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Wyoming coal plants illustrate cost challenges for power generation CCS in US.
Filings by Wyoming's two electric utilities that operate coal-fired power plants show the cost challenges that any North American operator would face in equipping their operations with carbon capture and storage (CCS) to reduce or negate GHG emissions.
In a rate filing, Rocky Mountain Power (RMP) told the Wyoming Public Service Commission (PSC) on 31 March that building sufficient CCS for a single coal unit would cost up to $1 billion, plus annual operating costs. Black Hills, which studied CCS for two smaller coal units than those of RMP, put the cost at $441 million to $468 million, plus more than $50 million to develop injection wells, in its own PSC filing, also on 31 March.
Another estimate of a North American CCS operation came in at $900 million this month, cited by Cleco, a Louisiana utility for its Project Diamond Vault on 11 April. That project would capture up to 95% of the CO2 from its solid fuel (coal, petcoke, or biomass) Madison 3 unit at the Brame Energy Center.
Those price tags represent a challenge for power producers, even as scientists on the UN Intergovernmental Panel on Climate Change say that CCS will be necessary for the world to reach net-zero emissions by 2050 and stave off the worst impacts of climate change.
With more than 80% of US primary energy demand satisfied by fossil fuels, "if emissions are to be controlled, carbon capture and storage is essential," added S&P Global Commodity Insights in a special report released in March, North American Carbon Capture and Storage: The Scale and Uncertainties.
But it warned, "CCS has been neither proved nor demonstrated at anything like the scale required for decarbonizing the electric power supply in North America, let alone the rest of the world. Such demonstration at scale does not appear likely in any near-term time frame."
No CCS project is currently operating at a coal-fired power plant in the US, although six are currently in the design phase, and one has reached the financing stage, according to S&P Global.
Wyoming and coal
Wyoming is by far the largest coal mining state in the US, with its nearly 219 million short tons (st) in 2020 representing 40% of US production, according to the US Energy Information Administration (EIA). It's the 10th-largest coal-using state, at 22 million st, but because of its small population it's second only to Alaska in energy use per capita.
The state has 12 coal-fired power plants with a total of 23 units that serve not only residents and businesses, but also export power to neighboring states. Legislators have tried various incentives and requirements to keep those coal plants operating, most notably HB200, which was passed in 2020. Under this law, utilities are required to report on the feasibility of using CCS as part of their Low-Carbon Energy Portfolio Standards in their long-term plans for power service.
RMP is on record as preferring to close its 11 Wyoming coal units. "CCUS was not selected as a least-cost resource in the company's 2021 integrated resource plan preferred portfolio," it told the Wyoming PSC in March.
RMP said three of its Wyoming coal units appear to be the best candidates for CCS in a technical sense, if not a financial sense. CCS would capture 90% of the CO2 from those plants, according to the analysis by construction firm Kiewit. In the 2021 request for expressions of interest by engineering firms, RMP said that one of the analyzed units (Dave Johnston Unit 4) had CO2 emissions of 2.3 million st in 2020 and 2.6 million st in 2019; the other two (Jim Bridger Units 3 and 4) had emissions of 2.9 million to 3.4 million st in those years.
A spokesperson for RMP's parent, PacifiCorp, told Net-Zero Business Daily that those three units were selected after weighing factors such as power capacity (to meet in-state demand); age; proximity to CO2 pipelines, sequestration fields, and water; need for additional pollution control equipment on the coal units; and more.
Black Hills' report to the state PSC, prepared by engineering firm Black & Veatch, said CCS units could be retrofitted to two coal units. These have a lower capacity than the RMP units and produce lower emissions as well of about 800,000-900,000 st per year at baseload operation. The CCS facilities would capture 90% of those emissions, or about 1.5 million mt of CO2 per year.
Reports from both utilities recommended amine-based solvent absorption systems as the most commercial ready option.
However, the analyses indicate the finances for CCS simply don't work, given restrictions that Wyoming has placed on cost recovery from the public.
HB200 set a maximum surcharge of 2% on annual bills to cover CCS, which is substantially less than the costs the utilities would incur if they pushed ahead with installing the technology.
Black Hills, which has 44,000 customers in the state, said that the rate recovery would account for only 6-7% of its CCS costs, assuming a 20-year operating life. To fully cover its expenditures, Black Hills said it would have to raise the bill for a typical residential customer of one coal plant by $25.34/month, or almost 16%, and by $22.75/month, or 13%, at the other.
PacifiCorp estimates the maximum allowed annual collection from its 142,000 ratepayers in the state would be about $13.1 million per year, also for 20 years. This could fund a $100-million project, not the potential $1 billion bill it's facing.
