May 10, 2023 - The looming EPA rule on power plants is expected to point to carbon capture as a viable option to cut emissions.
But many questions remain about whether the technology can be deployed fast enough and cheaply enough across the nation’s power sector. It ran into hurdles and cost overruns when large projects were proposed in the past. Gas plants — which are a growing part of the electricity mix — also pose higher cost challenges than some previous projects.
Even so, the International Energy Agency said last month that deployment needs to increase fourfold over projects currently planned to reach climate goals.
Unless the technology is deployed over the next 30 to 50 years, “we don’t have a shot at meeting climate targets because we’re not going to stop using fossil fuels globally,” said Charles McConnell, executive director of the University of Houston Center for Carbon Management in Energy who used to run the Department of Energy’s Office of Fossil Energy in the Obama administration.
But carbon capture and storage (CCS) doesn’t fully galvanize climate hawks. Many environmentalists say federal lifelines for it are simply handouts to the fossil fuel industry that deceived the public on climate change for decades. That puts the Biden administration in a tricky political situation.
Here’s 7 questions answered on CCS and power plants — where it’s been and where it’s headed.
What is carbon capture?
There are numerous acronyms swirling around carbon capture, several of which are relevant for power plants.
CCS typically refers to technology that grabs carbon dioxide from a power plant or industrial emitter and then stores the gas underground. It differs from direct air capture (DAC), where machines pull greenhouse gas directly from the air rather than the emissions stream of a smoke stack or factory.
The technology sometimes also is called CCUS, referring to carbon capture, utilization, and sequestration. With CCUS, captured carbon dioxide is used for things such as enhanced oil recovery or manufacturing of products — which can provide an additional revenue stream to build projects — rather than just being stored so it stays out of the air. Enhanced oil recovery involves injecting CO2 into oil fields to bring more crude to the surface.
Where has CCS on power plants been tried to date?
There currently is only one power plant in the world using carbon capture at scale: the Boundary Dam Power Station near Estevan, Canada — just over the North Dakota border. Operating since 2014, it captures up to 90 percent of CO2 emitted from a coal plant, according to its operators.
In the United States, only one power plant has ever captured CO2 at scale: the W.A. Parish Generating Station near Houston, which is the site of the Petra Nova project. The CCS technology at Petra Nova, bolstered by nearly $200 million in federal money, grabbed coal-produced CO2 and piped it to an oil field to be used for enhanced oil recovery.
In 2020, NRG Energy Inc., a partner on the project alongside JX Nippon Oil & Gas Exploration Corp., shut down Petra Nova, citing a pandemic-related plummet in oil prices.
But now, there’s chatter about bringing it back online.
An NRG spokesperson, Ann Duhon, told E&E News in late April that the unit hosting the CCS technology is set to restart by the end of June after completing repairs. Spokespeople for JX Nippon, a Japanese firm, did not respond to multiple requests for comment.
According to the Global CCS Institute, the Huaneng Longdong CCS project in China is under construction on a power plant and scheduled to be operational this year. In a recent study, the institute said it is “widely anticipated to be the world’s largest coal power CCUS project.”
Otherwise, there are more than a dozen proposed U.S. projects on power plants — including several with a target start date before 2030 — but none have moved to construction, according to the institute.
Many other attempts in the United States to install carbon capture in the power sector failed in the past 15 years, dating back to a 2011 American Electric Power Co. Inc. project in West Virginia called Mountaineer that sought to capture CO2 from a large coal plant.
Other failed projects include Southern Co.’s Kemper project, the Texas Clean Energy Project and FutureGen 2.0, which envisioned a low-emissions large coal plant in Illinois. Many of the initial CCS proposals on power plants were funded by the 2009 Recovery Act.
Why has it been so difficult?
The reason for the graveyard of projects on power plants in the United States is relatively simple: CCS is expensive, and the federal government does not regulate or price CO2 emissions, experts say.
“For a long time, it was a difficult industry because you were capturing something that was free to emit. It is always more expensive to capture CO2 than release it,” said Adam Goff, senior vice president for strategy at 8 Rivers Capital, a developer of CCS technologies. “There wasn’t really a business case.”
“If you think back to 2014, 2015, it wasn’t the world we are in today where you have net-zero commitments, where you have tax credits and a big push to decarbonize,” he added.
Top Biden administration officials say federal support has been far too small to spur new projects, although they say the Inflation Reduction Act passed last year could help change that.
“There's a significant misconception that there's always been significant federal policy support for carbon capture and storage,” Brad Crabtree, DOE’s top official in the Office of Fossil Energy and Carbon Management, told E&E News in an interview in March. “[There was] a lot of policy support for other clean energy technologies, but not for carbon capture and storage.”
The Inflation Reduction Act increased the value of the main CCS tax credit, which is called 45Q for its place in the tax code. It is now a $85 credit per metric ton of CO2 captured from power plants and industrial facilities and stored in geological formations — up from the previous $50 per metric ton. For companies that want to capture carbon and use it for enhanced oil recovery or other industrial applications, the 45Q credit provides $60 per metric ton, up from $35. Direct air capture projects can get up to $180 per metric ton.
