The fate of a major low-carbon technology is playing out in the states, where regulators are contemplating whether it's worth paying for -- and whether federal law will change that.
Integrated gasification combined cycle, or IGCC, is held up as one of the main ways to reduce greenhouse gas emissions from coal. It essentially extracts carbon dioxide from coal and concentrates it before the remaining gas is burned to generate power. The CO2 can then be dispatched for storage underground.
The process can capture 90 percent of the CO2, and the "combined cycle" aspect raises the efficiency of burning coal.
Yet like many low-carbon technologies, IGCC is unproven at scale. Capital costs can top a few billion dollars, so investors are reluctant to build an IGCC plant fully on their own dime.
In several states, investors have pitched IGCC plants to public service commissions -- the state-level boards that regulate power -- to ask if the public will bear some of the cost through higher electric rates.
The investors and utilities have argued that IGCC plants offer a hedge against two trends: rising electricity costs and the likelihood of federal climate legislation. Public service commissions have had to consider whether the benefits -- emissions cuts, jobs from carbon capture and storage (CCS) -- outweigh the costs.
The results have been spotty. Some plants have been approved, albeit with fears of swelling price tags; others have been denied for high or uncertain costs.
"The fundamental problem is that the commissions, for the most part, are required to do the cheapest thing and most reliable thing they can," said John Thompson, director of the coal transition project for the Clean Air Task Force. "How does a public service commission consider the impact of future carbon regulations when those regulations aren't on the books yet?"
Whether these projects succeed or fail could hold immense importance for the climate. Some argue humanity can abandon coal and meet its energy needs through renewable energy, but others say coal has to be part of the picture because it is so cheap. The International Energy Agency says that without CCS -- the method through which it is reckoned coal can reduce its emissions -- the cost of meeting midcentury climate targets rises by 70 percent.
A race to build the 2nd one
Coal is also growing so rapidly in developing countries, many say, that if CCS technology isn't used, global climate goals become virtually unreachable.
Industry observers speak of IGCC as a technology that has only to prove its effectiveness at utility scale, yet they lament that "everyone wants to be the first to build the second one."
That's a matter of cost. IGCC's high cost means it can't spread through the power fleet until it gets cheaper. According to these companies, it won't get cheaper until the first handful of plants is built, operated and evaluated.
One company watching the policy and economics of CCS is General Electric Co., whose IGCC technology will run a power plant being built for Duke Energy in Edwardsport, Ind.
If completed, the plant would be the United States' largest IGCC unit to run on coal. At 630 megawatts, its power capacity rivals that of many conventional power plants. Two things set it apart: its ability to capture 65 percent of the CO2 from burning coal and its high cost.
Pamela Farrell, head of government affairs for GE Energy, said an IGCC plant can cost $2 billion to $3 billion, much more than a conventional coal plant. "But every time we build one, it becomes less expensive," she said. "If we could get five started, not GE but everyone," companies would learn enough that the next IGCC projects would be cheaper.
Monte Atwell, general manager for gasification at GE Energy, said it's partly an engineering challenge. He said there's lots of equipment overlap between a normal power plant and a gasification plant, so engineers are familiar with individual components like the turbine, switchgear and steam generator.
But these aren't plug-and-play technologies: Add a machine, and you add uncertainty. A gasification unit is a new technology, and it has to work seamlessly with the other machines. Since no one has done this at utility scale, that takes practice. "It's not the components per se that we need the experience on, it's building these large, complex plants," he said.
Atwell said when engineers build another one, they'll have a sense of where to cut cost, such as excess steel, concrete and pipes that were in the first project. "As that experience matures, cost will start to come down," he said. "It's no different from any other big industrial or commercial technology deployment."
Scrambling up the learning curve
GE is already moving down the learning curve, according to Farrell: She said the company already expects its next IGCC unit to cost less than the Indiana one.
Yet when GE and Duke originally proposed the project to Indiana regulators, they faced a financial catch-22.
