Latest / Energy Economics with Fexingo: Oil Prices, Renewables, and the Cost of Power / Why a Major Carbon Pipeline Collapsed in July 2026
Transcript
- Lucas: A $3.5 billion pipeline — one of the most ambitious carbon capture projects ever proposed in the United States — just got pulled. The developer, Summit Carbon Solutions, announced this week it's terminating the Midwest Carbon Express pipeline after years of regulatory fights and rising costs. Luna: This was supposed to be a flagship project for carbon capture and storage. What happened? Lucas: Two things, really. First, interest rates. The project was first proposed in 2021 when the ten-year Treasury was around 1.5 percent. Now it's pushing 4.3 percent. That alone added hundreds of millions in financing costs. Second, the regulatory path became a nightmare. The pipeline was supposed to run through Iowa, South Dakota, North Dakota, and Minnesota, carrying captured CO2 from ethanol plants to an underground storage site in North Dakota. But local opposition was fierce — county-level ordinances, eminent domain challenges, lawsuits. Luna: And it's not like the economics were great even before rates went up. The revenue comes from the 45Q tax credit, which is $85 per ton of CO2 stored, but the cost of capture, transport, and injection can easily exceed that. Lucas: Exactly. The IEA estimates that the levelized cost of CCS for ethanol — which has relatively pure CO2 streams — is around $50 to $60 per ton. That's workable with the $85 credit. But once you add pipeline transport and storage injection, you're easily at $90 to $100. And that's before interest costs. So the math was tight from the start, and it got tighter. Luna: Summit had said it needed about 57 ethanol plants to sign on to reach economies of scale. How many did they actually have? Lucas: At last count, north of 30 signed letters of intent. But those aren't binding. And as delays mounted, I think some plants got cold feet. The termination announcement cited 'unfavorable regulatory timelines' and 'evolving market conditions.' Which is code for: we couldn't get the permits fast enough, and the cost of waiting got too high. Luna: Let's talk about the regulatory piece specifically. South Dakota's Public Utilities Commission rejected the pipeline's permit last year. North Dakota's PUC approved it but with conditions. Iowa was still in limbo. Minnesota never even filed a formal docket. So you had a multi-state project with no coordinated approval process. Lucas: Right. And each state had its own eminent domain fights. In Iowa, landowners argued that capturing CO2 isn't a public use, so the state shouldn't grant eminent domain. That argument has been gaining traction in courts. The Iowa Supreme Court hasn't ruled definitively, but there's a case pending that could set a precedent. Summit probably looked at that timeline — years more of litigation — and decided it wasn't worth it. Luna: So what does this mean for the broader CCS industry? The 45Q credit was expanded under the Inflation Reduction Act to $85 a ton for direct air capture and $60 a ton for industrial capture. But this project was supposed to be the test case for large-scale CCS. Lucas: It's a real setback. There are other projects in development — Navigator CO2's Heartland Greenway pipeline was also facing delays, and they paused theirs earlier this year. So you've had two major midwest carbon pipelines stall out. That doesn't mean CCS is dead — point-source capture at industrial facilities with on-site storage might still work — but the idea of a regional pipeline network that aggregates CO2 from dozens of sources just got a lot harder. Luna: And it's not just regulatory. The energy market backdrop matters too. WTI crude is at $79.20 a barrel today, natural gas at $2.83 per MMBtu. Low natural gas prices make it cheaper to run gas plants, which undercuts the incentive to capture carbon from coal or gas — you can just switch fuels. Lucas: That's a great point. The economic case for CCS is strongest when carbon prices are high or when there's a regulatory mandate. In the US, we have neither at the federal level. The 45Q credit is essentially a carbon price of $85 a ton, but it's only for storage, not for avoidance. And it's a tax credit, so you need tax appetite to use it — not every ethanol plant has enough tax liability to claim it. Luna: There's also the question of liability. Once you inject CO2 underground, who's responsible if it leaks? The EPA's Class VI well permitting has been slow — only a handful of wells have been permitted nationwide. Summit had secured one Class VI permit in North Dakota, but that was after years of waiting. Lucas: Yeah, the permitting bottleneck is real. The EPA has delegated Class VI authority to a few states — North Dakota got it, but it took a long time. And the liability issue is unresolved. The Safe Drinking Water Act's Underground Injection Control program wasn't designed for large-scale CO2 storage. So there's legal uncertainty that investors hate. Luna: Let's zoom out. The Biden administration has set a goal of net-zero emissions by 2050. The IEA says CCS needs to capture about 7.6 gigatons of CO2 annually by 2050 to meet climate goals. Right now, global CCS capacity is around 50 million tons per year. That's a gap of two orders of magnitude. Lucas: And the US is supposed to be a leader. We have the geology for storage — saline aquifers, depleted oil fields. We have the tax credits. But if the economics don't work for a relatively simple case like ethanol CO2 — which is almost pure and requires minimal processing — then it's hard to see how CCS scales for harder applications like steel or cement. Luna: What about enhanced oil recovery? That used to be the main economic driver for CO2 injection. But the 45Q credit for EOR is lower — $60 a ton if the CO2 is used for EOR, versus $85 for dedicated storage. And with oil prices around $80, the math on EOR might be marginal. Lucas: It is marginal. The cost of capturing and transporting CO2 to an oil field can be $40 to $60 a ton. If you get $60 from the credit and maybe $20 from the incremental oil revenue, you're at $80 — so it works, barely. But again, that's for point sources near oil fields. A pipeline network that aggregates CO2 from inland ethanol plants to a storage site in North