Ashley Schapitl, a Treasury Department spokesperson, declined to comment on timing for guidance on a final 45Q credit, indicating only that it will come after the IRS finishes off phase one of its Inflation Reduction Act implementation, which has included proposals on credits for electric vehicles and energy communities.
Still, some experts say the Biden administration hasn’t delivered the proper assurances to the fossil fuel sector that it will be able to sell enough electricity produced from natural gas and coal equipped with capture technology. There is still fear that the Biden administration — or a future administration — will put in place policies to phase out fossil fuels completely, thereby leaving companies with stranded CCS infrastructure.
“You’re not going to do CCUS unless you have the opportunity to sell baseload power — not just power on the margin or power that you can start up whenever you need it or whenever the wind is not blowing or the sun is not shining,” said the Center for Carbon Management in Energy's McConnell. “I can’t spend billions of dollars and put CCUS on my plant in that kind of market construct.”
Meanwhile, an academic paper authored by a political staffer at the Department of Energy earlier this year in Environmental Research: Infrastructure and Sustainability has caused a stir by calling for an “extremely cautious” regulatory approach to CCS projects.
“Particularly given long lead times, limited experience, and the potential for CCS projects to crowd or defer more effective alternatives, regulators should be extremely cautious about power sector CCS proposals,” wrote Emily Grubert, who was deputy assistant secretary at the DOE Office of Fossil Energy and Carbon Management before taking on a faculty position at the University of Notre Dame last year.
While at Notre Dame, Grubert continues to work for DOE. In the paper, she also took a swipe at the tax credit’s potential benefits to climate change.
“An ongoing challenge is that the tax credit is still issued per [ton] of CO or CO2 utilized and/or stored rather than [ton] of life cycle CO2e abated or removed relative to some baseline,” she wrote.
What makes it so expensive?
The challenge for CCS developers has been that it’s not just the capture process that costs money, but the transport of greenhouse gas — typically through a pipeline — to its ultimate sequestration or utilization site. In the power sector, many utilities currently have cheaper options for electricity.
The Petra Nova project ran up a roughly $1 billion tab, including nearly $200 million in federal money. The Kemper project projection skyrocketed to $7.5 billion before the plant switched to natural gas without carbon capture, according to one analysis.
In another example, McConnell said a CCS network in the Gulf Coast would cost $100 billion to develop, "if not $200 [billion] to $300 billion when it’s all done" over 20 to 30 years. “That money’s not going to come from DOE or the federal government. It’s going to come from private industry that’s continuing to build out.”
Meanwhile, DOE is moving forward with CCS funding authorized by the 2021 infrastructure law. The DOE Office of Clean Energy Demonstrations is accepting applications for $2.5 billion in grants to boost CCS deployment on both power plants and the industrial sector. That funding is aiming to help underwrite new research and development that could bring costs down substantially.
CCS experts say it’s not a question of whether the technology will work on power plants, but of the financial and regulatory incentives.
“We’re not fusion, right. We’re not seeking fundamental breakthroughs in whether this works,” Goff of 8 Rivers Capital said. “If you haven’t invented an idea yet, it’s not going to get you to cutting air emissions by 2035. We see the technology tool kit.”
“It’s very much a thing that we know how to do,” he said.
He and others point to the long use of CCS in industries like fertilizer production and natural gas processing, where it is cheaper to capture carbon than in a power plant. In those industries, some companies have been using the technology since the 1980s.
Will it be more expensive to do CCS on gas plants than coal?
The short answer is yes, although costs can vary from plant to plant.
CO2 is far more concentrated in ethanol and coal than natural gas, meaning the revenue yield from capture is more attractive for coal and ethanol producers. The same is true with industries like fertilizer production.
“The more concentrated the CO2 is, the less it costs to capture it,” said Crabtree of the Office of Fossil Energy and Carbon Management. “And so the consideration for most of these industries, whether there's commercial technology deployed or not, is usually a cost consideration, not a technical one.”
John Thompson, director for technology and markets at the environmental organization Clean Air Task Force, said the credit of $85 per metric ton in the Inflation Reduction Act “is kind of at the lower end of gas plants, for many gas plants, and enough for some coal plants.”
A 2021 chart from the International Energy Agency outlines the cost differences. Carbon capture on power generation, for instance, can range from roughly $50 per metric ton to $100 per metric ton — meaning the Inflation Reduction Act incentives would go further with some proposals than others.
One company has a notable strategy to pare down costs. New gas plants with CCS technology licensed by Net Power LLC, which has pitched itself as the “McDonald’s of power generation,” will come modularized, said Danny Rice, the incoming CEO of the company, in an interview.
“We haven’t seen it in the power industry today,” said Rice. “That standardization really allows us to achieve really great scale efficiencies on manufacturing plants. So we can do it at a lower cost than the alternative bespoke designs.”
