When the Department of Energy announced in January that it would cancel funding for the vaunted FutureGen project (to build the world’s first coal-fired power plant with zero carbon dioxide emissions), the decision was widely viewed as the biggest setback to date for carbon capture and storage (C.C.S.) technologies.

First announced by the D.O.E. in 2003, FutureGen was seen as a prototype for a new fleet of coal plants that would strip the carbon from coal and coal plant smokestacks, and bury it deep underground where it would remain for thousands of years. Working with a coalition of domestic and foreign energy companies, the federal government was to pay 74 percent of the cost – which by the time the concept was scrapped had soared to a projected $1.8 billion, up from $1 billion.

FutureGen also bore the hope of industry and government officials that “clean coal” – long an oxymoron to those who actually mine and burn the stuff – could become a reality. In February 2007, Energy Secretary Samuel Bodman called FutureGen “one of our most exciting projects,” noting that it would build “the world’s first commercial scale, coal-fired power plant that produces no significant emissions of carbon or pollutants into the atmosphere.” In December, less than two months before the D.O.E. backed away, the new FutureGen plant site at Mattoon, Illinois was announced with great fanfare. 

Now those plans are in ruins – along with the projections of the most optimistic proponents, who had hoped to build on a grand scale, so that we could significantly reduce carbon dioxide emissions in this country while continuing to rely on coal for most of our electricity.

FutureGen CEO Michael Mudd, for one, hasn’t given up, saying he hopes “to continue to work with the D.O.E.” to salvage the ambitious project, or else to seek new funding from Congress, where members from coal-producing states have been big FutureGen supporters. “FutureGen is too important for the future of coal, and for the advancement of [carbon capture and storage] technology, not only for Illinois and the U.S. but actually for the world, to just to walk away from,” Mudd said two weeks after the D.O.E. decision was made public.

But while it has all the characteristics of a massive government boondoggle – a bloated original concept, ballooning budgets, competing interests focused as much on their own piece of the pie as on the overall goal, and an abrupt and embarrassing pulling of the plug – the FutureGen debacle did not occur within a vacuum. Nor is it the only setback for a viable nationwide C.C.S. system.

Problems with FutureGen had been noted for months, most prominently in a March 2007 report by a research group from Massachusetts Institute of Technology headed by Ernest Moniz, a physics and engineering systems professor. That report characterized the project as overregulated, underfunded, and poorly managed. “The Future of Coal: Options for a Carbon Constrained World” was characterized by the mainstream press as casting a cold eye on the concept of clean coal, particularly on the gasification technology known as integrated gasification combined cycle (I.G.C.C., which involves converting coal into a gaseous state rather than pulverizing it, before it is burned in boilers). That’s not the case: Moniz has stated that I.G.C.C. “looks like the most economic option for using coal and capturing the carbon dioxide for sequestration,” and the report makes it clear that the government should put more, not less, money and muscle into C.C.S. projects.

But the report also states that a single, federally funded “super-project” will be insufficient to prove the technology and attract the investment necessary to make C.C.S. into a reality.

Meanwhile a number of other proposed designs for C.C.S. projects have suffered FutureGen’s fate.

- Minneapolis-based Xcel Energy, an electric utility that serves eight states across the Midwest and the Rockies, said in November it will postpone for at least two years its plans to build an I.G.C.C. plant with carbon capture capability in Colorado.
- Rebuffing a coalition of mayors headed by Laura Miller of Dallas, Mike Green, CEO of Texas energy giant TXU Power, said that I.G.C.C. will not work with Texas lignite or Western coal. Green told The Dallas Morning News that I.G.C.C. and C.C.S. are “not ready for prime time.”
- In 2006, Governor Brian Schweitzer of Montana announced a grandiose scheme for coal plants featuring C.C.S. technology, saying that Montana and three other Rocky Mountain neighbors could produce enough liquid fuel from coal and oil shale to supply America’s oil and gas needs for the next 800 years. But he has been forced to concede that his original vision was overblown, and that none of his envisioned projects have gotten past the press-release stage.

Despite years of glowing pronouncements from politicians and D.O.E. officials, and hundreds of millions in research and development funds from the states and the federal government, not a spade has been turned to build clean coal plants in Montana – or anywhere else in America, for that matter. Does that mean that carbon capture and storage, and its associated technologies like I.G.C.C., are beyond repair? Hardly. But it does mean that we are moving beyond the period of artists’ renderings and enthusiastic press conferences to a phase of hard realities, as the promise and the challenge of capturing and storing large amounts of carbon dioxide are examined in a harsher light. A look at a pair existing C.C.S. projects – one on the Northern Plains and one on the Gulf Coast of Texas and Mississippi – demonstrates that capturing carbon from coal-based power generation is difficult, storing it for hundreds of years is quite feasible, and building the infrastructure to do so on a national scale is going to be very, very expensive.

It is not entirely accurate to say that FutureGen would have been the world’s first coal-based plant with a carbon-capture system attached. That distinction belongs to the Dakota Gasification Plant about 50 miles northwest of Bismarck, North Dakota. However, Dakota Gas doesn’t produce electricity; it just converts coal into natural gas, in the process capturing carbon dioxide from the coal and sending it via a 325-kilometer pipeline to EnCana’s Weyburn oilfield in Canada. There the carbon dioxide is pumped deep underground to aid with enhanced oil recovery (E.O.R.), prolonging the life of the Weyburn wells.

Dakota Gas is actually a remnant of America’s first energy crisis, the 1970s oil shock that lead to a brief flowering of alternative-energy research, and its tangled history gives an idea of how difficult it might be to finance and build a full-fledged coal-fired electricity industry using carbon capture. Planned and funded under President Jimmy Carter, the gasification plant was completed at a cost of $2.1 billion in 1984 and filed for bankruptcy on the first day natural gas from coal began flowing from the plant. Operated by the government for four years, it was sold in 1988 to the Great Basin Electrical Co-op, which also owns two 450-megawatt coal stations adjacent to the gasification plant.

