Despite Growth of CCS Projects, Profitability Remains Elusive

With more carbon capture and storage (CCS) plants operating than any other place in the world, the U.S. knows what it needs to make CCS work and accelerate deployment.

Getting all the ingredients together for large-scale ramp-up remains the challenge.

CCS project developers have found geology favorable for sequestering captured carbon, including in the Gulf of Mexico Basin, home to the Haynesville Shale. They have pinpointed spots where tons of emissions exist. Some, particularly those in the U.S. Gulf Coast, also have access to CO₂ pipelines and other existing infrastructure. Many focused on capturing their own emissions are making some progress.

The U.S. and other parts of the world are counting on CCS to help lower greenhouse-gas emissions. However, locking in agreements with emitters willing to pay for costs associated with carbon capture may be a struggle.

For many, decisions on whether to capture comes down to economics, despite the environmental benefits. That, experts say, is contributing to the pace of growth for CCS—even as federal dollars arrive for some projects and long-awaited permitting milestones are reached for others. CCS technologies remain expensive, particularly for post-combustion processes such as for power plants and for cement and steel operations, according to Jeffery Jen, a senior associate with Enverus’ energy transition research team. CO₂ purity and low concentration are making it more challenging and ultimately, more expensive to capture.

“As more CCUS (carbon capture utilization and sequestration) projects are put in-service, there will be operational learnings that will benefit the economics and execution of these projects,” said Jen. “CCUS needs to go through the same learning cycles as mature industries such as oil and gas before it reaches its ‘plateau of productivity.’”

Lingering cost concerns

There were only 15 CCS facilities operating in the U.S. in December 2023, according to a Congressional Budget Office (CBO) report. The Global CCS Institute reported that the U.S. was home to 260 of 564 CCS projects worldwide in various stages of development as of March 2024.

Analysts forecast those numbers to grow amid the continued drive to lower emissions, but costs are a deterrent for most of the heavy emitters that need CCS the most. In many instances, costs outweigh value.

“Estimates of the cost to capture CO₂ come mainly from engineering and economic modeling and can vary widely depending on the assumptions made in that modeling,” the CBO said in its report. “An indicative range of estimates is from about $15 to $120 per metric ton of CO₂ captured, with additional costs for transporting and storing the CO₂. Sectors at the lower end of that range provide fewer opportunities for capturing significant amounts of CO₂.”

Power generation and industrial production capture projects are on the pricier side, leaving the sectors little financial incentive to pursue such projects. “The main financial incentives to use CCS are revenues from enhanced oil recovery and a federal tax credit for capturing and storing CO₂,” the CBO said. It later added that costs may fall as more CCS projects come online and illustrate best practices. Plus, researchers are studying ways to make CO₂ capture less expensive.

“Optimistically, we do think costs are coming down,” said Peter Findlay, director of CCUS analytics for Wood Mackenzie. Speaking during the consultancy’s Houston conference, he pointed out the falling levelized cost for CCS. “We think most of what’s shown will be incremental, but transformational technologies are possible. There’s lots of companies working on them. There’s lots of startups, venture capital money … and we do think with scale and some modularization and transformational technologies, it could probably come down lower than this.”

Tapping tech, ‘low-hanging fruit’

Targeting lower post-combustion capture costs, some companies are developing new amines, metal organic frameworks and other novel capture methods, Jen said. Federal tax incentives such as the 45Q tax credit for CCUS is not enough to move some big emitters into CCS action.

“With only $85/tonne from the 45Q to work with, many of these post-combustion applications are left uneconomic before accounting for the cost of transporting and storing the CO₂. This is further exasperated by the fact that post-combustion industries are typically the ones that have the highest emissions and the ones that should install CCUS,” Jen said. “However, the way the 45Q and U.S. policies are structured, there are no penalties for emitting (other than California, which has a cap-and-trade system), so if emitters cannot capture their emissions, transport it and store it for under $85/tonne, then they will not.”

Many companies moving forward with CCS projects are targeting pre-combustion capture, which is more efficient than post-combustion capture because the CO₂ is more concentrated and at a higher pressure. That makes pre-combustion capture more attractive, said Aethon Energy President and Partner Gordon Huddleston, calling it low-hanging fruit.

“We have these existing pure streams of CO₂ being emitted that can easily be captured and then transported, and the nature of the basin is that there’s a lot of geology that is prospective for carbon sequestration,” Huddleston said. “The industry needs to prioritize these types of projects [as] the lower hanging fruit, as well as make sure they do it correctly.”

Dallas-based Aethon is perhaps best known for being one of the largest natural gas producers in the Haynesville Shale. But the company, which got a little bigger with its $260 million acquisition of Tellurian’s upstream and midstream assets, is positioning itself to become a major carbon capture player in the South. With 10 amine plants in its midstream portfolio, Aethon is focused on pre-combustion capture from its own assets and third parties.

Like bigger CCS players, Aethon plans to handle the capture, transport and storage of CO₂ on its own. The company is early on the permitting process. Others are already marking milestones.

