Carbon Capture Economics
The Inflation Reduction Act increased a tax credit for capturing carbon oxide emissions and extended the deadline to qualify. The tax credit, even before the latest increase, was already contributing to growing interest in installing carbon capture equipment at ethanol and fertilizer plants, steel mills and petrochemical facilities. More than 200 people attended an Infocast CCS and decarbonization summit in Houston in late July. The following is an edited transcript of a wide-ranging panel discussion on where carbon capture companies are getting traction, the risks in deals and how transactions are being structured.
The panelists are Cindy Crane, CEO of Enchant Energy, Aaron Hood, CFO of Summit Carbon Solutions, Tyler Durham, chief development officer of Navigator CO2 Ventures, Jeremy DeMuth, a managing director of Deloitte Tax, and Bob Purgason, managing director of carbon solutions for Enlink Midstream. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Cindy Crane, at what types of industrial facilities do the economics work currently for carbon capture, and why don’t they work for other types of facilities?
MS. CRANE: The economics seem to work best at ethanol plants. I am working on a carbon capture project at a large coal-fired power plant. We think such projects became economic with the funds that are available in the Biden infrastructure bill for demonstration projects. We just completed a FEED study that validated the economics, so we are excited to move forward.
MR. MARTIN: The economics don’t seem to work well at many power plants because of the parasitic load. The amount of electricity that must be used to compress the CO2 for transport is very high. I think at your plant it is something like 30%. Is that the main challenge for power plants?
MS. CRANE: It depends. Our power plant is owned by Enchant Energy. The carbon capture equipment will be owned by a separate company that will be a customer of the power plant for power, steam, water and flue gas. What you might call parasitic load in another context is actually a steady revenue stream for the power plant.
MR. MARTIN: Aaron Hood, Summit Carbon seems to be focusing on ethanol and fertilizer.
MR. HOOD: We are focused on all emitters whose emissions we can capture economically in our footprint area. Ethanol and fertilizer plants have the lowest cost to capture today. We are open to other emitters as the economics improve or section 45Q tax credit amounts increase.
MR. MARTIN: What is special about ethanol and fertilizer? Why do they have the lowest cost of capture?
MR. HOOD: They have a relatively pure carbon dioxide emissions stream. Ethanol plants have been capturing CO2 for industrial use for as long as they have been around to make fizzy beverages and dry ice. It is a relatively straightforward process technologically.
MR. MARTIN: Tyler Durham, you came from Schlumberger. It has been on the road pitching its services to capture emissions. Where are you finding that the economics do not work?
MR. DURHAM: The concentrated CO2 emissions streams are the easiest to capture. From a technical perspective, that is the first stop for carbon capture and storage. But it takes more than a pure CO2 emissions stream to make the economics work.
The challenge with ethanol facilities is they are spread out. A big part of any organized effort to capture their emissions is how to tie them together at scale. Contrast that with a post-combustion facility like a power plant where you may be looking at a technical challenge rather than a logistics and infrastructure challenge.
MR. MARTIN: Let’s unpack that. There are two CO2 streams in a typical industrial facility. There is a relatively pure one that is pre-combustion and then a dirtier one where the CO2 is mixed in with other gases. It is post-combustion. Is the point that the CO2 is more expensive to extract from a post-combustion stream?
MR. DURHAM: Yes. It is cheaper to complete the separation process with an emissions stream that is highly concentrated CO2. A lot of work is being done on the technology to make it more economic to extract CO2 from post-combustion emissions streams.
Until the technology improves, most of the capture projects will be at ethanol, fertilizer, bio-energy, steam methane reforming and other chemical plants that, by nature, generate highly concentrated CO2 streams.
MR. MARTIN: You anticipated my next question. What will be the next lowest-hanging fruit for carbon capture after ethanol and fertilizer? You included bio-energy on your list. Is that anerobic digestion and renewable natural gas?
MR. DURHAM: Certainly waste to gas will have concentrated streams that may be targets. It will depend on scale and how far they are from infrastructure. We expect to start seeing direct air capture pilot plants.
We also expect to see carbon capture at plants that are producing sustainable aviation fuels and other alternative fuels that are able to go to market only by controlling the carbon intensity of their production processes.
MR. MARTIN: Jeremy DeMuth, you look about to say something.
MR. DEMUTH: In addition to ethanol, ammonia and steam methane reformation, we are also seeing chemical production processes that release a lot of CO2. Then you start to get into the more difficult-to-capture post-combustion sources, such as steel mills. Carbon capture is becoming an environmental imperative for some of these companies.
Emerging Business Models
MR. MARTIN: That is a good bridge to the next topic, which is emerging business models. There doesn’t seem to be a single business model yet around which everyone has coalesced. The federal government puts a lot of money on the table in the form of tax credits. Every participant in the deal wants a share. The business model is driven by the commercial deal on who gets what share and how to label the money transfers.
