Skip to contents
Energy

Colorado power companies bet big on net-zero emissions as state debates 100% renewable energy future

Xcel, Platte River banking on lowering emissions with nuclear, geothermal and carbon capture tech, but critics argue it would be too small, too slow

The 156-megawatt Comanche solar array, shown here on Jan 20, 2019, in front of the Comanche Station, a coal-fired power plant. (Mike Sweeney, Special to The Colorado Sun)
  • Credibility:

Xcel Energy and Platte River Power Authority, two of Colorado’s biggest utilities, left themselves some wiggle room when they pledged to remove greenhouse gases from their emissions.

While there is a big push in Colorado to run on 100 percent renewable energy — it’s Gov. Jared Polis’ goal to do it by 2040 — the utilities opted for a net-zero carbon emissions goal instead.

Xcel, the state’s largest utility, wants to reach the goal by 2050. Platte River, which serves Fort Collins and other Northern Colorado municipalities, has a target of 2030.

The nuance leaves open the door for a wide range of other technologies — small nuclear plants that can be assembled like Legos, hydropower generators attached to water pipes, wells drilled deep into the Earth to tap its heat — and the ability to continue burning fossil fuels.

MORE: Read more environmental coverage from The Colorado Sun.

It also underscores a debate over the most efficient ways to remove carbon dioxide — the main gas linked to climate change — as a byproduct of powering the economy.

Platte River’s goal came with the caveat that the power provider could only meet its net-zero carbon goal provided that markets and technology “advance and improve.”

“Other zero-carbon technologies are on the horizon,” said Alice Jackson, president of Xcel’s Colorado subsidiary. “We don’t know what technology is going to develop in the next 20 or 30 years.”

To put the challenge for Xcel and Platte River into perspective, coal and natural gas make up 63 percent of Xcel’s electricity generating capacity and 80 percent of Platte Valley’s.

Xcel would have to replace or retrofit plants that account for 6,422 megawatts of capacity.

Platte River Power Authority’s Rawhide Energy Station north of Wellington, Colorado, generates electricity using coal, natural gas and solar. The company has pledged to reach net-zero carbon emissions by 2030. It serves Fort Collins and other Northern Colorado municipalities. (Ed Kosmicki, Special to The Colorado Sun)

Platte River has 822 megawatts that would have to be swapped for wind, solar, battery storage or other technologies.

Under a plan approved by the Colorado Public Utilities Commission, Xcel is closing two coal-fired units with 660 megawatts and will add 1,100 megawatts of wind, solar and storage by 2026, making 55 percent of its generation renewable. The question is what will fill the rest of the gap.

Net-zero also doesn’t necessarily mean not burning fossil fuels. A net-zero analysis done for Platte River projects reaching the goal with 25 percent of the authority’s electricity coming from fossil-fuel plants, and that is offset by sales of surplus renewable energy.

Xcel’s $1.3 billion, Comanche 3 coal-fired unit, which went into operation in 2010 with a projected 70-year life, could be a candidate for technology that removes carbon dioxide from the smokestack to be stored or recycled, Jackson said.

“We need new technology,” Jackson said. “Some of these technologies aren’t cost effective today, but could be in the future.”

The 100-percent renewable versus net-zero carbon debate isn’t unique to Colorado. In Congress a number of lawmakers, including U.S. Rep. Joe Neguse, D-Boulder, are pushing for a “Green Deal” that includes a shift to 100 percent renewable energy.

On Jan. 10, a group of 626 environmental and community groups sent a letter to Congress in support of the Green Deal, but said “any definition of renewable energy must also exclude all combustion-based power generation, nuclear, biomass energy, large-scale hydro and waste-to-energy technologies.”

Last September, California adopted new clean-electricity standards with the aim of 60 percent renewable energy by 2030 and 100 percent “carbon-free” energy by 2045.

“The California clean energy standard by 2045 gives utilities more leeway and allows for new technology to emerge and for a residual role for natural gas,” said Dallas Burtraw, a senior fellow at Resources for the Future, a Washington, D.C.-based energy and environment think tank.

“If the goal is carbon reduction, you don’t need to preordain renewable generation,” Burtraw said. “It doesn’t make sense to lock in to a 100-percent renewable goal.”

Others cast a jaundiced eye on the prospects for these new technologies — particularly modular nuclear plants, deep geothermal wells and carbon capture.

“It is difficult to see bringing these technologies into play on a big scale in the time frames we are talking about,” said Mike Jacobs, a senior analyst with the non-profit Union of Concerned Scientists. “Better to continue to push along with what is proven to work and continue to finance R&D.”

But Jacobs raised the question of whether committing to net-zero electricity was the best way to get carbon-dioxide emissions out the economy and environment since the last increment will be the most expensive.

