Pricing tomorrow's coal-fired power plant
New research explores the gap between what the public wants and what power companies seek in a new power plant.
The price tag for a new coal-fired power plant runs into the billions of dollars. With energy demand rising at 1% per year in the U.S. and carbon-control legislation being discussed enthusiastically in Congress, some utility executives are in gridlock over which technology to choose for future power needs. New research published today on ES&T’s Research ASAP website (DOI: 10.1021/es062198e) shows utility executives and policy makers that coal, and lots of it, can continue to be burned without consumer costs rising much higher than they are today, provided that several policy actions are taken soon.
Coauthors Joule Bergerson, a postdoctoral fellow at the University of Calgary (Canada), and Lester Lave, codirector of Carnegie Mellon University’s (CMU’s) Electricity Industry Center, provide an engineering–economic analysis for utility executives and public officials. The paper aims to help decision makers choose a coal technology, given their beliefs about future environmental regulations. Should the plant use traditional, pulverized coal (PC) technology or the slightly more efficient integrated coal gasification combined-cycle (IGCC) process? Should it be equipped for carbon capture and storage (CCS) capability before or after the plant is built?
The researchers used the Integrated Environmental Control Model, a well-known, publicly available tool developed at CMU and designed to compare the performance, emissions, and cost of various electricity generation technologies. Using 2002 dollars adjusted for inflation, they inserted recent costs of actual medium-sized power plants and engineering cost estimates of new plants with similar power outputs of 450–480 megawatts. The plants all burned the same high-Btu-value coals (Illinois #6 and Pittsburg #8).
Bergerson and Lave modeled various scenarios with assumptions based on new stringent emissions standards for SO2, nitrogen oxides, particulate matter, and mercury, as well as a national carbon tax, to see how those would affect the price and utility choice.
The results are surprising. “People think IGCC would make more sense to build for future generation, but our numbers didn’t show that,” Bergerson says. “We couldn’t find a case for a utility to build an IGCC plant unless Congress imposed a very high carbon tax and the tax was implemented very soon,” she adds.
The analysis reveals that a tax could tip the scale: if a company is committed to building a PC system, “the carbon price would have to be $46 per ton of CO2 or more to justify adding CCS,” the authors write. A lower tax or one that was delayed would have no effect, they add, because a cost analysis would steer the generator to build the cheap PC plant and pay the tax. Still, they caution that these estimates are subject to a myriad of uncertainties, including coal quality, advances in IGCC and CCS technologies, and the type of carbon legislation that might be enacted.
The paper makes a unique contribution by examining the difference between what the public prefers and what company executives want from a new power plant and placing a dollar amount on these differences. “This appears to be the first time I’ve seen a real cost assigned to public and private motivations,” says Rita Bajura, former director of the U.S. Department of Energy’s National Energy Technology Laboratory. “They look at private and public motivations, and they do so without bias. They come at it with a purely academic viewpoint,” which, she says, is hard to find. “Almost any interested player has a vested interest in this,” Bajura says. Karen Palmer of the nonprofit research group Resources for the Future agrees that an objective discussion of public versus private interests has been overlooked and suggests that this area of research be expanded.
Lave says the paper shows that the cost of generating electricity with CCS will rise sharply but that the cost of delivered power to consumers won’t be much more than what some customers will be paying in the next few years. BGE, the utility that serves customers in central Maryland, recently received approval for a 72% price increase, Lave says, partly because energy prices were frozen when the state deregulated the electricity industry. As deregulation policies are removed from other states, prices will rise there as well. “In the future, the additional cost of carbon capture and storage will be noticeable but won’t be extraordinary,” Lave says.