The variations start with who owns the capture equipment. That is where the money comes in the first instance since the capture equipment owner is entitled to the federal tax credits.
Aaron Hood, will Summit Carbon own the capture equipment at ethanol and fertilizer plants?
MR. HOOD: We are using a vertically-integrated model at the 32 ethanol plants with which we have partnered today. What does that mean? It means we own the capture equipment. We build the pipeline. We own the storage facility in North Dakota.
That does a couple of things for us. First, it keeps all the risk under the same roof so that there are fewer players around the table negotiating about risk allocation. Second, our ethanol plant partners do not have to take a view on the potential uplift from the low carbon fuel standard or voluntary carbon markets. We know that biogenic removal credits for voluntary markets are going to be much more valuable than the credits that are available today.
MR. MARTIN: So there is less finger pointing if things go wrong? There is just one party to point to, and that’s you?
MR. HOOD: I think there will be plenty of finger pointing, but fewer people pointing the fingers.
MR. MARTIN: Tyler Durham, is that your business proposition as well?
MR. DURHAM: We are a little more flexible on business model. There are cases where we will own the entire chain. There will be other cases where the capture equipment is owned by the industrial facility.
MR. MARTIN: Will you act as both the pipeline and sequestration company?
MR. DURHAM: We will. Potentially all the way from the capture equipment to the sequestration or other use case. We see the voluntary carbon market as part of that. We expect to release some more news later this year on that side and how we see that market developing.
MR. MARTIN: In cases where your customers who are the source of the CO2 keep the capture equipment and therefore the tax credits, do you know if they are planning to use them themselves or to raise third-party tax equity?
MR. DURHAM: We may see both situations. It depends very much on the operator. Some have capacity to use the tax credits and others do not. In the latter case, we will have to bring in a tax equity investor, which adds another cost to the economics.
MR. MARTIN: Cindy Crane, who will own the capture equipment at the San Juan generating station?
MS. CRANE: Enchant Energy will own the equipment from capture all the way to storage. We will also own 95% of the power plant.
We hope to be the carbon capture and storage provider to the industry and are developing a pipeline of other projects. We want to remain flexible with owning a percentage of the emitter itself where it makes sense to do so. We will be looking to monetize the tax credits with tax equity investors, unless Congress enacts a direct-pay alternative.
MR. MARTIN: Did I hear you say you would also sequester the CO2? You will handle that part of it?
MS. CRANE: Yes, although we are open to joint venture partnerships for the transport and storage side. We are working on a CO2 pipeline today that will connect into the Cortez. That will allow flexibility for enhanced oil recovery.
We have also partnered with the New Mexico Institute of Mining and Technology on a carbon safe program. It is doing the work to characterize the geologic formation. We have identified the location of the injection wells. Our joint venture partner is preparing to drill the stratigraphic well, but the EPA class VI injection well permits will be filed in Enchant’s name.
MR. MARTIN: Jeremy DeMuth, it looks like you want to add something.
MR. DEMUTH: The IRS issued a helpful revenue ruling last year that lets the tax credits be claimed by someone who owns at least one component of a single process train of carbon capture equipment. A single process train means everything from capture all the way through compression and preparing for transport.
That means you may have different companies owning different pieces of a single process train. It allows flexibility to have one party do the carbon capture while another can claim the tax credits.
MR. MARTIN: Let me ask on that. The problem was a lot of factories have a gas separation unit that is embedded in the factory and is as old as the factory. The IRS regulations say the tax credits belong to the person who owns the capture equipment, but it is impossible to take that piece out and give it to a tax equity investor whom you want to claim the tax credits. So, as you said, the IRS concluded last July that a person who owns at least one piece of the capture train and has responsibility for disposing of the CO2 can claim the tax credits.
How little of the capture train do you feel comfortable saying that person can own? Most tax advisors, I imagine, will be uncomfortable with owning a single compressor.
MR. DEMUTH: You have a lot of flexibility because of the revenue ruling, but I don’t think that it would be good to push it too close to the edge.
MR. MARTIN: Let’s turn to revenue sources. There are at least two revenue streams coming into these deals. One is a federal tax credit of $50 a metric ton for captured CO2 that is sequestered permanently underground and $35 where the CO2 is used for enhanced oil recovery or to make a commercial product. [Editor’s note: The Inflation Reduction Act increased the tax credit amounts to $85 and $60.]
Aaron Hood mentioned an uplift for LCFS credits in California. That is a potential benefit for ethanol producers whose ethanol is being supplied, in theory, to the California market. But if they capture the carbon emissions, the credits are worth more because the ethanol will be assigned a lower carbon intensity. What about other revenue streams? Cindy Crane, you mentioned one.
