We're fighting for our homes and our land, and for the safety of South Dakota communities just like yours. But we can't do this alone, we need your help, so if you can, pitch in and let's make some hay.
We're fighting for our homes and our land, and for the safety of South Dakota communities just like yours. But we can't do this alone, we need your help, by being informed and taking action when it matters most.
FORT DODGE, Iowa (KTIV) – The first big test for carbon-capture pipelines in Iowa begins Tuesday in Fort Dodge.
Summit Carbon Solutions is set to begin its evidentiary hearing in front of the Iowa Utilities Board.
Summit Carbon Solutions is seeking a permit to construct, operate and maintain 687 miles of pipeline across 29 counties in northwest and central Iowa. In total, the pipeline would cross 2,000 miles of land across 5 states. That pipeline will carry hazardous liquid carbon dioxide from roughly a dozen ethanol plants in Iowa to North Dakota to be stored under caprock.
Summit Carbon Solutions is also seeking the right of eminent domain over more than 900 parcels of Iowa land on the proposed route.
The hearing, scheduled to begin Tuesday in Fort Dodge, is expected to last several days.
KTIV will be in Fort Dodge tomorrow and will provide fill coverage from the hearings here on News 4.
PIERRE, S.D. (KELO) — Attorneys from multiple sides of the fight over Navigator building a carbon-dioxide pipeline in South Dakota will face off at the state Capitol later this week for an argument that’s never come up before.
The South Dakota Public Utilities Commission is deciding whether to issue a permit to Navigator. A state law passed in 1981 lets the state commission supersede or pre-empt local land-use controls for some trans-state projects — but only when the requirements are “unreasonably restrictive.”
Navigator’s permit could turn on what the state commission decides regarding pipeline ordinances in Minnehaha County and Moody County. The same could be true for the CO2 pipeline that Summit Carbon Solutions wants to build. The county ordinances were passed after both companies applied to the state commission.
The commission has completed the main hearing on the Navigator project and plans to decide on the permit September 6. The commission will hold a special mini-hearing for Thursday, August 24, and if necessary the following day, to consider the pre-emption question.
What the state commission decides on pre-emption could decide whether the Navigator project moves ahead. That’s because company officials have already testified in the permit hearing that the project is a no-go if the Minnehaha and Moody ordinances are allowed to stand.
Minnehaha County and Moody County plan to present witnesses Thursday.
The state commission’s decision might not be the final word, however. Any of the sides could challenge the state commission’s ruling in court.
What the state commission decides regarding pre-emption could also affect the SCS project. The state hearing on the SCS application starts September 11. Attorneys for SCS on Monday asked the state commission to pre-empt pipeline ordinances in Minnehaha, Spink, Brown and McPherson counties.
By Nicholas Klein, Staff Mechanical Engineer, Burns & McDonnell
By Tisha Scroggin-Wicker, PE, Director, Process Technology, Burns & McDonnell
Carbon capture, utilization and storage (CCUS) technologies make it possible to prevent up to 95% or more of a power plant’s carbon dioxide emissions from entering the atmosphere. The Inflation Reduction Act (IRA) of 2022 established a significant revenue stream that carbon capture facilities can leverage, leading to a successful project economic pro forma.
Faced with renewable energy requirements and carbon dioxide (CO2) reduction goals and mandates, utilities with aging coal-fired power plants or industrial hydrogen producers have had few choices other than to plan their plants’ retirements. Carbon capture provides an opportunity for these facilities to support decarbonization goals, generate lower carbon intensity power and reinvent their purpose by generating revenue through the capture of carbon.
Carbon capture technologies make it possible to remove CO2 from plant emissions. Existing power plants retrofitted, and new plants outfitted with carbon capture systems have the potential to continue supporting jobs in their communities and extending their operating lives by a decade or more.