Now run under a revenue-sharing agreement with the D.O.E., the plant sends an annual 3 million tons of carbon dioxide north to the Weyburn field, which has produced nearly 400 million barrels since its 1954 discovery. There, at a rate of around 125 million cubic feet per day, the carbon dioxide is pumped down into the reservoir, where it mixes with the oil and makes it easier to pump to the surface. Carbon dioxide that is removed with the oil is extracted and recycled back into the wells.

By almost any measure, the Dakota Gas/Weyburn project has been a success. It has proven the technological and geological feasibility of stripping carbon dioxide from coal prior to burning and using it for E.O.R. – an increasingly important technique as domestic oilfields face depletion. The economics, though, are a different matter.

“If this thing cost $2 billion in the 1970s, what do you think it would cost today?” asks Gary Loop, the C.O.O. of Dakota Gas. He questions whether such greenfield plants can be built and run to make them commercially profitable. In fact, a Phase 2 plan to build a generating station at the Beulah facility using gas from the Dakota Gas plant has been on the books for years, but Loop says, “We don’t believe Phase 2 is economical.”

“Of course, we’ve got 1970s technology,” he adds. The company is currently looking for a partner – and federal funding, naturally – to build such a generating station nearby, plus an expanded pipeline system that would collect carbon dioxide from other plants in the region and ship it north to Weyburn. “If you took all the carbon being produced in electrical plants in this area – most of which have carbon dioxide that would be more difficult to capture than ours – there’s enough known E.O.R. sites within 300 miles, which is the economic distance, to handle all the output for the next 50 years.”

There are several “ifs” embedded in that statement: if you could find a way to economically retrofit the existing plants; if the utilities could find financing to build the new capture systems; if consumers could be convinced to absorb the added price per kilowatt-hour of their electricity; and if you could successfully store the CO2 underground once you ran out of oil wells needing E.O.R.

That last question is the piece of the puzzle being examined by a team of geologists and oilfield engineers, at the Bureau of Economic Geology at the University of Texas. With funding from the D.O.E.’s Regional Carbon Sequestration Program, which is backing seven such partnerships around the country, the researchers have spent the last 4 years injecting 1,850 tons of carbon dioxide into the Frio formation, about 30 miles east of Houston. Soon they’ll begin scaling up the system for a much more ambitious project near Natchez, Mississippi.

Scheduled for 10 years, with $38 million in D.O.E. funding, this second phase will be the first long-term project in the U.S. to study the feasibility of injecting large volumes of CO2 into underground storage locations. Unlike the Frio project, which stored relatively small amounts, the Mississippi experiment will handle commercial volumes, from a plant owned by Denbury Resources, Inc. of Plano, Texas. According to lead scientist Susan Hovorka, that will come to around 1 million tons of carbon dioxide a year. “We need to go to the next level,” says Hovorka. “We’ll be injecting at a rate of 1 million tons a year in four wells.”

Noting that a typical 450 MW power plant produces 5 million to 8 million tons of CO2 annually, Hovorka says, “The math is easy – you’ll need a well field. If we can get 1 million tons [a year] easily in four wells, and you want to do five times that, that gives you 20 wells.”

So far the data from the Frio tests has been encouraging. The carbon dioxide injections have been stable, and no leaks have been detected – to the extent that even drilling a well and trying to “produce” carbon dioxide (i.e., pump it to the surface) proved difficult. The storage part of capture-and-storage is “in the bag,” says Hovorka. “If you want it, it’s there,” she adds. “The question of whether you want to pay for capturing it also remains open.”

But many questions remain. First and foremost: what will all this cost?

And where to put all that carbon? Not all sites with coal plants are situated above geological formations suitable for storing carbon dioxide for thousands of years. Getting the carbon from the plants to the storage sites will entail building an extensive pipeline system comparable to the existing natural gas one, which was built up over decades at a cost of billions (in today’s dollars). The 60 percent figure from the N.E.T.L. report does not include the cost of pipelines, which must be built from expensive alloys or fiberglass rather than the typical steel used in conventional pipelines.

Then there is the question of water. Both I.G.C.C. and carbon-capture technologies use vastly increased amounts compared to conventional coal-fired plants. Another N.E.T.L. report released in December predicts that the power industry’s water use would nearly double if carbon capture were instituted on a national scale. That would be particularly problematic in the western U.S., which already experiences significant water shortages.

Finally there is the issue of timing. The best-case industry scenarios estimate that significant carbon-capture technologies are still a decade away. FutureGen itself was not slated to be operational until 2015 – surely an optimistic date. Joseph Romm, a Clinton Administration energy official and currently a fellow at the Center for American Progress in Washington, D.C., has written on his blog, “By the time this technology was [sic] ready to commercialize on a significant scale in the early 2020s, the world will have built or begun construction on more than a thousand gigawatts of coal plants, using traditional technology that is not designed for carbon capture and storage.”

None of these roadblocks mean that C.C.S. is a dead end. The hundreds of millions of dollars already committed – to research and development and pilot programs – indicates that the technology is bound to move forward, one way or another. That said, the power industry and the federal government face a quandary. Should they try to build expensive projects now, and incur the risks of unreliable technology, lack of transport and storage infrastructure, and high construction costs; or should they wait to create new I.G.C.C. plants and C.C.S. systems until the technology is more proven, while watching new conventional coal plants come online, with all the CO2 emissions they bring?

It’s not an insoluble dilemma. But solving it will take a lot more realism than can currently be found in today’s C.C.S. discussions. And those answers may be decades in coming.