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Air permit issued for Louisiana Green Fuels project

The project components include a biorefinery converting forestry waste to renewable fuel; a biomass-fired power plant for the entire facility; and a carbon sequestration complex to store the carbon dioxide.

Strategic Biofuels, a developer of negative carbon footprint biofuels plants, announced today that its Louisiana Green Fuels (LGF) project has been issued an Air Permit from the Louisiana Department of Environmental Quality (DEQ).

After a comprehensive technical review and public comment period, DEQ determined that the project, located in Caldwell Parish Louisiana, will not have an adverse impact on local air resources, signaling another milestone to advance the world’s lowest carbon footprint liquid fuel plant, according to a news release.

The facility will be classified as a “synthetic minor” and will be subject to all applicable state and federal regulations, including the National Ambient Air Quality Standards

“Securing the Air Permit for the integrated facility is a significant development for our project,” said Paul Oesterreich, Senior Vice President of Project Development, Strategic Biofuels. “The permit application for our facility is the first of its kind in Louisiana to be reviewed by the DEQ. We greatly appreciate the design innovation brought by Hatch to drive down the emissions from the integrated facility and the diligence from Eagle Environmental Services our environmental consultant, in shepherding the application through the regulatory review process.”

The LGF project integrates three key elements that through key engineering innovation, led by Hatch, has the ability to reduce the total emissions by 70 percent below the allowable limit if each of the facilities were operated independently. The three project components include a biorefinery converting forestry waste to renewable fuel; biomass-fired “green energy” power plant for the entire facility; and carbon sequestration complex to permanently store the carbon dioxide captured from both.

Securing the Air Permit builds on the significant recent advancement of the LGF project’s US EPA Class VI well permit application, which the EPA has deemed as “administratively complete” and includes the extensive data collected from the LGF Class V Stratigraphic Test Well, the thorough subsurface mapping of the region, and state-of-the-art reservoir, geo-mechanical, and plume expansion modeling, according to the release. Strategic Biofuels previously announced that it has entered into an agreement with SLB, a global technology company, to provide carbon sequestration services for LGF.

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Nevada plant on track for SAF production this year

The facility, which changed hands last year, is nearly through the conversion of a renewable diesel plant to sustainable aviation fuel production.

New Rise Renewables, a renewable energy company, today announced the inauguration its new 3200 barrel-per-day renewable sustainable aviation fuel (SAF) facility located at the Reno-Tahoe Industrial Complex in Storey County, Nevada.

The facility is nearly through the conversion of its existing renewable diesel plant as part of a groundbreaking effort to revolutionize the aviation industry by producing sustainable aviation fuel (SAF). It is scheduled to commence SAF production in the summer of 2024, according to a news release.

Camber Energy, a NYSE-traded energy company, last year reached a deal to acquire 100% of the interests in New Rise Renewables.

The plant was purchased for $499m, representing a purchase price of $750m less $251m of existing company liabilities, according to a securities filing. The seller was RESC Renewables Holdings, a predecessor company to Ryze Renewables, which developed the project.

The parties had reached a framework for the deal in late 2021, subject to purchase price adjustments and other closing conditions.

Reno-based Greater Commercial Lending (GCL) facilitated $112.6m in government-guaranteed credit for the development of New Rise Renewables Reno. Eighty percent of the GCL-arranged financing for New Rise Renewables Reno is guaranteed by the United States Department of Agriculture (USDA) via its 9003 Biorefinery, Renewable Chemical and Biodiesel Production Manufacturing Assistance Program. The financing structure includes participation by GCL parent Greater Nevada Credit Union, other credit unions, insurance companies and secondary market groups.

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Ares acquires RNG developer

Ares has made a strategic investment to acquire RNG developer Dynamic Renewables in a process run by Lazard.

Dynamic Renewables, a full-service developer, owner and operator of waste management and anaerobic digestion renewable fuel projects across the U.S., has been acquired by fund managed by Ares Management’s Infrastructure Opportunities strategy, according to a news release.

In addition, an unregulated affiliate of NorthWestern Energy has acquired a small minority stake in the company.

