SAMSUNG E&A will leverage Honeywell’s carbon capture technologies with the goal of helping power plants reduce carbon emissions and meet environmental goals. Together, the companies will offer customers a carbon capture solution by jointly marketing Honeywell’s solvent carbon capture (ASCC) technology.

“As two carbon capture leaders, our collaboration highlights the importance of cooperative approaches in reducing greenhouse gas emissions,” said Hong Namkoong, president and CEO of SAMSUNG E&A. “Deploying Honeywell’s carbon capture technologies allows SAMSUNG E&A to offer viable, more sustainable solutions for global clients during this energy transition.”

Honeywell’s CCUS technologies have been developed and deployed in numerous applications globally. Between 2023 and 2030, Honeywell estimates that the company’s CCUS technologies will have a cumulative impact of mitigating 320 million metric tons of CO₂e.

“Honeywell has long been a global leader in carbon capture technologies and our collaboration with SAMSUNG E&A only further highlights our commitment to reducing emissions and tackling climate challenges,” said Ken West, president and CEO of Honeywell Energy and Sustainability Solutions. “With decades of experience and a broad portfolio of carbon capture solutions, we are ready to help businesses meet growing carbon mitigation expectations and increasingly stringent environment goals by abating emissions from existing sources.”

Proponents of carbon capture, utilization, and storage (CCUS) argue the method can reduce carbon dioxide (CO₂) emissions, acting as a stopgap during the expected transition from fossil fuels to lower-carbon energy sources.

Earlier this year, the U.S. Environmental Protection Agency (EPA) announced final rules to crack down on emissions from coal-fired and new natural gas-fired power plants. Notably, the final rule heavily relies on on carbon capture and sequestration/storage (CCS) as the best system of emission reduction (BSER) for the longest-running existing coal-fired units and most heavily utilized new gas turbines.

The power industry has been fractured over EPA’s emissions-slashing proposal since the initial version was released last May. Opposition to the rule has mainly come with concerns that its implementation would jeopardize grid reliability and that the emission reduction technologies proposed by EPA aren’t ready for prime time.

The project would repurpose an industrial gasifier to utilize petroleum coke while permanently storing carbon dioxide to produce 500,000 metric tons of anhydrous ammonia annually. LPO’s conditional commitment would be part of a total investment of $2.4 billion that Wabash Valley Resources would secure for the project through private investment. 

The investment aims to help revitalize a community deeply affected by coal-fired plant retirements. The initiative is expected to create over 1,100 direct and indirect jobs, Wabash Valley Resources said. It would also create at least 500 union construction jobs.

Wabash Valley Resources would be the first domestic producer located in the Corn Belt to produce low-carbon ammonia for local farmers and co-ops in the region. This low-carbon ammonia would be cost-competitive compared to existing ammonia imports, DOE said, which could help drive down costs for local businesses and consumers. The market for ammonia can be volatile, subjecting farmers to price fluctuations — for example, the Russian invasion of Ukraine significantly increased ammonia costs for U.S. farmers.

Ammonia-based fertilizer is an important element of the U.S. agricultural system, but its production is a significant contributor to climate change, DOE said. Globally, ammonia manufacturing accounts for 1% to 2% of all CO₂ emissions.

Workers at the Wabash Valley Resources facility are expected to be represented by several unions, such as the International Brotherhood of Electrical Workers (IBEW), Boilermakers Local 374, Bricklayers Local 4, Cement Masons Local 692, Plumbers and Steamfitters Local 157, and Operating Engineers Local 841. 

Wabash Valley Resources also plans to engage with four local colleges that may offer training in the skills necessary to operate the anhydrous ammonia plant: Rose-Hulman Institute of Technology, Indiana State University, Saint Mary-of-the-Woods College, and Ivy Tech Community College. The company will also be pursuing a collaborative program for pre-employment testing and certification.

While the DOE’s conditional commitment indicates its intent to finance the project, DOE and Wabash Valley Resources must satisfy certain technical, legal, environmental, and financial conditions before DOE enters into definitive financing documents and funds the loan guarantee.