To build the plant, they would need money. Getting financial help from the state meant arguing to the Indiana Utility Regulatory Commission that the IGCC plant was a better way to meet the public's power needs than other fuels.
If the IURC agreed, it would add a charge to electricity rates. The developers could take this guarantee to investors and get cash to start building the plant.
But the IURC also had an obligation to the public: to keep electricity rates as low as possible.
So the project's price tag would be a crucial number. Yet Duke and GE had never built a gasification project of such scale; they couldn't be positive about the construction costs. Moreover, without a price on carbon, there wasn't even a guarantee that the IGCC's priciest feature -- sidelining carbon -- was worthwhile.
Ultimately, the IURC found that the specter of federal carbon legislation was enough.
"Planning for the likelihood of more stringent emission reduction and the possibility of carbon regulation is a reasonable and prudent aspect of the Petitioner's planning process," it said.
In late 2007, the commission approved the estimated construction cost of $1.985 billion and agreed to raise electric rates to cover that cost.
Since then, costs have increased more than once. Most recently, this April Duke asked IURC to change the cost estimate to $2.88 billion, and to raise electric rates another 3 percent to cover the change. It said it was 85 percent certain that the cost won't go up again; the docket is pending.
In some cases, the uncertainties have proved too much for state regulators.
Va. finds cost estimates 'not credible'
In 2007, Appalachian Power, a division of American Electric Power, proposed a 630-megawatt IGCC plant to West Virginia and Virginia regulators.
"This is about CO2. This is about us recognizing that the forecast is for rain, and so we are going to bring an umbrella," an Appalachian official told the Virginia State Corporation Commission.
West Virginia's Public Service Commission approved the project, but Virginia regulators were unmoved. In their final ruling in April 2008, they said "the company's cost estimate [of $2.23 billion] is not credible."
What about future carbon regulations? The commission said the exact shape of these laws is unknown, so it couldn't be known whether the best path was IGCC, retrofitting an older coal plant for CCS, or forgoing CCS altogether. "We cannot ask Virginia ratepayers to bear the enormous risks -- and potential huge costs -- of these uncertainties in the context of the specific Application before us," the commission said.
For IGCC supporters, part of the challenge is that their plants are being compared to the most efficient natural gas plants, an established technology that has a low emissions profile even without carbon capture.
A 2009 analysis by Lazard Ltd., an investment bank, compared the costs of generating power with different fuels. IGCC weighed in at $110 a megawatt-hour. Natural gas combined cycle, or NGCC, a high-efficiency version, cost $69.
In the states, petitioners have argued that IGCC is still better because it offers a hedge. Natural gas costs more than coal and is less abundant; its prices also swing more dramatically. Moreover, if Congress enacts a stiff carbon price, the oldest coal plants will likely have to shut down. If nuclear, gas and renewables aren't cheaper by then, and IGCC isn't available, the average price of electricity will have to go up.
Rodney Andrews, who directs the Center for Applied Energy Research at the University of Kentucky, called the focus on natural gas shortsighted.
Competition with gas in Ky.
He referred to Cash Creek, a proposal in Kentucky to turn coal into gas and capture the CO2 from it. Then the plant would burn some of the gas for power, ship the remainder to buyers and pump the CO2 underground to excavate oil.
When the plant applied for its air permit, he said, U.S. EPA said Kentucky needed to consider a natural gas plant instead of coal.
Kentucky gets 90 percent of its power from coal; at current recovery rates, the Energy Information Administration has said, it has more than a century of reserves. Most of its natural gas comes by pipeline, from the Gulf Coast.
"From an energy security and supply point of view, I think that it's risky to push everything to natural gas," Andrews said. "Kentucky could be looking at importing natural gas to meet demand, while sitting on huge reserves of coal."
To make coal-gasification plants more competitive with natural gas, project developers have often sought co-products to sell in commodity markets. Cash Creek, for example, signed a contract with a Texas company to use its CO2 for oil extraction, and it showed this contract to Kentucky regulators as part of its business case.