MS. CRANE: The voluntary credit market is just getting started. Direct pay is another revenue source that allows the section 45Q tax credits at the federal level to be converted into cash without having to go through tax equity investors.
MR. MARTIN: The voluntary credit market is the carbon offset market?
MS. CRANE: Yes. Many companies with carbon emissions will be looking for offset credits in circumstances where it is not economic or practical for them to decarbonize directly. While we are not counting on additional revenue from it in our pro formas, we hope to see that market evolve over the next two to four years.
MR. MARTIN: You made an important point, which is it is hard to take revenue streams into account during financing unless they are predictable. Aaron Hood, how predictable is the LCFS uplift?
MR. HOOD: It is not particularly predictable, but it has expanded beyond California into Washington, Oregon and all of Canada. A bunch of other US states are looking at low carbon fuel standards and building what has effectively become a compliance market.
We think that has great long-term value for us alongside the voluntary market.
Our project alone will capture close to 10 million tons of CO2 a year. It has the potential to change that market fundamentally. Obviously, there are ethanol producers who cannot ship their product physically to California. As the low carbon fuel markets expand across North America, the entire ethanol industry will benefit.
Ethanol has a carbon intensity in the mid-60% range. Capturing the CO2 reduces the carbon intensity by 30 or more points. It is not as if this makes only a marginal difference. It is a massive step change.
MR. MARTIN: We have seen revenue figures in projects where the LCFS uplift is worth more than the federal tax credits. Are you seeing that as well? What are the relative values?
MR. HOOD: LCFS credits have varied from $175 to around $100. They are a significant revenue source. Our projected operating expense to transport and sequester CO2 is about $25 a ton.
However, as you said, it has been challenging to get lenders to credit the LCFS uplift or voluntary offset credits toward any financing.
By having a vertically-integrated model, we are not nearly as reliant on that revenue stream. It is an equity risk and potential upside. It is not a risk we are asking the lenders or the tax equity partners to take.
MR. MARTIN: Where the CO2 is used for enhanced oil recovery, does the EOR company pay for the CO2, or is it paid to dispose of it?
MS. CRANE: The EOR company needs to pay to get the economics to work.
MR. MARTIN: What about where CO2 is turned into a usable commercial product? That must be another revenue stream.
MR. DEMUTH: We certainly see revenue streams from use of captured CO2 to make commercial products. We do a lot of work at Deloitte on the lifecycle greenhouse emissions analyses that are required in such situations. Aaron said earlier that people have been capturing CO2 for a long time and using it in dozens of different applications, from carbonated beverages to fire extinguishers to several intermediate chemicals. There is a big demand for CO2. It affects how much someone is willing to pay for it.
There has been a CO2 shortage in this country for the last couple years. Think about the amount of dry ice that has been needed for COVID vaccines.
MR. PURGASON: We have a transport-only role in our project in Louisiana, but we also have a project with BVK Corporation in the Barnett shale area in north Texas. Matheson will end up buying some of the CO2 to supply to the beverage market, and we will be paid a fee to bury the rest underground.
We spend a lot of time on the financial engineering around the projects, but in my mind, carbon capture is a regional business. You look at the nearby opportunities to use the captured CO2.
In Louisiana, there is a 200-mile corridor from Baton Rouge to New Orleans with many different emission sources, including ammonia, ethanol, methanol and ethylene, that need compression, transportation via pipeline and sequestration to get into the ground.
MR. MARTIN: We talked about low hanging fruit earlier. You are pointing out the low hanging fruit may not only be ethanol and fertilizer, but also where you have concentrated CO2 emissions and you can move them easily.
MR. DURHAM: One thing we have not mentioned is we expect companies to experiment with pilot-scale efforts over the next few years to use CO2 to make alternative fuels and to make new chemicals as potential replacements for chemicals used in more traditional chemical processing operations. That is another potential upside.
MR. MARTIN: All of this explains why most of the new carbon capture projects are in the Midwest, where there is lots of ethanol, and Louisiana and the Houston ship channel, where there are petrochemical facilities, LNG export terminals, steel mills and concentrated industrial corridors.
We talked about revenue streams: the tax credits are a large dollar amount. They are probably the most predictable revenue stream. There is an LCFS uplift. There may be carbon offset credits. There may be other revenue sources, like payments for buy CO2 to use in enhanced oil recovery or to make commercial products.
How does the revenue get split among the various deal participants? Is there a way of breaking it down among the emissions source, the capture equipment owner, the pipeline and the sequestration company? Or is it too early?
MR. HOOD: We have constructed a business model where we are not asking our ethanol partners to invest capital upfront. Many of our ethanol partners are single-plant facilities that are owned by the farmers that produce the corn that is sold to the ethanol plant. A single plant can have hundreds of shareholders. The plants have other things to do with their capital, whether it is distributing it to their owners or use for yield optimization in their plants. The way our revenue model works is we share the uplift with them after our operating expenses have been paid.