When installing carbon capture systems, utilities must consider how they will dispose of and benefit from the large amounts of captured CO2. Currently, there are two predominant options. One is geological sequestration, which involves injecting the CO2 into very large underground geological formations for permanent storage and sequestration. That means disposing of CO2 as a waste product, which requires costly infrastructure and permitting, along with overcoming potential public opposition. This option is highly location-dependent, likely requiring a facility to be near the required geologic formation or a CO2 transport pipeline to remain economically feasible. Leveraging existing or new pipeline networks for the transport of CO2 is a potential transportation avenue. Securing permits for new CO2 pipelines, especially interstate pipelines, has thus far been challenging but pipeline development continues to progress and advance.
Another option is to sell the CO2 to the oil industry for enhanced oil recovery (EOR). Oil companies utilizing CO2 for EOR are typically willing to pay for the CO2, since they currently rely on natural CO2 sources found underground. Captured CO2 can be used to replace and supplement these resources. The potential supply of CO2, however, greatly exceeds likely demand from EOR utilization. This option is also highly dependent on the proximity of the plant to CO2 pipelines or oil fields with sufficient capacity to transport the captured gas.
Does the installation of a carbon capture system make economic sense? This is the question a growing number of utility and power producers are asking, and projects in development are expected to provide the answer.
DOE funding initiative
As a result of recent legislation, the U.S. Department of Energy (DOE) has been able to offer unprecedented levels of funding for carbon capture projects. Within the Infrastructure Investment and Jobs Act (IIJA) passed in 2021, the DOE allocated $3.5 billion combined for demonstrations and pilots along with $2.5 billion for the development of large-scale carbon storage commercial projects. Additionally, $310 million for carbon utilization applications and $100 million for technology and front-end engineering and design (FEED) projects were allotted.
Additional funding was made available through IIJA for direct air capture (DAC), involving $3.5 billion for multiple hubs across the country to capture and either store or make use of CO2. Prizes worth $115 million are also obtainable in technology competitions for creative processes seeking to develop DAC as a viable approach for carbon removal.
To jump-start the commercialization of carbon capture technologies, the DOE recently announced $189 million in available awards for nine FEED studies associated with carbon capture demonstration projects. These studies involve an assortment of carbon capture technologies and sites, including coal, integrated gasification combined-cycle, natural gas combined-cycle, cement and cogeneration facilities. DOE funding has been earmarked for projects designed to accelerate the deployment of existing carbon capture technologies and the development and refinement of new ones, as well as the assessment and verification of commercial‑scale CO2 storage. By deploying a variety of large-scale CCUS pilot and demonstration projects, the DOE expects to build the knowledge base needed to test and further prove the viability of carbon capture technologies on a commercial scale.
45Q tax credits
The new 45Q tax credits set forth in the IRA of 2022 form the economic engine propelling this market forward. Section 45Q of the Internal Revenue Service tax code has been substantially updated to increase incentives per metric ton of CO2 to $60 for utilization or EOR, and $85 for sequestration, if apprenticeship and prevailing wage requirements are met. The minimum carbon capture requirements that power plants need to meet to be eligible for these tax credits include capturing at least 75% of CO2 emissions and 18,750 metric tons of CO2 annually. Similar to the 2018 update, these credits would be accessible for 12 years after a project begins operation. DAC sites must capture at least 1,000 metric tons of CO2 annually in order to qualify for tax credits assessed per metric ton of CO2 that are $130 for utilization or EOR and $180 for sequestration if applicable conditions for apprenticeship and prevailing wages are reached.
The IRA also provides the option for these tax credits to be issued through direct payments to for-profit entities (for up to five years after the initial operation date) and tax-exempt organizations (for up to the full 12 years after the initial operation date). Additionally, there is potential for transfer or sale of part or all of these tax credits.
The 45Q rule lays out the relevant qualification requirements. To receive the tax credit for geologic storage, a utility must meet the U.S. Environmental Protection Agency’s (EPA) sequestration reporting rules (40 CFR Part 98, Subpart RR), which include a monitoring, reporting and verification plan that documents the amount of carbon injected and stored. Entities seeking credits for EOR have the choice of satisfying either EPA regulations governing geological CO2 sequestration or the CO2 storage guidelines developed by the International Organization for Standardization (ISO) and the American National Standards Institute (ANSI) (CSA/ANSI ISO 27916:19).