For the moment, both utilities are seeking rate recovery of a few million dollars each that would cover the cost of preparing requests for proposal for the FEED analysis from engineering firms. The FEED would enable them to give the PSC more detailed cost analyses and timelines for CCS installations—though that's still several steps away from actually financing and building the facilities. RMP's report indicated a 2026 startup, based on time for permitting, construction, and testing.
Great need, but high costs
The activity in Wyoming is matched by growing interest in CCS across the US for a number of applications. The Carbon Capture Coalition (CCC), a US-based research and lobbying group, pegs the current number of US-based CCS facilities at 12 industrial facilities, but with 90 announced or at some level of development, such as a FEED study.
In a comment letter to the Council on Environmental Quality (CEQ) on 18 April, the coalition said it believes that in the US alone, capture capacity could reach 210-250 million mt per year by 2035, with the proper federal tax incentives and streamlined site permitting.
Those installations would serve the power industry, ethanol producers, and industrial processors, plus coal units would not necessarily be at the front of the line. "We're seeing more interest starting to emerge from natural gas power operators looking at retrofits or even newbuilds," Jessie Stolark, public policy manager for CCC, told Net-Zero Business Daily. "It's reflective of the overall economics for coal generation in the US."
But Stolark hastened to add that the coalition "is very supportive of deploying the technology in the coal power sector. It's really important from a global climate perspective to demonstrate CCS in the US and deploy on it on a much younger coal fleet in Asia-Pacific, where plants are less than 20 years old in most cases."
Financial incentives and innovation
Teaming CCS with coal or gas plants will require a major adjustment in the cost or the incentives for carbon capture, or both, analysts said.
"Power generation is one of the most expensive sectors to add CCS, and I think that's not going to change any time soon," said Paola Perez Pena, S&P Global Commodity Insights principal research analyst, power & energy.
With innovations, the $1 billion cost of a full-scale CCS operation to capture 90% of the carbon from a 1-GW power plant cost could be reduced to $700 million-$800 million in about a decade, she said.
"The reason we're not seeing utility-scale CCS, or in steel, is economics," Perez Pena said.
Given that price tag, a federal price on carbon or extensive government funding to support CCS is crucial, and Perez Pena said the extension of the 45Q investment tax for carbon sequestration is an important matter for the industry. It provides $50/mt for stored carbon and $35/mt for carbon that is reused, such as for enhanced oil recovery (EOR).
But the tax credit is only enough to potentially reach positive returns for the lowest-cost CCS, such as for ethanol and ammonia producers, or for natural gas processing plants, she said. Their costs are lower because the CO2 streams they process are purer than from coal-fired power plants.
One report provided to Net-Zero Business Daily by the CCC estimates the cost of ethanol, ammonia, and gas processing CCS at $15-$20/mt of carbon removed, whereas coal is at $55-$65/mt, and combined-cycle natural gas at $65-$75/mt.
While EOR can provide a revenue stream, there doesn't appear to be enough demand—and at an attractive price—to solve the problem. Ethanol producers can earn CCS credits under the Low Carbon Fuel Standard, but that's not available for coal-fired electricity production.
Given the existing incentives, Perez Pena said that private sector investors are waiting for costs to decrease and for infrastructure to be built to move captured CO2 to storage facilities before they make a big commitment to CCS.
Meanwhile, for utilities looking to reduce their carbon emissions, renewables are a much cheaper option (though regional grid system operators are watching out for reliability issues as the share of renewables in their mix increases). S&P Global estimates that the cost of a newly built coal power unit in North America with CCS would be approximately $4,600 per kilowatt (kWh). This includes the need to increase capacity at the power plant to run the carbon capture equipment, itself an energy-intensive process.
The cost of retrofitting CCS to support an existing coal plant would be even higher, due to "the constraints and compromises of the existing plant footprint and of tying the new process equipment into an existing facility that was not built for this purpose" all adding to the cost. S&P Global estimates this would tack on another 10-50%, depending on the specific facility.
For comparison, the EIA said that a new utility-scale solar facility in the US cost under $1,800 kWh in 2019.
CCS innovation will close that gap, Stolark said. "What sometimes gets lost in the conversation is that we are at an early point in CCS development … [compared] with other low- and zero-carbon technologies," she said. "We forget that the cost of wind and solar fell dramatically because they were afforded many years of tax credits."
The 45Q credit is part of the answer, as it will encourage commercial projects and build a supply chain, she said. Also, she said the industry is poised to benefit from knowledge gained through projects funded by $12 billion set aside for carbon sequestration in the 2021 infrastructure bill, as the law states that two projects must be for coal and two for natural gas.
Yet, questions remain about how much improvement can be made, and how quickly. In its report to the Wyoming PSC, Black Hills said that innovation could cut the cost of CCS by 40% and improve carbon capture to 99% from the current 90-95%. But it said those technologies are in the R&D stage and would not be ready for commercial deployment until at least 2035.
This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.
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