Local environmentalists have scrutinized the Indian River Power Plant for years, but it’s complicated. Everyone agrees the plant’s dirty — it’s a perennial favorite atop the state’s Toxic Release Index.
But it’s also operating in full compliance with the law, 99 percent of the time.
The Department of Natural Resources and Environmental Control (DNREC) recently levied a $30,000 fine against the plant for burning 75 rail carloads of sulfur-rich coal back in January 2003.
However, DNREC’s Thomas Lilly (Air Quality Management) said Indian River Power had reported the violation voluntarily. DNREC has the ability to perform random coal sampling, he said, but hadn’t done so recently.
Lilly was unaware of any violations since 2003. And even that case was somewhat out of the norm, he explained.
Ordinarily, the power plant would have shipped the coal back to the supplier, he noted. But these weren’t ordinary times for Indian River Power’s parent company, NRG Energy.
Creditors had pulled NRG into bankruptcy proceedings in late 2002, and that legal wrangling was in full-swing by January 2003. (The company would eventually enter Chapter 11 bankruptcy protection in May, and reemerge in December.)
While the company continued to work through its financial troubles, the banks had set a budget for the company, Lilly said — and part of that budget had restricted the amount of coal NRG could stockpile at the Indian River Power Plant.
But 2003 ushered in an especially cold winter for the northeast, with record or near-record snowfalls from Virginia to Boston, on the heels of the northeast’s warmest winter on record, 2001-2002 (according to the National Oceanic and Atmospheric Administration Web site).
Lilly said Indian River Power operators were facing a depleted stockpile when they decided to burn the 75 rail carloads of sulfur-rich coal.
Standards demand coal containing no more than 1.6 percent sulfur. The coal supplier’s tests, prior to delivery to Indian River Power, indicated less than 1.5 percent.
But subsequent testing at the plant (as required by the permits, Lilly pointed out) discovered sulfur content at around 1.9 percent instead — 20 percent higher than originally indicated.
Lilly chalked it up to different testing methods, suggesting Indian River’s sampling from a belt conveyor offered better results than samples taken at the mine itself. “You get a more accurate sample at the plant,” he said.
In other coal-related issues, Lilly said Indian River was continuing to test low-sulfur coal out of Wyoming — “Powder River Basin” coal. But while Wyoming coal is cleaner, it also produces less heat when burned.
“From (Indian River’s) point of view, they need to be able to burn this coal and still maintain capacity,” Lilly said. “The (British Thermal Unit) BTU production is less than a bituminous coal they’re burning. They’re doing some test burns to find out if it’s feasible.”
In the meantime, DNREC’s Ron Amirikian (Air Quality Management) said the department was looking at ways to address the other chemicals escaping Indian River Power Plant smokestack, through new regulations.
Amirikian said part of the problem with the regulatory system in place now is that the rules govern things at the front end (case in point, restricting sulfur content in the coal), but not the actual emissions.
The particularly offensive compounds are sulfur dioxide (SO2) and various forms of nitrogen oxide (NOx) — both are linked to respiratory problems and acid rain.
Four out of four Indian River Power Plant boilers miss the mark for downwind concentrations of these compounds. A fifth unit, installed in the 1960s (fuel oil turbine) does well on SO2, but still misses the mark on NOx.
According to Amirikian, DNREC is targeting one specific toxin, in addition to the two chemical compounds — mercury. “The mercury is coming directly from the coal,” he pointed out. While some of it is trapped in the ash, he said the majority is vaporized in the boilers and makes it into the atmosphere.
Amirikian said the department was looking at ways power plants around the state can “feasibly retrofit” their operations. This could mean upgrading non-catalytic NOx reduction systems to catalytic systems, or installing “smokestack scrubbers,” which would get rid of the SO2, Amirikian said.
Smokestack scrubber systems would have the added benefit of reducing hydrochloric gas. “That’s not directly regulated, but it would be a secondary benefit,” he pointed out.
According to Amirikian, the department is working to have the draft regulations ready for public workshop by mid-year. “We’re hoping to have regulations in place sometime in September,” he said.