Energy companies are seeing growing opportunity to invest in U.S. low-carbon projects, especially with beefed-up tax incentives passed under the Inflation Reduction Act last summer.
But ubiquitous fears over project permitting, potential changes to political regimes and the huge capital lift required to get new projects off the ground pose huge risks to the nation’s emerging low-carbon marketplace.
Despite a myriad of different risks, permitting issues stand out as the biggest barrier to scaling the low-carbon energy transition at this point, experts discussed during Hart Energy’s Carbon & ESG Strategies conference on Aug. 31.
Carbon capture and storage (CCS) projects, for example, are getting tangled up in red tape as they move through the regulatory process. Projects in most U.S. states require permits from the Environmental Protection Agency (EPA) to drill Class VI injection wells, which are used to inject CO2 into underground reservoirs for permanent storage.
The EPA is currently working through a sizable backlog of permit applications for Class VI injection wells.
“CCS projects are just bereft with concerns about your ability to permit the project—whether it be the wells, whether it be the facility,” said Roger Fox, head of responsible investment at Tailwater Capital and CEO at Tailwater Innovation Partners.
Jennifer Stewart, director of climate and ESG policy at the American Petroleum Institute, said clean energy infrastructure projects are facing similar permitting hurdles that oil and gas producers have faced for years.
“[The biggest risk] is most certainly permitting: permitting for carbon capture investment, permitting for infrastructure, both carbon pipeline infrastructure and hydrocarbon infrastructure,” Stewart said.
So far, only two states are able to call their own shots when it comes to permitting Class VI wells for CO2 sequestration. The EPA has approved primacy, or primary enforcement responsibility, over Class VI well permitting in North Dakota and Wyoming.
The EPA also signed a proposed rule to approve Louisiana’s request for Class VI primacy earlier this year.
But outside of North Dakota and Wyoming, timelines for permit approvals are ballooning.
“That permitting side can take a while and you can have a lot of different agencies that you have to go through to get those,” said Jason Hill, counsel at Hunton Andrews Kurth.
“By far, the biggest holdup on getting federal permits is on the environmental reviews, and that’s driven by the statute called the National Environmental Policy Act,” he said.
There are about 120 pending permit applications for Class VI injection wells around the country, according to EPA data.
Cost, calendar complications
As the U.S. low-carbon sector works out its early kinks, some companies are seeing the resurgence of old-fashioned project execution risk, Fox said.
Unlike drilling a horizontal oil well—a fairly streamlined manufacturing process replicated in basins across the country—there really isn’t a playbook for developing a successful low-carbon project at scale.
Ambitious projects in the CCS space, such as direct air capture (DAC), are relying on emerging and early-stage technologies.
And these technologies aren’t cheap—Occidental Petroleum is spending roughly $1.1 billion to build its first commercial-scale DAC project in the Permian Basin, according to the company’s most recent update to investors.
“The CCS projects we talked about today—they’re a lot of money. These aren’t small bets,” Fox said. “And these things are not necessarily coming in on time or budget.”
So when you’re faced with enormous capital spending budgets, aimed at scaling technologies that largely haven’t been proven at commercial scale, underpinned by federal permitting uncertainty—it’s difficult to knit those together into an investible opportunity, Fox said.
“There can be some train wrecks out there,” Fox said.
Companies are keeping their options open and seeking multiple revenue streams as they dive into CCS. Exxon Mobil Corp.’s $4.9 billion acquisition of Denbury Inc. is centered around Denbury’s massive CO2 pipeline network and its onshore sequestration sites.
But Denbury’s core business of enhanced oil recovery (EOR)—where CO2 is injected into maturing oil reservoirs to maximize recovery—gives Exxon places to sequester CO2 while working through the Class VI permitting process.
That’s because the clock is ticking for some of Exxon’s CO2 offtake agreements, some of which were inked prior to the Denbury deal. The company’s agreement to transport and permanently store up to 2.2 million metric tons annually of CO2 from Linde’s hydrogen production facility in Beaumont, Texas, is slated to begin in 2025.
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