Utilities split on readiness of IGCC

Resource planners at electric utilities have never had it so good—or bad. On the one hand, planners have never had more technology options for building needed generating capacity at their disposal. On the other are the huge cost and reliability uncertainties inherent in the deployment of any new and unproven power production technology—represented all too well by integrated gasification combined-cycle (IGCC) plants.

This article represents a bit of a departure from POWER’s normal modus operandi. It attempts to cut through the considerable hype that has accompanied IGCC technology for the past few years by not assuming (as many articles do) that utilities leap at any chance, whatever the risks, to be among the first to employ a sexy new technology.

Rather than survey the field of candidate IGCC technologies (which would be appropriate if IGCC had no apparent downsides), this article begins where utility resource planners begin: by comparing the highest-level technical and economic characteristics of IGCC with those of its closest-competing generation technology—conventional pulverized coal (PC) combustion. IGCC is still in its infancy, and there will be plenty of opportunities for POWER to cover its evolution as thoroughly as the magazine has reported on other paradigm shifts in generating technology over the past 125 years.

Of cost and carbon

Perhaps the biggest question involving IGCC plants is whether their presumed ability to be equipped inexpensively in the future to capture CO2 justifies IGCC’s capital cost premium over mainstream PC combustion. Conventional wisdom puts that premium at 15% to 20%. Table 1 compares IGCC’s estimated costs with those of other generating technologies.

Table 1. Comparing the costs of IGCC and other generating technologies. Source: Pace Global Energy Services

At the Platts Second Annual IGCC Symposium in Pittsburgh this May, the hopes and hurdles for adoption of the technology were on full display, and cost figured prominently in the presentations of utilities on both sides of the divide.

Kay Pashos, president of Duke Energy Indiana, ticked off five factors that have driven her company to seriously consider building a 600-MW IGCC plant in southern Indiana in the near future. Two—the abundance of Midwest coal reserves and the rising price of natural gas—are so clear that they require no further discussion here. Pashos" third factor—IGCC’s superior and more-cost effective environmental performance on high-sulfur local coals, relative to PC combustion—is inextricably intertwined with the fourth and fifth factors: shrinking pollutant emissions limits and the availability of incentives to close IGCC’s capital cost gap.

The trend of pollutant emissions limits that seem to be marching toward zero began with the 1990 Clean Air Act Amendments, continued with the NOx SIP (state implementation plan) Call program, and remains ongoing in the form of the Clean Air Interstate and Mercury Rules (CAIR and CAMR). Under CAIR and CAMR, compliance deadlines for utility emissions of NOx, SO2, and mercury are already in place as far out as 2018.

It is also possible that CO2 will be classified as a pollutant, making it subject to regulation by the U.S. EPA. Two states already cap CO2 emissions from power plants, and others are sure to follow now that global warming has become a cultural touchstone.

Regarding the availability of incentives to help utilities close IGCC’s aforementioned capital cost gap, Pashos noted that Indiana law provides for timely recovery of an IGCC plant’s construction and operating costs, as well as substantial investment tax credits—10% of the first $500 million of a project’s cost, plus 5% of the remainder.

In addition to those sops, the 2005 Energy Policy Act (EPAct) provides a 20% investment tax credit for "eligible properties" for gasification. That wording, however, may effectively reduce the actual credit for an IGCC plant to 12%. Because the combined-cycle power plant portion of an IGCC facility accounts for as much as 40% of its overall cost, if the tax credit is applied only to the cost of the gasifier, a utility may only be able to obtain a credit amounting to 20% of 60% of the facility’s cost, or 12%. In other words, the gasification may be covered, but the integration may not be. What’s more, there’s a cap on the total federal tax credit available each year, and at press time the DOE has already received applications for credits totaling four times that level (see Speaking of Power).

Adventures in availability

That Duke Energy Indiana is considering building an IGCC plant (according to Pashos, a go/no-go decision will be made by the middle of 2007) underscores the utility-specific nature of the technology’s pros and cons. As PSI Energy, Duke Energy Indiana’s parent—Cinergy Corp.—partnered with Destec to build Wabash River, one of the seven demonstration IGCC plants that account for the technology’s entire operating history worldwide (Table 2).

Table 2. Commercial-scale coal/petcoke-based IGCC demonstration plants. Source: Ola Maurstad, Massachusetts Institute of Technology’s Laboratory for Energy and the Environment

The Wabash River plant went commercial in late 1995. Within a few months, both the gasification and combined-cycle plants were running at full capacity and in environmental compliance on high-sulfur Illinois Basin bituminous coal. However, by the end of the first year of operation, annual availability measured just 35%. More than half of total outage time was attributed to failures of the ceramic candle filters in the gasification plant’s dry char particulate removal system.

After changing to metallic filters and making other improvements, Wabash River saw its production and availability numbers rise during its second and third years. During the third year, the plant successfully demonstrated the ability to use a second coal feedstock as well as a blend of two different Illinois No. 6 coals, improving the site’s fuel flexibility. Later, up to 2,000 tons/day of petroleum coke were gasified and converted to more than 250 MW of power without exceeding permitted emissions levels.

