Coal inventories climb again, coal ‘decrement’ stages a comeback at Duke Energy Indiana

Due to a recent climb in coal inventories as its coal-fired capacity ran into tough competition in the power markets, Duke Energy Indiana on July 28 again instituted a coal “decrement” for units at its Cayuga and Gibson power plants.

John D. Swez, employed by Duke Energy Carolinas LLC as Director of Generation Dispatch and Operations, provided July 30 testimony to the Indiana Utility Regulatory Commission on behalf of Duke Energy Indiana. The filing was part of a twice-yearly fuel adjustment clause (FAC) review case. All of these utilities are subsidiaries of Duke Energy (NYSE: DUK).

A decrement is basically a way of figuring the cost of not burning coal, like the cost of keeping it in stockpile, into the prices that Duke Energy Indiana bids into the Midcontinent ISO market.

Swez noted about the history of the decrement: “Starting in late February 2012, the Company started applying a coal price decrement to the dispatch costs of Gibson 1-5, Wabash River 2-6, and Cayuga 1-2 generating units to correctly reflect the economics of additional costs associated with avoiding or reducing surplus coal inventories. To the extent that the price decrement results in units being dispatched that otherwise would not be, coal coming into the station is consumed, other potential costs are avoided, and customers ultimately benefit because higher cost alternatives to manage the inventory are avoided. With the price decrement in place, the Company 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. In short, the price decrement is working as designed.

“It should be noted that on specific hours and days, the price decrement will have no impact on the commitment and dispatch of the Company’s generating units because the unit in question was already economic without application of the price decrement. In other words, the price decrement does not make a difference under certain circumstances.

“During this FAC period, the coal price decrement has been zero the entire time. During times when the coal price decrement is zero, there is no difference between the non-decremented dispatch price and the as offered price of a generating unit. … During this FAC period, there was no projected excess inventory. Therefore, there was no need to create a coal price decrement stack.

“The Company continues to forecast its coal inventory position as part of the normal course of business. In fact, due to increased coal inventories and an excess coal inventory forecast, the Company has implemented a coal price decrement for Gibson 1-5 and Cayuga 1-2 beginning on July 28, 2015.”

Brett Phipps, the Managing Director, Fuel Procurement for Duke Energy Progress, a utility affiliate of Duke Energy Indiana, filed companion July 30 testimony that also addressed the coal inventory issue. He noted is as of Feb. 28, 2015, Duke Energy Indiana’s coal inventories were approximately 4,196,000 tons (or 68 days of coal supply at a full load burn rate per day) across the system. As of May 31, 2015, coal inventories increased to approximately 4,892,000 tons (or 80 days of coal supply) due to lower power prices and low natural gas prices this past spring. Duke Energy Indiana expects coal inventories to stay relatively flat over the next quarter, Phipps added.

Phipps pointed to the decrement as way one way to deal with the burgeoning inventories. Other options include to store or defer contract coal or resell surplus coal into the market. “Upon the evaluation of the growing levels of coal inventory, the Company has extended an existing storage agreement with one supplier to store coal at the supplier’s mine facilities for up to one additional year,” Phipps wrote. “This existing storage agreement was referenced in FAC 99. In addition, the Company 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. The Company will continue to closely monitor its anticipated coal requirements and inventories and take every action available to cost effectively control coal inventories in the least cost-impact manner for customers.”

Cayuga unit came back from a long outage in June

Swez in his testimony addressed various operational issues for Duke Energy Indiana.