Gaining project, permit momentum

A monumental moment for the global CCS sector was marked overseas in September when the Northern Lights CCS project officially opened in Norway. The first phase capacity of 1.5 million tons of CO₂ per year is fully booked, according to Equinor and JV partners Shell and TotalEnergies. CO₂ is captured from industrial sources and stored underground in the North Sea.

Chevron is pursuing CCS projects onshore and offshore in the U.S., with experience gained from operating one of the world’s largest CCS projects—Gorgon offshore Australia. More than 10 million tonnes of CO₂ has been injected since the system started up in 2019, according to Chevron’s website. CO₂is taken from offshore gas reservoirs and injected into a huge sandstone formation 2 km beneath Barrow Island.

In the U.S., Chevron’s signature CCS Bayou Bend project in southeast Texas is progressing. Two stratigraphic wells, one offshore and one onshore, have been drilled for the project that is being developed as Bayou Bend East (offshore) and Bayou Bend West (onshore).

Majors are not the only ones marking milestones.

California Resources Corp.’s carbon management arm Carbon TerraVault (CTV) expects to receive its Class VI permit from the U.S. Environmental Protection Agency (EPA) in December, moving closer to establishing the state’s first commercial-scale CCS facility.

“Shortly after receipt of the EPA permit, we expect to FID and break ground on our first carbon capture to storage project at our Elk Hills gas processing plant,” California Resources CEO Francisco Leon said during the company’s third-quarter earnings call.

CTV’s first capture-to-storage project at California Resources’ Elk Hills cryogenic gas plant is part of the CalCapture project, which aims to capture and permanently store 1.5 million metric tons of CO2 annually. It is a targeted milestone that CRC has been discussing for about three years as it works to decarbonize California’s hard-to-abate industrial sectors, including power. The company has about 3 mtpa of brownfield CCS projects under consideration along with about
1.2 mtpa of greenfield projects.

Due to the significant amount of time and staff it takes to understand Class VI wells and to ensure no public harm comes from such wells, it historically takes about 42 months for Class VI permit approvals, Jen said. In North Dakota, which has primacy, it’s about an eight-month approval process.

But permits for Class VI wells are starting to trickle in, including a draft permit to Oxy Low Carbon Ventures for three proposed geologic CO₂ sequestration wells in Ector County, Texas.

Chevron’s permit application is in the technical review phase, expected to take a couple years. It received the EPA’s “administratively complete” acknowledgement for its offshore Class VI well earlier this year, Chris Powers, vice president of CCUS and emerging for Chevron New Energies, told Oil and Gas Investor. Work continued at the time on progressing the permit process for the onshore project.

“The technical review remains the longest portion of the Class VI review process,” Jen said, “and there is an effort between the EPA and industry to standardize the applications to streamline the application process.”

‘Massive influx’

In Louisiana, legislators and regulators are working to strengthen the sector, having enacted laws that give pipeline companies authority to expropriate property rights for pipelines transporting CO₂ for CCS projects and another that authorizes unitization for CO₂ sequestration. But it’ll take some time to move projects through the Class VI permit approval process.

When the state got Class VI primacy it wanted to re-evaluate pending applications from the beginning, Jen said.

“With [Louisiana] being one of the highest quality storage locations for CO₂ sequestration, specifically along the Gulf Coast, the Louisiana Department of Energy and Natural Resources is dealing with a large permit queue of 26 projects, totaling to 65 Class VI wells,” he added. “Since [Louisiana] was awarded primacy in December 2023, we have not seen any Class VI permits be approved from the state.… [Louisiana] is still dealing with the massive influx of projects that were in the queue from the EPA and we expect that it will still benefit from primacy, issuing permits faster than the historical 42-month timeline from the EPA.”

Aethon Energy is in pursuit of permits needed to jumpstart its CCS project targeting the capture and sequestration of 3 million tons per annum (mtpa) in Louisiana and Texas.

“The reservoirs where we’re looking at will have further ability to take additional CO₂, but that’s kind of how we’re scoping the project today,” Huddleston said. “We want to expand it. We’ll have to increase the overall plume size but I think the key is the geology is there to support that.”

As of early November, Aethon’s permit applications for Class V wells in Louisiana were in the public hearing phase. If secured, the permit will give Aethon permission to start drilling stratigraphic wells, which are typically drilled to gather geologic data, before Class VI wells are drilled for CO₂ injection. Public hearings set by the Louisiana Department of Energy and Natural Resources could take place in early 2025. The company will seek Class VI afterward.

In Texas, Aethon has a wildcat permit that essentially allows the company to drill the so-called strat wells anytime, the company said. Here, Aethon is nearing the last step to obtain a Class II Permit from the Texas Railroad Commission, allowing the company to inject CO₂. The permit is being pursued as Aethon also works to obtain a Class VI well permit from the EPA to sequester CO₂ in Texas.

Aethon hopes to eventually scale to 10 Mtpa, but its focus today is on getting permits and lining up CO₂ offtake and transportation agreements.

Locking in offtake

Getting permits is only part of the journey. Locking in offtake is essential to making CCS projects happen, and first injection depends on customers.