Terms of the deal were not disclosed. Lazard acted as financial advisor to Dynamic on the transaction. Husch Blackwell served as legal counsel to Dynamic. Latham & Watkins LLP served as legal counsel to Ares.

The investment from Ares is intended to support Dynamic in the further development and construction of its broader pipeline of renewable natural gas (“RNG”) assets located throughout the U.S. Ares has approximately $14.9bn in infrastructure equity and debt assets under management as of March 31.

Founded in 2011, Dynamic is a leading fully integrated origination, development, financing and operations platform that provides waste recovery solutions focused on the dairy and food processing industries. Dynamic has a material project development pipeline and is currently overseeing the construction of six assets, which are expected to be operational by the end of 2023 and forecasted to generate a combined total of more than 4,000 MMBtu per day of renewable natural gas. These six projects are projected to mitigate more than 300,000 metric tons of carbon dioxide emissions per year.

Dynamic is also the owner of BC Organics, a flagship asset developed by the Company. Located in Brown County, Wisconsin, BC Organics is a large-scale biorefinery facility that sources dairy manure feedstock from eleven multigenerational farms and comprises sixteen anaerobic digester tanks capable of processing 900,000 gallons of manure per day. BC Organics will produce carbon negative transportation fuel and provide its partner dairy farms with a long-term, sustainable manure management solution that converts the feedstock into clean water and reusable animal bedding.

Dynamic is led by its co-founders – Chief Executive Officer Duane Toenges, Chief Technology Officer Dan Nemke and Executive Vice President of Special Projects Karl Crave – who have worked together in the anaerobic digestion industry for nearly two decades.

“We are excited about the business we have built in Dynamic and our current momentum,” said Toenges. “Ares brings a wealth of experience in investing and developing projects in the renewable natural gas industry. They have expressed their support for the Company and our strategy in achieving our next phase of growth. Further, the recent commissioning of our BC Organics project is a tremendous milestone for Dynamic, and we look forward to completing additional projects this year for our strategic partners.”

“We are thrilled to partner with Dynamic, and our investment is aligned with Ares’ commitment to accelerate the transition to a lower-carbon economy through the Company’s innovative waste management and anaerobic digestion capabilities,” said Andy Pike, partner and co-head of Ares Infrastructure Opportunities. “Dynamic has a demonstrated track record of leadership in the rapidly growing renewable fuels sector, and we look forward to working together to build out its pipeline while supporting local communities in delivering more sustainable waste management practices.”

“We are pleased to further our existing relationship with Dynamic with this minority investment in the Company,” said Brian Bird, president and chief executive officer of NorthWestern. “The investment in Dynamic is a positive step for NorthWestern in meeting its net zero goals and a great opportunity to expand the RNG production capabilities of our service territory and its surrounding area. We are excited about the growth of the RNG industry, the carbon negative fuel that Dynamic’s assets will generate, and the complementary nature of this investment with our long-term goals.”

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Group to bring zero-emissions passenger flights to Denmark

DAT, Everfuel, and Universal Hydrogen Co. will collaborate on regional aviation by enabling zero-emissions flight using clean hydrogen by the end of 2025.

DAT, Everfuel, and Universal Hydrogen Co. will collaborate on regional aviation in Denmark by enabling zero-emissions flight using clean hydrogen by the end of 2025.

The three companies will combine their expertise in flight operations, hydrogen fuel production, and hydrogen logistics and aircraft propulsion to bring into service hydrogen-powered ATR 72-600 regional aircraft on DAT routes in Denmark, with the goal of converting all of DAT’s domestic flights to true zero-emission flights by 2030, according to a press release.

DAT plans to use ATR 72s converted using Universal Hydrogen technology. These aircraft will accommodate 56 passengers following conversion to hydrogen. Universal Hydrogen will also provide fuel services to supply green hydrogen using modular capsules, without the need for changes to existing airport infrastructure.

The green hydrogen will be produced at Everfuel’s first Power-to-X (PtX) plant in Fredericia, the release states.