OCED awarded PPL with the first tranche of funding – $4.9 million – to begin Phase 1 activities. The carbon capture project – developed in partnership with the University of Kentucky and others – represents a total investment of more than $100 million and will be hosted at the Cane Run generating station jointly owned and operated by PPL subsidiaries Kentucky Utilities and Louisville Gas and Electric Company.

“We are proud to take the lead in evaluating and piloting carbon capture technology on natural gas combined-cycle generation, and we’re grateful for the DOE’s support,” said PPL President and Chief Executive Officer Vincent Sorgi. “Ultimately, we believe reliable, dispatchable natural gas units will be essential in the years ahead to ensure there’s sufficient supply to meet electricity demand 24/7. Further, we believe natural gas can be a reliable partner in accelerating the transition to renewables while preserving reliability and affordability.”

The system planned for Cane Run is designed to capture a portion of the CO₂ from the natural gas plant’s flue gas using a heat-integrated CO₂ capture technology. PPL said the system is expected to capture more than 95% of the carbon emissions from up to 20 megawatts (MW) of the plant’s 691 MW generating capacity, or up to 67,000 metric tons of CO₂ per year.

PPL maintains that the demonstration project is an important step in assessing the future viability of utility-scale carbon capture technology on natural gas units. Current plans include the captured CO₂ being purified and reused in its entirety by a nearby industrial customer.

In addition to the University of Kentucky, collaborators on the project include the Electric Power Research Institute (EPRI); Kentucky State University; Visage Energy; and American Welding & Gas. Vogt Power International Inc., a Babcock Power Inc. subsidiary, and Siemens Energy, manufacturers of the Cane Run 7 Generating Station, are contributing technical support as part of the project team on integrating the new CO₂ capture system. Koch Modular Process Systems and others will support the design, fabrication and construction of the carbon capture unit.

PPL subsidiaries LG&E and KU have partnered with the University of Kentucky for nearly two decades on various carbon capture research projects and were founders of the university’s carbon capture research program in 2006. Together with EPRI, the company and university deployed a pilot-scale carbon capture facility in 2014 at the KU E.W. Brown coal-fired generating station.

Since the end of 2023, 8 Rivers and Siemens Energy have collaborated on development of direct-fired super critical CO₂ turbines across a range of applications and fuel types. 8 Rivers, a developer of decarbonization technology and projects, said the ongoing turbine development program provides line of sight to future commercial projects. 

Siemens Energy has selected the commercially available generator that will be used with the Allam-Fetvedt Cycle (AFC) turbine. Siemens Energy will also provide related equipment, services, compression and grid technologies.

However, 8 Rivers said it has completed a study with a commercial party which assessed the feasibility of a biomass fueled Allam-Fetvedt Cycle negative emissions power system (Biome). This resulted in the recent signing of an MoU with the aim of commercial deployment, the company said.

8 Rivers argues that biome as a power system allows for the generation of low-cost, reliable, negative emissions power while simultaneously generating large volumes of carbon dioxide removal (CDR).  

North Carolina-based 8 Rivers develops zero-carbon technologies such as hydrogen, carbon capture and biomass carbon removal. It jointly owns NET Power, whose Allam-Fetvedt Cycle combusts natural gas with oxygen (rather than air) to fuel a supercritical CO₂ cycle that generates electricity.

The technology reuses most of the carbon dioxide produced and captures the rest, meaning it emits virtually nothing into the atmosphere. NET Power has said its plants should cost no more to build and operate than a traditional natural gas plant.

In 2018, we reported NET Power successfully achieved first fire of its demonstration plant and test facility in La Porte, Texas. At that time, the company had targeted the global deployment of 300 MW capacity commercial-scale plants beginning as early as 2021.

The OUCC filed testimony last week to the Indiana Utility Regulatory Commission, arguing that the commission should reject Duke’s proposal due to the “speculative nature of the feasibility and affordability of a CCS system.”

Duke Energy’s request would raise annual revenues for its Indiana electric utility by nearly $492 million, the OUCC said, which would be implemented in two phases. The utility’s testimony and exhibits project that an average monthly residential bill for 1,000 kWh would be $170.67 when new rates are fully implemented in March 2025.