“I’ve got an oil-burning furnace and a gasoline car,” Jacobs said. “It would be good to get some credit for turning them electric.”

Colorado is in a good position to rely heavily on wind and solar since it has good resources for both, said Richard Powell, executive director of ClearPath, a nonprofit promoting conservative policies that accelerate clean energy. “You couldn’t do that in the Southeast, so there are places that are going to need new technologies.”

Wind turbine components await shipping at the Vestas tower plant on Jan. 19, 2019, in Pueblo, Colorado. The facility is one of three Vestas manufacturing plants operated in Colorado. (Mike Sweeney, Special to The Colorado Sun)

There is, however, a cautionary tale of jumping on technology too soon, Jackson said. In Xcel’s first contracts for wind power 10 years ago, the price was 6.9 cents a kilowatt-hour (kWh). The most recent quotes are as low as 1.2 cents a kWh.

“Let’s set the target and let the technologies race it out,” said Noah Horowitz, director for energy efficiency standards, climate and clean energy program at the Natural Resources Defense Council (NRDC), a national environmental group.

The technology that has been most controversial and most talked about is carbon capture, with advocates calling it essential and critics saying it is a boondoggle.

The technology removes the carbon from coal either before it is burned or from the flue gas after combustion. It is commonly referred to as carbon capture with storage (CCS) or carbon capture utilization and storage.

“CCS is achievable, the costs are just high,” Horowitz said. “That technology faces immense challenges if it is going to make it to market scale.”

The story of CCS is littered with cost overruns and failures. Atlanta-based utility Southern Company poured nearly $7 billion, more than twice the original price tag, into its Kemper project in Mississippi before scrapping it in 2017. The CCS technology used gasified coal and removed the carbon before combustion.

The price on Duke Energy’s Edwardsport plant in Indiana, using the same technology as Kemper, had jumped from nearly $2 billion to $3.5 billion by the time it was completed in 2013. The CCS unit, however, was not put in service because it is too costly to run.

The two CCS plants operating in North America are NRG Energy’s Petra Nova plant near Houston and the Canadian Boundary Dam plant owned by SaskPower.

Boundary Dam’s CCS unit cost $700 million, but the plant required upgrades and emission controls that raised the total cost to $1.5 billion. The Petra Nova unit cost $1 billion. The two plants use technology to remove carbon from flue gas after coal is burned.

The plants offset some of their cost by selling the captured CO2 for injection in oil fields to boost production. This requires additional investment in compressors and pipelines, and may not be an option for all coal plants.

CCS costs $60 a megawatt-hour (MWh), according to the U.S. Department of Energy. The current cost of coal-fired generation is around $30 a MWh.

The Institute of Energy Economics and Financial Analysis, a nonprofit energy think tank, calculated that the cost of the two would be $96 a MWh. Even with projected declines in technology costs, the price for coal-fired generation and CCS would be $60 a MWh, the analysis said.

That compares with recent prices for power purchase agreements between utilities and merchant power generators of $35 a MWh for solar plus battery storage, and $21 a MWh for wind plus storage.

Still advocates say that developing the technology is key, especially internationally as coal-fired generation is still being built in China and Southeast Asia.

“Some skepticism is understandable,” Laszlo Varro, chief economist for the International Energy Agency, wrote in a commentary. “But we should not dismiss this technology—in fact, carbon capture utilization and storage is going to be critical to the global clean-energy transitions.”

An analysis by DNV GL, a Norway-based maritime and energy-industry service company, says that the way to bring down costs is to ramp up use of CCS, for as the technology reaches economies of scale, it will become cheaper and more efficient.

The U.S., however, does not look like a fertile market for expensive new technology as more than half the country’s coal-fired plants are more than 50 years old, and only 14 percent are less than 30 years old, according to S&P Global Market Intelligence.

Xcel’s $1.3 billion, 750 megawatt Comanche 3 coal-fired unit, which went into operation in 2010 with a projected 70-year life, could be a candidate for technology that removes carbon dioxide from the smokestack to be stored or recycled. (Mike Sweeney, Special to The Colorado Sun)

Among the youngest plants, however, is Xcel’s 750 megawatt, Comanche 3 unit. Planning for the plant got an OK from the PUC in 2004. It went into service in 2010, with decades needed to amortize the $1.3 billion investment.

“When they built the third unit, what were they thinking?” said Burtraw. “They knew about climate issues. It was a bet.”

Xcel’s Jackson has called Comanche 3 a “wonderful baseload unit” and “cost effective for our customers,” including the Evraz steel mill in Pueblo, the company’s largest commercial account in Colorado.