The collaborative effort between the three companies follows the Government of Denmark’s request for tender to develop zero-emission commercial flights in Denmark.

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How hydrogen from nuclear power shows pitfalls of ‘additionality’

An interview with the Nuclear Energy Institute’s Director of Markets and Policy Benton Arnett.

Tax credits for low-carbon hydrogen production in the Inflation Reduction Act represent one of the climate law’s most ambitious timelines for implementation, with the provision taking effect late last year. That means low-carbon hydrogen producers can, in theory, already begin applying for tax credits of up to $3 per kilogram, depending on the emissions intensity of production.

However, IRS guidelines for clean hydrogen production have yet to be issued, and industry groups, environmentalists, and scientists are taking sides in a debate over whether the tax credits should require hydrogen made via electrolysis to be powered exclusively with new sources of zero-carbon electricity, a concept known as “additionality.”

In a February letter, a coalition of environmental groups and aspiring hydrogen producers expressed concern to the IRS that guidelines for 45V clean hydrogen production tax credit implementation would not be sufficiently rigorous, especially when it comes to grid-connected electrolyzers. Citing research from Princeton University, the group argued that grid-powered electrolyzers siphon off renewable generation capacity, requiring the grid to be backfilled by fossil power and thus producing twice the carbon emissions that natural gas-derived hydrogen emits currently.

(The group, which includes the National Resources Defense Council, Intersect Power, and EDF Renewables, among others, also argues in favor of hourly tracking, which they say would better guarantee energy used for electrolysis comes from clean sources, and deliverability, requiring renewable power to be sourced from within a reasonable geographic distance. In February, the European Commission issued a directive phasing in, over a number of years, rules for additionality, hourly tracking, and deliverability.)

Benton Arnett, director of markets and policy for the Washington, DC-based Nuclear Energy Institute, a nuclear industry trade association, does not believe the concept of additionality was part of Congress’s intent when the body crafted the Inflation Reduction Act. For one, he notes, the text of the 45V provision for clean hydrogen production includes specific prescriptions for the carbon intensity of hydrogen production as well as for the analysis of life-cycle emissions, but says nothing about additionality.

“When you get legislative text, you don’t usually have prescriptions on carbon intensities for the different levels of subsidies,” he said. “You don’t usually have specifications on what life-cycle analysis model to use – and yet all of that is included in the 45V text. Clearly [additionality] is not something that was intended by Congress.”

Reading further into the law, section 45V contains precise language allowing renewable electricity used for the production of hydrogen to also claim renewable energy tax credits, or “stacking” of tax credits. Further, the statute includes a subsection spelling out that producers of nuclear power used to make clean hydrogen can also avail themselves of the 45U tax credit for zero-emission nuclear energy production.

“It’s really hard for me to think of a scenario where the drafters of the IRA would have included a provision allowing existing nuclear assets to claim 45V production tax credits and also be thinking that additionality is something that would be applied,” Arnett said.

Text of the IRA

The NEI emphasized these provisions in a letter to Treasury and IRS officials last month, noting that, “given the ability to stack tax credits for existing sources with section 45V, the timing of when the section 45V credit was made available” – December 31, 2022 – “and congressional support for leveraging existing nuclear plants to produce hydrogen, it is clear Congress intended for existing facilities to be eligible to supply electricity for clean hydrogen production.”

Arnett adds that the debate around additionally ignores the fact that not all power generation assets are created equal. Nuclear facilities, in particular, given the regulatory and capital demands, do not fit within a model of additionality geared toward new renewable energy capacity. (Hydrogen developers have also proposed to use existing hydropower sources for projects in the Pacific Northwest and Northeast.)

This year, the NEI conducted a survey of its 19 member companies representing 80 nuclear facilities in the US. The survey found that 57% of the facilities are considering generation of carbon-free hydrogen. Meanwhile, the US Department of Energy’s hydrogen hubs grant program requires that one hub produce hydrogen from nuclear sources; and the DOE has teamed up with several utilities to demonstrate hydrogen production at nuclear power plants, including Constellation’s Nine Mile Point Power Station, Energy Harbor’s Davis-Besse Nuclear Power Station, Xcel Energy’s Prairie Island Nuclear Generating Plant, and Arizona Public Service’s Palo Verde Generating Station.

