AEP says Powder River Basin coal a key to new Rockport air plan

The Indiana Michigan Power subsidiary of American Electric Power (NYSE: AEP) is seeking ratemaking treatment from the Indiana Utility Regulatory Commission on its plan to install dry sorbent injection on both units of the 2,600-MW Rockport coal plant.

AEP had recently announced that instead of installing more expensive flue gas desulfurization technology on one of the 1,300-MW Rockport units, as it is required to do under a federal consent decree from several years ago, it would install cheaper DSI on both units.

“I&M proposes to install and use dry-sorbent injection technology (DSI) and related facilities and equipment improvements on Rockport Units 1 & 2 that will directly reduce regulated air emissions,” said an April 11 company filing at the commission. “The Rockport [Clean Coal Technology] CCT Project consists of advanced technologies designed to reduce acid gases such as hydrochloric acid (HCl) and sulfur dioxide (SO2) emissions associated with the combustion of coal at the Rockport plant and otherwise comply with the [Mercury and Air Toxics Standards] MATS Rule.”

In addition to the MATS rule, I&M is subject to the mandates of a consent decree executed with the Department of Justice (DOJ), the U.S. Environmental Protection Agency and other parties to resolve allegations related to the New Source Review provisions of the Clean Air Act. On Feb. 22, AEP, along with the DOJ, EPA and other parties, filed a proposed modified consent decree in the U.S. District Court for the Southern District of Ohio. This altered decree requires installation at Rockport of DSI on both units by April 16, 2015, and defers the installation of high efficiency scrubbers 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.

Powder River Basin coal needed as part of new compliance plan

In April 15 supporting testimony, Paul Chodak III, President and Chief Operating Officer of Indiana Michigan Power, told the commission: “The Rockport CCT 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.”

The cost of the Rockport CCT Project in total is estimated to be $284.7m, of which I&M’s ownership share is $142.4m. This total includes a cost estimate of $240.7m for the Rockport CCT Project and the $44m incurred in pursuing the now shelved installation of a dry scrubber on one unit at Rockport. The estimated total cost for the dry scrubber and related projects was $1.4bn.

“The Third Modification to the Consent Decree under review in this Cause permits I&M to satisfy its near-term emission reduction obligations by installing and operating DSI technology on both Rockport Units by April 16, 2015,” Chodak noted. “In addition, I&M will secure an additional 200 MWs of wind energy, provide additional mitigation funding to the states, and create a fund to support other energy efficiency and small scale renewable projects. I&M will also refuel or retire 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 emission reductions will be required at Rockport with the installation of Selective Catalytic Reduction (SCR) control equipment by the end of 2017 on one unit and by the end of 2019 on the other.”

DSI testing has shown strong SO2 capture co-benefits

Robert Walton, employed by the American Electric Power Service Corp. as Managing Director of Projects, said about DSI testing at Rockport: “The DSI testing performed to date at the Rockport Plant has yielded positive results. The testing utilized a temporary SBC injection system to treat approximately two-thirds of the flue gas stream and demonstrated the ability to achieve in excess of 90% HCl capture with a co-benefit of up to 46% SO2 removal. It should be noted that 46% removal was achieved even while test equipment sizing limited the amount of sorbent that could be injected during the test. These results indicate that a full-scale DSI installation will be capable of reducing emissions sufficiently to meet the MATS Rule compliance limits while obtaining a co-benefit of up to an approximate 50% SO2 removal efficiency at the Rockport Plant using the existing ESP for particulate control.”

Walton added: “FLSmidth has been selected as the supplier of the technology for the Rockport Unit 1 and 2 projects. FLSmidth is a long term strategic supplier of DSI systems to AEP dating back to the Gavin Trona Injection Project for SO3 mitigation which went into operation in 2004. They have invested significant research and development in establishing and advancing technology for SO3 mitigation and  bulk material handling using pressure-blown injection methods. FLSmidth provided all of the DSI equipment for AEP’s environmental compliance projects, previously identified. FLSmidth and AEP’s generation, technical and operations personnel have worked together to enhance and improve operational reliability of these systems at our fossil fuel plants. In addition, FLSmidth has continued to develop their proprietary and unique technology through laboratory testing and other research and development efforts. FLSmidth has been responsive and has satisfactorily resolved performance or warranty items when they arose.”

The purpose of this project is to install a DSI system and improvements to the existing electrostatic precipitator (ESP), activated carbon injection (ACI) system, fly ash removal (FAR) system and fly ash silos to achieve up to 50% SO2 removal and reduced emissions of mercury, acid gases, total particulate matter and other hazardous air pollutants from Rockport Units 1-2.

Rockport has a net generating capacity of 2,600 MW, which is produced by twin 1,300-MW units. The units were placed in service in 1984 (Unit 1) and 1989 (Unit 2). Both units are B&W universal pressure once through super critical steam generators. The units are pressurized furnace design equipped with Babcock & Wilcox low NOx burners and over fire air (OFA) equipment.

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.