3 energy questions hang over EPA’s carbon rule

By Jason Plautz, Carlos Anchondo, Christian Robles, Jeffrey Tomich | 04/26/2024 06:57 AM EDT

President Joe Biden’s power plant regulation could shift the future of carbon capture, hydrogen and natural gas.

smokestack, hydrogen fuel tank rendering, wind turbine

iStock, AP

EPA’s final emissions rule is renewing questions about the readiness of carbon capture technology for power plants and the ability of utilities to comply with new restrictions at a time of surging electricity demand.

Under the plan released Thursday, new gas-fired plants that run frequently are required to reduce 90 percent of their carbon emissions by 2032. Existing coal generators scheduled to run past 2032 also will have to slash emissions, and fossil fuel plants that aren’t retrofitted with pollution controls must exit the grid by 2039.

The rule, which is likely to face legal challenges, states that power producers can rely on carbon capture and storage (CCS) to comply.


The Biden administration touted the standards as a way to slash harmful emissions while encouraging utilities to invest in new technology.

But many companies that will have to comply had a different view. Edison Electric Institute President Dan Brouillette, whose group represents utilities, said the association is concerned that carbon capture “is not yet ready for full-scale, economy-wide deployment” and that there is not enough time to build the necessary infrastructure to support transportation and storage of captured emissions.

EPA Administrator Michael Regan addressed EEI’s criticism Thursday, telling reporters that, “in general, when a trade representative speaks for an industry or a group, they’re speaking to the least common denominator.”

“Of course they have to represent all of their members,” Regan said, following a speech on EPA’s rule at Howard University. “There are some of their members that are saying that carbon capture and storage is viable, is doable — quite frankly they’re investing billions of dollars in doing it. And so, I just challenge some of the naysayers with the facts.”

Here are three questions that will determine how EPA’s carbon rule is implemented:

Is carbon capture ready for power plants?

To date, CCS has been concentrated on ethanol and natural gas processing plants in the United States, rather than the power sector. The Petra Nova facility in Texas is the only carbon capture project to trap CO2 at scale from a U.S. power plant — a metric that has not changed since President Joe Biden took office. Globally, there are two power plants with carbon capture in China and one in Canada, according to the Global CCS Institute, which supports the industry.

That revives questions about whether the technology has been adequately proven and if projects can reliably capture 90 percent of CO2 emissions. Among the challenges for the technology with power plants are high capture costs and a need for more pipelines to carry captured gas to storage sites.

EPA “relies on some very contestable assumptions of cost reductions and high capture rates, both have been disproven by multiple researchers in this field,” said Lorenzo Sani, an analyst on the power and utilities team at the think tank Carbon Tracker, in an email.

EEI’s Brouillette, former Energy Department secretary in the Trump administration, said that “while CCS and other 24/7 clean energy technologies could be important tools for reducing emissions in the future, EPA’s record does not support a finding that CCS is demonstrated today.”

Similarly, the Tennessee Valley Authority — which announced plans earlier this month to replace its coal-fired Kingston Fossil Plant 40 miles west of downtown Knoxville mainly with natural gas generation — said in a final environmental review in February that carbon capture “is an emerging technology and as a [best system of emission reductions] has not been adequately demonstrated.”

TVA spokesperson Scott Brooks said Thursday that the public power utility is reviewing the new EPA rule and noted that the utility is retiring older, less efficient generation and is incorporating more renewables into its system.

Regan told reporters that EPA has talked to members of the power sector for two years and that there are “numerous ones” that say CCS is “viable — they’re currently pursuing it.”

“So, we feel very confident about that,” he said. “We also can look at some of the tax incentives and other instrumentation from the Inflation Reduction Act that encourages this technology. I would say whether you’re a public or private entity, these rules speak for themselves.”

Other carbon capture supporters such as the environmental organization Clean Air Task Force said the technology is effective and that EPA’s new guidelines are stringent.

The 90 percent capture rate required by the rule is “easily done,” said John Thompson, the group’s technology and markets director, in an interview.