The rules also outline that the IRS can recapture the credit if the carbon is intentionally leaked or withdrawn from storage. Once the carbon capture system begins commercial operation, the IRS can reclaim the credit up to the earlier date of three years after the date the tax credit is last claimed or the date when monitoring ends.
Together, these 45Q changes make implementation of carbon capture technology a more economically attractive proposition for utilities while not limiting the industry with a tax credit cap. There is, however, a catch: To be eligible, construction of these projects must commence by Jan. 1, 2033.
Carbon capture and storage technologies
Utilities and others contemplating post-combustion carbon capture projects have several options to choose from that are in varying stages of development. Processes in this space include membranes, adsorption with solid state sorbents, cryogenics, enzymes and chilled ammonia. Absorption through liquid solvents, primarily amines, is the most common carbon capture method currently being assessed and deployed.
Originally developed in the 1930s, amine technology has been used for decades in a variety of applications, including post-combustion carbon capture. Amine processes have become the primary method used by power plants, with proven capabilities of removing 95% or more of CO2 from emissions. Amines are chemical solvents that undergo a reversible reaction with CO2 and other acidic gases. During the amine-based process, when exhaust gas containing CO2 comes in contact with a liquid amine solution, the CO2 chemically binds to the amine molecules and is removed from the gas stream. This amine solution can be pumped into a separate column where heat is used to reverse the process, stripping the high-quality CO2 from the amine. The CO2 can then be compressed for EOR use or injected into a suitable geological formation for storage.
Many DOE-funded carbon capture projects to date employ amine-based processes. The differences between individual processes are primarily in their “secret sauce” — the proprietary chemicals used to increase the efficiency of the amine solution. Researchers continue to seek solutions that reduce the amount of auxiliary power and water amine-based systems need to capture and recover carbon, as well as the volume of steam and heat these processes consume during regeneration.
Efforts are also underway to minimize their relatively high capital, operating and installation costs. Non-aqueous solvents (NAS) are emerging as potential avenues to lower steam and auxiliary load demands of these facilities by utilizing less water in the capture process. Applying lessons learned in research and operational settings will support future advancements with these and other carbon capture technologies.
Opportunities and challenges ahead
Operators of power plants will need to determine not only the right carbon capture solutions for their operation, but also how to efficiently integrate them into their existing systems. Current carbon capture technologies can potentially impact power generation operations and efficiency. An experienced integrator that understands power plant operations and can model carbon capture processes is essential to minimizing potential power production losses and identifying opportunities for process optimization.
Before CCUS systems can be fully commercialized, additional challenges must be addressed:
Reduced capacity factors — The economic feasibility of a carbon capture facility depends on the relative amount of CO2 captured from the flue gas that can generate an adequate revenue stream. As a result, the carbon intensity of the plant is reduced, which increases the value of the electricity generated at the site for consumers looking to decrease their carbon footprint. This poses special challenges to coal plants facing reduced run times in areas with high renewable energy penetration. Since the early 2000s, the capacity factor of many coal plants has dropped significantly, reducing the economic benefit of the capital investment by over half in many cases. A retrofitted plant may be economical to bid into power markets at similar negative power prices as wind currently enters the market.
Sequestration vs. EOR concerns — Given the increase in 45Q tax credits, power plants appear at first glance to have the most revenue to gain by sequestering recovered CO2 in geological formations. But that may not be the case, as power plants that can obtain additional incremental revenue selling captured CO2 to an EOR off-taker have the potential for similar or greater total revenue generation. Plants located near oil fields are likely in a better position to market their captured carbon for EOR use than those that must transport it hundreds of miles or more for sale.
Competitive markets — Independent system operators (ISOs) recognize the potential impact CO2 reduction strategies can have on the competitive markets the ISOs design and operate. Those markets optimally run with minimal out-of-market influences, such as subsidies or carbon taxes. ISOs, however, must also create markets that properly reflect the economic impact of state and federal regulations, even without the benefit of any oversight of those regulations.
