October 15, 2006

Utilities split on readiness of IGCC

John Javetski

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 NO_x 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 NO_x, 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).