The Indiana Utility Regulatory Commission on Dec. 30 approved an Oct. 29 application from Duke Energy Indiana related to its fuel adjustment charge (FAC) costs to be applicable during the billing cycles of January, February, and March 2016.
The Dec. 30 order said: “Mr. Brett Phipps testified regarding Applicant’s coal procurement practices and its coal inventories. Mr. Phipps testified that Applicant has exercised its right to reopen the contract price of an existing long-term agreement in accordance with the terms of the contract by giving notice in March 2015. He testified that the parties concluded their negotiations in August of 2015 and agreed upon reduced pricing that will become effective January 1, 2016.
“Mr. Phipps also testified that as of August 31, 2015, coal inventories were approximately 4,519,075 tons (or 74 days of coal supply), which is lower than what was reported in FAC 105 due to a number of factors, noted below as well as the implementation of the coal price decrement in July 2015. Mr. Phipps added that Applicant continues to evaluate a host of options in order to effectively manage its growing coal inventory. Mr. Phipps stated that as inventory levels dictate, Applicant explores options to store or defer contract coal or resell surplus coal into the market. Mr. Phipps testified that upon the evaluation of the growing levels of coal inventory, Applicant has extended an existing storage agreement with one supplier to store coal at the supplier’s mine facilities for up to one additional year. In addition, Applicant has agreed to defer approximately 174,000 tons of coal for delivery in 2015 to 2016 with this same supplier. Due to continued weak coal market conditions, resell opportunities will continue to be extremely difficult in the near term.
“Mr. Phipps testified that spot natural gas prices are dynamic, volatile, and can change significantly day to day based on market fundamental drivers. During the three-month period from June through August 2015 the price Applicant paid for delivered natural gas at its gas burning stations was between $1.75 per million BTU to $3.65 per million BTU.”
Phipps is Managing Director of Fuel Procurement for Duke Energy Progress, a utility affiliate of Duke Energy Indiana through mutual parent Duke Energy (NYSE: DUK). Also supplying Oct. 29 testimony was John D. Swez, employed by Duke Energy Carolinas as Director, Generation Dispatch and Operations.
“Mr. Swez testified that in July 2015 the Edwardsport IGCC generating station produced more generation than in any month since being declared commercial in 2013,” said the commission’s Dec. 30 order. “In September 2015, the unit produced the second most generation in any month since being declared commercial. He stated that the unit also performed well during June and August 2015. He testified that when the unit’s gasifiers are operating, Edwardsport IGCC is being offered with a commitment status of must-run. Mr. Swez stated that Edwardsport IGCC has followed MISO’s dispatch direction between the minimum and maximum capability of the unit during this time. Mr. Swez also testified that during times when [coal-based] syngas is not available and the station is available on natural gas operation, the unit will typically be offered to MISO with a commitment status of economic and can be committed and dispatched at MISO’s discretion.
“Mr. Swez testified that beginning in late February 2012, a coal price decrement was applied to the dispatch costs of Gibson Units 1-5, Wabash River Units 2-6, and Cayuga Units 1-2 to correctly reflect the economics of additional costs associated with avoiding or reducing surplus coal inventories. He stated that, to the extent that the price decrement results in units being dispatched that otherwise would not be, coal coming to the station is consumed, other potential costs are avoided, and customers ultimately benefit because higher cost alternatives to manage the inventory are avoided. Mr. Swez testified the price decrement is working as designed as Applicant initially saw a significant increase in generation output from these units. As the level of the coal price decrement has decreased over time, the impact of the decrement has lessened. Mr. Swez testified that during this FAC period, the coal price decrement was zero until a non-zero coal price decrement was initiated for Cayuga 1-2 and Gibson 1-5 on July 28, 2015.
“Mr. Swez testified that Wabash River units 2-5, which will be retired by April 15, 2016, were previously granted a one-year extension of the April 2015 Mercury and Air Toxics Standards (‘MATS’) rule compliance date due to the need for at least two of the four units to operate at any given time for transmission system reliability. He explained that in consideration of the minimization of MATS related emissions during the extension period and the operational complexities of units at this point in the lifecycle, Applicant is employing a MISO offer strategy which prioritizes availability and operation of the units to solve transmission reliability constraints. As a result, Applicant will generally be holding two of the four of Wabash River units 2-5 in reserve shutdown available for emergency operation only. He testified that the number of units in reserve versus operation may vary depending on unit availability, the needs of the transmission system, and energy prices in the MISO market. Mr. Swez testified that given the units are nearing the end of their useful lives, Applicant’s goal will be to maintain the availability of the generating units primarily for transmission reliability support, and specifically to maintain availability during peak demand times such as summer and winter periods when transmission related events and/or energy prices could have the highest customer impact.”