In 1998 the Wabash River plant passed the milestones of 10,000 hours of operation on coal and 1,000,000 tons of coal processed. Net availability during that year was calculated at 77% by excluding the downtime of the power plant and subtracting time spent testing alternative fuels. Since 2000, the plant has operated with minimal problems and significantly improved on-stream performance while meeting all of its environmental targets. Today, Cinergy continues to dispatch Wabash River at a heat rate of 8,900 Btu/kWh (HHV), although the plant is now owned and operated by Global Energy Inc.

Wabash River’s increasing availability over the years as it got its sea legs may seem impressive. However, the plant is only in the middle of the "gang of six" IGCC demo plants in terms of availability (see figure below). The inability of any plant to reach and maintain 80% availability doesn"t sit well with Marty Smith, manager of environmental policy for Xcel Energy. Speaking at the Platts IGCC Symposium, Smith said that an IGCC plant would have to be capable of 90% availability to warrant his serious consideration.

Good enough for baseload? The availability histories of the six successful IGCC demonstration plants show that most were able to reach the 70% to 80% range (excluding operation on back-up fuel), but only after at least five years of operation. Equipped with a spare gasifier, an IGCC plant may be able to match the availability of a combined-cycle plant burning natural gas. Source: EPRI

In fact, the availabilities demonstrated by the four currently operating IGCC plants (Nuon Power Buggenum and Puertollano in Europe, and Wabash River and Polk Power Station in the U.S.) mean little to Smith because "[they] don"t represent the technology that would be built today." He also lamented:

  • The lack of standardization among the four IGCC technology candidates currently on the market (Table 3).
  • The "vexing" nature of the technology’s costs.
  • The performance penalty incurred when low-rank fuels such as lignite and Powder River Basin (PRB) coal are gasified. Western coals are higher in ash and moisture content and have other characteristics that make them much harder for a gasifier to handle.
  • The industry’s minimal experience with CO2 capture and running a gas turbine on a hydrogen-rich fuel. As a practical matter, future IGCC plants will capture so much carbon dioxide so quickly that storing it on-site will be impossible. The gas will have to be piped away in real time for sale or sequestration. Although carbon sequestration is being demonstrated successfully at a number of sites worldwide, the underground geologic formations suitable for the process aren"t necessarily available where IGCC plants will likely be built—close to coal mines.

Table 3. Syngas production technology suppliers. Source: Worley Parsons

Financing IGCC

At the Platts Second Annual Coal-fired Generation Conference about a year ago in Chicago, there was no shortage of financiers skeptical about the prospects for funding IGCC projects.

"As a firm, we are generally bullish [on IGCC]. Personally, I’m less optimistic," said John Cogan, senior VP for global energy investment banking at Credit Suisse First Boston LLC. A company such as American Electric Power or Cinergy will have to build an IGCC plant and put it into commercial service to determine how much it really costs to build, he said.

"IGCC makes a lot of sense, but at the end of the day it comes down to costs," said Joseph Esteves, managing director of LS Power Development LLC. LS Power is developing a 1,600-MW pulverized coal-fired project in Arkansas. "If we have trouble selling the output of a PC plant," it would be even harder to sell the output from an IGCC plant, said Esteves. Because an IGCC plant is more expensive to build than a PC plant, the cost of electricity to the customer is likely to be higher.

LS Power has lined up significant commitments for its Plum Point plant in Arkansas, but it has been tough going, said Esteves. He added that LS Power is taking a "novel" approach to financing its project. "We"re not going to wait to get the final piece of the Arkansas project’s capacity sold before closing on the financing."

Esteves said bankers he has polled typically want to see a five-year track record for a particular technology before they commit to financing, and that does not yet exist for IGCC. What banks want to see, he explained, is a smoothly functioning plant that was built under a tight construction schedule. "Project finance is not designed for new technology," he said. "[And] I don"t see any independents [successfully] building an IGCC [plant]," said Esteves, "It will have to be put into ratebase by a utility" or built with some form of government subsidy, he said.

Nonetheless, several independents have proposed IGCC plants. In fact, some of them came to IGCC because of the difficulties they had securing permits for PC plants. They are now seeking permits for IGCC plants and trying to line up financing. It is a difficult process.

Although the cleaner emissions profile of an IGCC plant relative to PC plants has attracted developers to the technology, it is not always such an easy sell. As Table 4 shows, IGCC technology is a clear winner over subcritical PC technology only in terms of emissions of SO2, particulate matter (PM), and carbon monoxide. Both are fairly close in production of NOx and removal of volatile organic compounds (VOCs).

Table 4. Which is cleaner: IGCC or PC? Source: U.S. EPA

IGCC plants, however, enjoy a big advantage when it comes to mercury and carbon dioxide control. IGCC plants should be able to remove 90% of mercury at 1/10th the cost of processes used by conventional plants. They also should be easier and less expensive to retrofit for CO2 capture (see "Technology options for capturing CO2") because at an IGCC plant carbon dioxide constitutes 90% of flue gas, vs. 10% at a conventional PC plant. It will be collected by water-gas shift reactors added to the syngas treatment system as well as by physical absorption processes.