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.”

The testing took place this week at ESG’s 4 MW power generation site in Holyoke, Massachusetts. Using calibrated humidity sensors positioned at both the beginning and the end of the exhaust stream, ESG says the results exceeded the modeled forecast of 83% that was developed during the initial design phase of its carbon capture process.

“This will work to our benefit as we scale to meet the demands of fossil fuel consumption in small and large power facilities, and eventually the transportation industry,” said Nick Scuderi, president of ESG Clean Energy.

ESG has plans to build a second gas-fired plant in Holyoke. The 4.2 MW plant would also be powered by Caterpillar engines.

ESG Clean Energy says it plans on implementing its CO2 capture technology across all its planned facilities and has licensed the technology to a subsidiary of Camber Energy for all of Canada and multiple locations in the United States.

The company says its system treats the exhaust stream to remove the water vapor before it is treated for capturing CO2. The system consists of a ceramic membrane that has been incorporated into a mechanical cooling system.

There’s a problem with traditional carbon capture, ESG Clean Energy says: separting and capturing carbon dioxide from a mixture of nitrogen, oxygen, carbon dioxide, nitrogen oxides, carbon monoxide, and water vapor can be difficult, and while some materials have been developed that can “selectively attach or react with the CO2 while letting the other gases pass by,” the water vapor remains. Water molecules interfere with the carbon capture process, ESG Clean Energy says, citing several scientific studies showing how water negatively affects CO2 capture.

The Environmental Protection Agency (EPA) is expected to propose updated carbon emission regulations for gas-fired plants in 2022, per comments from EPA head Michael Regan in March.

The agency recently took another step in that direction, publishing a white paper detailing ways gas-plants can reduce their CO2 emissions.

The paper presents opportunities for emission cuts, like the co-firing of natural gas with alternative fuels such as hydrogen; using carbon capture, utilization, and storage (CCUS) technologies; and the co-location with energy storage. Although it doesn’t set policy or establish standards, the EPA “anticipates that the white paper may be useful to inform future rulemaking efforts.”

The Clean Air Act requires new engines and equipment sold or distributed in the United States to be certified to meet EPA-established emissions requirements to protect public health and the environment from air pollution.

Under the latest standards from 2015, new natural gas power plants can emit no more than 1,000 pounds of carbon dioxide per MW of electricity produced. New coal-fired power plants can emit no more than 1,400 lbs CO2/MWh. The standards apply to sources on or after the date of publication of the proposed standards, June 18, 2014.

It’s not clear to what extent the new EPA rules will rely on CCUS technology. The agency’s white paper notes while there is increased interest in carbon capture for natural gas-fired plants, most CCUS efforts have focused on coal plants.

Examples of carbon capture installed on coal plants include the slip stream capture facilities AES Warrior Run in Maryland and AES Shady Point in Oklahoma. In both cases, the captured CO2 is used in the food processing industry. The EPA also cited Southern Company’s Plant Barry in Alabama and AEP’s Mountaineer in West Virginia as having CCUS technology.

Use of CCUS on combined cycle plants include the Bellingham, Massachusetts plant, which used Fluor’s Econamine FG PlusSM capture system. The 40 MW slipstream capture facility operated from 1991 to 2005 and captured 85 to 95 percent of the CO2 for use in the food industry.

The paper notes some emission control technologies that are currently available and some still in the research and development phase.

EPA officials noted the U.S. Department of Energy (DOE), utilities and other organizations are developing processes that use solvents, polymeric membranes, a combination of the two, or solid sorbents for separating and capturing CO2.

Fuel cells configured for emissions capture have also emerged as a CCUS technology. In this process, the flue gas from a plant is “routed through a molten carbonate fuel cell that concentrates the CO2 as a side reaction during the electric generation process in the fuel cell.”

The white paper also mentions oxygen combustion, the use of a mixture of oxygen and recycled flue gas in place of ambient air for combustion. An oxy-combustion power plant consists of an air separation unit (ASU), which generally requires a significant amount of energy. However, alternative oxygen separation methods are being researched for possible commercial-scale development. These include ion transport membranes (ITM), ceramic autothermal recovery, oxygen transport membranes, and chemical looping.

The EPA noted because oxy-combustion produces a flue gas that contains primarily CO₂ and water vapor, minimal post-combustion cleanup is required prior to compression, transportation, and injection for use in geological storage, enhanced oil or gas recovery, or some other use. However, a potential constraint of oxy-combustion is the ability of the air separation unit to respond to variable loads.

The Allam-Fetvedt Cycle, which combusts natural gas with oxygen instead of air, uses supercritical carbon dioxide as a working fluid to drive a turbine instead of steam. This theoretically eliminates all air emissions and inherently produces pipeline-quality CO₂ that can be sequestered.

There are several announced commercial projects proposing to use the Allam-Fetvedt cycle. These include the 280-MW Broadwing Clean Energy Complex in Illinois and the 280-MW Coyote Clean Power Project on the Southern Ute Indian Reservation in Colorado. Final investment decisions on the U.S. projects are expected in 2022 and commercial operations could commence by 2025.

EPA is asking for public comment on the white paper through June 6, 2022.

The agreement would accelerate development of the largest fully permitted carbon storage site in the United States.

Minnkota Power Cooperative and Summit Carbon Solutions have agreed to co-develop carbon dioxide storage facilities near Center, North Dakota.

The partnership builds on development already in the works. Minnkota and Summit have been working independently on developing their respective carbon capture and storage projects.

Minnkota’s Project Tundra aims to install carbon capture technologies at the Milton R. Young Station in North Dakota. The station is a two-unit, 705-MW lignite coal-burning plant. Unit 1 became operational 50 years ago, while Unit 2 began generating electricity seven years later. It is a primary generating facility for Minnkota, which hopes carbon capture could contain up to 90 percent of the carbon dioxide emissions from the Unit 2 generation.

Iowa-based Summit Carbon Solutions aims to capture and permanently store CO₂ from dozens of ethanol plants across five states in the Upper Midwest.

The agreement gives Summit access to Minnkota’s already permitted 100-million-ton capacity CO₂ storage site, the largest of only three such permitted sites in the United States. It also creates the framework to jointly develop additional CO₂ storage resources nearby, which could hold more than 200 million tons.