Environmental groups and some of Kentucky Power’s industrial customers, contend that the American Electric Power (NYSE:AEP) subsidiary should shut the 800-MW Unit 2 at the Big Sandy power plant instead of retrofitting it with an SO2 scrubber.
Kentucky Power (KPC) has already decided to eventually shut the older, smaller Big Sandy Unit 2. But it is now before the Kentucky Public Service Commission, with an application filed in December 2011, trying to win approval for the costs of retrofitting Unit 2 with a dry scrubber (also known as flue gas desulfurization or FGD).
The Sierra Club, represented by Earthjustice, said in a March 14 public statement that on March 12 it submitted expert testimony challenging Kentucky Power’s plan to charge its ratepayers $940m to retrofit Unit 2. The testimony from experts at Synapse Energy Economics was submitted to the Kentucky PSC. Expert testimony demonstrates that replacing the Big Sandy coal plant with energy efficiency, renewable energy, and cleaner natural gas generation would be a much better deal for ratepayers, the environmental groups contend.
“The experts found KPC made numerous errors in calculating that it would be most cost effective to pour close to one billion dollars into the aging Big Sandy plant,” said the environmental groups. “KPC initially claimed to agree that ratepayers would be best served if it closed the old, highly-polluting coal plant but later changed that decision. Customer rates will rise by more than 30 percent if the Kentucky Public Service Commission approves the plan to retrofit the Big Sandy coal plant.”
The Kentucky Industrial Utility Customers, representing major eastern Kentucky employers – including AK Steel, Air Products & Chemicals and Marathon Petroleum – also filed expert testimony on March 6 urging the commission to reject KPC proposal.
Lane Kollen, an expert hired by the Kentucky Industrial Utility Customers group, said in March 6 testimony that KPC’s own studies show that retiring Big Sandy Unit 2 by the end of 2015 and purchasing replacement energy and capacity off the PJM system for 10 years would save customers between $474m and $785m compared to the utility’s proposal.
“There might not be many issues on which the Sierra Club agrees with the oil and chemical industry in eastern Kentucky,” said Lauren McGrath, a representative of the Sierra Club. “But we agree on this—the best and cheapest way forward for Kentucky ratepayers is to retire the old Big Sandy plant.”
A hearing in the proceeding is scheduled for April 16 at the commission’s offices in Frankfort. The commission also announced March 15 that it will hold public meetings in April in Louisa, Pikeville, Whitesburg and Hazard to receive public comments on KPC’s overall environmental compliance plan and associated environmental surcharge request. “Kentucky Power is seeking PSC authorization to spend about $940 million to comply with new federal environmental requirements affecting utilities that burn coal to generate electricity,” the commission noted. “The company estimates that the total monthly electric bills for a typical residential customer would increase by about $31, or 30 percent, beginning in 2016.”
Kentucky Power needs quick commission decision
Besides current and pending U.S. Environmental Protection Agency air rules, KPC told the commission in a Dec. 5, 2011, application that in a consent decree it worked out with EPA in 2007 covering coal plants in five eastern states, it agreed in part to install FGD equipment on Big Sandy Unit 2 by the end of 2015. Kentucky Power is seeking a certificate of public convenience and necessity for the Big Sandy Unit 2 scrubber along with related projects, like a scrubber waste landfill.
Big Sandy Unit 1 at the same site is a 278-MW coal-fired unit completed in 1963. Big Sandy Unit 2 is an 800-MW coal-fired unit completed in 1969. Kentucky Power said in the Dec. 5 filing that it currently anticipates retiring Big Sandy Unit 1 by Jan. 1, 2015, and will make all needed filings related to this retirement by separate application. A big negative for Unit 1 is that lacks both selective catalytic reduction and an FGD system and would need both for future air compliance. Unit 2 already has an SCR. Unit 1 is also a subcritical pulverized coal facility, while Unit 2 is a more efficient supercritical unit.
Kentucky Power proposes to commence site construction activities at Big Sandy on or about July 1, 2013. Kentucky Power requested that the commission issue its certificate of public convenience and necessity by June 5, 2012.
Kentucky Power said that EPA’s Cross-State Air Pollution Rule (CSAPR) sets aggressive compliance timelines and restrictive emissions caps that will be difficult to comply with. Big Sandy units, the 800-MW Unit 2, would be severely curtailed, retired or retrofitted to achieve massive SO2 reductions through the installation of efficient FGD technology in order to approach the Phase 1 and ultimately, the Phase 2, CSAPR thresholds. CSAPR also provides the company with the option to acquire SO2 or NOx allowances to offset Phase 1 and Phase 2 emission levels that exceed annual EPA-budgeted allowance allocations. The extraordinarily brief compliance window will require Kentucky Power to operate Big Sandy Unit 2 in an uncontrolled fashion, but under a potentially constrained dispatch, said the company. This is due to the fact that the timeframe to permit arid install an FGD system is beyond the CSAPR compliance deadlines.
Kentucky Power prefers dry FGD option
Company witness Robert Walton described the difference between the commonly-used wet FGD process and the dry FGD system planned for Big Sandy Unit 2. Walton is Managing Director of Projects and Controls at American Electric Power Service.
“In a WFGD system, alkaline reagent slurry (usually lime or limestone) is injected into a vessel, where it reacts with the flue gas to collect the SO2,” said Walton. “A WFGD absorber utilizes a high volume of liquid slurry continuously circulating in the absorber vessel and collecting in the absorber reaction tank where the scrubbing reaction occurs. A DFGD is comprised of the absorber vessel or duct integrated with a pulse jet fabric filter (PJFF), often referred to as a baghouse. The DFGD does not utilize a liquid filled reaction tank, but instead relies on the scrubbing reactions to take place as the flue gas intermingles with the lime inside the vessel or ductwork and also in the highly reactive dust cake on the surface of the downstream fabric filter media.”
The NID DFGD system was compared to a Spray Dryer Absorber (SDA) technology, Circulating Dry Fluidized Bed Scrubber (CDS) technology and the Limestone Forced Oxidized (LSFO) Spray Tower WFGD technology. Considering equivalent SO2 removal efficiencies among those options, the proprietary NID DFGD system is the favored FGD technology, said Walton. Reasons for that include: lowest total evaluated cost on a 30-year cumulative present worth basis (capital and O&M); lowest water consumption; lowest auxiliary power usage; lowest reagent usage; and smallest equipment footprint.
The NID installation at Big Sandy Unit 2 will be designed to reduce SO2 emissions by 98%. The cost estimate for the DFGD installation, excluding Allowance for Funds Used During Construction (AFUDC), is currently $839m, which also covers ancillary costs like the scrubber waste landfill, KPC said in the Dec. 5 filing.