“Duke’s proposal would impose extreme rate shock and unfairly burden its residential customer base, which has experienced significant and worsening affordability challenges,” said Ben Inskeep, Citizens Action Coalition program director. “This rate case is inconsistent with the policy of the State of Indiana and the General Assembly’s repeated emphasis that electric utility bill affordability is a priority. Disappointingly, while Duke proposes a destabilizing rate increase that places a disproportionate burden on residential customers, it has not offered material improvements to its programs that would meaningfully help residential customers with their unaffordable electric bills.”

The OUCC argued its analysis shows that an increase of approximately $184.7 million (6.1%) is warranted instead, based on the case’s evidence and applicable law.

Duke was awarded a Department of Energy (DOE) grant to conduct a front-end engineering design (FEED) study on CCS systems at its Edwardsport Generating Station. The estimated cost of the project is more than $17 million, with an estimated offset of roughly $8 million in federal funding.

In his testimony, Brian Wright, a utility analyst in the electric division for Indiana’s OUCC, noted that Duke’s first CCS feasibility study concluded that CCS was not feasible at Edwardsport due to the “lack of geological formations onsite that could act as a good carbon storage medium.” However, more recent studies at the location have shown that dolomite formations in the area could provide carbon storage capacity.

While Duke Energy has claimed it cannot estimate whether any of its out-of-state subsidiaries could benefit from the study, the OUCC said at “at the very least” the study should improve Duke’s knowledge and experience in evaluating the technological and geographical feasibility of CCS at other sites. Therefore, OUCC argued, the benefits of Duke’s study will likely extend beyond Indiana’s borders, and portions of the cost should be allocated to Duke’s other jurisdictions.

In its petition, Duke Energy said it has been nearly five years since it last filed for a general rate increase, and the test year in the company’s last general rate case was a fully forecasted calendar year 2020 – meaning the case establishing its current rates and charges was filed and the record was closed before the COVID-19 pandemic. Since then, Duke Energy said, the economic climate has changed “significantly,” including increased inflation, increased cost of capital, and Duke Energy Indiana’s capital investments to its electric system.

The Baytown Decarbonization Project is designed to capture 95% of CO2 emissions from two of the three turbines at the company’s Baytown Energy Facility, enabling the facility to produce electricity as well as steam for collocated industrial use. Calpine will now begin the first phase of the DOE cooperative agreement, with other phases to follow upon successful completion of phase one and finalization of plans for subsequent phases.

“We are pleased to have reached another milestone in the development of our Baytown Decarbonization Project. This initial Phase 1 commitment by the DOE will support the engineering and design of the project, further our community engagement, and advance project planning,” said Caleb Stephenson, Calpine’s Executive Vice President of Commercial Operations.

“This marks an important step forward for the Baytown CCS Project,” added Stephenson. “While there remain many milestones ahead, this step demonstrates Calpine’s continued commitment to being a leader in the energy transition in general and in carbon capture technology in particular. Calpine looks forward to continuing its partnership with the DOE as we work toward decarbonization of facilities like the Baytown Energy Center, which will be a critical part of our energy infrastructure for the foreseeable future and play a key role in decarbonizing our nation’s industrial sector.” Stephenson said.

In addition to the company’s Baytown project, Calpine continues to advance its similarly sized Sutter Decarbonization Project in California, which is negotiating an agreement with OCED that will help advance that project as well.

“Calpine is grateful for the DOE’s commitment to working with Calpine to advance this important technology and believes that this a recognition of the quality and strength of Calpine’s CCS program,” said Stephenson.

Carbon capture and storage (CCS) involves removing carbon dioxide, either from the source of pollution or from the air at large and storing it deep underground. In some instances, the CO2 is transported across states through pipelines and stored at facilities and used for other purposes.

The Biden Administration believes large-scale deployment of carbon capture, transportation, and storage infrastructure could play a vital role in reducing emissions and has increased pressure on the CCS industry to show that the technology can significantly help combat climate change.

Proponents say CCS could have a huge role in reducing emissions, while environmentalists note the technology is far from scale and argue that focusing on it distracts from renewable energy solutions.

Will a new Environmental Protection Agency power plant emissions reduction rule render Utah’s grid vulnerable? 

For many Republican lawmakers, it’s a resounding yes, as they consider the deadline to install technologies to capture carbon dioxide — a process that captures and stores carbon dioxide in underground geologic formations — in order to keep coal plants open an impossible task. 