They have an infinite return on capital from the carbon capture project. They might not make as many dollars as they would if they were paying a tolling fee to us and installing their own capture equipment, but our business model dramatically lowers their complexity. They don’t have to worry about becoming carbon capture experts. They can worry about growing corn and making ethanol in as efficient manner possible. We are an agriculture company at the end of the day, and decarbonizing the agricultural industry is something we thought about when we conceived this company.
MR. MARTIN: You don’t pay anything to the fertilizer or ethanol plant. Rather, it pays you to come capture the carbon, and the payment is a function of the LCFS uplift it gets. Is that right?
MR. HOOD: There is an alignment of interests. It is a sharing of the returns from the project. We don’t ask them to pay us. We don’t pay them for their CO2. We pay: obviously we are going to spend $4.5 billion in capital expense. The pipelines are $3.5 billion out of the $4.5 billion when you run 2,000 miles of pipe.
MR. MARTIN: Tyler Durham, what is the Navigator business proposition?
MR. DURHAM: The revenue split may look very different in different places. For example, projects in the Middle East will be very competitive on price for the sequestration part, cheaper than in some parts of the US.
In the US, things will look different in the Gulf Coast than they do in California. It is more challenging in California to do a seismic survey, increasing the cost and pushing out the timeline to complete a project.
MR. MARTIN: Does Navigator follow the Summit Carbon model, where it is paid a share of the LCFS uplift?
MR. DURHAM: We have a couple ways to do that. We will do a fee-for-service, over-the-fence type arrangement where they pay us, we take the CO2 and they never see it. It is more closely related to a waste-disposal model. Alternatively, we may accept a smaller fee in exchange for a share of the upside.
MS. CRANE: We are a little different because—
MR. MARTIN: You are keeping it all.
MS. CRANE: For San Juan, yes, that is correct. But we are different because our carbon capture company relies on products that it needs from the power plant that is the source of the CO2 emissions. We have a good relationship between the carbon capture company and the power plant because we need its water, its power and its steam. And, by the way, we need the flue gas so that we can decarbonize the power plant.
The price we pay as the carbon capture company for all of that has to keep the power plant economic, meaning the power plant has to be able to attract its own capital and invest in maintenance of its assets.
MR. MARTIN: Jeremy DeMuth, are you aware of any tax equity deals that have closed?
MR. DEMUTH: The word on the street is one and perhaps two have signed documents. That may be high. We know of a number of deals that are in late-stage negotiations.
MR. MARTIN: One, maybe two, expected to close this year, but not yet closed?
MR. DEMUTH: That’s right.
MR. MARTIN: Let’s talk about risks. One of the biggest risks is that the emissions source, the factory, the ethanol plant, will shut down, eliminating the principal source of revenue. The tax credits run for 12 years. How is that risk being handled in deals?
MS. CRANE: In our deal, the carbon capture company is an anchor tenant of the power plant. Having the majority of the power contracted is a more favorable financing scenario.
MR. MARTIN: Aaron Hood, how is the shutdown risk being handled by Summit Carbon?
MR. HOOD: We don’t think the ethanol industry is going anywhere. Even under the most aggressive forecasts of how quickly the US will electrify the transportation sector, the US will still need a significant volume of transportation fuels for the full tax credit period.
Even if you cut the amount of ethanol needed in half, the Midwestern ethanol plants that are our focus are in the corn belt and the most efficient US producer of ethanol. The cheaper your corn, the better your position in the industry.
Having a portfolio of 30+ plants takes away a lot of the focus around what happens if I have a fire or my plant gets hit by tornado. If we were dealing with one or two plants, it would make things more complicated for sure. Having a large portfolio takes that off the table. Our largest single plant accounts for 4% to 5% of the total CO2. Having $6 billion worth of tax credits to monetize on the low side creates some other interesting issues.
MR. DURHAM: I agree that scale is the way to deal with shutdown risk.
We have 11 million tons a year of CO2 emissions under contract at this point. Our partners include Poet and Valero, two of the three largest ethanol producers in the country. We don’t think they are going anywhere.
MR. HOOD: Unlike oil and gas where different pieces of the value chain have been perfectly willing to put each other out of business for a buck, corn and ethanol go together in a way that you can’t stop making ethanol or the whole system comes apart. The farmers have to sell their corn somewhere. It is not what you see in oilfield services.
MR. MARTIN: Let’s move to another risk, which is big capital outlays are required to install the capture equipment, build the pipeline and put in the well sequestration facility. If there are two parties on either side — one owns the capture equipment, somebody else owns the pipeline and does the sequestration — it is a chicken-and-egg problem. Neither wants to spend money unless it is assured that the other is on track. How is this being handled?
