Indiana Michigan Power approved for Rockport air controls

The Indiana Utility Regulatory Commission on Nov. 13 approved air emissions projects for Indiana Michigan Power that include new SO2 controls for the 2,600-MW Rockport coal plant.

Installed on each of two Rockport units will be dry sorbent injection (DSI) systems and related equipment. Indiana Michigan Power, a unit of American Electric Power (NYSE: AEP) had earlier this year worked out a modified consent decree with the U.S. Environmental Protection that allowed these DSI installations on both units in the near term, to be in operation by April 2015, instead of a conventional scrubber on one unit in 2017 and the other unit in 2019. The original consent decree was worked out in 2007 and the compliance plan under it was estimated to cost about $1.4bn.

Among other things, because the DSI systems will reduce less SO2 than a conventional scrubber would, this altered consent decree means the plant will have to stay on low-sulfur Powder River Basin, instead of getting higher sulfur coal from the Illinois Basin.

This project is also necessary to reduce HCl emissions from each Rockport unit to meet the Mercury and Air Toxics Standards (MATS). The existing ACI system will be modified to comply with the MATS rule mercury emission limit while the existing electrostatic precipitators (ESPs) will be upgraded to control filterable particulate matter (PM) emissions to meet the corresponding MATS limit.

I&M under this modified decree will also change the fuel at or retire the coal-fired Tanners Creek Unit 4 by June 1, 2015. AEP has accepted more restrictive system-wide emission caps on the AEP units subject to the consent decree. Further NOX emission reductions will be required at Rockport with the installation of selective catalytic reduction (SCR) equipment by the end of 2017 on one unit and by the end of 2019 on the other.

Other parts of the approved project include: improvements to the existing activated carbon injection (ACI) system, ESPs and ash handing systems; and expansion of the Ovation distributed controls system (DCS) network and the existing Type II landfill.

The estimated capital cost for the project is $258m.

The Indiana Department of Environmental Management on Aug. 27 approved an air permit change that would allow the utility to install these new air controls. The approval covers construction of DSI 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.

Utility has decided to shut Tanners Creek 4, instead of firing it with gas

On Sept. 17, I&M announced that Tanners Creek 4 would be retired instead of refueled. That is according to Jon MacLean, Manager-Resource Planning in the Resource Planning Section of the Corporate Planning & Budgeting Department of American Electric Power Service Corp., a wholly owned subsidiary of AEP, which is also the parent company of I&M. He testified Sept. 30 at the Michigan Public Service Commission in a power supply cost recovery case.

At this time, I&M’s strategy for compliance with various air emissions rules and agreements includes: the installation of DSI, ACI and SCR at the two, 1,300-MW Rockport coal units; and retirement of the coal-fired Tanners Creek Units 1-4 (995 MW total winter capacity) by May 31, 2015.

Charles West, Manager, Fuel Procurement, in the Fuel, Emissions and Logistics Department for AEPSC, testified that Rockport, located in Spencer County, Ind., has an SO2 emissions of 1.2 lbs SO2 per MMBtu. Compliance with the emission limit is achieved by using a blend consisting primarily of low-sulfur subbituminous coal. The coal supply for Rockport currently uses a blend of Powder River Basin (PRB) coal from Wyoming and low-sulfur bituminous coal from Colorado and various eastern sources.

The Tanners Creek plant, located in Dearborn County, Ind., consists of four coal units with a total nominal capacity of 995 MW. Units 1, 2, and 3 (TC 1-3) are limited to SO2 emissions of 1.2 lbs SO2/MMBtu and Unit 4 (TC 4) has been modified to a 1.2% sulfur standard on an annual basis. As a result of the different air emission standards, as well as differences in the boiler designs, the coal supplies for TC 1-3 and TC 4 vary in order to meet the differing coal quality needs. The fuel requirements of TC 1-3 will be met from bituminous sources located in Colorado and/or from eastern bituminous sources. TC 4, similar to Rockport, can use a blend of subbituminous and bituminous coals.

The majority of I&M’s coal need during 2014 will be supplied by long-term contracts that have been in place for several years. Coal may also be purchased to fulfill any additional requirements through both long-term and spot agreements with other suppliers.

  • I&M expects to receive about 7.8 million tons of coal in 2014 at the Rockport plant at a projected weighted average delivered cost of 202.75 cents/MMBtu (exclusive of affiliated transportation costs).
  • I&M expects to take around 448,000 tons of coal in 2014 at TC 1-3 at a projected weighted average delivered cost 302.69 cents/MMBtu (exclusive of affiliate transportation costs).
  • I&M expects to receive about 1.2 million tons of coal in 2014 at TC 4 at a projected weighted average delivered cost of 197.80 cents/MMBtu (exclusive of affiliate transportation costs).

The expected impact of MATS is reflected particularly in 2015 when Tanners Creek is shut down and when Rockport will experience decreased burn while efforts are made to install environmental controls, West wrote.

  • AEPSC is projecting a take of 7.8 million tons of coal at Rockport in 2014, falling to 6.3 million tons in 2015, then rebounding to 9.1 million tons in 2016, 8.6 million tons in 2017 and 8.5 million tons in 2018.
  • At TC Units 1-3, the projected coal take is 448,000 tons in 2014, then only 43,000 tons in 2015, their final year of operation.
  • At TC 4, the projected coal take is 1.2 million tons in 2014, then only 235,000 tons in 2015, which is the final year of operation for this unit, as well.
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.