However, others argue that the conversation around keeping fossil fuel plants operating is missing the mark, and state policies securing a longer future for coal may be the cause of a more susceptible grid. Utah’s initiatives, they said, are also preventing the state from innovating and implementing the “energy sources of the future.” 

Utah has joined 24 other states in a lawsuit to fight the implementation of new greenhouse standards for some coal power plants and for new natural gas facilities. Some legislators that sponsored bills defining the state’s energy strategy, prioritizing existing technologies and ensuring a fund to legally challenge “federal overreach,” said the state should fight the EPA rule to protect the state’s energy security.

But energy experts, such as Logan Mitchell, climate scientist and energy analyst at Utah Clean Energy, warn that the route ratified during the 2024 legislative session may lead Utah to a riskier, more expensive and more polluting path for the state. 

“Utah’s no longer an ‘all of the above state.’ We have a special set of rules for costs associated with coal plants, and we have another set of rules that everything else has to follow,” Mitchell said referring to SB224, a bill that excludes the cost of dispatchable resources — such as coal — from some state energy strategy considerations. 

That’s why, in Mitchell’s view, utilities such as PacifiCorp are not incentivized to make coal plants cost effective, but to just keep them running because they have a guaranteed cost recovery. 

However, Mitchell doesn’t see how federal policies don’t phase out coal power plants in the next decade. In that context, prioritizing coal dips into dangerous waters.

“If we’re not building resources to replace them, then those other states around us will,” he said. “And when those coal plants do close down, ironically, it’s going to lead to more energy dependence on our surrounding states, because we haven’t built our replacement energy system.” 

Issues with the rule

Utah’s electricity generation mix included 57% coal in 2022 — less than the 94% documented in 2000 — while natural gas was 28% and renewables represented 15%. 

Rep. Colin Jack, R-St. George, who sponsored some of the most predominant energy bills last general session, said in April that installing carbon capture and sequestration systems by 2032 wouldn’t be a viable option, as the technology doesn’t exist at a utility scale. 

Jack suggested that the rule’s goal must be to kill coal “without providing any replacement.” Closing Utah’s coal plants isn’t an alternative either, because the country’s northwestern region would be left without a substantial amount of electricity generation.

Nationwide, 60% of utility-scale electricity is generated by fossil fuels, according to 2023 figures from the U.S. Energy Information Administration. About 16% of that is from coal and 43% from natural gas.

However, Sen. Nate Blouin, D-Millcreek, is skeptical about claims brought up by his Republican colleagues. According to a May 2024 reliability assessment by the North American Electric Reliability Corporation, the country’s northwestern region — which includes Utah — is expected to have enough resources to meet peak demands.

“At least in the short term, from what this report is saying, we’re in a pretty good space and that doesn’t mean we can’t do more, but to you know, make comments that our grid specifically here in Utah is teetering on the edge of blackouts is just ridiculous and not factual,” Blouin said.

The state could move in other directions, using federal incentives to boost natural gas, storage, and geothermal, among other technologies, Blouin said. And, overall, EPA rules allow years to make transitions.

Fossil fuels are also a finite resource, Blouin added, and resisting a transition “is a little frustrating.”

“I think it’s kind of anti-progress, I guess, to look at it like ‘we can’t do this,’” Blouin said, adding that throughout history, the country has proven that it can meet these types of challenges with innovation and market-driven incentives. 

Carbon capture woes

Technically, carbon capture and storage is a viable option, Mitchell said. The technology exists and there are tax incentives in place to implement the technology through the Inflation Reduction Act. 

But, it is rare. According to a 2023 report from the Congressional Budget Office, “only 15 facilities are currently capturing and transporting CO2 for permanent storage as part of an ongoing commercial operation.” None of them are coal plants. 

The system also nearly doubles the water consumption of coal plants, adding to the water supply challenges of the state and raising the cost of keeping fossil fuels in the state.

“You’re going to get less power, you’re going to use more water, and you’re also not going to address the other air pollutants that are emitted,” Mitchell said. “I don’t think the public would support it, if they understood what it truly meant to keep those coal plants online.”    

Blouin agrees with lawmakers who worried carbon capture and sequestration technologies would be hard to implement.