MR. PURGASON: We look at it just like our traditional pipeline business, which is we look for some sort of volume commitments that produce a minimum capital return and then share the upside from volume growth. Fundamentally it is not if we build it, you will come type of opportunity. It is a big guys’ game. You have to step up and commit to something.
MR. MARTIN: So both sides commit to each other. What happens if one fails to perform or is delayed?
MR. PURGASON: Both parties are looking for long-term returns on their capital before they put it out.
MR. DEMUTH: Call it critical mass, both in terms on the supply side of CO2 as well as the destination side. If you are in a place like Louisiana with many potential sources of CO2 clustered together, that helps in terms of hedging if the CO2 source happens to have an issue.
You might have another potential offtaker connected to the pipeline that can use the CO2 if something happens on the disposal side. Having that critical mass not just on the source of the CO2, but also on the back end is important because it means there will be fallback options.
MR. MARTIN: Another risk is one of three things must be done with the CO2 to claim tax credits. Either it has to be buried permanently underground, it has to be used for enhanced oil recovery, or it has to be used to make a product that can be sold in the commercial market.
Let’s say it’s buried. It has to stay there permanently. If it leaks within the first three years, then the IRS will ask for some of the tax credits back. How is that risk being handled in deals?
MS. CRANE: The insurers are developing products to address this. We are not mature enough as a market to have put those to the test yet.
MR. MARTIN: Have the tax insurers given you any sense of what the premiums will be?
MS. CRANE: If they did, you would have to threaten bodily harm to get the information.
MR. HOOD: Before we get to recapture risk, we should talk about permitting risk for sequestration, which is to me the elephant in the room.
MR. MARTIN: Be my guest. How long does it take to get the permits?
MR. HOOD: It depends on whether you are in North Dakota. North Dakota has class VI primacy. We announced a joint development agreement with Minnkota, an electric cooperative. It has a permit for its five-million-ton-per-year Tundra East project, and it should receive the permit for its Tundra West project in the next 60 days.
Minnkota had a similar situation where it had to put out a tremendous amount of capital — probably a billion dollars — that will probably have to be borne by the ratepayers if the project fails to advance. We help Minnkota de-risk its sequestration effort by paying the capital costs up front and then having Minnkota pay us back over time as we inject CO2 into the ground.
It was a great move not only for Minnkota, but also for us. It accelerated our development timetable by taking the class VI permitting issue off the table.
We have acquired about 130,000 acres of pore space adjacent to the Tundra facilities, which is about a billion tons of storage capacity, so we think of it as a long-term asset. As direct air capture becomes a reality and carbon capture at other emitters like coal-fired power plants becomes economic, we will have plenty of storage capacity.
It is not just class VI primacy that helps; it is also amalgamation and having the state take over the risks of CO2 leakage 10 years after you cease operations. The infrastructure is there, and helpful legal decisions have already been made.
You can’t have one landowner holding up for more pore space. The cake has to be baked so you can have certainty. We have bought a third of our rights-of-way for our 2,000 mile pipeline. We could never spend money on rights-of-way if we did not have certainty around our class VI permits.
MR. MARTIN: Tyler Durham, where is Navigator planning to inject the CO2?
MR. DURHAM: We have filed our first class VI permits for sites in Illinois.
MR. MARTIN: We have heard it takes 18 to 24 months to get a class VI well permit. Does that sound right?
MR. DURHAM: That is not an unreasonable estimate. We expect there to be a rigorous review. The Mount Simon site in Illinois is a formation that has already been used and EPA is familiar with it, so those are factors that work in our favor.
MR. MARTIN: Bob Purgason, where a pipeline has to be built, how long should one assume it will take? Does it depend on the state?
MR. PURGASON: It depends on the state and the location within the state. Are you building in a marsh or on dry land? In Louisiana, it is easier to build in the northern part of the state than it is to build in the Mississippi Delta. Eighteen months is a typical project timeline, but it depends on what you already have in place. Having rights of way and existing pipeline corridors can shorten the time period.
MR. MARTIN: I didn’t get an answer to what happens to the tax credit recapture risk if the CO2 leaks from underground storage. The sequestration company bears that risk, correct?
MS. CRANE: Agreed
MR. DURHAM: Agreed, but without disclosing the premiums that we have been quoted, we think that risk will be insured.
MR. HOOD: I agree. Geologically, the risk is not as significant as people thought before they started learning about this in more detail.
MR. MARTIN: So you two plan to buy insurance.
What about environmental liability associated with an underground leak of the CO2. Is that a real issue? The sequestration company takes that responsibility too. Is there cap on its liability?
MS. CRANE: Where you are doing business matters. States like North Dakota and Wyoming have not just primacy, but also laws in place to deal with the transfer of CO2 liability after CO2 has been injected in the ground. The states that are really at the forefront are doing what they need to incentivize and give security for industry to decarbonize.
We are trying to push a similar bill at the federal level. We are also pushing for legislation in New Mexico.
