Indiana Michigan Power had to scramble to deal with low Rockport coal burn

Indiana Michigan Power, in its latest fuel cost recovery application filed July 29 at the Indiana Utility Regulatory Commission, said its 2,600-MW Rockport coal plant has suffered low burns lately due to cheap natural gas.

Charles F. West, employed by American Electric Power Service Corp. (AEPSC), a subsidiary of I&M parent American Electric Power (NYSE: AEP) in the regulated Commercial Operations organization as Manager, Coal Procurement, outlined the coal situation.

The purpose of his testimony iis to provide a comparison of the forecasted December 2015-May 2016 (called the “Reconciliation Period”) delivered coal costs to actual deliveries, comment on current coal market and energy market conditions and the corresponding impact of each on coal procurement and consumption at the Rockport Plant, address l&M’s coal delivery forecast for the period covering October 2016-March 2017 (the “Forecast Period”), to summarize l&M’s long-term coal supply agreements, to describe l&M’s coal purchasing strategy and to describe l&M’s use of coal decrement pricing.

l&M’s Rockport station is located in Spencer County, Indiana, and consists of two 1,300-MW coal 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 Powder River Basin (PRB) low-sulfur sub-bituminous coal from Wyoming and low-sulfur bituminous coal from various Central Appalachian sources.

In order to comply with more stringent U.S. Environmental Protection Agency emissions standards, Dry Sorbent Injection (DSI) technology is being used at both Rockport units. The technology began operating on Rockport Unit 2 in December 2014 and on Rockport Unit 1 in April 2015. The DSI technology and Activated Carbon Injection (ACI) are being utilized to achieve compliance with the Mercury and Air Toxics Standards (MATS). The DSI system uses sodium bicarbonate to reduce emissions of acid gases; the ACI system uses brominated activated carbon to reduce emissions of mercury; and electrostatic precipitator upgrades including new transformers and controls, will ensure compliance with hazardous air pollutant limits that are measured via particulate matter emission limits.

During the Reconciliation Period, the overall weighted average delivered cost of coal for the Rockport plant from all sources was forecasted to be $44.97/ton or 244.32 cents/MMBtu. The actual delivered cost was $43.30/ton or 233.12 cents/MMBtu. The actual weighted average delivered cost of coal was approximately 4% lower than expected due mainly to no fuel adjustment on the rail transportation price and lower barge rates.

During 2015, low NYMEX (New York Mercantile Exchange) and CSX Transportation-origin coal pricing and reduced demand continued to apply downward pressure on the market, which led to the closure of a significant portion of the Central Appalachian (CAPP) coal production in Kentucky and West Virginia, West noted. The cost of NYMEX coal for Rockport remained moderately stable throughout the Reconciliation Period. While PRB coal pricing was relatively strong in the beginning of 2015, the market began experiencing the same downward pressure that other basins were experiencing throughout the year and the remainder of the Reconciliation Period.

Rockport’s scheduled tonnages of sub-bituminous coal during the Forecast Period will be supplied primarily by an agreement with Peabody COALSALES LLC, which has been in place for several years. The overall forecasted weighted average delivered cost of coal for Rockport from all sources during the Forecast Period is projected to be $43.72/ton or 241.43 cents/MMBtu.

Low burn starting in late 2015 pushed the utiility into decrement pricing

Beginning in late 2015, as a result of an unusually warm winter and continuing low natural gas prices, power prices in PJM began liquidating below Rockport’s cost of generation. This resulted in the Rockport units either being placed in a Down Not Required (DNR) status or operating at minimum load most of the time they were online, which reduced coal consumption to the point that l&M became concerned about meeting the minimum rail obligation and coal contractual commitments.

Rockport maintains two separate coal piles, bituminous and sub-bituminous, each with their own inventory. Both of these coal piles were expected to exceed their maximum physical capacity if l&M received all of its contractual obligations given the reduced burn. When l&M recognized a potential issue relative to reduced burn, coal storage pile limitations, and its contractual obligations, l&M began negotiating with suppliers to defer a portion of the tonnage delivery into 2017. Ultimately, l&M was able to successfully renegotiate the contracts with the largest suppliers of both bituminous and sub-bituminous coals by extending the term and delaying a portion of the tonnage into 2017 at no additional cost to l&M’s customers.

After deferring delivery of those tons, l&M evaluated multiple alternatives to further manage Rockport’s inventory. Offsite storage of coal, selling coal into the market, buying out of agreements, paying liquidated damages on a contract, and decrement pricing were all evaluated to find the lowest cost solution to address the critical issue of a growing inventory that was quickly approaching the physical capacity limits of Rockport’s coal piles, West wrote.

The offsite storage space that was available would have resulted in fees for storage as well as for extra transportation, handling, and transloading to move coal from mines to storage then ultimately to Rockport. Since the market was oversupplied, selling coal back into the market would not have been cost effective as the current market price was less than the contract prices. Buying out of agreements was potentially another way to manage a quickly growing inventory, but West said sellers are not always agreeable to this, particularly in the current climate where they need to sell as much coal as possible to keep their mines open. In addition, l&M’s reliability of coal supply could be adversely affected by this practice.

Paying liquidated damages on coal contracts was another option evaluated. l&M’s coal contracts allow for situations where the buyer cannot, for whatever reason, fulfill their obligation to take all of the contracted tons for a specific period. Rather than take the contracted tonnage, l&M could pay liquidated damages to the supplier. Liquidated damages would have needed to be paid on both rail and coal supply agreements and no coal would have been delivered for future use. Thus, simply paying liquidated damages was not the lowest cost option for l&M’s customers in this case.

After evaluating all of these alternatives, l&M determined that applying a decrement price was the most cost effective solution. l&M began applying decrement pricing to its market offer for the Rockport plant beginning in the second quarter of 2016.

Decrement pricing involves reducing the market offer provided to PJM Interconnection for the Rockport plant by an amount equal to or less than the liquidated damages that would be applicable should l&M not meet the minimum volume requirements under the rail and coal supply contracts. In other words, the decrement pricing represents the avoided cost associated with implementing a more expensive option to avoid or reduce surplus coal inventories.

In the second quarter of 2016, coal burn had decreased, inventory continued to increase, and rail and coal agreements had contractual minimum volume obligations that had to be met. At some point, there would physically be no room left to store coal at Rockport. If that happened and no other action was taken, l&M would have been forced to stop taking delivery of coal and would have incurred liquidated damages as defined in the coal and transportation agreements. The decrement pricing helped to avoid those charges while still ensuring that l&M received all of the coal it contracted for to use at a later time.

West noted that the most recent fuel cost orders for all four of the other investor-owned electric utilities operating in Indiana show that they have engaged in decrement pricing.

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.