Pathway to blue hydrogen — CCUS provides a pathway to reduced carbon emissions for a variety of industrial processes. In the context of conventional hydrogen production methods, CCUS gives existing hydrogen producers the option to invest in a reduced-carbon future via blue hydrogen. CO2 from combustion heating processes can be captured using various technologies from these point sources before being utilized for geologic sequestration, EOR, fertilizer synthesis or commercial use. In general, CO2 is collected, then separated in a cleanup step, transported and delivered to end users.
Regulatory support — Identifying and understanding the requirements of the relevant governing permitting entities is a crucial part of the development process for CCUS projects. The EPA governs CCUS permitting on the federal level, which applies to states without primacy, or the ability to manage their own permitting programs for geological sequestration. North Dakota, Wyoming and Louisiana have received primacy approvals from the EPA, which allows them to administer their own CCUS permitting systems within their respective states. Additional states are involved in various stages of the EPA’s primacy application process. It is also important to note that 45Q requires a monitoring period of geological formations for any leaks that may occur where vested parties could be liable for reimbursement of investment tax credits to the Treasury department. Awareness of the intricacies associated with CCUS permitting and monitoring is key to optimizing value in the set up and operation of CCUS facilities.
Despite its challenges, carbon capture has substantial political, regulatory and academic support that will likely continue to be incentivized through federal legislation, DOE support and state mandates. This provides opportunities for new plants to be designed with carbon capture capabilities in mind and existing sites to have a second life as carbon capture facilities.
Summit Carbon Solutions must reveal financial aspects of its agreements with ethanol plants to attorneys for groups seeking to verify the economic claims of Summit’s proposed carbon dioxide pipeline.
However, the Iowa Utilities Board (IUB) decision also allows the company to declare that unspecified “critical timing-related provisions” of the contract can be redacted.
The order follows a dispute over whether specific terms of the ethanol plant contracts are germane to Iowa’s hazardous pipeline permit process and if Summit’s project meets “the public convenience and necessity.”
Summit’s CO2 pipeline would span more than 2,000 miles in five states and connect to more than 30 ethanol plants, including Homeland Energy Solutions near New Hampton, Absolute Energy near St. Ansgar, Golden Grain Energy near Mason City.
The company’s witness testimony in pursuit of an Iowa permit claims ethanol producers might generate 10 to 35 cents of additional revenue per gallon because of the project. A study commissioned by the Iowa Renewable Fuels Association — which supports Summit’s project — said carbon dioxide pipelines could more than triple the profit margins of ethanol plants.
The IUB ordered Summit to provide the contracts with the provisions redacted within two days. The company will use a data-sharing site to disseminate those contracts, where they can be viewed but not downloaded.
The final evidentiary hearing for Summit’s permit is set to start Tuesday in Fort Dodge, although there are pending requests to delay the proceedings. The IUB recently published a schedule of witnesses including landowners, like Jessica Marson of Floyd County, who declined to sign voluntary easements for pipeline construction and are subject to Summit’s eminent domain requests.
State officials are recommending a water-rights permit for a carbon dioxide pipeline company, but some nearby residents who use the same aquifer fear they could be negatively affected.
The Summit Carbon Solutions pipeline route in South Dakota. (Courtesy of South Dakota Public Utilities Commission)
A corporate entity affiliated with Summit Carbon Solutions, called Redfield SCS Capture, has applied to drill a well that could take up to 21 million gallons of water per year from the Dakota Aquifer, which is an amount equivalent to about 32 Olympic-sized pools.
The well would be about 1,100 feet deep and located a few miles north of Redfield, in the same area as the Redfield Energy ethanol plant, which is a partner in the Summit pipeline project.
The state Department of Agriculture and Natural Resources said in a written statement to South Dakota Searchlight that the water will be used for “non-contact cooling.” The department provided no further information, and Summit did not respond to multiple Searchlight messages. Other sources interviewed for this story speculated the water will be used to cool pipes carrying pressurized carbon dioxide.
After its use, the water would be discharged into a local waterway, DANR’s report says. The report does not say which body of water, but the site is near Turtle Creek and the James River.