“It is expensive. It is not proven at a commercial scale. And to ask these coal plants to implement carbon capture is probably not realistic. And I think there’s plenty of flexibility built into the rule from what I’ve seen and other federal incentives to move in other directions,” Blouin said.

But, with or without the technology, Mitchell said, the U.S. Supreme Court has also ruled that the EPA needs to regulate carbon dioxide and this specific rule was designed to meet the court’s outline. The difference between this and the former proposals, he said, is that this one is a “much simpler, more targeted regulation, and focused on reducing emissions.”

But, that’s beyond the point, he continued. The point is that these kinds of rules have propelled industries to focus on innovating.

“In some ways, the focus on carbon capture is really a focus on the past, and we wouldn’t be better served if we would focus on the future and look at the amazing amount of innovation that’s happening and be pursuing those opportunities as fast as we can,” Mitchell said.

Are renewables the solution?

Though fossil fuels have served the electric system for a long time and have allowed the economy to prosper, Mitchell said, they have also contributed to climate change. Simultaneously, there have been substantial cost declines in wind, solar and battery systems.

Fighting to keep coal online in those conditions, he added, is contrary to Utah’s long history of environmental stewardship, and overall, creates a negative impression of the state.

The state’s lawsuit would most affect the lives of the people who operate the plants, Mitchell said, as they need policy consistency to plan their futures.

“Outside of the leadership in the legislature. I don’t know anyone who actually thinks those coal plants are going to run to 2042. It’s quite unrealistic,” Mitchell said. 

Building resources is not that difficult, Blouin added, especially with storage, a solution for the intermittency issues of renewables.

“I know in Utah using California as an example isn’t isn’t always popular, but seriously, I mean, California’s ability to bring new energy storage onto the grid and the last like two to three years is incredible,” Blouin said. 

Cleaner energy projects could be built in a couple of years if the conditions are good. 

“That’s not to say we’re going to transition to 100% renewable energy by 2030. But, by 2030, we could be doing things drastically differently than we are right now at a similar level of reliability and likely cost,” Blouin said.  

Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence. Contact Editor McKenzie Romero for questions: info@utahnewsdispatch.com. Follow Utah News Dispatch on Facebook and Twitter.

Capital Power said CCS technology is “technically viable” and a potential pathway to decarbonization for thermal generation facilities, including the Genesee Generating Station. However, the company ultimately concluded that the project was not economically feasible, even with government subsidies.

Environmental Defence, a Canadian environmental advocacy organization, released a statement in response to Capital Power’s decision to cancel the CCS project, arguing that carbon capture is “unnecessary, ineffective and expensive” when considered against clean energy like wind, solar and storage.

“This decision is just the latest failure in carbon capture’s terrible track record. It should serve as a lesson for governments on how reckless it is to be using taxpayer dollars to subsidize these projects,” said Environmental Defence’s Julia Levin, Associate Director, National Climate. “The decision came despite massive government subsidies. Capital Power was already given $5 million from the Government of Alberta and the project would have been able to access both federal and provincial tax credits. Despite this, Capital Power still decided that the project would not be financially viable.”

Additionally, Environmental Defence said the few carbon capture projects that actually make it off the ground, such as the one at the Boundary Dam coal plant, typically only capture a “fraction” of the promised rate.

“The bottom line: the most effective way to deal with carbon dioxide emissions is to prevent them from ever being created, rather than trying to pluck them from the air or smokestacks and inject them underground,” Levin said.

In 2021, Capital Power began repowering Units 1 and 2 at the Genesee Generating Station, replacing coal-fired steam generators with gas-fired combined cycle technology. The utility approved its project in 2020, and Missouri-based Burns & McDonnell began design and engineering began in 2021.

“We delivered affordable and reliable power across our diverse and strategically positioned fleet of flexible generation assets,” said Avik Dey, President and CEO of Capital Power. “We continued to build decarbonized power through our Genesee Repowering project where we reached a key milestone with our startup of simple cycle unit 1 during Q1 2024. Once we startup simple cycle unit 2, expected in mid-2024, we will be fully off coal, achieving a significant carbon reduction target.”

