PAYNE INSTITUTE STUDENT COMMENTARY SERIES: COMMENTARY

Part One: Carbon, Capture, Utilization, and Storage

September 11, 2026

Landmen know not only the site of prospective developments but the landowners, regulations, rightsholders, and often the historical context that comes with it. They function at once as the historian, mediator, lawyer, educator, business developer, and the public face of a project. Steve Hawthorne brings 30 years of experience in oil and gas to his current work in CCUS, and his perspective frames a broader discussion of Colorado and federal CCUS policy across utilization, sequestration, and transport. As he puts it, landmen are “where the rubber meets the road- what you want to do vs. what is possible.”

Graphic: The landman touches each part of the CCUS value chain from inception to injection.

The challenge the industry didn’t see coming, in Hawthorne’s view, is infrastructure. “Often for the people near where the storage space is, the infrastructure is the biggest concern,” he notes, and pipeline projects in the Midwest have been cancelled as a result- an outcome the industry did not initially expect.  Part of what has left developers exposed to that backlash is a federal safety framework that hasn’t kept pace.  The Pipeline and Hazardous Materials Safety Administration (PHMSA) has regulated supercritical CO₂ pipelines under 49 CFR Part 195 for decades, but the framework carries meaningful gaps around emergency response training for local first responders, leak detection performance standards, odorant requirements, and coverage of pipelines converted from other service.  PHMSA moved to close those gaps in January 2025, using a Notice of Proposed Rulemaking that would have expanded phase coverage, lowered the concentration threshold from 90 to 50 percent, required emergency response training and equipment for local responders, and set leak detection standards. The NPRM was withdrawn from Federal Register publication five days later under a White House memorandum, and by June PHMSA had pivoted to soliciting comment on whether to repeal or amend existing pipeline safety requirements “to eliminate undue burdens” on domestic energy development.

Federal oversight of CO₂ pipelines today is substantively unchanged from what it was in 2020.  Into that vacuum, states have moved first and mostly in the opposite direction: South Dakota banned eminent domain for CO₂ pipelines in March 2025, Louisianna restricted it to common carriers in June, and an Iowa bill imposing similar limits passed the legislature before being vetoed. Hawthorne notes that when industry is “heavy-handed” in its approach to property right acquisition (bullying tactics to get right of way, up-front mention of eminent domain, lack of clear communication of pipeline risks and consequences) the response is often equally as combative, as evidenced by these states actions, and the impact of the Wolf, Navigator, and Summit pipeline projects.

Compensation raises a different problem: landowners are being paid to accept something on their property, not to share in what comes out of it.  Hawthorne puts the contrast directly: oil and gas is extractive- “you remove something of value and monetize it” – while for CCUS, “the part that has value is the space, you’re putting something in.” That difference shapes both what landowners expect and what developers can offer.  Royalties tend to be modest relative to oil and gas, so the incentive for many landowners rests less on the payment than on the chance to contribute to climate goals. The problem is sharpest where CCUS competes for attention against active oil and gas leasing. “The hardest thing to do is to sell a CCUS project, to acquire the rights, in a place right next to oil and gas,” Hawthorne notes, “because everyone around them is making oil and gas money.” Dry holes and abandoned prospects are easier ground: pore space that produced nothing has a floor value of more than zero, which is a better starting point than a neighbor’s producing well. Absentee mineral owners complicate the picture further: a landowner who cares only about mineral royalties may have little interest in what happens on the surface, leaving surface-level negotiations without an obvious counterparty.

On top of these structural frictions, the 45Q tax credit (retained and expanded under the One Big Beautiful Bill Act, which brought the enhanced oil recovery credit to parity with the storage credit) remains performance-based. Hawthorne describes the result as a “rent-seeking mindset” among landowners and their neighbors, in which the prospect of larger payments drives a scramble for greater compensation. For investors, that scramble may not be warranted: unitization holdouts, shifting policy, uncertain project economics, and the prospect of a “dry well” all weigh against returns. OBBA did introduce new flexibility, allowing the 45Q credit to be transferred to a single taxpayer and lowering the barrier to entry for investors. Landowners themselves are still unlikely to directly receive the credit for a project sited on their land, leaving them dependent on developers. A fixed credit for landowners, one not tied to performance, could temper the rent-seeking that drives holdouts, and the new transferability mechanism offers a plausible route to implementing it, giving landowners a more direct stake in project returns.

Aggregating land is a third arena, and the one where landmen play their most central role. Familiarity with group leases informs estimates of available storage capacity, the structuring of pooling agreements, and strategies for handling holdouts, which, in Hawthorne’s experience, are less rare than developers might hope. “Some people say ‘I don’t want anything on my land’” he notes. “There are people who will just say no.  You have to figure out several places, to have some options and ways to store CO₂, even if some locations don’t work out.”  Rerouting around a holdout is the practical response, but it isn’t always available, and the harder cases are what push the industry towards legal tools that override individual holdouts.  Forced pooling combines leases even where not every leaseholder consents, while still extending incentives to all.  It’s well established in oil and gas, where state oil and gas commissions like the Colorado Energy and Carbon Management Commission can set a proportional, fair price for those who decline. CCUS has few equivalent forums (though these are increasing). A dedicated CCUS commission, or a purpose-built docket within an existing one, would give parties a place to bring disputes, work through them, and settle on a fair price. 

