AEP subsidiary nears permit change for Rockport DSI project

The Indiana Department of Environmental Management is taking public comment until Aug. 17 on a draft air permit change that would allow Indiana Michigan Power (I&M) to install dry sorbent injection for SO2 control on the two coal units at the Rockport power plant.

Several months ago, this American Electric Power (NYSE: AEP) subsidiary worked out a revised consent decree with the U.S. Environmental Protection Agency that was approved by a federal court on May 14 (the court approval is attached to the draft permit). That revision changed a requirement for one expensive flue gas desulfurization installation on one of these coal units, for a less costly DSI installation project on both units, with both DSI systems to be operational by April 2015.

Said a technical support document in the draft air permit: “The Office of Air Quality (OAQ) has reviewed a modification application, submitted by Indiana Michigan Power d.b.a. American Electric Power (AEP) Rockport Plant on February 27, 2013, relating to the construction of a new Dry Sorbent Injection (DSI) systems for Units 1 and 2, the replacement of the Unit 1 Ash silo Bin Vent Filters, separator strings, and Unit 2 Separator Strings on three of the four silos, along with modifications to the design and operation of the existing landfill to dispose of the additional combustion waste generated by the DSI systems and changes to the ACI Systems and the changes in the classification of the material being disposed. As part of the modification of the NSR Consent Decree, signed by the United States District Court for the Southern District of Ohio on May 14, 2013, Indiana Michigan Power Company has accepted federally enforceable limitations on annual SO2 emissions from the Rockport Plant Main Boilers, identified as MB1 and MB2. As a result of this agreement, Indiana Michigan Power Company requested that SO2 limitations be placed in the Rockport Plant Title V Permit.”

The draft air permit said that these coal units are:

  • One pulverized coal opposed wall fired dry bottom boiler, identified as MB1 (Main Boiler 1), with construction commenced in 1977 and completed in 1984, with a design heat input capacity of 12,374 million Btu per hour, with an electrostatic precipitator (ESP) system for control of particulate matter. Low NOX burners and an overfire air (OFA) system have been installed for NOX control. One powdered activated carbon (PAC) injection system, identified as activated carbon injection (ACI), permitted in 2008, 2010 and 2013, with a unit maximum capacity of injecting 4,000 pounds of halogenated or non-halogenated activated carbon per hour into the exhaust ductwork for Boiler 1 (MB1) from a dedicated silo)s). One dry sorbent injection (DSI) system, identified as DSI-U1, permitted in 2013, with a design injection capacity of 20,000 pounds of Sodium Bicarbonate per hour into the exhaust ductwork for Boilers 1 (MB1). Emissions from Units MB1 and MB2 are exhausted through the common stack, Stack CS012.
  • One pulverized coal opposed wall fired dry bottom boiler, identified as MB2 (Main Boiler 2), with construction commenced in 1977 and completed in 1989, with a design heat input capacity of 12,374 million Btu per hour, with an ESP system for control of particulate matter. Low NOX burners and an OFA system have been installed for NOX control. One PAC injection system, identified as ACI, permitted in 2008, 2010 and 2013, with a unit maximum capacity of injecting 4,000 pounds of halogenated or non-halogenated activated carbon per hour into the exhaust ductwork for Boiler 2 (MB2) from a dedicated silo(s). One DSI system, identified as DSI-U2, permitted in 2013, with a combined maximum capacity of injecting 20,000 pounds of Sodium Bicarbonate per hour into the exhaust ductwork for Boilers 1 (MB2).

This altered consent decree requires installation at Rockport of DSI on both units by April 16, 2015, and defers the installation of high efficiency FGD until Dec. 31, 2025, and Dec. 31, 2028. In addition, the coal-fired, 500-MW Tanners Creek Unit 4 will either retire or refuel to burn natural gas by June 1, 2015. The coal-fired Tanners Creek 1-3, at 495 MW total, are due for outright retirement.

In April 15 testimony filed at the Indiana Utility Regulatory Commission, Paul Chodak III, President and COO of Indiana Michigan Power, wrote about the DSI project: “The Rockport [Clean Coal Technology] project will not include a change in the fuel source used at the Rockport Plant because the required emission reductions can only be obtained through the continued use of Powder River Basin (PRB) coal from Wyoming. While I&M intended to switch to high sulfur coal from the Illinois Basin if the Rockport Environmental Project was constructed and operated, that is not a cost-effective option for the Rockport CCT Project. As a result, I&M will continue to transport coal from the Powder River Basin to the Cook Coal Terminal in Metropolis, Illinois for loading onto barges and delivery up the Ohio River to the Rockport Plant. In fact, due to the retirement or refueling of I&M’s Tanners Creek Plant, the Cook Coal Terminal will be used almost exclusively for I&M and [AEP Generating] AEG’s operations at the Rockport Plant.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.