Summit Carbon Solutions wants to capture carbon dioxide emitted from ethanol plants in five states. The gas would be pressurized into a liquid form and transmitted via pipelines to North Dakota for storage underground, to prevent the gas from trapping heat in the atmosphere. For its purported value in helping to fight climate change, the $5 billion project would be eligible for up to $1.5 billion in annual federal tax credits.
Neither DANR nor Summit responded to questions about whether Summit will apply for new water rights and wells at other locations.
The water source, the Dakota Aquifer, is a porous rock and sand formation where water gets stored as it trickles underground. It underlies about 66,500 of South Dakota’s 77,000 square miles of land. A 1982 report cited by the state indicated the aquifer held about 124 trillion gallons of “recoverable water storage” east of the Missouri River in South Dakota.
In a June 29 staff report, state Chief Engineer Eric Gronlund recommended approving the application, saying there’s enough water available for it, it’s unlikely to harm existing water users and it’s for a useful purpose.
Permit gets contested
Because some nearby residents sent opposition comments to the state during a public comment period, the proposed permit will be the subject of a contested case hearing this fall.
One of those nearby residents is Debra Curtis, who ranches about 2.5 miles from the proposed Summit well and fears it would “reduce the water pressure and flow of my well.”
Dave and Stacey Marlow wrote to the department that their drive-in theater “will not have adequate water pressure to continue business” if the project is permitted.
“I was told that much water being extracted will create a cone-shaped vacuum into the aquifer,” Dave Marlow told South Dakota Searchlight. “And for wells only a mile or so away, like ours, there’s just not enough pressure.”
Pheasant City Drive-In is located 1 mile north of Redfield on Highway 281, about a mile south of a proposed well for the Summit Carbon Solutions pipeline. (Courtesy of Stacey Marlow)
Jay Gilbertson manages the East Dakota Water Development District, based in Brookings. He said Marlow was referring to a “cone of depression,” a term describing the shape that forms in the water table around a well when water is pumped out – like drinking a milkshake through a straw.
“When water is pumped out of a well, the water level closer to the well goes down,” Gilbertson said. “If too much water is taken out, it can cause problems for the wells in the surrounding area.”
Gilbertson also referenced language in the state staff report that says if problems with existing residential systems occur, the company has to stop or at least reduce its usage.
Bureaucratic processes
Dave Marlow said a state employee told him he could “see a drastic decline in pressure” and that a lot of paperwork and bureaucracy would stand in the way of stopping Summit Carbon Solutions from pumping.
“I know the guy’s name but I really don’t want to give it out,” Marlow said.
Debra Curtis said a state employee she declined to identify told her something similar. But when she tried to contact the employee again, she was unable and was later referred to Ian Fury, the governor’s spokesperson.
“He assured me that as a resident, we’d have priority over the company,” Curtis said. But she remains skeptical about how long it would take to force a large pipeline company to stop pumping water.
The Department of Agriculture and Natural Resources did not immediately respond to Searchlight questions regarding the claims from Marlow and Curtis about the state employee who spoke with them.
Marlow said he and his wife only found out about Summit’s water-rights permit application by reading the legal section of their local paper.
“Most people have no idea what’s going on or that it’s even happening, and I think they’re going to have a big problem coming down the road,” Marlow said. “Nobody reads the notices in the paper anymore.”
To oppose the application, comments had to be filed with the state’s Water Rights Program by July 24.
South Dakota Searchlight sent the Department of Agriculture and Natural Resources questions about the proposed permit on July 11, July 13 and Aug. 10, but didn’t get a response until Aug. 11.
“The public notice period for this application has closed,” department spokesperson Brian Walsh wrote.
He added that three people or entities — Curtis, the Marlows and another rural Redfield resident, Brad Hekrdle — filed comments that automatically triggered a contested case hearing, which will take place Oct. 4 in Pierre before the state Water Management Board.
Meanwhile, the state Public Utilities Commission’s hearing on Summit’s pipeline permit application will begin Sept. 11 and is scheduled to run 13 days at the Casey Tibbs Rodeo Center in Fort Pierre.
The commission has already conducted hearings on another carbon pipeline, proposed by Navigator CO2, and is expected to issue a decision on that project soon.