“We’re worried that if [additionality] goes into effect it’s going to remove a valuable asset for producing hydrogen from the system, and it’s really going to slow down penetration of hydrogen into the market,” Arnett said.

As for the research underlying arguments in favor of additionality, Arnett says that it appears to take the 45V provision in a vacuum, without considering some of the larger changes that are taking shape in US electricity markets. For one, the research, which argues that electrolyzers would absorb renewable capacity and require fossil-based generation to backfill to meet demand, assumes that natural gas generation will continue to be the marginal producer on the electrical grid.

“One of the shortcomings of that is that the IRA has hundreds of billions of dollars of incentives aimed at changing that very dynamic. The whole goal of the IRA is that marginal additions of power are carbon-free,” he said, noting incentives for clean electricity production tax credits, investment tax credits, supply chain buildouts, and loan program office support for all of these projects.

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Government money still top of mind for early movers in US hydrogen

Gaining access to funding from government and other agency sources is top of mind for many developers seeking to de-risk their projects and reach FID. But only hydrogen, ammonia, and other clean fuels projects exhibiting “the best in the business” are garnering support from government financing agencies and commercial lenders, experts say.

The US Department of Energy came out this week with the news that it was not yet ready to release the long-awaited winners of its $8bn hydrogen hubs funding opportunity, as Secretary of Energy Jennifer Granholm noted Monday at the Hydrogen Americas Summit in Washington, DC.

The delay disappointed many in the industry, who are also waiting for crucial guidance from the IRS on rules for clean hydrogen tax credits.

Gaining access to funding from government and other agency sources is top of mind for many developers seeking to de-risk their projects and reach FID. But only hydrogen, ammonia, and other clean fuels projects exhibiting “the best in the business” are garnering support from government financing agencies and commercial lenders.

Speakers on a financing panel at the summit yesterday pointed to the successful FID of the Air Products-backed NEOM green hydrogen project in Saudi Arabia as an effective project finance model, where major sponsors working together helped to de-risk the proposal and attract support from export credit agencies and global banks.

In the US, large players like ExxonMobil (Hydrogen Liftoff Hub), NextEra (Southeast Hydrogen Network), and Chevron (ACES Delta) have applied for DOE hydrogen hubs funding, according to the results of a FOIA request, joining major utilities and other oil and gas companies like bp and Linde in the running for funds.

In addition to inadequate regulatory guidance, some developers have already started grumbling that the proposed government assistance will not be enough to meet the scale of decarbonization needs. And the nascent clean fuels project finance market still needs to sift through techno-economic challenges in order to reach its potential, according to comments made yesterday on a panel called Financing Clean Hydrogen.

Leopoldo Gomez, a vice president of global infrastructure finance at Citi, sees a big role for the project finance framework for hydrogen facilities undertaken by independent project developers as well as strategics looking to strike the appropriate risk allocation for new projects.

And Michael Mudd, a director on BofA’s global sustainable finance team, said hydrogen projects are similar in many ways to established facilities like power and LNG, but with additional complexities, like understanding the impact of intermittent power and how to appropriately scale technologies.

Credibility

This year, Pennsylvania-based Air Products along with ACWA Power and NEOM Company finalized and signed an $8.5bn financing agreement for NEOM the project, which will build 4 GW of renewables powering production of up to 600 tons per day of hydrogen. The National Development Fund and the Saudi Industrial Development Fund kicked in a total of $2.75bn for the project, with the balance covered by a consortium of 23 global lenders.

“It is very important from the financing side to make sure the parties that are at the table are the best in the business, and that’s what we’re seeing with the projects that are able to receive either commitments from the DOE Loan Programs office or from commercial lenders and export credit agencies,” Gomez said.

Highly credible engineering firms are also critical to advance projects, and the EPCs themselves might still need to get comfortable integrating new technologies that add more complexity to projects when compared to power generation or LNG projects.