MR. MARTIN: Protection from environmental exposure?
MS. CRANE: Yes, after injection. Transfer that liability to the state.
MR. MARTIN: The fact that you are working on a bill suggests you think it is a real issue.
MS. CRANE: Whether it is a real or merely perceived issue, the industry will want protection.
MR. HOOD: The more experience particular states have with oil and gas, the easier it is for them to get their hands around this. States like Louisiana, the Dakotas and Wyoming have been poking holes in the ground for 75 years. They are not jacked up about this. It is CO2.
MR. DURHAM: I agree with the exception of California.
MR. HOOD: The one good thing about California is CARB is really interested in carbon sequestration, so it wants these projects to succeed. It has been working hard with the EERC in North Dakota to accelerate the rulemaking around this. CARB has been pretty open minded about avoiding rules that are ridiculous and unrealistic.
MR. MARTIN: Bob Purgason, we all know how hard it is to build gas pipelines and electric transmission lines. Can eminent domain be used to site CO2 pipelines?
MR. PURGASON: It depends on the state, but there is no broad federal blanket, FERC-type eminent domain process. You have to have local engagement and make sure that the people are satisfied that you are going to take care of things. That is the way to get the pipeline in.
MR. MARTIN: Are the pipelines common carriers? Do they have to post a tariff? Is there a risk that anybody can knock on the door and say he or she wants to move CO2 on your pipeline?
MR. PURGASON: CO2 pipelines are not common carriers in Louisiana. But we are keen to take all comers and create the opportunity to move additional CO2.
MR. MARTIN: What about Summit Carbon and Navigator? Are your pipelines common carriers?
MR. HOOD: We will be a common carrier. The one complexity with CO2, unlike gas or oil, is you have to have something to do with it at the other end of the pipe. If you don’t have storage, that is a problem.
I think there is a very low chance of somebody who has arranged independently for storage trying to put CO2 in our pipeline. That said, we will take any emission source we can get.
MR. MARTIN: So there is no reason at the moment for people to move CO2 on your pipeline unless they have contracted with you.
Is another issue that tax equity investors who will monetize tax credits will not want to continue funding if the IRS comes in on audit and disallows some of the tax credits? More than half the section 45Q tax credits claimed in the past have been disallowed by the IRS, but due to faulty paperwork. Presumably nobody will do that again. How is the market dealing with this risk?
MS. CRANE: We are obviously not far enough down the road with the tax equity investors, but in reference to prior discussions you and I have had about other tax equity deals, I think there is more room in structuring section 45Q deals to provide the tax equity investor flexibility to manage risk. I think that’s one of the strong things about 45Q. For example, one way for the investor to shed part of the risk is to use a pay-go structure.
MR. DEMUTH: I think that’s right. The IRS put out a revenue procedure that allows flexibility to make close to half the tax equity investment contingent on tax credits.
MR. MARTIN: Let me ask the panel first, and then the audience, are there any other risks we have not discussed this morning?
MR. DURHAM: The legacy well situation. People whose equipment is on the surface sometimes fail to look at the subsurface. States like Louisiana have decades of experience with oil and gas wells. We have seen well diagrams from the 1940s and 1950s with a cartoon fish drawn and a few notes that say that something was left in the hole. When you have that, you end up in a discussion with the US Environmental Protection Agency about how you are going to remediate the legacy wells.
Those states are more comfortable with drilling, but they are also more fraught with legacy challenges that you will uncover as you build the sequestration site.
MR. MARTIN: Do you lock in the entire pore space or do you share it with someone else? You are also mixing CO2 emissions from lots of people, so I imagine if there is a leak, you split the burden among all the CO2 sources.
MR. DURHAM: There will certainly be complications. There will also be places where there is adjacent pore space where both parties are injecting into the same formation side by side. There are lots of unknowns around that part of the business.
MR. MARTIN: Before we move to a lightning round about our panelists’ projects, let me ask the audience whether it has any questions.
MR. GARCIA: We have posted a number of audience questions on the screen. The first question is for Tyler Durham and Aaron Hood. Is a section 45Q tax credit of $50 a ton enough to support the entire value chain, or do you need to rely on other incentives?
MR. HOOD: I think $50 works pretty well. You need to have some monetization of your carbon attributes in low carbon fuel markets or voluntary offset market. You don’t need heroic amounts of revenue from that. You need some but not that much.
You need a lot of scale. We are 9.5 million tons of CO2 a year. We are building expensive transportation infrastructure. We would like to upsize it as much as possible for business reasons and because it is the right thing to do from a policy perspective, but you can only finance what you can finance.
MR. DURHAM: What Aaron said holds true for concentrated sources. For post-combustion gas streams where the CO2 is more expensive to remove, the tax credit has to be much higher.