CCS is “a technology we are going to pay close attention to,” Jackson said. “It is not economic today, but could be 20 or 30 years when we need it.”

NRDC’s Horowitz said, “The Comanche problem is one they created for themselves, and they can get out of it with some creative thinking.”

As for the other technologies, their prospects remain uncertain. Large-scale nuclear power plants look to be a thing of the past with some existing plants running into problems competing with natural gas and renewable generation — six plant have closed in the last five years. The construction of new plants has been plagued by cost overruns.

Still, Xcel says that maintaining its two nuclear plants in Minnesota, which provide 30 percent of the electricity to the utility’s Upper Midwest customers, is key to meeting the net zero target in that state.

Small nuclear reactors, big potential

The solution, held out by many in the nuclear-energy industry, is the small-modular reactor, or SMR. “Good things come in small reactors,” is the way the Nuclear Energy Institute, the industry’s trade group, touts the technology.

The SMR would be constructed with factory-built components to create modules, making it more of a manufactured product than a construction project. The leader in the field is Corvallis, Oregon-based NuScale Power, which is backed by international engineering firm Fluor Corp. NuScale has gotten the go-ahead to set up its first plant, a 12-module, 720 megawatt installation at the Idaho National Laboratory and to begin providing electricity to local utilities in 2026.

The company estimates that a generic 720 megawatt plant would cost $2.9 billion, and the so-called levelized cost of its energy — the cost of building and operating a plant over its lifetime divided by the total electricity it produces — is at 6.5 cents per kWh.

In its last solicitation for new projects, Xcel, as part of the Colorado Energy Plan, the median for wind projects was 1.8 cents a kWh, 2.95 cents for solar and 2.1 cents for wind plus storage.

“The technology works and will be available in the 2020s,” said ClearPath’s Powell. “The question is the price point.”

Others aren’t so sure. Researchers from Harvard, Carnegie Mellon and the University of California, San Diego analyzed SMR technology and said its widespread availability is 50 years out. Since it isn’t cost competitive for generating electricity, the researchers looked for niche markets, such as industrial process heat — think steel making or other industrial manufacturing — where it might be competitive, but couldn’t find any. “SMRs do make nuclear more affordable, but not necessarily more economically competitive,” the analysis said.

Ultra-deep geothermal would appear to be an ideal answer. “Enhanced geothermal has the promise of being able to be used anywhere, siting wouldn’t be a problem,” said Powell. “It could power the whole country. It’s the Holy Grail.” The problem, he said, is the cost and that the drilling technology hasn’t been perfected.

A $23-million deep-thermal project is now being drilled in Cornwall, England: two wells, one 1.6 miles deep and a second 2.8 miles down. Water will be pumped down, and the hot water that comes back up will run a 3 megawatt power plant.

The largest geothermal installation in the world is the Geysers Geothermal complex with 18 power plants north of San Francisco. It first geothermal well was drilled in 1955 and now has 322 steam wells. The deepest is 2.4 miles long. The average is 1.6 miles.

Ultra-deep geothermal, which would sink wells nearly five to 10 miles deep, could allow almost any region to tap into the Earth’s heat. The Port of Rotterdam Authority in the Netherlands is exploring ultra-deep thermal as an industrial power source.

Calpine Corp., which operates the California’s Geyser complex, estimated that the total drilling time for one of its deep geothermal wells is 85 days. By comparison, a Colorado Front Range oil well, down a half-mile, can be drilled in eight days or less.

Hydropower provided 2.3 percent of Colorado’s electricity in 2018, according to the federal Energy Information Administration, and the prospects for added hydro are limited.

One innovation has been small hydro turbines that can be added to existing dams and any water stream with flow, such as farm irrigation ditches and water mains. There are 60 such projects in Colorado, ranging from West Slope farm fields to Denver and the city of Boulder water plants.

Colorado negotiated a pioneering agreement with the Federal Energy Regulatory Commission to speed permitting for such projects. That was followed by passage of federal hydro-reform legislation last October, co-sponsored by U.S. Rep. Diana DeGette, D-Denver, offering expedited approvals.

Still, a study by the Oak Ridge National Laboratory released in July 2018 estimated that 34 megawatts of small hydro could be added to the existing water distribution system — a hydropower drop in Colorado’s energy bucket.

“The answer isn’t going to be one thing,” Powell said. “It is going to be a number of things, though some may not look good right now.”

The Colorado Sun has no paywall, meaning readers do not have to pay to access stories. We believe vital information needs to be seen by the people impacted, whether it’s a public health crisis, investigative reporting or keeping lawmakers accountable.

This reporting depends on support from readers like you. For just $5/month, you can invest in an informed community.

More from The Colorado Sun