“The bottom line is that having someone that’s very credible to execute a complex project that involves electrolyzers or carbon capture or new renewable power generation within the parameters of the transaction” is critical for providing risk mitigation for the benefit of investors, Gomez added.

Funding sources

Additional funding sources are intended to be made available for clean fuels projects as part of the Inflation Reduction Act, the panelists said.

Most notably, tax credit transferability and the credits in section 45Q for carbon capture and sequestration and 45V for clean hydrogen are available on a long-term basis and as a direct-pay option, which would open up cash flows for developers.

“If you can use [tax credit transfers] as a contract, you can essentially monetize the tax credits in the form of debt and equity,” Mudd said. And if a highly rated corporate entity is the counterparty on the tax transfer, he added, the corporate rating of the buyer can be used to leverage the project for developers that don’t have the tax capacity.

Still, section 45V is potentially the most complex tax credit the market has ever seen, requiring a multi-layer analysis, according to Gomez, who advised patience among developers as prospective lenders evaluate the potential revenue streams from the tax credit market.

“First and foremost we’ll be looking at cash flows driven by the offtake contract, but it will be highly likely that lenders can take a view on […] underwriting 10 years of 45V at a given amount,” Gomez added.

Crucial guidance on how to conduct a lifecycle emissions analysis is still outstanding, however, making it difficult to bring all project parties to the table, according to Shannon Angielski, a principal at law and government relations firm Van Ness Feldman.

“It’s going to hinge on how the lifecycle analyses are conducted and how you have some transparency across states and borders” regarding the potential for a green premium on clean hydrogen, she added.

Agency support

In Canada, the Varennes Carbon Recycling plant in Quebec has received CAD 770m of provincial and federal support, primarily from the Canada Infrastructure Bank and the province of Quebec, noted Amendeep Garcha of Natural Resources Canada.

Around CAD 500m of funding from the Canada Infrastructure bank is also going to support hydrogen refueling infrastructure, Garcha said, with the aim of establishing a hydrogen highway that will form the basis of the hydrogen ecosystem in Quebec.

Pierre Audinet, lead energy specialist from World Bank Group, noted how the international development agency was stepping in to provide support for projects that might otherwise not get off the ground.

“In the world where I work, we face a lot of scarcity of capital,” he noted, adding that the World Bank has backed the implementation of clean fuels policies in India with a $1.5bn loan.

Additionally, the World Bank has supported a $150m project in Chile, providing insurance and capital for a financing facility that will reduce the costs of electrolyzers. Chile, while it benefits from sun and wind resources, said Audinet, is less competitive when it comes to transportation given its geographic location.

The agency is also working to help the local government in the Northeastern Brazil port of Pecem. Shared infrastructure at the port will help reduce risks for investors who have taken a stake in the port facilities, Audinet said.

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Feature: Is the U.S. Midwest still navigable terrain for CO2 pipelines?

Strained efforts to build thousands of miles of carbon dioxide pipelines in the U.S. Midwest could carry major implications for future projects – and for the region’s nascent clean fuels industry. According to one industry CEO, “Ethanol plants are sitting on a gold mine.”

“We’re just not interested.” 

That’s the sentiment that echoes through the testimonies of many landowners at an Iowa Utilities Board public hearing on November 7. The hearing is about Summit Carbon Solutions’ project to build a CO2 pipeline across five states, and the view is summarized in the words of Sue Carter, who owns a farm in the pipeline’s proposed path.

“We feel that it’s not a good idea to sequester the CO2, we feel that it would be detrimental to our farmland, to Iowa, and that we’re just not interested.” 

Summit Carbon Solutions, a private company backed by investors such as TPG Rise Climate, Tiger Infrastructure Partners, and John Deere, is planning to build around 2,000 miles of pipeline to transport CO2 captured at 34 ethanol and sustainable aviation fuel plants to geologic sequestration sites in North Dakota. The proposed network spans across Nebraska, North Dakota, South Dakota, Iowa, and Minnesota. 