Thompson cited Petra Nova, which restarted capture operations in September after sitting idle for three years. It has captured 92 percent of the CO2 it processed, according to a 2020 technical report from DOE. Still, the facility frequently suffered outages over the three-year span when it was operational, according to the same report.

More recently, power producer Calpine applied for and received air permits in Texas to retrofit two natural gas plants with carbon capture, Thompson said.

“If companies didn’t think they could do this, they wouldn’t have applied [for permits] prior to the rule being finalized,” he said. “They just wouldn’t do it.”

Power producers should have ample time to implement carbon capture technology, Thompson said.

“When you’ve got what looks like eight years to go from conceiving of the project to getting the permits to getting constructed and operating, that’s a very generous period.”

Under the final rule, new combined-cycle natural gas plants that run more than 40 percent of the time will also need to use CCS by 2032. Carbon capture technology is typically more expensive to operate on gas than coal, as carbon dioxide is less concentrated in the plant’s flue stream and offers less potential revenue.

Carbon capture critics say there are better ways to cut emissions from power plants.

Emma Hopkins, a Sierra Club field organizer, said another project — a planned CCS retrofit of an electric generation unit in Louisiana that’s mainly fueled by petroleum coke — should not go forward.

“The EPA’s rule also makes clear that Cleco Power should retire its Madison 3 petroleum coke and coal plant rather than spending $1.4 billion to retrofit it with carbon capture and sequestration technology — ratepayer dollars that would be better invested in renewables, energy efficiency programs, and transmission,” Hopkins said in a statement.

In a statement, Cleco said it is company policy to “conduct its business in an environmentally responsible manner” and that includes complying with environmental laws and regulations such as EPA’s new rule.

“We strive to meet or surpass the conditions of all permits and all environmental rules and regulations to which we are subject,” said Maile Murray, director of environmental, health and safety at Cleco, in an email.

On Thursday, Ann Duhon, a spokesperson for NRG Energy — which operates but doesn’t own Petra Nova — said the project proved that a commercial-scale carbon capture project could be successfully built and operated.

While the Texas-based power company remains supportive of CCS “as an important emissions-reducing solution” to hit global climate targets, NRG doesn’t have “any current plans to install [additional] carbon capture technology at any of our plants,” Duhon said.

How will utilities handle the emission cuts?

The boom in new data centers, manufacturing plants and electric cars is driving up electricity demand for the first time in decades. A 2023 report from consulting firm Grid Strategies found that the U.S. could add 38,000 megawatts of peak demand by 2028, a nearly 5 percent increase.

As a result, some utilities have said they need a flood of new gas generation — plants that will now face requirements to slash emissions.

Michelle Solomon, a senior policy analyst at the Energy Innovation think tank, said the emissions rules could force utilities back to the drawing board to find alternatives to gas.

“It’s my opinion that there’s nothing better than regulation to spur innovation,” said Solomon in an interview. “Utilities are out of practice with growing the grid and that leads them to have a knee-jerk reaction and turn to the fossil fuel plants they’re most familiar with. But we have so many options to expand our grid in a cleaner way.”

Clean energy groups say advances in long-duration energy storage could allow clean power to be dispatched for dozens of hours, for example. Research is showing viability for geothermal power that derives electricity from natural subsurface heat.

The Biden administration says it’s confident utilities can keep the lights on even while cutting emissions.

The final rule moved the date that carbon capture must be in use for coal to 2032 from 2030 in the draft proposal. It also allows states to keep retiring plants online for an additional year if they can show that the retirement threatens grid reliability.

Gas plants that operate less than 40 percent of the time are exempt from the strictest standards, allowing utilities to keep those plants online for periods of peak demand.

Todd Snitchler, president and CEO of the Electric Power Supply Association, said in an interview that while the timeline shift will help, the administration’s plan still presents a “myriad of issues … in a system that’s already under stress.” Even if CCS infrastructure develops in the next decade, he said it can still take too long to get a plant permitted, sited and built.

“The operational realities of the system are now in conflict with policy goals,” said Snitchler, whose group represents power generators.

