Editor’s note: Second of two articles on the impact of carbon capture and storage, and how rural utilities are grappling with the new regulations on greenhouse gas emissions.
Minnkota Power Cooperative, which supplies power to 11 rural electric co-ops in North Dakota and Minnesota, is making a bet on technology that can capture the carbon dioxide produced by generating electricity from coal.
Minnkota’s Project Tundra, which is relying heavily on federal incentives, is intended to help electric co-ops meet the Biden administration’s climate goals while keeping electric rates affordable for rural residents in the region.
Project Tundra is designed to capture up to 4 million metric tons of CO2 annually from the Milton R. Young Station, a lignite coal-fired power plant near Center, North Dakota. If completed as planned in 2029, it would be the world's largest carbon capture and storage (CCS) facility.
But Minnkota officials say the project may never be finished because of new EPA regulations that require coal-fired power plants and new natural gas facilities to capture 90% of their greenhouse gas emissions by 2032 and 2035, respectively.
“I’m concerned … that what EPA has done in this rule ultimately is unrealistic for most plants in this country,” Minnkota CEO Mac McLennan said.
Mac McLennan, Minnkota CEOThe skepticism is technical in nature. The Young station has two generating units with a total of 705 MW capacity. Tundra has capacity to treat 530 MW of flue gas, insufficient to cover EPA’s anticipated scope, so an additional CCS “train” would be needed. The train is the technology that moves, treats and compresses the gas for ultimate storage.
Tundra is designed to capture 95% of the flue gas when the CCS equipment is running at full load. If the two Young generators are still running but the CCS equipment is temporarily out of service, the utility said it will be difficult to meet the scope of the new source rule.
Minnkota had anticipated making a decision about whether to go forward with Tundra this year.
The EPA regulations, which are now being challenged at the U.S. Court of Appeals for the D.C. Circuit in Washington, call for coal plants that want to remain operational after 2039 to use CCS — considered the best available technology — by the 2032 deadline or shut down.
CCS is widely touted with little adoption in the utility sector, and largely uses amine-based postcombustion capture technology.
This method passes flue gas through a liquid solution containing amine compounds, which chemically react with the CO2, effectively capturing it and allowing for its later separation and storage. Motorized compressors take the CO2 and compress it into a denser state so it can be sequestered into a geologic formation or placed in a pipeline for commercial use.
CCS technology requires substantial amounts of power, so a portion of the electricity generated by the power plant being served is consumed as what is called "parasitic load."
EPA insists that CCS technology has been “adequately demonstrated,” as required by the Clean Air Act, and that the various components have been shown to operate simultaneously. "Even if the record only included demonstration of the individual components of CCS, the EPA would still determine that CCS is adequately demonstrated as it would be reasonable on a technical basis that the individual components are capable of functioning together," the EPA rule says.
The National Rural Electric Cooperative Association argues that utilities have few options for meeting EPA’s 90% reduction and that onsite geologic storage of the carbon dioxide isn’t feasible in many areas.
The Energy Department says the best formations for CCS are deep and porous, and filled with brine, or salty water.
Gavin McCollam, Basin COOBasin Electric Power Cooperative, a generation and transmission cooperative that services REC customers across nine states, also is preparing to comply with the EPA rule. Basin COO Gavin McCollam estimated that a postcombustion CCS system at its 405 MW Dry Fork coal plant in Wyoming would cost about $2 billion, more than 150% of the plant’s cost a decade ago.
And the technology may not meet EPA’s goals. “Basin Electric is not aware of any manufacturer currently offering to warrant equipment that will achieve 90% CCS under any conditions,” McCollam said.
He said Basin is familiar with the challenges experienced by Canada's SaskPower in maintaining and operating the capture unit at Boundary Dam — a coal-fired facility in Saskatchewan that has been operating with CCS since 2014 — including unplanned outages.
Basin received an EPA award to add 1,400 MW of renewable generation to serve customers in Montana and the Dakotas under the Empowering Rural America program, known as New ERA, an initiative managed by USDA and funded through the Inflation Reduction Act of 2022.
CCS expenses take many forms
There is no recognized yardstick for the costs of CCS, and capital costs are merely a starting point. The power industry also focuses on operating costs and the price of the resulting electricity.