And to contradict an earlier panel, I think one million tons a year is too small. The economics at that scale are very challenging even on the sequestration side. You are likely to need two wells to do a million-ton-a-year project. Once you get to five million tons, you have some redundancy. Once you get to 10 or 15 million tons, then you really start to see economies of scale.
MR. GARCIA: The next question is for Cindy Crane. If CCS gets qualified into the voluntary credit offset market, who gets the benefit? The emissions source or the capture facility?
MS. CRANE: In a voluntary offset market, you are basically selling an offset credit to another emitter to offset its emissions. The buyer has the benefit of the offset credit.
MR. HOOD: No double dipping, right? If you monetize in the low carbon fuel market by getting an uplift for reduced carbon intensity of your fuel, you can’t then monetize the carbon reduction in the voluntary offset market.
MS. CRANE: Correct. It is no different than renewable energy credits. We expect the same type of market to evolve. Once you retire a REC, you retire a REC. It would be the same thing in the voluntary offset market.
MR. GARCIA: The next question is for Bob Purgason. There are mixed reviews of repurposing pipelines for CO2 transmission. Where is repurposing better than greenfield?
MR. PURGASON: A good rule of thumb is that old pipe beats new pipe. If you can convert an existing pipeline to carry CO2, it is better than trying to build a new pipeline.
The limitation is the unique properties of CO2. It turns into a liquid-like state above 1,050 pounds of pressure. Therefore, if you plan to transport it at very high pressures over long distances, you need a new-style high-pressure pipe to do that efficiently. In Louisiana, we are using 70s-vintage pipe with nominal 1,000-pound operating pressure.
Stay below that pressure. It takes larger diameter pipes, but these pipes were built to take shelf gas and now the gas comes from the Marcellus formation, Haynesville or somewhere else. We have ample pipe capacity that we can use, but when we go to a longer transport or to a sequestration site where the CO2 will be injected into a well, it will be new pipe because it requires a 2,500-pound pressure design, and we need modern steel to do that.
MR. MARTIN: Let’s move to a lightning round. I want to ask each of the panelists a few questions. Short answers. Cindy Crane, let’s start with you. You have an 847-megawatt San Juan generating station in New Mexico where you want to attach carbon capture on the back end. That plant was scheduled to shut down on June 30 this year. Did it?
MS. CRANE: It did not. One unit was laid up and is being maintained to be brought back. The owners that are exiting needed power for the summer. They were fearful of rolling brownouts and blackouts, so they extended their operations through September.
MR. MARTIN: That is true of one of the four units? There were two to get to 847 megawatts.
MS. CRANE: That’s correct.
MR. MARTIN: Farmington, which is a town nearby, owns 5% of the power plant. Public Service Company of New Mexico, the local utility, owned 95%. Does Farmington now own the whole thing? Farmington had an option to buy the 95% PNM share for a dollar.
MS. CRANE: Farmington owns 5%, but there are four other utilities that own the remaining 95% of those two units. Farmington has an option to buy the 95% interest, and we have a rights transfer agreement with the City of Farmington. Those other owners are still in the plant taking the power offtake through September 30. The City of Farmington still has an option to buy the 95%.
MR. MARTIN: Installation of the capture equipment was expected to be completed this year. That was your original plan. Now it looks like the project is behind schedule and it will be 2025 before the capture equipment is fully installed. Is that still the plan?
MS. CRANE: The pandemic happened and schedules across the board were affected. Our FEED study was completed in June. It was filed with the US Department of Energy, and we are going through the final stage on the FEED study. There is a revised schedule for the project that is not public yet, but we are also seeing order backlogs for equipment. Compressors can take 113 weeks for delivery
MR. MARTIN: You plan to operate the power plant as a merchant power plant, if you do take it over. PNM does not want the power. The CO2 emissions I read somewhere to generate electricity are 2,000 pounds per megawatt hour. The state has a ceiling of 845 pounds that, I think, takes effect in January 2023. Your plan ultimately is to get emissions down to about 215 pounds, but not till 2025. How will this work as a merchant power plant given the state ceiling?
MS. CRANE: Coal plants operate typically in the 2,200 pounds-per-megawatt-hour range. The New Mexico “Energy Transition Act” sets a minimum threshold of 1,100 pounds per MWh. The rules around the Energy Transition Act on CO2 intensity are just now being promulgated. We expect those to be finalized by the end of October. We are working with the secretary of the environment in New Mexico on the compliance structure. We also prepared a piece of legislation that would extend the date to allow a true energy transition to occur.
MR. MARTIN: I see you have more than a fulltime job. You are also in discussions with the US Department of Energy for a $906 million loan guarantee. Where do those discussions stand?
MS. CRANE: You have been reading some of our early literature. Where we are on financing is we have updated our economic models with all of the FEED outputs. We are looking at the financing stack. We are preparing to respond to the Department of Energy’s demonstration project request for proposals. As soon as it gets issued, we plan to file an application for a funding grant, and then we will fill in the stack from there
MR. MARTIN: I also read you have a Navajo investment.