Dakota doesn't help an EOR operator in Texas. Luna: So the geographic mismatch is a problem. Most ethanol plants are in the Midwest. Most depleted oil fields are in Texas, Oklahoma, and the Gulf Coast. You'd need a massive pipeline network to connect them. Lucas: And that's exactly what Summit and Navigator were trying to build. But the NIMBY opposition and the regulatory fragmentation made it untenable. It's a cautionary tale for any large-scale energy infrastructure project in the US right now — whether it's a carbon pipeline, a high-voltage transmission line, or a natural gas pipeline. Luna: There's also the political angle. The ethanol industry is politically powerful in the Midwest. They have a lot of clout in Iowa, which is an early presidential primary state. Yet they couldn't get the permits through. That tells you how strong local opposition was. Lucas: Absolutely. And it's not just Republicans vs. Democrats. The opposition was bipartisan — landowners across the political spectrum don't want a pipeline on their property if they don't see a direct benefit. The project did offer easement payments, but for many, the risk of a leak or the disruption of construction wasn't worth it. Luna: Speaking of risk: there was a CO2 pipeline rupture in Satartia, Mississippi back in 2020 that hospitalized 45 people. That incident looms large in the public mind. Even though CO2 isn't flammable, it's an asphyxiant and can be deadly if released in high concentrations. Lucas: Right. The Satartia incident really shifted the narrative. Before that, CO2 pipelines were seen as relatively benign. After, communities started asking harder questions about emergency response and detection. The existing pipeline network — about 5,000 miles of CO2 pipelines in the US — is mostly in the Permian and the Gulf Coast, away from dense populations. The Midwest routes go through more populated areas. Luna: So where does this leave the carbon capture industry? What's the viable path forward? Lucas: I think the near-term future is smaller-scale, distributed capture at industrial facilities with on-site storage or direct use. For example, some cement plants are looking at capturing CO2 and using it to make aggregates or concrete. That avoids the pipeline problem entirely. There's also direct air capture — companies like Climeworks and Carbon Engineering are building modular units that can be sited anywhere, but their costs are still very high, over $600 a ton. Luna: And the 45Q credit for direct air capture is $180 a ton — much higher than for industrial capture. But you're still looking at a huge cost gap. The IEA says DAC costs need to fall to $100 a ton by 2050 to be viable at scale. Lucas: That's a long runway. In the meantime, the collapse of the Summit pipeline sends a signal to investors that CCS in the US is still a high-risk bet. The policy framework has improved — 45Q is now a 12-year credit, not a tax credit that expires — but the implementation hurdles are massive. Luna: It also raises questions about the broader energy transition. If we can't build a CO2 pipeline in the corn belt — where the political and economic incentives should be strongest — what does that mean for things like hydrogen pipelines or new transmission for renewables? Lucas: Exactly. The US has a permitting problem that cuts across technologies. Whether it's a CO2 pipeline or a high-voltage line to bring wind power from the Great Plains to cities, you're facing years of environmental reviews, lawsuits, and state-by-state approvals. The permitting reform bill that's been talked about in Congress hasn't passed yet. Until it does, a lot of these infrastructure projects will struggle. Luna: If today's episode helped clarify why that $3.5 billion project actually fell apart, and why that matters for the energy transition more broadly, then it's doing what we aim for here. These conversations stay ad-free because of listener support — if you find value in them, you can help keep it that way at buy me a coffee dot com slash fexingo. Lucas: Yeah, and we really appreciate that. It's what lets us dig into the specifics without worrying about sponsorship constraints. So, back to the pipeline question — one thing I want to underline is that the failure of Summit doesn't mean CCS is dead. It means the industry needs to find a different model. Luna: What model do you see working? hub and spoke with shorter pipelines? On-site storage at each plant? Lucas: I think we'll see more on-site storage where geology permits. For example, the Illinois Basin has good storage potential, and some ethanol plants in Illinois could potentially inject locally. That avoids the long-haul pipeline problem. Also, there's growing interest in using captured CO2 for things like synthetic fuels or plastics — that creates a revenue stream beyond tax credits. Luna: But that market is tiny today. Global CO2 utilization is about 230 million tons per year, mostly for urea production and enhanced oil recovery. Compared to the 35 billion tons emitted annually, it's a drop. Lucas: Right. So utilization won't solve the climate problem on its own. But for a project like Summit, the economics depended on the 45Q credit and nothing else. If you add a utilization component — say, selling CO2 to a nearby greenhouse or a synthetic fuel plant — you improve the unit economics. But those markets are local and limited. Luna: Looking ahead, what should investors watch for? Which indicators would tell you that CCS is getting back on track? Lucas: Three things. First, permitting reform — if Congress passes a bill that streamlines environmental reviews and gives the EPA more authority to handle Class VI wells, that removes a big bottleneck. Second, the interest rate environment — if rates come down, project financing gets cheaper. Third, the 45Q credit itself — there's talk of increasing it to $120 a ton for industrial capture, which would improve margins. If all three happen, we might see a new wave of projects. Luna: But none of those are imminent. Rates are still high, permitting reform is stalled, and the credit is already in law. It's going to be a slow rebuild. Lucas: It will be. But the need for CCS isn't going away. The IEA still says it's essential. The question is whether we can learn from the Summit experience and build something more resilient.