Tanners Creek shutdown in 2015 no big issue for Indiana Michigan

Despite the planned retirement of the 995-MW Tanners Creek coal plant in 2015, Indiana Michigan Power has adequate supply and demand resources to meet its load obligations for the next two decades.

That is according to an integrated resource plan (IRP) that this American Electric Power (NYSE: AEP) subsidiary filed under seal on Nov. 1 at the Indiana Utility Regulatory Commission, with a public version also made available.

Due to projected flat and even declining load growth, I&M said in the plan that it needs to:

  • Ensure that its two 1,300-MW Rockport coal units have the necessary environmental controls to comply with U.S. Environmental Protection Agency (EPA) regulations;
  • Maintain operation of the Cook Nuclear plant by completing the Life Cycle Management (LCM) program; and
  • Make continued investment in demand-side management.

I&M said it expects that utility-scale solar resources will become economically justifiable by 2020 and that customer-owned solar generation will begin to be economical to customers prior to that, further reducing the requirements for new utility-owned generation. This IRP recognizes the “imminent economic viability” of both distributed and utility-scale solar.

I&M’s total internal energy requirements are forecasted to increase at an average annual rate of 0.2% over the IRP planning period (2014-2033). For the Indiana portion of the company’s service area, the annual growth rate is also expected to be 0.2%. I&M’s corresponding summer and winter peak internal demands are forecasted to grow at average annual rates of 0.3% and 0.1%, respectively, with annual peak demand expected to continue to occur in the summer season through 2033.

Taking into account stakeholder input, I&M developed a Preferred Portfolio. The Preferred Portfolio is intended to provide the lowest reasonable cost of power to I&M’s customers while meeting environmental and reliability constraints and reflecting emerging preference for, and the viability of customer self-generation. This portfolio:

  • Retires the coal-fired Tanners Creek plant in 2015.
  • Adds environmental controls to Rockport in 2015 to comply with EPA regulations for the Mercury and Air Toxics Standards (MATS).
  • Adds additional environmental controls (selective catalytic reduction) to Rockport Units 1 and 2 in 2017 and 2019, respectively, to reduce NOX emissions.
  • In 2025 and 2028, adds dry flue gas desulfurization controls (DFGD) to Rockport Units 1 and 2, respectively, to further reduce SO2 emissions.
  • Continues operation of the Cook Nuclear Plant until the mid-2030s.
  • Implements Energy Efficiency programs so as to reduce energy requirements by 2,586 GWh (or 9.5% of projected energy needs) by 2033.
  • Maintains Indiana demand response programs to reduce peak capacity requirements by 296 MW.
  • Adds 200 MW of wind energy from the Headwaters Wind Farm by the end of 2014 and 100 MW of generic wind in 2026.
  • Beginning in 2020, I&M will add 50 MW (nameplate) of solar capacity per year.
  • Recognizes additional solar capacity will be added by customers, starting in 2016 of about 10 MW (nameplate) and ramping up to about 150 MW (nameplate) by 2033.

Everbody’s getting out of the AEP pool, so I&M will swim alone

The company operates two coal-fired plants, Rockport and Tanners Creek, the Cook nuclear plant, and six hydroelectric stations along the St. Joseph River – two in Indiana and four in Michigan.

As of the end of this year, the long-standing power pool that AEP ran for its eastern U.S. utilities will be dissolved, meaning that I&M will now be responsible for its own generation resources and will need to maintain an adequate level of power supply resources to individually meet its own load requirements for capacity and energy, including any required reserve margin.

The IRP noted that Rockport’s need for coal is being supplied primarily through two long-term supply agreements with Peabody COALSALES LLC for Powder River Basin coal. In addition to these long-term contracts, there are several other committed contracts, both term and spot, that will contribute to fulfilling the supply requirements. Any remaining supply requirements will be fulfilled with non-committed purchases.

Contract coal for Tanners Creek 1-3 will be supplied under the Bowie Resources LLC (Colorado coal), Magnum Coal Sales LLC (Central Appalachia) and the Argus Energy LLC (Central Appalachia) long-term agreements. The primary source of Tanners Creek 4 coal deliveries is an extended Peabody COALSALES LLC contract. In addition to these long-term contracts, non-committed coal will be purchased to maintain coal supplies.

Rockport, located in Spencer County, Ind., consists of two 1,300-MW coal units. SO2 emissions at Rockport are limited to 1.2 lb SO2/MMBtu. Compliance with the emission limit is achieved by using a blend of Powder River Basin low sulfur sub-bituminous coal and low sulfur bituminous coal from Colorado or eastern sources.

Tanners Creek is located in Dearborn County, and consists of four coal-fired units with a total net maximum capacity of 995 MW. In accordance with an NSR Consent Decree with the EPA, Tanners Creek Units 1-3 (TC 1-3) are limited to fuels with a sulfur content no greater than 1.2 lb SO2/MMBtu and Unit 4 (TC-4) is limited to fuels with a sulfur content no greater than 1.2%. As a result of the different air emission standards, as well as differences in the boiler designs, coal supplies for Tanners Creek 1-3 and Tanners Creek 4 vary in order to match the differing quality requirements of the units. The fuel for Tanners Creek 1-3 will be from bituminous sources located in Colorado and from eastern bituminous sources. Tanners Creek 4, similar to Rockport, can use a blend of Powder River Basin coal from Wyoming and low sulfur bituminous coal from eastern sources.

The two Rockport units are due to get dry sorbent injection (DSI) installations in 2015 to reduce SO2 emissions, instead of more expensive flue gas desulfurization installations that had once been planned for both units later this decade. This means that the units will have to stay on PRB coal, instead of pursuing cheaper, higher-sulfur Illinois Basin and Northern Appalachia coals. The dry FGDs are not due to be installed until mid to late next decade.

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.