Eminent domain, specifically when it comes to pipelines, is a more difficult puzzle to solve.   Louisiana has been pulling back on it since 2024, first removing it for geologic storage, then limiting pipeline eminent domain to “common carrier” projects and raising the unitization threshold from 75 to 85 percent landowner consent. A pending constitutional challenge could narrow what remains.  Oil and gas eminent domain cases establish just compensation and can involve forced pooling, but CCUS runs into a problem oil and gas doesn’t: there’s no settled price for pore space, and no clear market or policy floor to work from.  The Summit case shows what that looks like in practice.  After years of marketing its Midwest Carbon Express as pure sequestration, the company shifted in March 2026 toward enhanced oil recovery, a pivot analysts have tied to the OBBA change that brought the EOR credit to parity with the storage credit.  That story is still developing.  As long as the market and policy for CO₂ remain this unsettled, pore space won’t have a price landowners and investors can agree on.

At the state level there has been a push to increase the speed at which Class VI permits are approved, by applying for Class VI primacy or by implementing mechanisms to process them faster. Colorado is no exception: the ECMC submitted its Class VI primary application to the EPA on October 7, 2025, and EPA published a proposed approval in the Federal Register on March 19, 2026 (with a final decision pending).  If granted, primacy will let the ECMC issue and enforce Class VI permits directly rather than route them through EPA Region 8.  Additionally, the ECMC and Wyoming Department of Environmental Quality signed a memorandum of understanding to coordinate on projects near their shared border, since CO₂ plumes migrate through geologic formations that don’t stop at state lines. Other states with primacy offer some indication of what to expect.  North Dakota has issued 8 Class VI permits since 2018, Wyoming has issued 9 since 2020, Louisiana has approved its first permit since receiving primacy in 2024, while West Virginia, Arizona, and Texas all received primacy in 2025 and are still processing initial applications. By comparison, the EPA has issued 18 Class VI permit decisions since the program began in 2010 with more than 110 applications under review.  By using existing frameworks, agencies, organizations, partnerships, and processes: permits can move across the finish line quicker. However, it is yet to be seen if these advantages are fully realized and if they come to affect the speed of permit approvals.

Hawthorne is cautious about how much primacy will actually deliver. “Bringing that control to the state level should make things quicker and cheaper,” he says, “that remains to be seen with the ECMC.”  He draws a comparison to oil and gas, where the ECMC (formerly the COGCC) shifted over roughly a decade from facilitator to regulator, with different priorities coming along with that change. As of 2024, the ECMC’s adoption of carbon storage rules exceeds the EPA’s regulations and requires the submission of a cumulative impact and for the well to be sited at least 2,000 feet from residences, schools, or commercial buildings. Hawthorne wonders how that could play out for CCUS “If that attitude works into CCUS, you will see the primacy not resulting in a lot of benefit.”  That skepticism sits alongside a genuine appetite for the technology in Colorado. Hawthorne points to both statewide emissions goals and to the more tangible concern about outdoor resources, and he expects the state to make CCUS more accessible than oil and gas has been. Where projects end up is shaped by geography as much as regulation: “Rural areas are easier than the front range, where it’s more suburban, and constrained by the mountains.”  Water is a related constraint, though a manageable one.  The demand is at the emitter, where the compression requires cooling, not at the injection site or along the pipeline.  Most current Colorado projects, including a pending injection permit at Windsor, are at ethanol plants that have their own water.  Extending CCUS to cement or power plants in growing areas would raise the water questions but Hawthorne expects it to remain “a footnote rather than a primary issue.” Subsurface characterization tends to reassure landowners once they see it: in Hawthorne’s experience, “most people walk away happier, or less unhappy when they hear about the level of evaluation.”

What Hawthorne describes in Colorado holds elsewhere too. Transport, compensation, and aggregation all come back to unresolved fundamentals. Pore space doesn’t have a settled price, federal safety rules for CO₂ pipelines are unresolved, and the tax credit that drives project economics is politically vulnerable.  States are moving in different directions on all three, some tightening restrictions and others clearing pathways, and the resulting patchwork is what any given project has to navigate.  Whether CCUS finds its footing will depend on regulators, developers, and landowners settling on workable terms once activity picks back up, and the landman is usually the first person to see how that goes.

ABOUT THE AUTHORS

Sarah Severin
MS, Natural Resources and Energy Policy, Colorado School of Mines
Sarah Severin is a student researcher at the Payne Institute for Public Policy and is currently pursuing a Master of Science in Natural Resources and Energy Policy at the Colorado School of Mines. Her research interests include energy politics and policy, political risk, carbon capture and its utilization and storage, and geothermal energy. Sarah graduated from Texas A&M University with a Bachelor of Science in political science. She is passionate about exploring energy systems, engaging young people in the energy landscape, and exploring the interaction between land use and policy.

Anna Littlefield
Payne Institute Geothermal and Low Carbon Energy Technologies Program Manager and Research Associate and PhD Student, Geology and Geological Engineering, Colorado School of Mines
Anna Littlefield is the Geothermal and Low Carbon Energy Technologies Program Manager for the Payne Institute at the Colorado School of Mines. As a current PhD student in the Mines geology department, her research focuses on the geochemical impacts of injecting CO2 into the subsurface as well as the overlap of geotechnical considerations with policymaking. Anna joins the Payne Institute with 8 years’ experience in the oil and gas industry, where she worked development, appraisal, exploration, new ventures, and carbon sequestration projects. Her academic background is in hydrogeology with an M.S. in geology from Texas A&M University, and a B.S. in geology from Appalachian State University. Anna is passionate about addressing both the societal and technical challenges of future of energy and applying her experience to advance this effort.

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DISCLAIMER: The opinions, beliefs, and viewpoints expressed in this article are solely those of the author and do not reflect the opinions, beliefs, viewpoints, or official policies of the Payne Institute or the Colorado School of Mines.