The project, which would build one of the largest CO2 pipelines in the world, promises to capture and store up to 18 million tons of CO2 per year, offering the Midwest’s ethanol industry a path to net zero. 

But building is far from easy. 

In September, public service commissions in both North and South Dakota denied key permits to build the pipeline across those states. In Iowa, Summit is encountering staunch opposition from some landowners, who are worried about issues like safety and land preservation, and it is requesting the right of eminent domain over approximately 900 parcels of land. 

Commercial operations, which were initially expected for 2024, have been pushed back to 2026, and the project cost has risen from $4.5bn to around $5.5bn. 

In a country that, according to some estimates, needs to expand its carbon pipeline network more than ten times in 30 years to reach the ambitious goal of net zero emissions by 2050, Summit’s struggle to advance its Midwest project is emblematic of what might soon happen elsewhere. Navigator CO2 Ventures, for instance, has recently canceled a pipeline project in the area after encountering similar problems. 

And the uncertainty around pipeline development might hinder the region’s nascent clean fuels industry, which relies heavily on ethanol production and carbon capture technologies. 

*

Courtesy of Summit Carbon Solutions.

A potential cost increase was something that Summit took into consideration from the start, “whether that was because of factors related to inflation, supply chain shortages, or a longer-than-expected regulatory process,” according to Sabrina Ahmed Zenor, director of stakeholder engagement and corporate communications at Summit. He pointed out that Summit also increased the project’s expected capacity from 12 million to 18 million tons of CO2 since it was first announced. 

Regardless, the way Summit goes about securing success for its project and the extra costs and delays it faces are bound to set an example for developers across the country. 

“We need to see one or many of these projects be successful to develop a model as to how to deploy them,” said Matt Fry, senior policy manager at the Great Plains Institute, a non-profit organization dedicated to supporting carbon management technologies to achieve climate objectives. “We already have some infrastructure to transport CO2, but we just haven’t seen 1,000 to 2,000 miles transporting 10 plus million tons of CO2 a year yet.”

Already, Navigator has canceled its 1,300-mile Heartland Greenway pipeline, which was supposed to carry CO2 across Illinois, Iowa, Minnesota, Nebraska, and South Dakota. The company announced the decision on October 20, citing “the unpredictable nature of the regulatory and government processes involved, particularly in South Dakota and Iowa.”

Permitting regulations regarding carbon pipelines change from state to state. 

“Some states have deadlines or timelines associated with when an application is submitted to when a decision must be granted, which provides certainty. Some places not so much,” said Elizabeth Burns-Thompson, vice president of government and public affairs at Navigator. “Ultimately, the board did not see a pathway forward that was commercially viable.” 

According to Burns-Thompson, Summit’s challenges contributed to the decision as well. Navigator will now focus on a sequestration site in Illinois.  

Asked about Navigator’s cancellation, Summit said it “welcomes and is well positioned to add additional plants and communities to our project footprint.”

On a smaller scale, Wolf Carbon Solutions is also planning a 280-mile CO2 pipeline in Iowa and Illinois, where it filed permit applications in February and June respectively. And in May 2022 Tallgrass Energy announced its intention to convert 392 miles of natural gas pipeline into a CO2 pipeline connecting Nebraska, Colorado, and Wyoming.

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Pipelines have been carrying CO2 in the U.S. for over 50 years, with the first large-scale carrier built in the 1970s. At the moment, there are around 5,000 miles of active CO2 pipelines in the U.S., mostly carrying the gas to oilfields, where it’s used for enhanced oil recovery. For comparison, the country has around two million miles of natural gas distribution mains and pipelines. 

“There’s a very high likelihood, almost a certainty, that if the US is to reach net zero by 2050, it’s going to need many hundreds of millions of tons of CCS, maybe a billion,” said Chris Greig a senior research scientist at Princeton University, and one of the lead authors of Net Zero America, a study that presents various pathways for the U.S. to achieve the net-zero emissions goal. 