BISMARCK, N.D. — Public utility regulators in Iowa will begin a hearing today on a proposed carbon dioxide pipeline for transporting emissions of the climate-warming greenhouse gas for storage underground that has been met by resistant landowners who fear the taking of their land and dangers of a pipeline rupture.
Summit Carbon Solutions’ proposed $5.5 billion, 2,000-mile pipeline network would carry CO2 from 34 ethanol plants in five states to North Dakota for storage deep underground — a project involving carbon capture technology, which has attracted both interest and scrutiny in the U.S.
North Dakota regulators earlier this month denied a siting permit for Summit’s proposed route in the state, citing issues they say Summit didn’t appropriately address, such as cultural resource impacts, geologic instability and landowner concerns. On Friday, Summit petitioned regulators to reconsider.
Other similar projects are proposed around the country, including ones by Navigator CO2 Ventures and Wolf Carbon Solutions, which would also have routes in Iowa.
Carbon capture entails the gathering and removal of planet-warming CO2 emissions from industrial plants to be pumped deep underground for permanent storage.
Supporters view the technology as a combatant of climate change. But opponents say carbon capture and storage isn’t proven at scale and could require huge investments at the expense of cheaper alternatives such as solar and wind power, all at a time when there is an urgent need to phase out all fossil fuels.
Carbon capture also is viewed by opponents as a way for fossil fuel companies to claim they are addressing climate change without actually having to significantly change their ways.
“I think there’s a recognition even in the fossil fuel industry that, whether you like it or not and agree or not, [climate change] is a reality you’re going to deal with from a regulatory standpoint, and you’d better get out in front of it or you’re going to get left behind,” said Derrick Braaten, a Bismarck-based attorney involved in issues related to Summit’s project.
New federal tax incentives have made carbon capture a lucrative enterprise. The technology has the support of the Biden administration, with billions of dollars approved by Congress for various carbon capture efforts.
High-profile supporters of Summit’s project include North Dakota Republican Gov. Doug Burgum, a presidential candidate who has called the state’s underground CO2 storage ability a “geologic jackpot,” and oil magnate Harold Hamm, whose company last year announced a $250 million commitment to Summit’s project.
“Carbon capture and storage is going to be more and more important every day as we go forward in America,” Hamm has said.
The Iowa Utilities Board begins its public evidentiary hearing today in Fort Dodge, a hearing “anticipated to last several weeks,” according to a news release. The board’s final decision on Summit’s permit request will come sometime after the hearing.
Minnesota’s Public Utilities Commission has a hearing set for Aug. 31 in which the panel “will make decisions about the scope of environmental review” regarding Summit’s permit application for its pipeline in two counties, said Charley Bruce, an energy facilities planner with the commission.
A Summit attorney recently indicated to Minnesota that North Dakota regulators’ decision to deny a permit will not affect the company’s plans, including for other proposed routes in southern Minnesota.
The South Dakota Public Utilities Commission is set to begin its evidentiary hearing for the project on Sept. 11 and expects to make a final decision by Nov. 15.
Nebraska has no state-level regulatory authority for CO2 pipelines. Summit is working with counties individually in Nebraska.
Counties don’t approve or deny a route, but can institute ordinances’ setbacks for land-use purposes that can dictate where a pipeline may go, and can enter into road haul agreements and road crossing permits, said Omaha-based attorney Brian Jorde. He represents more than 1,000 landowners opposed to CO2 pipeline projects in four states.
Summit hasn’t hit “an insurmountable legal obstacle” in North Dakota regulators’ denial “because they literally said ‘try again,'” Braaten said.
“If they get over themselves I think that they could do it and get approved, but I think they certainly shot themselves in the foot and they’re making it much harder in those other states because they’re going to come in with those commissioners there looking at them with a certain level of skepticism because you literally just got denied a permit in North Dakota,” he said.
Landowners have raised concerns about the pipeline breaking, as well as eminent domain, or the taking of private land for the project, with compensation.
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Summit Carbon Solutions must reveal financial aspects of its agreements with ethanol plants to attorneys for groups seeking to verify the economic claims of Summit’s proposed carbon dioxide pipeline.
