looking at new technologies and that utility regulators are able to look at getting to even deeper reductions based on what the actual cost trajectories turn out to be,” he said.

Colorado’s energy regulation framework is well suited to achieving those deep reductions —even deeper than the low-cost 98.5% emissions-free that this modeling suggests will be possible.

A final report, after review by stakeholders, is expected in December.

Following are what the modeling study cites as its key findings. The language is verbatim from the report:

  • The Economic Deployment scenario, which relies on current state and federal policies and is projected to meet demand at the lowest cost, is projected to reliably meet electricity needs in 2040 while achieving 98.5% reduction in greenhouse gas emissions in 2040 from a 2005 level while also achieving near zero emissions reduction in nitrous oxide and sulfur oxide.
  • Wind and solar will be the main source of electricity in Colorado in 2040. In the Economic Deployment scenario, 76% of electricity comes from in-state wind and solar; 16% comes from out-of-state imports of near zero-emissions electricity (mostly wind from a wholesale electricity market); and 10% from energy efficiency, with the rest coming from other sources. Across all other scenarios, in-state wind and solar account for more than 90% of electricity.
  • In the Economic Deployment scenario, gas-fired electricity generation meets only about 1% of total need for electricity.
  • Under current cost assumptions, the Optimized 100 scenario, which achieves zero emissions by 2040 using a technology-neutral, least-cost approach, selects a substantial amount of hydrogen and a modest amount of geothermal to complement wind, solar, and batteries. It is 25% more expensive than the economic deployment scenario.
  • The Wind, Solar and Battery scenario is 20% more expensive than the Optimized 100 scenario and 50% more expensive than the least cost Economic Deployment scenario. The Accelerate Geothermal scenario is 11% more expensive than the Optimized 100.
  • The Optimized 100 scenario retires all gas-fired generation by 2040. It replaces retiring gas capacity primarily with clean hydrogen starting in 2032. By 2040, this scenario has 5,061 MW of clean hydrogen and 125 MW of geothermal generation.
  • The model does not select gas with carbon capture or advanced modular reactors in any scenario because of the cost.
  • The Accelerated Geothermal scenario adds a requirement to have 10% of demand met with geothermal in 2040, which results in 1,989 MW of installed capacity (compared to 125 MW in the Optimized 100 scenario).
Allen Best
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