If we capture carbon, we also need to transport it. According to the Net Zero America report, the U.S. would need to develop over 60,000 miles of new CO2 pipelines over the next 30 years, which would come at a capital cost ranging from $170 billion to $230 billion, depending on the overall reliance on carbon capture. 

*

The United States is the largest producer of ethanol in the world, and it mostly produces it in the Midwest, with Iowa leading the charge. 

Ethanol can be used to make sustainable aviation fuel, and its fermentation process emits a CO2 that is almost pure, making it a very good candidate for carbon capture. The CO2 captured at ethanol plants, in turn, can be used to produce clean fuels such as e-fuels, sustainable aviation fuel, or green methanol. 

That means the Midwest is well situated to become a major clean fuel hub, but some say that depends on the successful development of pipelines that can move CO2 at scale.  

Pipelines are not the only way to move CO2, which can be trucked or shipped. But Summit’s project is expected to transport around 18 million tons of carbon dioxide annually, and that would require an army of railcars and trucks, and cost much more. 

Navigator, whose canceled project was supposed to have the capacity to transport 10 million tonnes of CO2 per year, expandable to 15 million tonnes in the future, estimated that it would have had to employ nearly half a million trucks to move the same amount. 

Biofuel maker Gevo has recently vented the possibility of relocating its $1bn Lake Preston Net-Zero-1 sustainable aviation fuel plant if the Summit pipeline doesn’t go through. The Lake Preston project is anticipated to start operations in South Dakota in 2025 

“Failure for the Summit pipeline to be built in South Dakota puts our Lake Preston project at severe risk of being relocated to a more advantageous location that has the availability of CCS,” said Kent Hartwig, Gevo’s director of state and local affairs, at a Brown County, South Dakota, commission meeting on October 3. 

Because of the cancellation of Navigator’s pipeline, a memorandum of understanding between Infinium and Navigator to produce e-fuels was scrapped. Navigator was supposed to provide Infinium with 600,000 tons of CO2 per year for use as feedstock for e-fuels, an amount of CO2 that would require multiple ethanol emission sources tied together to be delivered. Infinium did not respond to a request for comment. 

An alternative could be to produce the fuels in the same place where the CO2 is captured. That’s the business model of CapCO2 Solutions, a company that develops green methanol-producing technology that fits in a shipping crate. 

“Ethanol plants are sitting on a gold mine,” said Jeffrey Bonar, CapCO2’s CEO. And that’s regardless of whether large CO2 pipelines get built. 

CapCO2 is currently raising money to place its first shipping crate at an ethanol plant in Illinois. Eight to ten shipping crates would be able to process all the carbon captured at an average ethanol plant, making green methanol as a result.

According to experts, though, the scale of carbon capture that pipelines can provide is still needed. 

“While it is possible to produce synthetic fuels with CO2, the current scale of these production activities and the markets are not yet able to utilize millions of tons of CO2 per year, so associated CO2 storage would be necessary,” said Fry at the Great Plains Institute. “If we are, as a nation, serious about meeting climate objectives, we’re going to have to figure out how to make this work.”

*

Summit says it has secured voluntary easements for 75%, or around 1,300 miles of the pipeline’s route, and it’s still working to secure rights over all the land it needs. More landowners “are signing every day,” according to Ahmed Zenor, of Summit.

In 2020, a pipeline carrying both CO2 and hydrogen sulfide ruptured in Satartia, Mississippi, sending 45 people to the hospital. The episode was the first major accident involving a CO2 pipeline in at least 20 years — according to the Pipeline and Hazardous Materials Safety Administration’s data, there have been 105 incidents since 2003, and no fatalities — and it spurred an ongoing update of PHMSA safety regulations. 

Among the landowners who don’t want to give Summit access to their land, the incident exemplifies their safety concerns. 

“Pipelines such as the one Summit Carbon Solutions has proposed are highly regulated to ensure public safety,” said Ahmed Zenor in an emailed statement. “In addition to being regulated by the PHMSA, the project is also subject to federal environmental regulations and state oversight.” 

Transporting materials via pipeline, she added, is safer than transporting them via truck or rail. 

