With the closure around the end of May of its Tanners Creek power plant, Indiana Michigan Power has only one coal-fired plant left, the 2,600-MW Rockport facility, fired primarily with Powder River Basin coal.
Indiana Michigan Power (I&M), a subsidiary of American Electric Power (NYSE: AEP), on Sept. 30 filed its latest annual Power Supply Cost Recovery plan with the Michigan Public Service Commission. That plan covers calendar 2016.
Jon R. MacLean, Manager-Resource Planning in the Corporate Planning & Budgeting Department of American Electric Power Service Corp., wrote in supporting testimony that Rockport consists of two 1,300-MW (nominal) units which are jointly owned or leased by I&M and AEP Generating Co. (AEG), another AEP subsidiary. I&M’s projected generating capacity resources reflect the following Rockport-related arrangements:
- I&M’s 50% ownership share of Rockport Unit 1 and I&M’s 50% leased share of Rockport Unit 2 (i.e., 660 MW of Unit 1 and 650 MW of Unit 2).
- AEG’s 50% share of Rockport Unit 1 and AEG’s 50% leased share of Rockport Unit 2 (i.e., 660 MW of Unit 1 and 650 MW of Unit 2).
- The Unit Power sale agreements among AEG, I&M, and Kentucky Power Co. (KPCo), another AEP System operating company, under which I&M committed to purchase 70% of AEG’s share of each Rockport unit, and KPCo committed to purchase 30% of AEG’s share of each Rockport unit.
The agreements by which KPCo purchases shares of the Rockport units run through Dec. 7, 2022. I&M’s net capacity resources for 2016 from Rockport Unit 1 include 1,122 MW (winter) and 1,118 (summer), and 1,105 MW (winter and summer) from Rockport Unit 2.
Charles F. West, Manager, Coal Procurement in the regulated Commercial Operations organization of American Electric Power Service Corp., wrote in his testimony: “I&M had two coal generating stations, Rockport and Tanners Creek. While Rockport is projected to continue its operation, Tanners Creek, as previously discussed in prior fuel proceedings, received its final coal deliveries and retired in May 2015 as a result of stricter EPA emissions standards.
“The Rockport generating station, located in Spencer County, Indiana, consists of two 1300-megawatt coal generating units. Sulfur dioxide (SO2) emissions at Rockport are limited by the New Source Performance Standard to 1.2 lbs. SO2 per million British thermal unit (MMBtu). Compliance with the emission limit is achieved by using a blend consisting primarily of low-sulfur subbituminous coal in the steam generators. The coal supply for Rockport currently uses a blend of Powder River Basin (PRB) coal from Wyoming and low-sulfur bituminous coal from eastern sources. In order to comply with stricter U.S. Environmental Protection Agency (EPA) emissions standards, the installation of Dry Sorbent Injection (DSI) is being used at both Rockport units. Rockport Unit 2’s new DSI technology began operating in December 2014 and Rockport Unit 1’s began operating in April 2015. The new DSI technology did not change the current coal blend at Rockport.”
In addition to an existing long-term contract with an unnamed coal supplier, coal may also be purchased to fulfill any additional supply requirements through spot agreements with various other suppliers, West noted. I&M expects to receive approximately 8.2 million tons of coal in 2016 at the Rockport plant at a projected weighted average delivered cost of 211.99 cents/MMBtu or $39.13 per ton (exclusive of affiliated transportation costs). That unidentified mainstay coal supplier, under a contract due to expire in December 2016, will supply about 4.6 million tons in 2016, the West testimony showed.
Rockport is projected to take these tonnages of coal each year through 2020:
- 2016 – 8.175 million tons;
- 2017 – 7.404 million tons;
- 2018 – 7.345 million tons;
- 2019 – 7.716 million tons; and
- 2020 – 6.940 million tons.
West said about coal market conditions in general: “The Polar Vortex events in the first quarter of 2014 led to unprecedented natural gas prices in the northeast United States, which set record high power prices in PJM. This, in turn, led to a temporary increase in coal prices in the first half of 2014. Cool summer weather reduced power demand, which led to lower gas pricing and lower coal prices in the back half of 2014.
“The market for Eastern bituminous coal at the end of 2014 and thus far in 2015 has showed much lower demand and pricing than has been seen for several years. The trend for future Central Appalachian (CAPP) pricing appears to be levelizing or even decreasing slightly. PRB coal pricing was relatively strong in the beginning of 2014 because of rail delivery problems and low coal plant inventories, but pricing softened somewhat in the back half of 2014 and in the first part of 2015. In general, slight increases in PRB demand and pricing are expected as either demand for electricity or the pricing of natural gas supply increase.”
Based on current market projections, I&M may expect to pay between $10/ton and $14/ton for PRB coal and between $45/ton and $60/ton for bituminous coal in 2016, West added in the Michigan testimony.
By the way, in July 30 fuel cost testimony filed at the Indiana Utility Regulatory Commission, West identified Rockport’s primary coal supplier. “Due to the retirement of the Tanners Creek plant in May 2015, inventory at both TC 1-3 and TC 4 was exhausted by the end of May 2015,” he wrote about the four Tanners Creek units. “Rockport’s scheduled tonnages of coal during the forecast period from October 2015 through March 2016 will be supplied primarily by an agreement with Peabody COALSALES, LLC that has been in place for several years. The overall forecasted weighted average delivered cost of coal for Rockport from all sources during the period of October 2015 through March 2016 is projected to be $44.52/ton or 242.17 cents/MMBtu.”