  • Cayuga Unit 2 entered a forced outage on Oct. 22, 2014, following a failure in the Intermediate Pressure (IP) section of the turbine. The failure required replacement of several blade rows in the High Pressure (HP) and IP sections of the turbine. In order to minimize the overall outage time for the unit, the company moved the previously scheduled spring selective catalytic reduction (SCR) tie-in outage that was scheduled for March 21, 2015, until May 31, 2015, to minimize the unit’s downtime. The SCR is being added for NOx control. The planned outage work was completed during the unit’s outage, as was the repair to the turbine, with the forced outage event ending on April 3, 2015. However, due to other equipment inspection findings on the Unit 2 LP turbine rotors, the unit did not return to service until June 1, 2015.
  • Swez also pointed out that, as long planned, the coal-fired Wabash River units 2-5 will be retired by April 15, 2016. These units were granted a one-year extension of the April 2015 Mercury and Air Toxics Standards (MATS) compliance date due to the need for at least two of the four units to operate at any given time for transmission system reliability (in addition to Wabash River Unit 6, which also has a one-year MATS rule extension of time). 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, Duke Energy Indiana is employing a MISO offer strategy which prioritizes availability and operation of the units to solve transmission reliability constraints. As a result, Duke Energy Indiana will generally be holding two of the four of Wabash River units 2-5 in reserve shutdown available for emergency operation only. 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.
  • During March 2015, the new Edwardsport integrated gasification combined cycle (IGCC) coal plant produced more generation than in any month since being declared commercial in 2013. Following this period, the unit was on planned outage during periods of April and May 2015, Swez reported. Since the planned outage, the unit has returned to service and during June 2015, the unit produced the fourth most generation since commercial operation began. Finally, through the first 27 days of July 2015, Edwardsport has already surpassed the June 2015 generation total with 4 additional days still remaining in the month. When the unit’s gasifiers are operating, Edwardsport is being offered with a commitment status of must-run with the unit’s parameters outlined for MISO, as is typically the case with other Duke Energy Indiana large coal generating units. Edwardsport has followed MISO’s dispatch direction between the minimum and maximum capability of the unit during this time. In addition, during times when 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.

Phipps outlines coal procurement factors

Phipps wrote in his testimony that Gibson, Wabash River, Cayuga and the Edwardsport IGCC are supplied by long-term coal supply agreements. Gallagher Station will continue to be supplied by spot purchases depending on how much the Gallagher units actually operate.

For the twelve-month period ending May 31, 2015, the Duke Energy Indiana purchased a total of approximately 12.7 million tons of coal (pursuant to both long- and short-term contract commitments) at an approximate average cost of $2.65/MMBtu. The delivered cost of coal purchased under long-term commitments averaged $2.65/MMBtu and made up 97.4% of total coal receipts. The delivered cost of coal purchased under short-term commitments averaged $2.91/MMBtu.

“Although published prices for U.S. coal markets have not changed significantly since the last fuel proceeding they have softened across the regions,” Phipps added. “The following are 2015 price indications for the different coal producing regions: High-sulfur Illinois basin coal prices are in the low to mid $30’s per ton; Central Appalachia coal prices are in the mid $40’s; Northern Appalachia coal prices are in the low to mid $40’s; and Powder River Basin coal prices are approximately $10 per ton. Coal demand has lessened slightly since the last FAC mainly due to cheaper natural gas pricing and lower purchase power cost. As such, utility stockpiles have seen some growth since the last FAC.

“Coal markets are likely to be relatively stable in Indiana between now and the next FAC; however, in the next year there is potential for market volatility due to a number of factors, including: (a) deterioration of the financial health of coal suppliers; (b) recent U.S. Environmental Protection Agency (‘EPA’) regulations for power plants that result in utilities retiring or modifying plants, which lower total domestic steam coal demand, and can result in some plants shifting coal sources to different basins; (c) softening demand in global markets for both steam and metallurgical coal, causing export opportunities to decline for U.S. coal producers; (d) increased production in the Illinois Basin and Northern Appalachian regions; (e) increased volatility in gas prices, and continued increase in gas supply combined with installation of new combine cycle (‘CC’) generation by utilities, especially in the south, which may also lower overall coal demand; (f) increasingly stringent safety regulations for mining operations, which result in higher costs and lower productivity ; (g) volatile power prices; (h) mergers and acquisitions in the different coal basins; and (i) mining employee layoffs and production declines in an attempt to bring an oversupply of coal into balance with current demand.”

As for natural gas prices, Phipps wrote: “Spot natural gas prices are dynamic, volatile and can change significantly day to day based on market fundamental drivers. The current spot price for natural gas is in the range of approximately $2.75 to $3.05 per MMBtu. For the period March through May 2015 the price the Company paid for delivered natural gas at its gas burning stations was between a low of $2.48 MMBtu on April 10, 2015 to a high of $6.25 on March 5, 2015. In comparison, during the previous period of December 2015 to February 2015, the price the Company paid for delivered natural gas at its gas burning generation stations during this period was in a range of delivered daily gas prices between a low of $2.66 MMBtu on February 9, 2015 to a high of $11.50 per MMBtu on February 19, 2015.”

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.