In some cases, the rule parallels what utilities are already doing, especially in states that have their own climate goals.

One of the Midwest’s largest electric utilities, Michigan-based DTE Energy, said the EPA rule “broadly aligns” with the company’s clean energy plan, which calls for retiring its last remaining coal-fired power plants, including the 3,280-MW Monroe plant south of Detroit by 2032.

“We’ve worked closely with the EPA to advocate for sensible rules that balance the need for investments while ensuring our customers’ bills stay affordable,” the utility said in an emailed statement.

However, companies running other coal plants now will have to revisit their plans.

The operator of the coal-fired 1,600-MW Prairie State Energy Campus in southern Illinois — the state’s largest source of CO2 emissions in 2022 — said in a statement it is exploring the viability of a partnership with a third party to install carbon capture technology but stated the EPA rule would have an “unprecedented impact” on the plant as well as the rest of the nation’s coal fleet.

The Prairie State plant and two other publicly owned coal-fueled plants in Illinois face more stringent compliance timelines under the EPA rule than they do under the state’s landmark climate law enacted in 2021.

EPA is collecting comments on the possibility of cutting emissions from existing gas plants, which were not part of the final rule Thursday.

Regional power grid representatives say that growing use of renewables, coupled with retirements of coal and gas plants, leaves the grid at risk at times when the sun is not shining or the wind is not blowing.

But Energy Innovation’s Solomon said improvements to the nation’s transmission system could “get more out of the grid” and allow more low-carbon energy. The Biden administration paired the power plant rule with a suite of new transmission announcements, including a goal to upgrade 100,000 miles of existing lines in the next five years.

“A fossil-fueled electric grid is expensive and unreliable, and 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,” Heather O’Neill, president and CEO of Advanced Energy United, said in a statement.

Will the rule nix plans for ‘clean’ hydrogen?

Power providers could switch gas plants to run on cleaner-burning hydrogen under the rule, although the fuel is no longer listed as a benchmark technology to meet EPA’s standards.

That differs from an EPA proposal last year that highlighted hydrogen produced with renewable energy as a technology for emissions reductions.

Even so, “the omission is basically a nonfactor for hydrogen,” said Salem Esber, an energy adviser at PA Consulting, in an interview.

Hydrogen’s use for gas-fired power plants today is limited to the low-capacity ones that aren’t covered under the rule, he said.

Similarly, Fuel Cell and Hydrogen Energy Association President Frank Wolak said U.S. utilities will likely continue to announce hydrogen pilot programs and may consider retrofitting gas turbines with hydrogen-compatible ones.

Wolak and Esber agreed that hydrogen’s future in the power sector hinges on the industry increasing production of low-cost fuel rather than EPA’s final regulations.

“The lack of [hydrogen] in rulemaking doesn’t change the pathway that hydrogen was needing to go,” Wolak said.

Before Wednesday’s announcement, several U.S. utilities had announced plans to incorporate hydrogen into gas-fired power plants through small pilot projects. Florida Power & Light, a NextEra Energy subsidiary, and Duke Energy are among those companies.

The two utilities did not respond to requests for comments on whether EPA’s new rules will affect their hydrogen projects.

Theo Keith, a spokesperson for Xcel Energy, a utility and natural gas delivery company interested in using hydrogen for power generation, said EPA’s regulations don’t change the company’s plans or mean it will turn to carbon capture.

“The technology and economics will determine the timeline to net-zero,” natural gas and carbon-free electricity by 2050, he wrote in an email.

Wolak said that a key factor in ramping up hydrogen production is flexible rules for tax subsidies from the Inflation Reduction Act, known as 45V. Wolak’s group and others have argued that proposed guidance from the Treasury Department on those credits will stifle the deployment of clean hydrogen. Treasury has not yet released final guidance.

A federal advisory committee earlier this week published a report that made 23 recommendations to help the hydrogen industry expand the production of clean, low-cost fuel.

Correction: An earlier version of this story misidentified the Prairie State Energy Campus in southern Illinois.