“The critical path will flow through the customer signing up. So, the dates will be driven by when we get commercial certainty on the contracts, and that’s one of the biggest challenges, I think, for the industry broadly,” Powers said of Chevron’s projects. “45Q is helpful. But what we’re seeing—and again, remember, Bayou Bend is a customer-facing sequestration project as opposed to our own equity emissions—the customers are being thoughtful and methodical about how they’re deciding when they want to sign up to sequester the CO₂.”

Costs remain a major factor for customers with emissions, especially those requiring more expensive post-combustion capture. Post-combustion capture is considered more difficult because the concentration of CO₂ in flue gas is low, which means more energy is needed to separate it. This, in turn, makes the process more expensive.

Powers pointed out that capture costs for a refinery, power or chemical facility could be between 60% and 70% of the project’s overall cost. That could be an investment of hundreds of millions of dollars.

“The customers, the emitters, have to have the wherewithal and fortitude to say we’re going to make that capital investment on our own facility to capture the CO₂,” Powers said. “It’s a relatively smaller investment on the transportation and sequestration side. I think that’s what’s really causing this to pace a little bit. These emitters … they’re working to figure out, ‘hey, does the math work for me with the current rubric and construct?’”

Chevron has been in talks with many counterparties and is “making good progress,” he said.

In November, California Resources said CTV inked its first third-party brownfield emissions agreement: a memorandum of understanding with Hull Street Energy for a post-combustion CCS project targeting about 1.5 mtpa (million tonnes per annum) of CO₂ emissions.

The agreement with Hull Street Energy shows there is market appetite for such projects, California Resources CEO Francisco Leon said during the company’s third-quarter earnings call. The MOU is CTV’s first third-party brownfield emissions project.

“Our new MOU with Hull Street Energy, a leading power provider in a state that desperately needs more clean power today, is aligned with ours and the state’s climate objectives,” he said. “Natural gas is necessary to powering California today and combining it with CCS will deliver net-zero power, which is needed to achieve the state’s climate goals.”

Overcoming hurdles

The business case still doesn’t work for some emitters.

Some recent hurdles on building the business up is how lukewarm some folks are, according to Joe Colletti, a U.S. Gulf Coast CCUS venture executive for Exxon Mobil Low Carbon Solutions.

“They get excited to want to move forward on an opportunity but then maybe hold because they start thinking about policy risk or what happens with this election cycle,” Colletti said during Wood Mackenzie’s energy conference in Houston.

The energy giant is developing a CCS project as part of its planned low-carbon hydrogen plant in Baytown, Texas. It will store up to 10 million metric tons (mt) of CO₂ per year—equal to the emissions from more than 2 million cars.

The company in October signed its largest U.S. offshore CO₂ storage lease with the Texas General Land Office. The agreement is for a site larger than 271,000 acres.

Exxon, which strengthened its CCS business with its acquisition of Denbury, has more than 6.7 million tons of CO₂ under definitive agreements where it’s either the capturer, transporter and/or storage provider, according to Colletti. Exxon has lined up definitive agreements with customers from three industries: Linde, industrial gases; CF Industries, fertilizer manufacturing; and Nucor Corp., steel.

Findlay pointed out that companies like Exxon have made FID on projects, in part by building the whole value chain themselves or having one partner and a straightforward commercial agreement that works for both parties.

Community support is also part of the picture. Resistance is strong in some areas.

Public resistance

Carbon capture projects, including CO₂ pipelines, have already faced resistance for a variety of reasons. Safety—along with land rights and environmental concerns—is among them. Archer Daniel Midland’s (ADM) discovery of a potential underground CO₂ leak at its Decatur, Illinois, CCS site this year prompted the company to pause injection, sparking outcries from environmentalists and angst for CCS developers looking to get their projects off the ground.

The EPA in September issued a proposed enforcement order against ADM for alleged violation of its Class VI permit when injected fluid migrated into an unauthorized zone about 5,000 ft deep. The EPA said in a news release that the fluid migration was caused by holes in one of ADM’s monitoring wells. The lower portion of the well was plugged to halt further fluid migration, the company said.

Public opinion concerning safety of CO₂ pipelines and storage is among the biggest obstacles to development of CCS projects in the U.S., Jen said. Another public opinion obstacle is a belief by many that CCS is an idea propped up by the oil and gas industry to prolong its lifespan, though it will help decarbonize oil and gas as well as many hard-to-abate industries such as cement and steel.

“It will be up to the CCUS industry to continue to engage the public and educate them on not just the benefits but also the risks and how they are addressing the risks of CO₂ to the public,” he said.

Huddleston said Aethon has worked with Louisiana regulatory agencies as far back as 2018-2019 on carbon capture. The relationship included discussions on which types of reservoirs are suitable for storage and ensuring other safeguards are put in place. Among its suggestions was requiring developers take improved corrosion-resistant casing all the way to surface, spending the additional capital to guard against potential corrosion from any shallow water and encroachment of CO₂.

“It’s a relatively small amount of incremental cost when you look at overall project economics,” Huddleston said. “While technically it could be viewed as unnecessary, it provides an additional layer of safeguards that should give more comfort to adjacent landowners and residents.”

Companies should develop these projects as if they are living next to them. “I think that’s a very responsible way to think about it,” he said.