The company has intellectual property rights over a CCS system that produces electricity by combusting natural gas and pure oxygen, which produces water and carbon dioxide, according to Net Power’s website. The bulk of the CO2 is recirculated into the system, allowing high-purity CO2 to “be easily sequestered or sold to industry,” it says.
The company plans to finish construction on a plant near Odessa, Texas, in 2026 that will provide "near emissions-free power" to Occidental Petroleum Corp.'s operations in the Permian Basin and future direct air capture sites. For companies that want to replicate that plant, they’ll have to license the technology from Net Power.
“That standardization starts with that serial-number-1 plant that’s going to Odessa in 2026,” Rice said.
But Rice concedes the costs are still going to be far higher than the alternative of running a traditional gas plant.
“When we're in full scale manufacturing mode, these plants will cost around $500 million. And their carbon emitting alternative or regular combined cycle plant costs like $150 million to $200 million less,” he said. The companies that actually deploy the Net Power plants are expected to use the 45Q credits.
Will new EPA rules be enough to spur CCS on power plants?
Under the Clean Air Act, EPA sets emissions limits consistent with the “best available control technology,” or BACT, and then leaves it to utilities and states to decide how to meet the emissions limits.
McConnell said the agency is likely to conclude capture technology is a BACT.
“EPA has been doing this for the past 50 years when you have a control technology that’s validated,” he said. “That’s like the scrubbers and the baghouses and all the other BACT stuff that EPA has mandated over time. We’ve now decided that CCUS is a BACT-worthy technology.”
“Let’s stop talking about whether it’s OK or not. This seems to send the signal that it is okay,” McConnell said, referring to the looming EPA rule.
Officials familiar with the coming rule have indicated it may require coal and gas plant to cut or capture nearly all their carbon by 2040. That is a decade earlier than many of the low-carbon targets set by some of the nation’s largest utilities, including those that are considering CCS in their planning.
“Right now, we’re being incentivized by carrots where you’ve got tax credits,” Goff said. “Combining a carrot and stick regime could be really powerful and hopefully will kind of drag ambition across the utility industry.”
“We also are very curious to see the rule,” he said.
The regulation could carve out exceptions for about 1,000 natural gas peaker plants, which are used to ensure there’s sufficient electricity when demand spikes.
Where would all the CO2 go?
Currently, the vast majority of captured CO2 is used for enhanced oil recovery because it provides a financial incentive for use of the greenhouse gas. That has been a source of controversy, as it involves capturing a greenhouse gas to extract more of a fossil fuel — oil — that releases CO2 when burned.
“EPA must consider that over 70% of captured carbon from CCS projects is used to extract more fossil fuels [through] EOR, a process that perpetuates fossil fuel use and in turn, adds to the climate crisis,” Victoria Bogdan Tejeda, an attorney with the Center for Biological Diversity, said in comments on the EPA rule.
The agency “should recognize the significant drawbacks of carbon capture and storage (CCS or CCUS) technologies and incorporate environmental justice considerations in its rulemaking,” Bogdan Tejeda said.
Some industries, such as the carbonated beverage sector, purchase and use CO2 in production. But there would be challenges in linking up large amounts of captured CO2 from power plants with production from those industries, including transport of the greenhouse gas through pipelines. Proposed CO2 pipelines in the Midwest — although tied to ethanol — have faced pushback from landowners and opponents to eminent domain.
Meanwhile, to tackle climate change, the Biden administration and private sector are eyeing permanent geologic storage. There are obstacles there, too. Along with the need for transporting greenhouse gas from a capture site, some research has raised concerns about large volumes of injected CO2 and earthquakes. Public acceptance of a technology that could allow stored greenhouse gas near communities also is a factor.
“Meaningful engagement and support of local communities is going to be essential for the sustainable scale up of this technology,” said Sally Benson, deputy director for energy at the White House’s Office of Science and Technology Policy, at a Global CCS Institute event Tuesday.
CCS supporters say injection of CO2 underground has been tested for more than a half-century. A DOE-backed project in Illinois, for instance, injected large amounts of captured carbon dioxide underground from an ethanol plant into geological formations.
EPA is now facing pressure over the pace of approving permits for underground injection wells of carbon dioxide. Several states have been pushing for primacy, which allows them to implement their own Safe Drinking Water Act-compliant storage programs.
This month, EPA proposed to approve Louisiana's bid for regulatory primacy over CO2 injection wells in the state. If finalized, the rule would make Louisiana the third state — following North Dakota and Wyoming — to obtain primary enforcement authority over the injection sites, known as Class VI wells.
“You have to get permits for geologic storage. We've got two states in the country that have primacy and a bunch of other states that are in line with an EPA in Washington that's ill equipped to handle all of these permits at this stage,” said McConnell, who also pointed to permit challenges for pipelines, the primary transportation method for captured CO2 in the United States.
“The administration wants to deploy all this money that they’ve got available for the marketplace to create infrastructure,” he said. “You gotta get these permits in place ... or else you’re never going to get those dollars released.”
Reporter Jean Chemnick contributed.