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Cleaner Coal Faces an Uncertain Future

The end of an ambitious carbon-capture project shows that it’s hard to economically justify the technology in the absence of a carbon policy.

American Electric Power’s recent decision to scrap plans to capture and sequester carbon dioxide at a West Virginia power station is just the latest in a string of cancellations of carbon capture and storage (CCS) projects. The moves have dimmed the prospects for carbon-free power generation from coal. However, a handful of CCS projects are moving forward—including one in Mississippi that broke ground in December—so it might be too early to completely write off the technology.

Uncaptured carbon: A planned tenfold scale-up of carbon capture at this West Virginia power plant is on hold until stronger policy incentives arrive.

The U.S. Department of Energy’s goal is to start five to 10 large CCS projects within the next five years. The DOE believes those projects could drive down the cost of CCS, which currently boosts generation costs by at least 44 percent—but the incentives it’s offering have clearly not been sufficient to entice utilities. Low natural-gas prices have eroded coal’s cost advantage, while a national policy to penalize carbon-dioxide emissions has yet to materialize. As a result, utilities have been unwilling to pursue CCS, even with the DOE footing half the bill. “The federal incentives offered to move the technology forward just aren’t working,” says Kurt Waltzer, a carbon storage expert with the Clean Air Task Force, a nonprofit environmental consulting firm based in Boston.

For example, Columbus, Ohio-based AEP walked away from a $334 million federal grant to cover half of its proposed CCS installation. The plan was to capture at least 90 percent of the carbon dioxide from a portion of the flue gases at its 1,300-megawatt power plant in New Haven, West Virginia. The 1.5 million tons per year of captured carbon dioxide was to be permanently stored in geologic formations below the plant. But expected supports did not come through. The U.S. Senate rejected a cap-and-trade bill last year (AEP supported the legislation), while Virginia and West Virginia’s public utility commissions refused to pass along all of AEP’s costs to ratepayers.

Basin Electric cited cost as a primary factor in its December decision to walk away from a similar CCS retrofit. The Bismarck, North Dakota-based rural electricity cooperative had secured $100 million in DOE funding for a $287 million project to capture a million tons of carbon dioxide annually at its coal-fired power station in Antelope Valley, North Dakota.

Utilities moving forward with CCS projects are closing the gap by selling their carbon dioxide to enhanced oil recovery operations, which inject carbon dioxide into oil wells to help push more oil to the surface. Such operations currently provide about 5 percent of U.S. domestic oil production, and could ultimately double U.S. oil reserves, according to a report last year by MIT’s Energy Initiative.

Southern Company plans to seize that opportunity with a $2.4 billion, 582-megawatt advanced coal power plant that it began building in Kemper County, Mississippi, this winter. The integrated gasification combined cycle (IGCC) plant will convert coal to clean-burning gases, from which carbon dioxide is easier to remove than the diluted flue gases from a conventional coal plant. Southern has contracted to sell most of its captured carbon dioxide to oil and gas producer Denbury Resources starting in 2014. Southern will also receive $682 million in federal incentives, and Mississippi’s Public Service Commission is allowing it to recover most of its remaining costs from customers.

Seattle-based Summit Power is generating further revenue with the 400-megawatt IGCC plant that it is developing in Penwell, Texas. Summit plans to capture and sell the plant’s carbon dioxide for oil recovery, and is also converting some of its coal-derived gases into urea fertilizer.

But selling carbon dioxide for use in enhanced oil recovery is not an option for plants in much of the eastern U.S. because they lack access to oil fields. Julio Friedmann, director of Lawrence Livermore National Laboratory’s Carbon Management Program, says the lack of revenue from its carbon-dioxide generation was part of what held back AEP’s project. It also helps explain why Charlotte, North Carolina-based Duke Energy has not committed to carbon capture at a $2.9 billion IGCC plant that is near completion in Indiana. “Barring a huge pipeline to the Gulf of Mexico, projects in the Midwest will be disadvantaged,” says Friedmann.

Waltzer says the best hope for moving CCS forward at coal-fired power plants is the new emissions standards for power plants that the U.S. Environmental Protection Agency plans to issue in September. The EPA may, for the first time, include a standard for carbon-dioxide emissions. Waltzer hopes the EPA will match the standard in California, which limits carbon-dioxide emissions to the levels produced by natural-gas-fired power plants. To meet that standard, coal-fired power plants would have to capture roughly two-thirds of their carbon dioxide—exactly what Southern Company plans to do at its Kemper IGCC plant.

In California, meanwhile, government laboratories and utilities have begun to study carbon capture from the natural-gas-fired plants that provide half of the state’s power. That may be essential to help meet California’s goal of reducing greenhouse-gas emissions by 25 percent by 2020 (from 1990 levels).

Ultimately, says Waltzer, CCS will be required on all power plants to achieve the 80 percent reduction by 2050 that many climate scientists argue is needed to hold global warming this century to 2 °C. As Friedmann puts it, “We will not hit the steep abatement targets proposed by many experts and the president without sequestering carbon dioxide from both coal and natural gas.”

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