The safety concerns mix with a list of worries, including construction spoiling the land, potential leaks contaminating water sources, misuse of public money, and what some landowners describe as generally aggressive behavior from Summit’s agents trying to convince them to sign voluntary easements.  

“They went to nursing homes with donuts to try to convince vulnerable senior landowners,” said Jess Mazour, program coordinator of the Iowa Chapter of the Sierra Club, an environmental organization that’s been active in fighting the pipeline.

Overall, Summit is facing the opposition any linear infrastructure always faces — a Maine transmission line linking hydroelectric dams in Canada to the Northeast, for example, has been slowed down by permitting delays — complicated by a lack of uniform regulations. 

“Siting and construction are dealt with on a state-by-state basis for CO2 pipelines,” said Danny Broberg, associate director for the Bipartisan Policy Center’s energy program. “This is not the case for gas pipelines, for which interstate siting and construction authorities exist through FERC, the Federal Energy Regulatory Commission. One challenge at play for CO2 pipelines is that there is no federal jurisdiction for interstate siting and construction.” 

Stakeholders and legislators have started discussing how to overcome the challenge — if, for example, siting and construction for CO2 pipelines should be through FERC or not — and in May, the Biden Administration urged Congress to consider providing federal siting authority for CO2 pipelines as a priority for facilitating clean energy development. No official proposal is on the table yet. 

Despite the permitting setbacks, Summit says it believes “the regulatory process around pipeline projects works well.” 

*

Eminent domain is, to use the Great Plains Institute’s Fry words, “one of the most contentious things on the planet,” and as activists and opposing landowners have pointed out during the Iowa Utilities Board public hearing, it’s not clear it would apply to CO2 pipelines, at least in Iowa. 

“In Iowa, you can only use eminent domain if it’s a public use and convenience,” said Mazour of the Sierra Club. “And that’s one of our biggest arguments. This is not a public benefit.”

Carbon capture, according to Mazour, is extending the life of a harmful industry. “We don’t believe that ethanol is the best solution to take care of our soils and our water and our rural communities and our farmers,” she said. “And then if we have healthy soils and if we treat the land differently and farm differently, we can actually sequester a lot of carbon in our ground.” 

A better solution, according to Mazour and the Sierra Club, would be to expand deployment of wind and solar. 

Whether Summit is entitled to use eminent domain in Iowa or not is something that will be settled once the Iowa Utilities Board issues its final decision — the public hearing wrapped up on November 8, and there is no deadline they have to meet. 

Additionally, Summit has to refile a permit application in South Dakota, and still gain all the necessary permits in North Dakota, Nebraska, and Minnesota. 

The debate over eminent domain ties to a more general discussion over the benefits and effectiveness of carbon capture technology. Recently, a Bloomberg investigation found that last year Occidental sold its Century carbon capture facility for way less than it spent building it, after the plant never reached its full capacity in over ten years. The Petra Nova carbon capture facility in Texas has also struggled to meet capacity and financial objectives, and it just recently came back online after suspending operations for over two years. 

“Innovation includes risks and some tolerance for failure,” said Broberg at the Bipartisan Policy Center. “It’s going to take the entire toolkit of resources to meet net zero, both from the government and the private sector.” 

*

As the Midwest becomes an incubator for plans and strategies to build CO2 pipelines, and conversations are starting over how to make regulations more uniform, developers are probably going to take a few lessons from Summit and Navigator. 

The most important of these, according to experts, is how to better engage with communities and spearhead education about carbon capture technologies. 

“Everyone’s in a rush to take advantage of subsidies through the IRA,” said  Greig at Princeton University. “But you can’t rush communities, right? I’m not convinced that all the developers have the level of sensitive, forward-looking stakeholder engagement and community engagement and discussion that is going to be necessary.” 

If government entities are serious about developing carbon capture technologies, however, it can’t just be private companies explaining why we need them, according to Navigator’s Burns-Thompson. “It needs to come from the trusted voice of the regulators themselves. And that’s not just state entities. That’s our federal entities as well.”

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