The technology, developed by CORMETECH Inc., is designed to capture at least 95% of carbon dioxide (CO2) from the flue gas of NGCC power plants. CORMETECH received funding from DOE-NETL to develop the technology in a project titled Bench Scale Test of a Polyethyleneimine Monolith Carbon Capture Process for Natural Gas Combined Cycle Point Sources.

This specific technology approach uses a monolithic amine contactor to capture CO₂ from natural gas combined-cycle point sources. The monolith is a honeycomb structure with tiny flow channels for flue gas to pass through. The CO₂ within the flue gas adsorbs to the amine (polyethyleneimine) that is contained within the monolith’s internal porous structure. The CO₂ is later desorbed using steam for subsequent storage or use. The process is like Global Thermostat’s leading direct air capture process but incorporates modifications that enable its application at NGCC plants, NETL said.

The CORMETECH project was among 12 projects awarded a total of $45 million in federal funding to advance point-source carbon capture and storage technologies that can capture at least 95% of CO₂ emissions generated from natural gas power and industrial facilities.

Of the 491 GW of natural gas-fired electric-generating capacity in the country, more than half are combined-cycle systems that include both steam turbines and combustion turbines, according to the U.S. Energy Information Administration.

The development came in RMP’s update to its 2023 Integrated Resource Plan (IRP). Less than a year ago the utility said it would retire its Hunter and Huntington coal-fired units by 2032. Now RMP is proposing to return to the retirement schedule from its 2021 IRP.

That would mean the two units at Huntington would continue to burn coal until 2036 and the three units at Hunter would do so until 2042.

Rocky Mountain Power said these changes were driven by U.S. Environmental Protection Agency’s
(EPA) approval of Wyoming’s state Ozone Transport Rule (OTR) plan, the stay of EPA’s disapproval of Utah’s state OTR plan, extensions to the assumed operational life of new natural gas generating resources, energy storage acquisition strategy, forecast load demand, higher coal prices and natural gas and wholesale power market price updates.

“PacifiCorp’s coal resources will continue to play a pivotal role in following fluctuations in renewable energy as the remaining coal units approach retirement dates,” the company said in its 2023 IRP update. “EPA’s approval of Wyoming’s ozone plan and the stay of EPA’s disapproval of Utah’s ozone plan results in fewer restrictions on coal-fired operation than were assumed in the 2023 IRP.”

Additional investments in the updated plan include new wind and solar resources, the conversion of two coal-fired units to natural gas peaking units, growth in demand response and energy efficiency programs, an advanced nuclear resource and energy storage.

The IRP update shows a decrease in renewable acquisitions compared to RMP’s prior plans, and it had previously intended to replace the Huntington and Hunter coal-fired units with nuclear power.

RMP intends to acquire the following resources, according to the IRP:

• 9,818 MW of wind resources
• 4,016 MW of storage resources
• 3,763 MW of solar resources, most of which will be paired with storage
• 4,326 MW of capacity through energy efficiency programs, and 1,123 MW of capacity through demand response
• 500 MW of advanced nuclear through the TerraPower Natrium reactor demonstration project in 2030
• 5,385 MW of natural gas peaker plants
• Installation of carbon capture technology on Jim Bridger Units 3 and 4.
• New transmission projects and upgrades

With support from South Korea’s SK Group, RMP also announced it had formalized a Memorandum of Understanding (MOU) to collaborate with 8 Rivers to evaluate a potential carbon capture project at one of the utility’s existing brownfield power plant sites in Wyoming.

The project would utilize solid fuel-fired Allam-Fetvedt Cycle (AFC) technology, which would include syngas fired power generation with inherent carbon capture. The technology is an integration of commercially available gasification technology and the AFC technology. The Allam-Fetvedt Cycle is an oxyfuel process invented by 8 Rivers that uses carbon dioxide to drive a turbine to generate power.  Rocky Mountain Power has been evaluating potential carbon capture projects at its Wyoming coal facilities since 2018. 

“Rocky Mountain Power has been diligently engaged in the process to comply with Wyoming’s desire to implement carbon capture at the company’s coal generating units in Wyoming,” said James Owen, Rocky Mountain Power vice president for environmental, fuels and mining. “The partnership and collaboration announced today is a major step forward in determining if carbon capture technologies can bring benefits to our customers in Wyoming at a reasonable cost.”