An Illinois proposal, the Taylorville Energy Center, would purposely gasify more coal than it needed for its 600-megawatt power plant; the spare gas would be sold into the commodity market. If natural gas prices rose, plant operators could idle part of the power plant and sell even more gas on the market.
Between this funding stream and nearly $3 billion of federal support, developers will hope for the blessing of the Illinois General Assembly this November. (The project's total cost is $3.5 billion.)
"In the main, it's true that these sorts of projects won't go forward in the absence of a carbon price, unless there's some other package of incentives to make it worthwhile as a business proposition," said Scott Anderson, a CCS policy expert at Environmental Defense Fund.
Fancy packaging in Texas
Texas, for example, has no public service commission -- the power market decides what is and isn't worth building. Nevertheless, IGCC proposers still have to make a business case -- a case made easier by oil fields.
A proposed power station in the western part of the state, called the Texas Clean Energy Project, would generate about 200 megawatts of power after capturing 70 percent of the CO2, Anderson said.
Most of the CO2 will be used for oil recovery in the Permian Basin. But on top of that, Anderson said, the project has packaged state and federal tax credits with a $350 million DOE grant to attract investors who would otherwise balk at the $1.75 billion price tag.
White House efforts have included IGCC but not focused on it exclusively. In March, the Obama administration convened a task force to assess how to widely deploy CCS by 2020, with a midterm goal of five to 10 commercial demonstrations by 2016.
The task force's report, issued in August, says 10 DOE-supported demonstrations will be under way by 2016. Three are IGCC projects; the remainder use other CCS technologies and strategies.
The report calls the lack of a carbon price the biggest barrier to the commercialization of CCS, but it also says congressional climate bills had such low carbon prices that the government would also have to chip in incentives to shepherd CCS along.
In one case, these federal incentives kept IGCC plans afloat when they were ready to sink.
In Kemper County, Miss., a division of Southern Co. had proposed a 582-megawatt IGCC unit that could run on lignite, a low-grade coal with massive reserves in Mississippi -- 4 billion tons of it, according to the company.
Pressure from DOE in Mississippi
To bolster its proposal, Southern said it had a $270 million DOE grant and $133 million in tax credits -- funds that putatively would reduce the uptick on Mississippians' power bills. Overall, the project was slated to cost $2.4 billion.
The plant's first test was of "public convenience and necessity." Last April, the three-member Public Service Commission said it failed the test. It said that when it modeled natural gas and carbon price scenarios, a natural gas power plant would have the edge almost every time.
On top of that, construction costs had risen 9 percent since Southern's first proposal, so the price of building the plant was a critical question mark. If Southern wanted to build the plant, the PSC said, it would have to accept a construction cost cap.
In May, one of the Mississippi commissioners got a letter from Energy Secretary Steven Chu. It emphasized the importance of CCS; it testified that DOE staff had worked with Southern on the technology and that it was legitimate.
Chu also said money was at stake.
"The Department is considering commitments of substantial financial assistance to support the two technologies that the Kemper County project would demonstrate," he said. "If the project schedule is delayed, the Department might need to reallocate its CCPI funds to other recipients."
A few weeks later, Southern accepted the state's terms. The PSC gave Southern 20 percent headroom -- its construction costs could not exceed $2.88 billion -- and approved the plant.
At least some state regulators have argued for foresight: to look at long-term costs for ratepayers, not just the immediate ones.
In a 2004 speech, David Hadley, then a member of the Indiana Utility Regulatory Commission, said that by choosing to build conventional coal, most utilities were exposing themselves to tremendous risk: "Many utilities are in denial about carbon management. I believe any plant built today will need to manage carbon sooner rather than later."
"One hundred new coal plants. Only a handful are IGCC," he said. "Utilities like to do things the way they have always done them."
Want to read more stories like this?
E&E is the leading source for comprehensive, daily coverage of environmental and energy politics and policy.
Click here to start a free trial to E&E -- the best way to track policy and markets.