Project Tundra is estimated to cost $2 billion to build. Boundary Dam cost $1.47 billion, according to researchers. Petra Nova, a CCS-equipped facility in Fort Bend County, Texas, owned by JX Nippon Oil and Gas Exploration, cost $1 billion.
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“A lot of uncertainty remains, and factors driving cost can vary greatly depending on site location and other issues,” said a spokesperson for the Electric Power Research Institute, a global industry research group.
A study published in 2020 by the DOE’s Pacific Northwest National Laboratory showed postcombustion capture using an amine-based solvent had a total capture cost, including capital expenditures, of $50.60 per metric ton of CO2, “among the lowest capture costs claimed to date.” Estimates in the industry of total capture costs vary widely.
One industry consultant who didn’t want to be identified said federal incentives could offset those kinds of total capture costs.
“The bigger issue might be the technical barriers, which may include availability of sites near the CCS facility to store carbon or the availability of pipelines to haul the CO2 into offsite storage or to be used in industry,” he said.
The EPA's consultant for cost and performance assumptions for carbon capture, Sargent & Lundy, last year said in a report that the cost of capture for coal-fired units "is generally in the range of $30-$50 per metric ton."
The report estimated that cost of capture, in 2017 dollars, at Boundary Dam was around $110 per metric ton, compared to $65 at Petro Nova.
U.K.-based commodity research group CRU estimates a carbon price of around $200 per metric ton of CO2 is needed for currently proposed CCS coal power projects to be competitive. “Neither the current carbon price in Europe … nor the 45Q tax credits for CCS under the U.S. IRA are sufficient to incentivize investment in CCS without other support,” CRU said.
In the group’s recent study, total operating costs from capture through to injection were estimated at $40-$60 per metric ton. The technology would increase the cost of coal-fired power by 30% or more, the study concluded.
Utilities are running the numbers to determine compliance costs. East Kentucky Power Cooperative estimated that installing CCS at its 1,608 MW Spurlock coal plant would cost $10.7 billion. The benefit of the 45Q tax credit for carbon capture is $77.11 per metric ton at the site, but running CCS would produce power at more than $129 per MW, more than six times the daytime spot market price on a recent typical October day. Average customer bills from the co-op would rise by 67%-96%, the utility said.
CCS obstacles remain
One of the biggest disappointments of green groups, climate advocates and the utility industry is the failure of the U.S. to create a market for carbon credits in tandem with mandatory carbon reductions. A proposal for a cap-and-trade system passed the House in 2009 but died in the Senate and hasn’t been resurrected.
The touchstone resource for climate data and policy, the United Nations’ Intergovernmental Panel on Climate Change, is not optimistic about CCS. The group said in its 2022 update that adoption of solar, wind and batteries has occurred much faster than anticipated, while nuclear energy and CCS in the electricity sector are slow to be accepted.
Utilities have other options, not all of them palatable for rural economies.
Natural gas-fired generation has chipped away at coal in recent decades and produces roughly 40% of U.S. power. EPA suggests in the proposed rule that “intermediate” natural gas plants only operate up to 40% of the time, or produce 1,150 pounds of CO2 per MWh. Peaker plants with capacity factors of 20% or less can use gas or other lower-emitting fuels.
The other alternative is to build renewable generation, like wind and solar. Industry officials warn that renewables are intermittent and undependable.
Still, Tri-State Generation and Transmission, which serves rural electric co-ops in Colorado, Nebraska, New Mexico and Wyoming, has put out requests for proposals to build 1,250 MW of renewables and battery storage, along with a 290 MW natural gas unit. That gas plant is expected to go online in 2028, with CCS added in 2031.
Tri-State said the Inflation Reduction Act incentivizes cooperatives to develop their own renewables instead of making power purchases. USDA grants and the ability to monetize tax credits “will have a big impact,” the company said.
Tri-State also intends to shut down two large coal plants, Craig Unit 3 in 2028 in Colorado and Springerville Unit 3 in Arizona in 2031.
Colorado has been pushing for green power and the changes to Tri-State’s generation portfolio should slash greenhouse gas emissions related to wholesale power sales in that state by 89% by 2030 from 2005 levels.
In the coming years, demand response mechanisms among its customers are expected to be able to dampen utility loads in the region. A decade from now, coal’s portion of Tri-State’s resources likely will be more than halved, replaced mainly by natural gas, wind hybrids and battery storage.
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