MS. CRANE: Yes, we do. The San Juan plant is surrounded by five tribes, of which the Navajo Nation is the largest. San Juan plant and the mine adjacent to it currently employ a significant number of Native American workers. The Navajo transitional energy company NTEC invested in Enchant. We are working with it to see how our technology can be applied to save other jobs for the Navajo Nation.
MR. MARTIN: Aaron Hood, rapid fire. At last count, you had 32 ethanol plants signed up. Is that still the right number?
MR. HOOD: Yes.
MR. MARTIN: Is your focus solely emissions from ethanol or also fertilizer?
MR. HOOD: We will talk to anybody in our footprint that we think can credibly capture within the time frame in which we are operating or in the future to the extent we have excess capacity.
MR. MARTIN: You said you are going to bury the CO2 in North Dakota and you have the class VI permit at this point, correct?
MR. HOOD: Yes, we have one in conjunction with our joint development agreement with Minnkota, and we have a series of other permits. North Dakota has been approving permits if they are properly put together in six to seven months. We have been granted several.
MR. MARTIN: At what stage is the pipeline you are planning to build across five states?
MR. HOOD: We own about a third of the rights of way. Our pipeline permits are in South Dakota and Iowa. There is no state-level permit in Nebraska. We will submit our permit in North Dakota shortly, as well as our core districts that we need and a few other ones. We have something like 6,000 crossing permits and little things like that to clean up. So if anybody wants to come help make crossing permits, you can. There is plenty of work to do.
We talked about eminent domain briefly. You had better buy a lot of rights-of-way before you start talking about eminent domain. It is not written down anywhere, but if you can’t buy most of your rights-of-way on a voluntary basis, it will be a tough permitting process.
MR. MARTIN: You said earlier how much the pipeline will cost to build, but it is worth repeating. Also, how many of millions of tons of CO2 a year do you have tied up at this point?
MR. HOOD: A little over nine million tons. It is about a $4.5 billion project, with $3.5 billion in the pipe and the rest in sequestration and other costs.
MR. MARTIN: Tyler Durham, Navigator signed a letter of intent with Poet, the largest US ethanol producer, to move five million metric tons a year of CO2. How many tons of CO2 do you have locked up at this point in total?
MR. DURHAM: Just over 11 million tons under contract. We expect that to climb to 15, which is the planned size for the project.
MR. MARTIN: You said earlier you plan to bury the CO2 in Illinois.
MR. DURHAM: We filed our first six class VI permit applications in Illinois. We will have at least that many more to get to scale for the full project.
MR. MARTIN: Jeremy DeMuth, an investor usually cannot claim tax benefits if that’s all he is getting out of the deal. Usually people want a cash-on-cash return. In some of these deals, there is nothing but the tax credits. How comfortable are you that the investors can claim on that basis?
MR. DEMUTH: I think that is a real issue. If your only return is from tax credits, you will not fall in the safe harbor the IRS published in a revenue procedure. Either the IRS will have to revise the revenue procedure or you are going to have to be comfortable operating outside the safe harbor. It is certainly an issue and certainly something that we would like to see the IRS resolve.
MR. MARTIN: The tax credit can be passed through by the owner of the capture equipment to the sequestration company. Have you seen this election used? Do you expect it to be used?
MR. DEMUTH: We have seen it used. It is potentially helpful because you are not dealing with partnership allocations and the risks associated with them. There is some administrative complexity. You don’t really want to bank on someone else making the election on their return and then waiting to file your return until that someone else has made the election.
MR. MARTIN: Bob Purgason, how will your pipeline be compensated for moving CO2?
MR. PURGASON: We are basically a fixed-fee pipeline. We would love to take a share of the tax credit uplifts, but that is usually not on the table.
MR. MARTIN: What sort of deliver-or-pay requirement will there be? You mentioned we are all big boys. Emitters will have to step up to some sort of commitment.
MR. PURGASON: To meet minimum required returns on capital, there will have to be a volume commitment.
MR. MARTIN: For a minimum percentage of what you expect to receive ultimately? Is it 30%? 50%?
MR. PURGASON: It varies based on the size of the commitment.
MR. MARTIN: What happens if there are line losses with the result that you don’t get the CO2 to the field where it is supposed to be sequestered. Tax credits cannot be claimed for capturing CO2 that is not sequestered.
MR. PURGASON: There will be shrinkage that will be dealt with in the contract. The capture company will not be able to claim tax credits on 100% of the captured emissions.
MR. MARTIN: Some people would say it is your risk because you are moving the CO2, but what do you think is an appropriate shrinkage percentage before you are called to account?
MR. PURGASON: It is a single digit kind of percentage.